Vectren (VVC) 10-K 23 Feb 17 2016 FY Annual report Financial data

Document And Entity Information

Document And Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2016	Jan. 31, 2017	Jun. 30, 2016
Entity Information [Line Items]
Entity Registrant Name	VECTREN CORP
Entity Central Index Key	1,096,385
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	No
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$ 4,356,496,757
Entity Common Stock, Shares Outstanding		82,922,412
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	FY
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2016
Current Fiscal Year End Date	--12-31

Balance Sheet

Balance Sheet - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Current Assets
Cash and cash equivalents	$ 68.6	$ 74.7
Accounts receivable - less reserves of $6.0 & $5.6, respectively	225.3	227.5
Accrued unbilled revenues	172.4	142.5
Inventories	129.9	133.7
Recoverable fuel and natural gas costs	29.9	0
Prepayments and other current assets	52.7	81
Total current assets	678.8	659.4
Utility Plant
Original cost	6,545.4	6,090.4
Less: accumulated depreciation and amortization	2,562.5	2,415.5
Net utility plant	3,982.9	3,674.9
Investments in unconsolidated affiliates	20.4	20.9
Other utility and corporate investments	34.1	31.2
Other nonutility investments	16.1	16.2
Nonutility plant - net	423.9	414.6
Goodwill	293.5	293.5
Regulatory assets	308.8	249.4
Other assets	42.2	39.9
TOTAL ASSETS	5,800.7	5,400
Current Liabilities
Accounts payable	302.2	248.8
Refundable fuel and natural gas costs	0	7.9
Accrued liabilities	207.7	183.6
Short-term borrowings	194.4	14.5
Current maturities of long-term debt	124.1	73
Total current liabilities	828.4	527.8
Long-term Debt - Net of Current Maturities	1,589.9	1,712.9
Deferred Income Taxes and Other Liabilities
Deferred income taxes	905.7	805.4
Regulatory liabilities	453.7	433.9
Deferred credits and other liabilities	254.9	236.2
Total deferred credits and other liabilities	1,614.3	1,475.5
Commitments & Contingencies (Notes 7, 17-20)
Common Shareholders' Equity
Common stock (no par value) - issued & outstanding 82.9 & 82.8 shares, respectively	729.8	722.8
Retained earnings	1,039.6	962.2
Accumulated other comprehensive income/(loss)	(1.3)	(1.2)
Total common shareholders' equity	1,768.1	1,683.8
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$ 5,800.7	$ 5,400

Income Statement

Income Statement - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
OPERATING REVENUES
Gas utility	$ 771.7	$ 792.6	$ 944.6
Electric utility	605.8	601.6	624.8
Nonutility	1,070.8	1,040.5	1,042.3
Total operating revenues	2,448.3	2,434.7	2,611.7
OPERATING EXPENSES
Cost of gas sold	266.7	305.4	468.7
Cost of fuel and purchased power	183.6	187.5	201.8
Cost of nonutility revenues	363.4	355	346.4
Other operating	932.2	909.2	943.4
Depreciation and amortization	260	256.3	273.4
Taxes other than income taxes	60.9	59.5	63.5
Total operating expenses	2,066.8	2,072.9	2,297.2
OPERATING INCOME	381.5	361.8	314.5
OTHER INCOME (EXPENSE)
Equity in earnings (losses) of unconsolidated affiliates	(0.2)	(0.6)	0.5
Other income - net	28.7	20.3	19.7
Total other income	28.5	19.7	20.2
Interest expense	85.5	84.5	86.7
INCOME BEFORE INCOME TAXES	324.5	297	248
Income taxes	112.9	99.7	81.1
Net income	$ 211.6	$ 197.3	$ 166.9
AVERAGE COMMON SHARES OUTSTANDING (in shares)	82.8	82.7	82.5
DILUTED COMMON SHARES OUTSTANDING (in shares)	82.8	82.7	82.5
EARNINGS PER SHARE OF COMMON STOCK:
BASIC (in dollars per share)	$ 2.55	$ 2.39	$ 2.02

Balance Sheet (Parenthetical)

Balance Sheet (Parenthetical) - USD ($) shares in Millions, $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Current Assets
Reserves	$ 6	$ 5.6
Common Shareholders' Equity
Common stock Shares, Issued (in shares)	82.9	82.8
Common stock, Shares Outstanding (in shares)	82.9	82.8

CONSOLIDATED CONDENSED STATEMEN

CONSOLIDATED CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Net Income	$ 211.6	$ 197.3	$ 166.9
Other comprehensive income	(0.1)	0.1	(0.6)
TOTAL COMPREHENSIVE INCOME	211.5	197.4	166.3
Pensions and Other Benefits [Member]
Amounts arising during the year before tax	(10.1)	1.2	(52.6)
Reclassifications to periodic cost before tax	4.7	6.9	3.4
Deferrals to regulatory assets	5.3	(8)	48.2
Income taxes	0	0	0.4
Other comprehensive income	$ (0.1)	$ 0.1	$ (0.6)

Statement of Cash Flows

Statement of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$ 211.6	$ 197.3	$ 166.9
Adjustments to reconcile net income to cash from operating activities:
Depreciation and amortization	260	256.3	273.4
Deferred income taxes and investment tax credits	100.1	80.4	37.9
Provision for uncollectible accounts	6.9	8.1	7.3
Expense portion of pension and postretirement benefit cost	3.6	6.8	6.6
Other non-cash charges - net	7.8	7.3	5.3
Loss on Sale of Business (pretax)	0	0	41.8
Gain on Revaluation of Contingent Consideration	0	0	(14.8)
Changes in working capital accounts:
Accounts receivable & accrued unbilled revenues	(39.6)	(15.4)	11.8
Inventories	3.9	(15.2)	(22.5)
Recoverable/refundable fuel and natural gas costs	(37.8)	15.2	(4.4)
Prepayments and other current assets	22.9	20.3	(35.2)
Accounts payable, including to affiliated companies	40.7	(0.5)	20.2
Accrued liabilities	22.7	(0.9)	12.3
Employer contributions to pension and postretirement plans	(19.6)	(26.5)	(5.1)
Changes in noncurrent assets	(44)	(21.9)	0.1
Changes in noncurrent liabilities	(15.1)	(6.1)	(13.4)
Net cash flows from operating activities	524.1	505.2	488.2
Proceeds from:
Long-term debt, net of issuance costs	0	385.5	62.4
Dividend reinvestment plan and other common stock issuances	6.3	6.2	6.1
Requirements for:
Dividends on common stock	(134.2)	(127.3)	(120.4)
Retirement of long-term debt	(73)	(170)	(293.6)
Other financing activities	0	0.2	0.1
Net change in short-term borrowings	179.9	(141.9)	87.8
Net cash flows from financing activities	(21)	(47.3)	(257.6)
Proceeds from:
Sale of business	0	0	311.2
Sale of Assets and Other collections	33	27.5	9.5
Requirements for:
Capital expenditures, excluding AFUDC equity	(542)	(476.9)	(448.3)
Business Acquisitions and Other Costs	(5.2)	(14.3)	(38.1)
Changes in Restricted Cash	5	(5.9)	0
Net cash flows from investing activities	(509.2)	(469.6)	(165.7)
Net change in cash and cash equivalents	(6.1)	(11.7)	64.9
Cash and cash equivalents at beginning of period	74.7	86.4	21.5
Cash and cash equivalents at end of period	$ 68.6	$ 74.7	$ 86.4

Statement of Shareholders' Equi

Statement of Shareholders' Equity - USD ($) shares in Millions, $ in Millions	Total	Common Stock [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Income (Loss) [Member]
Balance at beginning of period at Dec. 31, 2013	$ 1,554.3	$ 709.3	$ 845.7	$ (0.7)
Balance at beginning of period (in shares) at Dec. 31, 2013		82.4
Comprehensive income:
Net Income	166.9		166.9
Other comprehensive income (loss)	(0.6)			(0.6)
Common stock:
Issuance: option exercises and dividend reinvestment plan (in shares)		0.2
Issuance: option exercised and dividend reinvestment plan	6.1	$ 6.1
Dividends ($1.460, $1.540 and $1.620 per share)	(120.4)		(120.4)
Other	0.3	0.3
Balance at end of period at Dec. 31, 2014	1,606.6	$ 715.7	892.2	(1.3)
Balance at end of period (in shares) at Dec. 31, 2014		82.6
Comprehensive income:
Net Income	197.3		197.3
Other comprehensive income (loss)	0.1			0.1
Common stock:
Issuance: option exercises and dividend reinvestment plan (in shares)		0.2
Issuance: option exercised and dividend reinvestment plan	6.2	$ 6.2
Dividends ($1.460, $1.540 and $1.620 per share)	(127.3)		(127.3)
Other	0.9	0.9
Balance at end of period at Dec. 31, 2015	$ 1,683.8	$ 722.8	962.2	(1.2)
Balance at end of period (in shares) at Dec. 31, 2015	82.8	82.8
Comprehensive income:
Net Income	$ 211.6		211.6
Other comprehensive income (loss)	(0.1)			(0.1)
Common stock:
Issuance: option exercises and dividend reinvestment plan (in shares)		0.1
Issuance: option exercised and dividend reinvestment plan	6.3	$ 6.3
Dividends ($1.460, $1.540 and $1.620 per share)	(134.2)		(134.2)
Other	0.7	0.7
Balance at end of period at Dec. 31, 2016	$ 1,768.1	$ 729.8	$ 1,039.6	$ (1.3)
Balance at end of period (in shares) at Dec. 31, 2016	82.9	82.9

Statement of Shareholders' Equ8

Statement of Shareholders' Equity (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Statement of Stockholders' Equity [Abstract]
Dividends (in dollars per share)	$ 1.620	$ 1.540	$ 1.460

Organization and Nature of Oper

Organization and Nature of Operations	12 Months Ended
	Dec. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization and Nature of Operations	Organization and Nature of Operations Vectren Corporation (the Company or Vectren), an Indiana corporation, is an energy holding company headquartered in Evansville, Indiana. The Company’s wholly owned subsidiary, Vectren Utility Holdings, Inc. (Utility Holdings or VUHI), serves as the intermediate holding company for three public utilities: Indiana Gas Company, Inc. (Indiana Gas or Vectren Energy Delivery of Indiana - North), Southern Indiana Gas and Electric Company (SIGECO or Vectren Energy Delivery of Indiana - South), and Vectren Energy Delivery of Ohio, Inc. (VEDO). Utility Holdings also has other assets that provide information technology and other services to the three utilities. Utility Holdings’ consolidated operations are collectively referred to as the Utility Group. Both Vectren and Utility Holdings are holding companies as defined by the Energy Policy Act of 2005. Vectren was incorporated under the laws of Indiana on June 10, 1999. Indiana Gas provides energy delivery services to approximately 587,000 natural gas customers located in central and southern Indiana. SIGECO provides energy delivery services to approximately 144,000 electric customers and approximately 111,000 gas customers located near Evansville in southwestern Indiana. SIGECO also owns and operates electric generation assets to serve its electric customers and optimizes those assets in the wholesale power market. Indiana Gas and SIGECO generally do business as Vectren Energy Delivery of Indiana. VEDO provides energy delivery services to approximately 316,000 natural gas customers located near Dayton in west central Ohio. The Company, through Vectren Enterprises, Inc. (Enterprises), is involved in nonutility activities in two primary business areas: Infrastructure Services and Energy Services. Infrastructure Services provides underground pipeline construction and repair services. Energy Services provides energy performance contracting and sustainable infrastructure, such as renewables, distributed generation, and combined heat and power projects. Prior to August 29, 2014, the Company had activities in a coal mining business. Results in the financial statements include the results of Vectren Fuels, Inc. (Vectren Fuels) through the date of sale of August 29, 2014, when the Company exited the coal mining business. Enterprises also has other legacy businesses that have investments in energy-related opportunities and services and other investments. All of the above is collectively referred to as the Nonutility Group. Enterprises supports the Company's regulated utilities by providing infrastructure services.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	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 pension and postretirement benefit obligations, 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 and nonutility plant and the testing of goodwill and other assets for impairment. Recorded estimates are revised when better information becomes available or when actual amounts can be determined. Actual results could differ from current estimates. Principles of Consolidation The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries, after appropriate elimination of intercompany transactions. The Infrastructure Services segment, through wholly owned subsidiaries Miller Pipeline, LLC and Minnesota Limited, LLC, provides underground pipeline construction and repair services for customers that include Vectren Utility Holdings' utilities. In accordance with consolidation guidance under ASC 980, fees incurred by Vectren Utility Holdings and its subsidiaries for these pipeline construction and repair services, are appropriately not eliminated in consolidation. Subsequent Events Review Management performs a review of subsequent events for any events occurring after the balance sheet date but prior to the date the financial statements are issued. Cash & Cash Equivalents 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 at the Company’s Indiana utilities are recorded using the Last In – First Out (LIFO) method. Inventory related to the Company’s regulated operations 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 Both the Company’s Utility Plant and Nonutility 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 Both the IURC and PUCO allow the Company’s utilities to capitalize financing costs associated with Utility Plant based on a computed interest cost and a designated cost of equity funds. These financing costs are commonly referred to as AFUDC and are capitalized for ratemaking purposes and for financial reporting purposes instead of amounts that would otherwise be capitalized when acquiring nonutility plant. The Company reports both the debt and equity components of AFUDC in Other – net in the Consolidated Statements of Income . When property that represents a retirement unit is replaced or removed, the remaining historical value of such property is charged to Utility Plant , with an offsetting charge to Accumulated depreciation , resulting in no gain or loss. Costs to dismantle and remove retired property are recovered through the depreciation rates as determined by the IURC and PUCO. The Company’s portion of jointly owned Utility Plant , along with that plant’s related operating expenses, is presented in these financial statements in proportion to the ownership percentage. Nonutility Plant & Related Depreciation The depreciation of Nonutility Plant is charged against income over its estimated useful life, using the straight-line method of depreciation. When nonutility property is retired, or otherwise disposed of, the asset and accumulated depreciation are removed, and the resulting gain or loss is reflected in income, typically impacting operating expenses. Impairment Reviews Property, plant and equipment along with other long-lived assets are reviewed as facts and circumstances indicate that the carrying amount may be impaired. This impairment review involves the comparison of an asset’s (or group of assets’) carrying value to the estimated future cash flows the asset (or asset group) is expected to generate over a remaining life. If this evaluation were to conclude that the carrying value is impaired, an impairment charge would be recorded based on the difference between the carrying amount and its fair value (less costs to sell for assets to be disposed of by sale) as a charge to operations or discontinued operations. Investments in Unconsolidated Affiliates Investments in unconsolidated affiliates where the Company has significant influence are accounted for using the equity method of accounting. The Company’s share of net income or loss from these investments is recorded in Equity in earnings (losses) of unconsolidated affiliates . Dividends are recorded as a reduction of the carrying value of the investment when received. Investments in unconsolidated affiliates where the Company does not have significant influence are accounted for using the cost method of accounting. Dividends associated with cost method investments are recorded as Other income – net when received. Investments are reviewed as facts and circumstances indicate that the carrying amount may be impaired. This impairment review involves the comparison of an investment's fair value to its carrying value. Investments, when necessary, include adjustments for declines in value judged to be other than temporary. Goodwill Goodwill recorded on the Consolidated Balance Sheets results from business acquisitions and is based on a fair value allocation of the businesses’ purchase price at the time of acquisition. Goodwill is charged to expense only when it is impaired. The Company tests its goodwill for impairment at an operating segment level because the components within the segments are similar. These tests are performed at least annually and at the beginning of each year. Impairment reviews consist of a comparison of fair value to the carrying amount. If the fair value is less than the carrying amount, an impairment loss is recognized in operations. No goodwill impairments have been recorded during the periods presented. Regulation Retail public utility operations affecting Indiana customers are subject to regulation by the IURC, and retail public utility operations affecting Ohio customers are subject to regulation by the PUCO. The Company’s accounting policies give recognition to the ratemaking and accounting practices authorized by these agencies. Refundable or Recoverable Gas Costs & Cost of Fuel & Purchased Power All metered gas rates in Indiana contain a gas cost adjustment clause that allows the Company to charge for changes in the cost of purchased gas. Metered electric rates contain a fuel adjustment clause that allows for adjustment in charges for electric energy to reflect changes in the cost of fuel. The net energy cost of purchased power, subject to a variable benchmark based on NYMEX natural gas prices, is also recovered through regulatory proceedings. The Company records any under-or-over-recovery resulting from gas and fuel adjustment clauses 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, and the cost of fuel and purchased power for electric generation is charged to operating expense when consumed. 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 that are to be credited to customers through the ratemaking process. The Company continually assesses the recoverability of costs recognized as regulatory assets and liabilities and the ability to recognize new regulatory assets and liabilities associated with its regulated utility operations. Given the current regulatory environment in its jurisdictions, 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. Postretirement Obligations & Costs The Company recognizes the funded status of its pension plans and postretirement plans on its balance sheet. The funded status of a defined benefit plan is its assets (if any) less its projected benefit obligation (PBO), which reflects service accrued to date and includes the impact of projected salary increases (for pay-related benefits). The funded status of a postretirement plan is its assets (if any) less its accumulated postretirement benefit obligation (APBO), which reflects accrued service to date. To the extent this obligation exceeds amounts previously recognized in the statement of income, the Company records a Regulatory asset for that portion related to its rate regulated utilities. To the extent that excess liability does not relate to a rate regulated utility, the offset is recorded as a reduction to equity in Accumulated other comprehensive income . The annual cost of all postretirement plans is recognized in operating expenses or capitalized to plant following the direct labor of current employees. Specific to pension plans, the Company uses the projected unit credit actuarial cost method to calculate service cost and the PBO. This method projects the present value of benefits at retirement and allocates that cost over the projected years of service. Annual service cost represents one year’s benefit accrual while the PBO represents benefits allocated to previously accrued service. For other postretirement plans, service cost is calculated by dividing the present value of a participant’s projected postretirement benefits into equal parts based upon the number of years between a participant’s hire date and first eligible retirement date. Annual service cost represents one year’s benefit accrual while the APBO represents benefit allocated to previously accrued service. To calculate the expected return on pension plan assets, the Company uses the plan assets’ market-related value and an expected long-term rate of return. For the majority of the Company’s pension plans, the fair market value of the assets at the balance sheet date is adjusted to a market-related value by recognizing the change in fair value experienced in a given year ratably over a five-year period. Interest cost represents the annual accretion of the PBO and APBO at the discount rate. Actuarial gains and losses outside of a corridor (equal to 10 percent of the greater of the benefit obligation and the market-related value of assets) are amortized over the expected future working lifetime of active participants (except for plans where almost all participants are inactive). Prior service costs related to plan changes are amortized over the expected future working lifetime (or to full eligibility date for postretirement plan other than pensions) of the active participants at the time of the amendment. Asset Retirement Obligations A portion of removal costs related to interim retirements of gas utility pipeline and utility poles, certain asbestos-related issues, and reclamation activities 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. Product Warranties, Performance Guarantees & Other Guarantees Liabilities and expenses associated with product warranties and performance guarantees are recognized based on historical experience at the time the associated revenue is recognized. Adjustments are made as changes become reasonably estimable. The Company does not recognize the fair value of an obligation at inception for these guarantees because they are guarantees of the Company’s own performance and/or product installations. While not significant for the periods presented, the Company does recognize the fair value of an obligation at the inception of a guarantee in certain circumstances. These circumstances would include executing certain indemnification agreements and guaranteeing operating lease residual values, the performance of a third party, or the indebtedness of a third party. 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, optimizing its generation assets, 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 Real Time and Day Ahead purchase and sale contracts with the MISO, natural gas purchases, and wind farm and other electric generating contracts. 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 when the contracts are expected to be settled. Contracts and any associated collateral with counter-parties subject to master netting arrangements are presented net in the Consolidated Balance Sheets . The offset resulting from carrying the derivative at fair value on the balance sheet is charged to earnings unless it qualifies as a hedge or is subject to regulatory accounting treatment. When hedge accounting is appropriate, the Company assesses and documents hedging relationships between the derivative contract and underlying risks as well as its risk management objectives and anticipated effectiveness. When the hedging relationship is highly effective, derivatives are designated as hedges. The market value of the effective portion of the hedge is marked to market in Accumulated other comprehensive income for cash flow hedges. Ineffective portions of hedging arrangements are marked to market through earnings. For fair value hedges, both the derivative and the underlying hedged item are marked to market through earnings. The offset to contracts affected by regulatory accounting treatment are marked to market as a regulatory asset or liability. Market value for derivative contracts is determined using quoted market prices from independent sources. The Company rarely enters into contracts that have a significant impact to the financial statements where internal models are used to calculate fair value. As of and for the periods presented, related derivative activity is not material to these financial statements. Income Taxes 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 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’s rate regulated utilities recognize 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. Production tax credits (PTCs) are recognized as energy is generated and sold based on a per kilowatt hour rate prescribed in applicable federal and state statutes. Revenues Most revenues are recognized as products and services are delivered to customers. Some nonutility revenues are recognized using the percentage of completion method. The Company records revenues for services and goods delivered but not billed at the end of an accounting period in Accrued unbilled revenues . MISO Transactions With the IURC’s approval, the Company is a member of the MISO, a FERC approved regional transmission organization. The MISO serves the electrical transmission needs of much of the Midcontinent region and maintains operational control over the Company’s electric transmission facilities as well as that of other utilities in the region. The Company is an active participant in the MISO energy markets, bidding its owned generation into the Day Ahead and Real Time markets and procuring power for its retail customers at Locational Marginal Pricing (LMP) as determined by the MISO market. MISO-related purchase and sale transactions are recorded using settlement information provided by the MISO. These purchase and sale transactions are accounted for on a net hourly position. Net purchases in a single hour are recorded in Cost of fuel & purchased power and net sales in a single hour are recorded in Electric utility revenues . On occasion, prior period transactions are resettled outside the routine process due to a change in the MISO’s tariff or a material interpretation thereof. Expenses associated with resettlements are recorded once the resettlement is probable and the resettlement amount can be estimated. Revenues associated with resettlements are recognized when the amount is determinable and collectability is reasonably assured. The Company also receives transmission revenue that results from other members’ use of the Company’s transmission system. These revenues are also included in Electric utility revenues. Generally, these transmission revenues along with costs charged by the MISO are considered components of base rates and any variance from that included in base rates is recovered from / refunded to retail customers through tracking mechanisms. Share-Based Compensation The Company grants share-based awards to certain employees and board members. Liability classified share-based compensation awards are re-measured at the end of each period based on an expected settlement date fair value. Equity classified share-based compensation awards are measured at the grant date, based on the fair value of the award. Expense associated with share-based awards is recognized over the requisite service period, which generally begins on the date the award is granted through the earlier of the date the award vests or the date the employee becomes retirement eligible. Excise & Utility Receipts Taxes Excise taxes and 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 $28.3 million in 2016 , $29.4 million in 2015 , and $32.3 million in 2014 . Expense associated with excise and utility receipts taxes are recorded as a component of Taxes other than income taxes . Operating Segments The Company’s chief operating decision maker is the Chief Executive Officer. The Company uses net income calculated in accordance with generally accepted accounting principles as its most relevant performance measure. The Company has three operating segments within its Utility Group, three operating segments in its Nonutility Group, and a Corporate and Other segment. Fair Value Measurements Certain assets and liabilities are valued and disclosed at fair value. Financial assets include securities held in trust by the Company’s pension plans. Nonfinancial assets and liabilities include the initial measurement of an asset retirement obligation or the use of fair value in goodwill, intangible assets, and long-lived assets impairment tests. FASB guidance provides the framework for measuring fair value. That framework provides a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of the fair value hierarchy are described as follows: Level 1 Inputs to the valuation methodology are unadjusted quoted prices for identical assets or liabilities in active markets that the Company has the ability to access. Level 2 Inputs to the valuation methodology include · quoted prices for similar assets or liabilities in active markets; · quoted prices for identical or similar assets or liabilities in inactive markets; · inputs other than quoted prices that are observable for the asset or liability; · inputs that are derived principally from or corroborated by observable market data by correlation or other means If the asset or liability has a specified (contractual) term, the Level 2 input must be observable for substantially the full term of the asset or liability. Level 3 Inputs to the valuation methodology are unobservable and significant to the fair value measurement. 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.

Utility & Nonutility Plant

Utility & Nonutility Plant	12 Months Ended
	Dec. 31, 2016
Property, Plant and Equipment [Abstract]
Utility and Nonutility Plant	Utility & Nonutility Plant The original cost of Utility Plant , together with depreciation rates expressed as a percentage of original cost, follows: At December 31, (In millions) 2016 2015 Original Cost Depreciation Rates as a Percent of Original Cost Original Cost Depreciation Rates as a Percent of Original Cost Gas utility plant $ 3,627.0 3.4 % $ 3,279.7 3.4 % Electric utility plant 2,799.1 3.4 % 2,695.8 3.3 % Common utility plant 56.3 3.2 % 55.0 3.2 % Construction work in progress 63.0 — 59.9 — Total original cost $ 6,545.4 $ 6,090.4 SIGECO and Alcoa Generating Corporation (AGC), a subsidiary of Alcoa, Inc. (Alcoa), own a 300 MW unit at the Warrick Power Plant (Warrick Unit 4) as tenants in common. SIGECO's share of the cost of this unit at December 31, 2016 , is $190.4 million with accumulated depreciation totaling $110.8 million . AGC and SIGECO share equally in the cost of operation and output of the unit. SIGECO's share of operating costs is included in Other operating expenses in the Consolidated Statements of Income . In the first quarter of 2016, Alcoa closed its smelter operations. Historically, on-site generation owned and operated by AGC has been used to provide power to the smelter, as well as other mill operations, which will continue. Generation from Alcoa's share of the Warrick Unit 4 has historically been sold into the MISO market. The Company is actively working with Alcoa on plans related to continued operation of this generation. Nonutility Plant , net of accumulated depreciation and amortization follows: At December 31, (In millions) 2016 2015 Computer hardware & software $ 121.8 $ 108.8 Land & buildings 77.9 86.4 Vehicles & equipment 207.4 203.0 All other 16.8 16.4 Nonutility plant - net $ 423.9 $ 414.6 Nonutility Plant is presented net of accumulated depreciation and amortization totaling $460.8 million and $420.3 million as of December 31, 2016 and 2015 , respectively. For the years ended December 31, 2016 , 2015 , and 2014 , the Company capitalized interest totaling $1.0 million , $0.4 million , and $0.6 million , respectively, on nonutility plant construction projects. In 2016, the estimated depreciable lives for certain pieces of equipment at Minnesota Limited, LLC were reevaluated and extended due to a change in service life of the equipment. As a result of this evaluation, the Company extended the estimated useful life of certain pieces of equipment effective January 1 of the current year. The effect of this change in estimate was a reduction of annual depreciation expense of approximately $9.6 million in 2016.

Regulatory Assets & Liabilities

Regulatory Assets & Liabilities	12 Months Ended
	Dec. 31, 2016
Regulatory Assets and Liabilities Disclosure [Abstract]
Regulatory Assets and Liabilities	Regulatory Assets & Liabilities Regulatory Assets Regulatory assets consist of the following: At December 31, (In millions) 2016 2015 Future amounts recoverable from ratepayers related to: Benefit obligations (See Note 11) $ 102.6 $ 97.3 Net deferred income taxes (See Note 10) (17.1 ) (16.9 ) 85.5 80.4 Amounts deferred for future recovery related to: Cost recovery riders & other 91.6 54.6 91.6 54.6 Amounts currently recovered in customer rates related to: Loss on reacquired debt & hedging proceeds 24.1 25.8 Indiana authorized trackers 64.2 42.6 Deferred coal costs and other 21.2 28.3 Ohio authorized trackers 22.2 17.6 Other base rate recoveries — 0.1 131.7 114.4 Total regulatory assets $ 308.8 $ 249.4 Of the $132 million currently being recovered in customer rates, no amounts are earning a return. The weighted average recovery period of regulatory assets currently being recovered in base rates, which totals $24 million , is 24 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 that future recovery is probable. Assets arising from benefit obligations represent the funded status of retirement plans less amounts previously recognized in the statement of income. The Company records a Regulatory asset for that portion related to its rate regulated utilities. See Note 11. Regulatory Liabilities At December 31, 2016 and 2015 , the Company has approximately $453.7 million and $433.9 million , respectively, in Regulatory liabilities . Of these amounts most relate to cost of removal obligations.

Federal Business Unit Acquisiti

Federal Business Unit Acquisition Federal Business Unit Acquisition	12 Months Ended
	Dec. 31, 2016
Business Combinations [Abstract]
Business Combination Disclosure [Text Block]	Federal Business Unit Acquisition On April 1, 2014 , the Company, through Energy Systems Group, LLC (ESG), a subsidiary of the Energy Services operating segment, purchased the federal sector energy services unit of Chevron Energy Solutions from Chevron USA, referred to hereafter as the Federal Business Unit (FBU). FBU performs under several long-term operations and maintenance contracts (O&M), and has a construction project sales funnel. Included in the acquisition are several Indefinite Delivery / Indefinite Quantity contracts with federal government entities including Energy Savings Performance Contracts (ESPC) with the U.S. Department of Energy and U.S. Army Corps of Engineers. Also included are long-term O&M contracts with multiple Department of Defense installations. FBU is included in the Company’s nonutility Energy Services operating segment. The acquisition purchase price was $42.1 million , which included contingent consideration to be paid if certain new order targets were met in 2014. Those new order targets were not met in 2014 and therefore the contingent consideration was not earned. As such, the contingent consideration liability as of December 31, 2014 of $14.8 million was reversed as operating income. The initial new order target at the end of 2014 was dependent on the signing of contracts with sufficient revenue to meet the threshold. A single contract was targeted that would have been sufficient to meet the threshold but the signing of that contract was delayed by the customer. That contract was signed in August 2015. Transaction costs associated with the acquisition and expensed by the Company totaled approximately $1.7 million , of which $0.8 million and $0.9 million are included in other operating expenses during the years ended December 31, 2014 and 2013, respectively. For the period from April 1, 2014 through December 31, 2014, FBU contributed an immaterial amount of revenue and net loss to the Company's revenue and net income. For the year ended December 2014, unaudited proforma results of the combined companies, assuming the acquisition closed on January 1, 2014, would have added approximately $17.7 million to consolidated revenues. The impact to net income and earnings per share would have been de minimis. These proforma results may not be indicative of what actual results would have been if the acquisition had taken place on the proforma date or of future results.

Sale of Vectren Fuels, Inc.

Sale of Vectren Fuels, Inc.	12 Months Ended
	Dec. 31, 2016
Discontinued Operations and Disposal Groups [Abstract]
Disposal Groups, Including Discontinued Operations, Disclosure [Text Block]	Sale of Vectren Fuels, Inc. (Vectren Fuels) On August 29, 2014 the Company sold its wholly owned coal mining subsidiary, Vectren Fuels, to Sunrise Coal, LLC (Sunrise Coal), an Indiana-based wholly owned subsidiary of Hallador Energy Company. Total cash received was approximately $311 million . The pre-tax loss on disposition of $32 million was reflected in the Consolidated Statement of Income as a $42 million charge to other operating expense, offset by $10 million in lower depreciation expense as depreciation for the assets ceased upon the announcement of the transaction on June 30, 2014. Results from Coal Mining for the year ended December 31, 2014, inclusive of the loss on sale, was a loss of $21.1 million , net of tax. The transaction did not meet the requirements under GAAP to qualify as discontinued operations since Vectren has significant continuing cash flows related to the purchase of coal from the buyer of these mines.

ProLiance Holdings, LLC

ProLiance Holdings, LLC	12 Months Ended
	Dec. 31, 2016
Equity Method Investments and Joint Ventures [Abstract]
ProLiance Holdings, LLC	Investment in ProLiance Holdings, LLC The Company has an investment in ProLiance Holdings, LLC (ProLiance or ProLiance Holdings), an affiliate of the Company and Citizens Energy Group (Citizens). Much of the ProLiance business was sold on June 18, 2013 when ProLiance exited the natural gas marketing business through the disposition of certain of the net assets of its energy marketing business, ProLiance Energy, LLC. The Company's remaining investment in ProLiance relates primarily to an investment in LA Storage, LLC (LA Storage). Consistent with its ownership percentage, the Company is allocated 61 percent of ProLiance’s profits and losses; however, governance and voting rights remain at 50 percent for each member, and therefore, the Company accounts for its investment in ProLiance using the equity method of accounting. The Company's remaining investment at December 31, 2016 , shown at its 61 percent ownership share of the individual net assets of ProLiance, is as follows. As of December 31, (In millions) 2016 Cash $ 1.6 Investment in LA Storage 22.4 Other midstream asset investment 5.3 Total investment in ProLiance $ 29.3 Included in: Investments in unconsolidated affiliates 19.2 Other nonutility investments 10.1 LA Storage, LLC Storage Asset Investment ProLiance Transportation and Storage, LLC (PT&S), a subsidiary of ProLiance, and Sempra Energy International (SEI), a subsidiary of Sempra Energy (SE), through a joint venture, have a 100 percent interest in a development project for salt-cavern natural gas storage facilities known as LA Storage. PT&S is the minority member with an approximate 25 percent interest, which it accounts for using the equity method. The project, which includes a pipeline system, is expected to include 12-19 Bcf of storage capacity, and has the potential for further expansion. This pipeline system is currently connected with several interstate pipelines, including the Cameron Interstate Pipeline operated by Sempra Pipelines & Storage, and can connect area liquefied natural gas regasification terminals to an interstate natural gas transmission system and storage facilities. Approximately 12 Bcf of the storage, which comprises three of the four FERC certified caverns, is fully tested but additional work is required to further develop the caverns. The timing and extent of development of these caverns and pipeline system is dependent on market conditions, including pricing, need for storage and transmission capacity, and development of the liquefied natural gas market, among other factors. To date, development activity has been modest due to the current low demand for storage facilities. The development of the storage market and related pricing are critical assumptions in the analysis of the recoverability of the investment's carrying value. At December 31, 2016 and 2015, ProLiance's investment in the joint venture was $36.7 million and $36.4 million , respectively.

Nonutility Real Estate & Other

Nonutility Real Estate & Other Legacy Holdings	12 Months Ended
	Dec. 31, 2016
Nonutility Real Estate Other Legacy Holdings [Abstract]
Nonutility Real Estate and Other Legacy Holdings	Nonutility Legacy Holdings Within the nonutility group, there are legacy investments involved in other ventures. As of both December 31, 2016 and 2015 , total remaining legacy investments, other than the investment in ProLiance, included in the Other Businesses portfolio totaled $7.0 million . During 2015, the Company sold its investment in commercial real estate property as well as an interest in a leveraged lease for approximate book value. For the period presented, the remaining investment relates to a debt security related to the sale of commercial real estate of $5.1 million and other investments of $1.9 million .

Intangible Assets

Intangible Assets	12 Months Ended
	Dec. 31, 2016
Goodwill and Intangible Assets Disclosure [Abstract]
Intangible Assets	Intangible Assets Intangible assets, which are included in Other assets , consist of the following: (In millions) At December 31, 2016 2015 Amortizing Non-amortizing Amortizing Non-amortizing Customer-related assets $ 20.9 $ — $ 23.1 $ — Market-related assets — 13.0 0.2 13.0 Intangible assets, net $ 20.9 $ 13.0 $ 23.3 $ 13.0 As of December 31, 2016 , the weighted average remaining life for amortizing customer-related assets is 11 years. These amortizing intangible assets have no significant residual values. Intangible assets are presented net of accumulated amortization totaling $12.0 million for customer-related assets and $4.5 million for market-related assets at December 31, 2016 and $9.8 million for customer-related assets and $4.3 million for market-related assets at December 31, 2015 . Annual amortization associated with intangible assets totaled $2.5 million in 2016 , $3.1 million in 2015 and $2.8 million in 2014 . Amortization should approximate (in millions) $2.6 , $2.6 , $2.6 , $2.6 , and $2.6 in 2017, 2018 , 2019 , 2020 , and 2021 , respectively. Intangible assets are primarily in the Nonutility Group.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes A reconciliation of the federal statutory rate to the effective income tax rate follows: Year Ended December 31, 2016 2015 2014 Statutory rate: 35.0 % 35.0 % 35.0 % State & local taxes-net of federal benefit 2.8 3.6 4.1 Amortization of investment tax credit (0.3 ) (0.2 ) (0.3 ) Depletion — — (2.6 ) Domestic production deduction (0.4 ) (1.0 ) (1.1 ) Energy efficiency building deductions (1.7 ) (2.3 ) (1.6 ) Research and development credit (0.6 ) (1.6 ) (0.3 ) Other tax credits (0.1 ) (0.1 ) (0.2 ) All other-net 0.1 0.2 (0.3 ) Effective tax rate 34.8 % 33.6 % 32.7 % Significant components of the net deferred tax liability follow: At December 31, (In millions) 2016 2015 Noncurrent deferred tax liabilities (assets): Depreciation & cost recovery timing differences $ 902.4 $ 827.6 Regulatory assets recoverable through future rates 17.6 31.6 Alternative minimum tax carryforward (29.3 ) (34.5 ) Employee benefit obligations (8.1 ) (9.3 ) Net operating loss & other carryforwards (3.2 ) (3.7 ) Regulatory liabilities to be settled through future rates (15.9 ) (29.9 ) Impairments (2.5 ) (3.0 ) Deferred fuel costs-net 25.9 14.2 Other-net 18.8 12.4 Net noncurrent deferred tax liability $ 905.7 $ 805.4 At December 31, 2016 and 2015 , investment tax credits totaling $1.6 million and $4.1 million respectively, are included in Deferred credits & other liabilities . At December 31, 2016 , the Company has alternative minimum tax carryforwards which do not expire. In addition, the Company has $3.2 million in net operating loss and general business credit carryforwards, which will expire in 5 to 20 years . The net operating loss carryforward and other carryforwards were reduced for the impacts of unrecognized tax benefits and a valuation allowance relating primarily to state net operating loss carryforwards. At December 31, 2016 and 2015 , the valuation allowance was $8.3 million and $8.1 million , respectively. The components of income tax expense follow: Year Ended December 31, (In millions) 2016 2015 2014 Current: Federal $ 6.8 $ 10.8 $ 24.7 State 6.0 8.5 18.5 Total current taxes 12.8 19.3 43.2 Deferred: Federal 97.6 79.0 42.7 State 3.6 2.0 (4.2 ) Total deferred taxes 101.2 81.0 38.5 Amortization of investment tax credits (1.1 ) (0.6 ) (0.6 ) Total income tax expense $ 112.9 $ 99.7 $ 81.1 Uncertain Tax Positions Unrecognized tax benefits for all periods presented were not material to the Company. The net liability on the Consolidated Balance Sheet for unrecognized tax benefits inclusive of interest and penalties totaled $1.2 million and $0.9 million , respectively, at December 31, 2016 and 2015 . The Company and/or certain of its subsidiaries file income tax returns in the U.S. federal jurisdiction and various states. The Internal Revenue Service (IRS) has concluded examinations of the Company's U.S. federal income tax returns for tax years through December 31, 2012. The State of Indiana, the Company'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 and 2019. 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.

Retirement Plans & Other Postre

Retirement Plans & Other Postretirement Benefits	12 Months Ended
	Dec. 31, 2016
Compensation and Retirement Disclosure [Abstract]
Retirement Plans and Other Postretirement Benefits	Retirement Plans & Other Postretirement Benefits At December 31, 2016 , the Company maintains three closed qualified defined benefit pension plans, a nonqualified supplemental executive retirement plan (SERP), and a postretirement benefit plan. The defined benefit pension plans and postretirement benefit plan, which cover 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. The qualified pension plans and the SERP are aggregated under the heading “Pension Benefits.” The postretirement benefit plan is presented under the heading “Other Benefits.” Net Periodic Benefit Costs A summary of the components of net periodic benefit cost for the three years ended December 31, 2016 follows: Pension Benefits Other Benefits (In millions) 2016 2015 2014 2016 2015 2014 Service cost $ 7.0 $ 7.9 $ 7.4 $ 0.3 $ 0.4 $ 0.4 Interest cost 14.7 14.6 15.5 1.7 2.0 2.3 Expected return on plan assets (22.8 ) (22.5 ) (22.7 ) — — — Amortization of prior service cost (benefit) 0.4 0.7 1.0 (2.9 ) (3.0 ) (3.0 ) Amortization of actuarial loss 7.2 8.5 5.0 — 0.7 0.4 Settlement charge — 0.6 3.1 — — — Net periodic benefit cost (benefit) $ 6.5 $ 9.8 $ 9.3 $ (0.9 ) $ 0.1 $ 0.1 A portion of the net periodic benefit cost disclosed in the table above is capitalized as Utility Plant following the allocation of current employee labor costs. Costs capitalized in 2016 , 2015 , and 2014 are estimated at $1.9 million , $3.1 million , and $2.8 million , respectively. The Company increased the discount rate used to measure periodic cost from 4.05 percent in 2015 to 4.31 percent in 2016 due to higher benchmark interest rates that approximated the expected duration of the Company’s benefit obligations as of that valuation date. The Company derives its discount rate by identifying a theoretical settlement portfolio of high quality corporate bonds sufficient to provide for the plans' projected benefit payments. For fiscal year 2017 , the weighted average discount rate assumption will decrease to 4.07 percent for the defined benefit pension plans, based on decreased benchmark interest rates. The weighted averages of significant assumptions used to determine net periodic benefit costs follow: Pension Benefits Other Benefits 2016 2015 2014 2016 2015 2014 Discount rate 4.31 % 4.05 % 4.74 % 4.21 % 3.95 % 4.66 % Rate of compensation increase 3.50 % 3.50 % 3.50 % N/A N/A N/A Expected return on plan assets 7.50 % 7.50 % 7.75 % N/A N/A N/A Expected increase in Consumer Price Index N/A N/A N/A 2.50 % 2.50 % 2.75 % The Company uses a "building block" approach to develop an expected long-term rate of return. For fiscal year 2017, the Company has lowered the expected return on plan assets from 7.50 percent to 7.0 percent based on this approach. Health care cost trend rate assumptions do not have a material effect on the service and interest cost components of benefit costs. The Company’s plans limit its exposure to increases in health care costs to annual changes in the Consumer Price Index (CPI). Any increase in health care costs in excess of the CPI increase is the responsibility of the plan participants. Benefit Obligations A reconciliation of the Company’s benefit obligations at December 31, 2016 and 2015 follows: Pension Benefits Other Benefits (In millions) 2016 2015 2016 2015 Benefit obligation, beginning of period $ 348.3 $ 371.9 $ 43.5 $ 53.3 Service cost – benefits earned during the period 7.0 7.9 0.3 0.4 Interest cost on projected benefit obligation 14.7 14.6 1.7 2.0 Plan participants' contributions — — 1.1 1.0 Plan amendments — 0.5 — — Actuarial loss (gain) 8.7 (17.0 ) (1.6 ) (8.6 ) Benefit payments (28.3 ) (27.9 ) (4.5 ) (4.6 ) Settlement payments — (1.7 ) — — Benefit obligation, end of period $ 350.4 $ 348.3 $ 40.5 $ 43.5 The accumulated benefit obligation for all defined benefit pension plans was $339.8 million and $336.1 million at December 31, 2016 and 2015 , respectively. The increase in the pension benefit obligation in 2016 is primarily due to a decrease in the discount rate used to measure the obligation at year end. Mortality Assumption Changes In October 2014, the Society of Actuaries (SOA) released updated mortality estimates that reflect increased life expectancy. The Company updated its mortality assumptions to incorporate this increase in life expectancy. Accordingly, the Company updated its base mortality assumption to the SOA 2014 table as well as updated its projected mortality improvement. In October 2015 and 2016, the SOA released updated projected mortality improvement that reflect additional years of data. The Company continues to use the SOA 2014 base table and has updated to the projected mortality improvement data that was released in 2015 and 2016, respectively. These changes are reflected in the Company's benefit obligation as of December 31, 2016. Other Material Assumptions The benefit obligation as of December 31, 2016 and 2015 was calculated using the following weighted average assumptions: Pension Benefits Other Benefits 2016 2015 2016 2015 Discount rate 4.07 % 4.31 % 4.04 % 4.21 % Rate of compensation increase 3.50 % 3.50 % N/A N/A Expected increase in Consumer Price Index N/A N/A 2.50 % 2.50 % To calculate the 2016 ending postretirement benefit obligation, medical claims costs in 2017 were assumed to be 5.5 percent higher than those incurred in 2016 . That trend, beginning at 8.0 percent in 2012, was assumed to reach its ultimate trending increase of 5.0 percent by 2018 and remain level thereafter. A one-percentage point change in assumed health care cost trend rates would have changed the benefit obligation by approximately $0.2 million . Plan Assets A reconciliation of the Company’s plan assets at December 31, 2016 and 2015 follows: Pension Benefits Other Benefits (In millions) 2016 2015 2016 2015 Plan assets at fair value, beginning of period $ 296.9 $ 305.6 $ — $ — Actual return on plan assets 19.7 (2.0 ) — — Employer contributions 16.2 22.9 3.4 3.6 Plan participants' contributions — — 1.1 1.0 Benefit payments (28.3 ) (27.9 ) (4.5 ) (4.6 ) Settlement payments — (1.7 ) — — Fair value of plan assets, end of period $ 304.5 $ 296.9 $ — $ — The Company’s overall investment strategy for its retirement plan trusts is to maintain investments in a diversified portfolio, comprised of primarily equity and fixed income investments, which are further diversified among various asset classes. The diversification is designed to minimize the risk of large losses while maximizing total return within reasonable and prudent levels of risk. The investment objectives specify a targeted investment allocation for the pension plans of 62 percent equities, 35 percent debt, and 3 percent for other investments, including real estate. Both the equity and debt securities have a blend of domestic and international exposures. Objectives do not target a specific return by asset class. The portfolios’ return is monitored in total. Following is a description of the valuation methodologies used for trust assets measured at fair value. Mutual Funds The fair values of mutual funds are derived from the daily closing price as reported by the fund as these instruments have active markets (Level 1 inputs). Common Collective Trust Funds (CTF’s) The Company’s plans have investments in trust funds similar to mutual funds in that they are created by pooling of funds from investors into a common trust and such funds are managed by a third party investment manager. These trust funds typically give investors a wider range of investment options through this pooling of funds than those generally available to investors on an individual basis. However, unlike mutual funds, these trusts are not publicly traded in an active market. The funds are valued at the net asset value of the underlying investments. The net asset value is used as a practical expedient to estimate fair value. In relation to these investments, there are no unfunded commitments. Also, the Plan can exchange shares with minimal restrictions, however, certain events may exist where share exchanges are restricted for up to 31 days. In 2015, FASB issued Accounting Standards Update No. 2015-07, Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent). In accordance with this guidance, investments measured at net asset value per share as a practical expedient are no longer categorized within in the fair value hierarchy as shown in the tables below. The update was effective for plan years beginning after December 15, 2015. This change was applied retrospectively to all periods presented. The fair values of the Company’s pension and other retirement plan assets at December 31, 2016 and December 31, 2015 by asset category and by fair value hierarchy are as follows: As of December 31, 2016 (In millions) Level 1 Level 2 Level 3 Total Domestic equities & equity funds $ 135.1 $ — $ — $ 135.1 International equities & equity funds 42.0 — — 42.0 Domestic bonds & bond funds 44.6 — — 44.6 Real estate, commodities & other 6.0 — 4.4 10.4 Investments measured at net asset value (a) — — — 72.4 Total plan investments $ 227.7 $ — $ 4.4 $ 304.5 As of December 31, 2015 (In millions) Level 1 Level 2 Level 3 Total Domestic equities & equity funds $ 113.5 $ — $ — $ 113.5 International equities & equity funds 38.2 — — 38.2 Domestic bonds & bond funds 36.6 — — 36.6 Real estate, commodities & other 4.8 — 4.3 9.1 Investments measured at net asset value (a) — — — 99.5 Total plan investments $ 193.1 $ — $ 4.3 $ 296.9 (a) In accordance with Subtopic 820-10, certain investments that were measured at net asset value per share, or its equivalent, have not been classified in the fair value hierarchy. Investments Measured Using the Net Asset Value per Share Practical Expedient The Company's Plans invest in certain common trust funds for which fair value is measured using the net asset value per share practical expedient. The fair value of those funds totaled $72.4 million and $99.5 million as of December 31, 2016 and 2015, respectively. Guaranteed Annuity Contract One of the Company’s pension plans is party to a group annuity contract with John Hancock Life Insurance Company (John Hancock). At December 31, 2016 and 2015 , the estimate of undiscounted funds necessary to satisfy John Hancock’s remaining obligation was $4.0 million and $3.9 million , respectively. If funds retained by John Hancock are not sufficient to satisfy retirement payments due to these retirees, the shortfall must be funded by the Company. The composite investment return, net of manager fees and other charges for the years ended December 31, 2016 and 2015 was 3.60 percent and 3.65 percent , respectively. The Company values this illiquid investment using long-term interest rate and mortality assumptions, among others, and is therefore considered a Level 3 investment. There is no unfunded commitment related to this investment. A roll forward of the fair value of the guaranteed annuity contract calculated using Level 3 valuation assumptions follows: (In millions) 2016 2015 Fair value, beginning of year $ 4.3 $ 4.2 Unrealized gains related to investments still held at reporting date 0.2 0.2 Purchases, sales & settlements, net (0.1 ) (0.1 ) Fair value, end of year $ 4.4 $ 4.3 Funded Status The funded status of the plans as of December 31, 2016 and 2015 follows: Pension Benefits Other Benefits (In millions) 2016 2015 2016 2015 Qualified Plans Benefit obligation, end of period $ (329.7 ) $ (328.7 ) $ (40.5 ) $ (43.5 ) Fair value of plan assets, end of period 304.5 296.9 — — Funded Status of Qualified Plans, end of period (25.2 ) (31.8 ) (40.5 ) (43.5 ) Benefit obligation of SERP Plan, end of period (20.6 ) (19.6 ) — — Total funded status, end of period $ (45.8 ) $ (51.4 ) $ (40.5 ) $ (43.5 ) Accrued liabilities $ 1.2 $ 1.2 $ 4.5 $ 4.6 Deferred credits & other liabilities $ 44.6 $ 50.2 $ 36.0 $ 38.9 Expected Cash Flows The Company currently does not anticipate making a contribution to the qualified pension plans in 2017. In addition, the Company expects to make contributions totaling approximately $1.2 million into the SERP plan and approximately $3.1 million into the postretirement plan. Estimated retiree pension benefit payments, including the SERP, projected to be required during the years following 2016 are approximately (in millions) $26.3 in 2017 , $38.0 in 2018 , $26.8 in 2019 , $29.1 in 2020 , $26.6 in 2021 , and $132.4 in years 2022-2026 . Expected benefit payments projected to be required for postretirement benefits during the years following 2016 (in millions) are approximately $4.5 in 2017 , $4.6 in 2018 , $4.7 in 2019 , $5.0 in 2020 , $5.1 in 2021 , and $24.0 in years 2022-2026 . Prior Service Cost, Actuarial Gains and Losses, and Transition Obligation Effects Following is a roll forward of prior service cost and actuarial gains and losses. Pensions Other Benefits (In millions) Prior Service Cost Net Gain or Loss Prior Service Cost Net Gain or Loss Balance at January 1, 2014 $ 3.0 $ 67.3 $ (20.1 ) $ 8.1 Amounts arising during the period — 49.4 — 3.2 Reclassification to benefit costs (1.0 ) (5.0 ) 3.0 (0.4 ) Balance at December 31, 2014 $ 2.0 $ 111.7 $ (17.1 ) $ 10.9 Amounts arising during the period 0.5 6.9 — (8.6 ) Reclassification to benefit costs (0.7 ) (8.5 ) 3.0 (0.7 ) Balance at December 31, 2015 $ 1.8 $ 110.1 $ (14.1 ) $ 1.6 Amounts arising during the period — 11.7 — (1.6 ) Reclassification to benefit costs (0.4 ) (7.2 ) 2.9 — Balance at December 31, 2016 $ 1.4 $ 114.6 $ (11.2 ) $ — Following is a reconciliation of the amounts in Accumulated other comprehensive income (AOCI) and Regulatory assets related to retirement plan obligations at December 31, 2016 and 2015 . (In millions) 2016 2015 Pensions Other Benefits Pensions Other Benefits Prior service cost $ 1.4 $ (11.2 ) $ 1.8 $ (14.1 ) Unamortized actuarial gain/(loss) 114.6 — 110.1 1.6 116.0 (11.2 ) 111.9 (12.5 ) Less: Regulatory asset deferral (113.6 ) 11.0 (109.6 ) 12.3 AOCI before taxes $ 2.4 $ (0.2 ) $ 2.3 $ (0.2 ) Related to pension plans, $0.4 million of prior service cost and $7.6 million of actuarial gain/loss is expected to be amortized to cost in 2017 . Related to other benefits, no actuarial gain/loss is expected to be amortized to periodic cost in 2017 , and $2.4 million of prior service cost is expected to reduce costs in 2017 . Multiemployer Benefit Plan The Company, through its Infrastructure Services operating segment, participates in several industry wide multiemployer pension plans for its union employees which provide for monthly benefits based on length of service. The risks of participating in multiemployer pension plans are different from the risks of participating in single-employer pension plans in the following respects: 1) assets contributed to the multiemployer plan by one employer may be used to provide benefits to employees of other participating employers, 2) if a participating employer stops contributing to the plan, the unfunded obligations of the plan allocable to such withdrawing employer may be borne by the remaining participating employers, and 3) if the Company stops participating in some of its multiemployer pension plans, the Company may be required to pay those plans an amount based on its allocable share of the underfunded status of the plan, referred to as a withdrawal liability. Expense is recognized as payments are accrued for work performed or when withdrawal liabilities are probable and estimable. Expense associated with multiemployer plans was $35.0 million , $32.7 million and $32.4 million for the years ended December 31, 2016 , 2015 , and 2014 , respectively. During 2016 , the Company made contributions to these multiemployer plans on behalf of employees that participate in approximately 280 local unions. Contracts with these unions are negotiated with trade agreements through two primary contractor associations. These trade agreements have varying expiration dates ranging from 2017 through 2021. The average contribution related to these local unions was less than $0.2 million , and the largest contribution was $2.9 million . Multiple unions can contribute to a single multiemployer plan. The Company made contributions to at least 60 plans in 2016 , six of which are considered significant plans based on, among other things, the amount of the contributions, the number of employees participating in the plan, and the funded status of the plan. The Company's participation in the significant plans is outlined in the following table. The Employer Identification Number (EIN) / Pension Plan Number column provides the EIN and three digit pension plan numbers. The most recent Pension Protection Act Zone Status available in 2016 and 2015 is for the plan year end at February 1, 2015 and 2014 for the Central Pension Fund, January 1, 2015 and 2014 for the Pipeline Industry Benefit Fund, June 1, 2015 and 2014 for the Indiana Laborers Pension Fund, August 1, 2015 and 2014 for the Ohio Operating Engineers Pension Fund, January 1, 2015 and 2014 for the Minnesota Laborers Pension Fund, and January 1, 2015 and 2014 for the Laborers District Fund of Ohio, respectively. Generally, plans in the red zone are less than 65 percent funded, plans in the yellow zone are less than 80 percent funded and plans in the green zone are at least 80 percent funded. The FIP/RP Status Pending / Implemented column indicates plans for which a funding improvement plan ("FIP") or rehabilitation plan ("RP") is either pending or has been implemented. The multiemployer contributions listed in the table below are the Company's multiemployer contributions made in 2016 , 2015 , and 2014 . (In millions) Pension Protection Act Zone Status Multiemployer Contributions Pension Fund EIN/Pension Plan Number 2016 2015 FIP/RP Status Pending/Implemented 2016 2015 2014 Surcharge Imposed Central Pension Fund 36-6052390-001 Green Green No $7.4 $7.2 $7.7 No Pipeline Industry Benefit Fund 73-0742835-001 Green Green No 3.0 4.0 5.1 No Indiana Laborers Pension Fund (1) 35-6027150-001 Yellow Yellow Implemented 4.4 4.1 3.5 No Ohio Operating Engineers Pension Fund 31-6129968-001 Green Green No 2.1 2.2 1.7 No Minnesota Laborers Pension Fund 41-6159599-001 Green Green No 1.2 1.8 2.2 No Laborers District Fund of Ohio 31-6129964-001 Green Green No 2.0 1.5 1.1 No Other 14.9 11.9 11.1 Total Contributions $35.0 $32.7 $32.4 (1) Federal law requires pension plans in endangered status to adopt a FIP aimed at restoring the financial health of the plan. In December 2014, the Multiemployer Pension Reform Act of 2014 was passed and permanently extended the Pension Protection Act of 2006 multiemployer plan critical and endangered status funding rules, among other things, including providing a provision for a plan sponsor to suspend or reduce benefit payments to preserve plans in critical and declining status. The Indiana Laborers Pension Fund (Fund) was not in "critical" status but rather in an “endangered” status in the Plan Year ending May 31, 2016 because of a funded ratio of 72 percent , no projected funding deficiency in the funding standard account, at least 8 years of benefit payments within plan assets and other results. In an effort to improve the Plan’s funding situation, the trustees adopted a FIP on December 17, 2015. The funding improvement period is June 1, 2017 to May 31, 2027 or the date the Fund’s actuary certifies it has emerged from endangered status. While not considered significant to the Company, there are nine plans in red zone status receiving Company contributions. There are seven plans where Company contributions exceed 5 percent of each plan's total contributions and two of these plans were considered significant to the Company (Pipeline Industry Benefit Fund and Indiana Laborers Pension Fund). Defined Contribution Plan The Company also has defined contribution retirement savings plans qualified under sections 401(a) and 401(k) of the Internal Revenue Code and include an option to invest in Vectren common stock, among other alternatives. During 2016 , 2015 and 2014 , the Company made contributions to these plans of $12.1 million , $11.0 million , and $9.1 million , respectively.

Borrowing Arrangements

Borrowing Arrangements	12 Months Ended
	Dec. 31, 2016
Debt Disclosure [Abstract]
Borrowing Arrangements	Borrowing Arrangements Long-Term Debt Long-term senior unsecured obligations and first mortgage bonds outstanding by subsidiary follow: At December 31, (In millions) 2016 2015 Utility Holdings Fixed Rate Senior Unsecured Notes 2018, 5.75% $ 100.0 $ 100.0 2020, 6.28% 100.0 100.0 2021, 4.67% 55.0 55.0 2023, 3.72% 150.0 150.0 2026, 5.02% 60.0 60.0 2028, 3.20% 45.0 45.0 2035, 6.10% 75.0 75.0 2035, 3.90% 25.0 25.0 2041, 5.99% 35.0 35.0 2042, 5.00% 100.0 100.0 2043, 4.25% 80.0 80.0 2045, 4.36% 135.0 135.0 2055, 4.51% 40.0 40.0 Total Utility Holdings 1,000.0 1,000.0 Indiana Gas Fixed Rate Senior Unsecured Notes 2025, Series E, 6.53% 10.0 10.0 2027, Series E, 6.42% 5.0 5.0 2027, Series E, 6.68% 1.0 1.0 2027, Series F, 6.34% 20.0 20.0 2028, Series F, 6.36% 10.0 10.0 2028, Series F, 6.55% 20.0 20.0 2029, Series G, 7.08% 30.0 30.0 Total Indiana Gas 96.0 96.0 SIGECO First Mortgage Bonds 2016, 1986 Series, 8.875% — 13.0 2022, 2013 Series C, 1.95%, tax-exempt 4.6 4.6 2024, 2013 Series D, 1.95%, tax-exempt 22.5 22.5 2025, 2014 Series B, current adjustable rate 1.045%, tax-exempt 41.3 41.3 2029, 1999 Series, 6.72% 80.0 80.0 2037, 2013 Series E, 1.95%, tax-exempt 22.0 22.0 2038, 2013 Series A, 4.00%, tax-exempt 22.2 22.2 2043, 2013 Series B, 4.05%, tax-exempt 39.6 39.6 2044, 2014 Series A, 4.00% tax-exempt 22.3 22.3 2055, 2015 Series Mt. Vernon, 2.375%, tax-exempt 23.0 23.0 2055, 2015 Series Warrick County, 2.375%, tax-exempt 15.2 15.2 Total SIGECO 292.7 305.7 At December 31, (In millions) 2016 2015 Vectren Capital Corp. Fixed Rate Senior Unsecured Notes 2016, 6.92% $ — $ 60.0 2017, 3.48% 75.0 75.0 2019, 7.30% 60.0 60.0 2022, 3.33% 75.0 75.0 2025, 4.53% 50.0 50.0 2030, 3.90% 75.0 75.0 Total Vectren Capital Corp. 335.0 395.0 Total long-term debt outstanding 1,723.7 1,796.7 Current maturities of long-term debt (124.1 ) (73.0 ) Debt issuance costs (9.0 ) (9.9 ) Unamortized debt premium & discount-net (0.7 ) (0.9 ) Total long-term debt-net $ 1,589.9 $ 1,712.9 Simplifying the Presentation of Debt Issuance Costs In April 2015, the FASB issued new accounting guidance on accounting for debt issuance costs which changes the presentation of debt issuance costs in financial statements. This ASU requires an entity to present such costs in the balance sheet as a direct reduction from the related debt liability rather than as an asset. Amortization of the costs will continue to be reported as interest expense. This ASU is effective for annual reporting periods beginning after December 15, 2015. The guidance was adopted as of January 1, 2016 and has been applied retrospectively to all periods presented. The effect of the change on the December 31, 2015 balance sheet was the reclassification of $8.6 million from Regulatory assets to Long-term Debt and the reclassification of $1.3 million from Other assets to Long-term Debt . The reclassification had no material impact on the Company's financial condition, results of operations, or cash flows as a result of the adoption. Vectren Capital Unsecured Note Retirement On March 11, 2016, a $60 million Vectren Capital senior unsecured note matured. The Series B note, which was part of a private placement Note Purchase Agreement entered into on March 11, 2009, carried a fixed interest rate of 6.92 percent . The repayment of debt was funded from the Company's cash on hand. SIGECO Bond Retirement On June 1, 2016, a $13 million SIGECO bond matured. The First Mortgage Bond, which was a portion of an original $25 million public issuance sold on June 1, 1986, carried a fixed interest rate of 8.875 percent . The repayment of debt was funded from the Company’s commercial paper program. Indiana Gas Unsecured Note Retirement On March 15, 2015, a $5 million Indiana Gas 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 Company's commercial paper program. SIGECO Debt Issuance On September 9, 2015, SIGECO completed a $38.2 million tax-exempt first mortgage bond issuance. The principal terms of the two new series of tax-exempt debt are: (i) $23.0 million in Environmental Improvement Revenue Bonds, Series 2015, issued by the City of Mount Vernon, Indiana and (ii) $15.2 million in Environmental Improvement Revenue Bonds, Series 2015, issued by Warrick County, Indiana. Both bonds were sold in a public offering at an initial interest rate of 2.375 percent per annum that is fixed until September 1, 2020 when the bonds will be remarketed. The bonds have a final maturity of September 1, 2055. Vectren Utility Holdings, Vectren Capital, and Indiana Gas Debt Transactions On December 15, 2015, Utility Holdings issued Guaranteed Senior Notes in a private placement to various institutional investors in the following tranches: (i) $25 million of 3.90 percent Guaranteed Senior Notes, Series A, due December 15, 2035 , (ii) $135 million of 4.36 percent Guaranteed Senior Notes, Series B, due December 15, 2045 , and (iii) $40 million of 4.51 percent Guaranteed Senior Notes, Series C, due December 15, 2055 . The notes are unconditionally guaranteed by Indiana Gas, SIGECO and VEDO. Additionally, on December 15, 2015 , Vectren Capital issued Guaranteed Senior Notes in a private placement to various institutional investors in the following tranches: (i) $75 million of 3.33 percent Guaranteed Senior Notes, Series A, due December 15, 2022 and (ii) $75 million of 3.90 percent Guaranteed Senior Notes, Series B, due December 15, 2030 . The notes are guaranteed by Vectren Corporation. A portion of the proceeds received from these issuances were used to finance the following retirements of debt: (i) $75 million of 5.45 percent Utility Holdings senior unsecured notes that matured on December 1, 2015, (ii) $75 million 5.31 percent Vectren Capital senior unsecured notes that matured on December 15, 2015, and (iii) $5 and $10 million of 6.69 percent Indiana Gas senior unsecured notes that matured on December 21, 2015 and December 29, 2015, respectively. Vectren Capital Unsecured Note Retirement On March 11, 2014, a $30 million Vectren Capital senior unsecured note matured. The Series A note, which was part of a private placement Note Purchase Agreement entered into on March 11, 2009, carried a fixed interest rate of 6.37 percent . The repayment of debt was funded from the Company's short-term credit facility. SIGECO Debt Refund and Issuance On September 24, 2014 , SIGECO issued two new series of tax-exempt debt totaling $63.6 million . Proceeds from the issuance were used to retire three series of tax-exempt bonds aggregating $63.6 million at a redemption price of par plus accrued interest. The principal terms of the two new series of tax-exempt debt are: (i) $22.3 million sold in a public offering and bear interest at 4.00 percent per annum, due September 1, 2044 and (ii) $41.3 million , due July 1, 2025, sold in a private placement at variable rates through September 2019. Mandatory Tenders At December 31, 2016 , certain series of SIGECO bonds, aggregating $87.3 million , currently bear interest at fixed rates, of which $49.1 million is subject to mandatory tender in September 2017 and $38.2 million is subject to mandatory tender in September 2020 . Additionally, SIGECO Bond Series 2014B, in the amount of $41.3 million , with a variable interest rate that is reset monthly, is subject to mandatory tender in September 2019 . Future Long-Term Debt Sinking Fund Requirements and Maturities The annual sinking fund requirement of SIGECO's first mortgage bonds is 1 percent of the greatest amount of bonds outstanding under the Mortgage Indenture. This requirement may be satisfied by certification to the Trustee of unfunded property additions in the prescribed amount as provided in the Mortgage Indenture. SIGECO met the 2016 sinking fund requirement by this means and, expects to also meet this requirement in 2017 in this manner. Accordingly, the sinking fund requirement is excluded from Current liabilities in the Consolidated Balance Sheets . At December 31, 2016 , $1.4 billion of SIGECO's utility plant remained unfunded under SIGECO's Mortgage Indenture. SIGECO’s gross utility plant balance subject to the Mortgage Indenture approximated $3.3 billion at December 31, 2016 . Consolidated maturities of long-term debt during the five years following 2016 (in millions) are $124 in 2017 , $100 in 2018 , $60 in 2019 , $100 in 2020 , $55 in 2021 , and $1,275 thereafter. Debt Guarantees Vectren Corporation guarantees Vectren Capital’s debt, but does not guarantee Utility Holdings' debt. Vectren Capital's long-term debt, including current maturities outstanding at December 31, 2016 approximated $334 million . Vectren Capital had no short-term obligations outstanding at December 31, 2016. Utility Holdings’ outstanding long-term and short-term borrowing arrangements are jointly and severally guaranteed by its wholly owned subsidiaries and regulated utilities Indiana Gas, SIGECO, and VEDO. Utility Holdings’ long-term debt and short-term obligations outstanding at December 31, 2016 approximated $996 million and $194 million , respectively. Covenants Both long-term and short-term borrowing arrangements contain customary default provisions; restrictions on liens, sale-leaseback transactions, mergers or consolidations, and sales of assets; and restrictions on leverage, among other restrictions. Multiple debt agreements contain a covenant that the ratio of consolidated total debt to consolidated total capitalization will not exceed 65 percent . As of December 31, 2016, the Company was in compliance with all debt covenants. Short-Term Borrowings At December 31, 2016 , the Company had $600 million of short-term borrowing capacity, including $350 million for the Utility Group and $250 million for the wholly owned Nonutility Group and corporate operations. As reduced by borrowings currently outstanding, approximately $156 million was available for the Utility Group operations and $250 million was available for the wholly owned Nonutility Group and corporate operations. Both Vectren Capital’s and Utility Holdings’ short-term credit facilities are available through October 31, 2019. These facilities are used to supplement working capital needs and also to fund capital investments and debt redemptions. The Company has historically funded the short-term borrowing needs of Utility Holdings’ operations through the commercial paper market but maintains the ability to use the Utility Holdings' short-term borrowing facility when necessary. Following is certain information regarding these short-term borrowing arrangements. Utility Group Borrowings Nonutility Group Borrowings (In millions) 2016 2015 2014 2016 2015 2014 As of Year End Balance Outstanding $ 194.4 $ 14.5 $ 156.4 $ — $ — $ — Weighted Average Interest Rate 1.05 % 0.55 % 0.50 % N/A N/A N/A Annual Average Balance Outstanding $ 59.8 $ 53.8 $ 35.6 $ 0.2 $ 24.8 $ 34.5 Weighted Average Interest Rate 0.71 % 0.38 % 0.34 % 1.60 % 1.33 % 1.29 % Maximum Month End Balance Outstanding $ 194.4 $ 121.5 $ 156.4 $ 6.3 $ 69.1 $ 76.3 Throughout the years presented, Utility Holdings has successfully placed commercial paper as needed.

Common Shareholder's Equity

Common Shareholder's Equity	12 Months Ended
	Dec. 31, 2016
Stockholders' Equity Note [Abstract]
Common Shareholder's Equity	Common Shareholders’ Equity Authorized, Reserved Common and Preferred Shares At December 31, 2016 and 2015 , the Company was authorized to issue 480 million shares of common stock and 20 million shares of preferred stock. Of the authorized common shares, approximately 4.6 million shares at December 31, 2016 and 5.1 million shares at December 31, 2015 were reserved by the board of directors for issuance through the Company’s share-based compensation plans, benefit plans, and dividend reinvestment plan. At December 31, 2016 and 2015 , there were 392.5 million and 392.1 million , respectively, of authorized shares of common stock and all authorized shares of preferred stock, available for a variety of general corporate purposes, including future public offerings to raise additional capital.

Earnings Per Share

Earnings Per Share	12 Months Ended
	Dec. 31, 2016
Earnings Per Share [Abstract]
Earnings Per Share	Earnings Per Share The Company uses the two class method to calculate earnings per share (EPS). The two class method is an earnings allocation formula that treats a participating security as having rights to earnings that otherwise would have been available to common shareholders. Under the two class method, earnings for a period are allocated between common shareholders and participating security holders based on their respective rights to receive dividends as if all undistributed book earnings for the period were distributed. Basic EPS is computed by dividing net income attributable to only the common shareholders by the weighted-average number of common shares outstanding for the period. Diluted EPS includes the impact of stock options and other equity based instruments to the extent the effect is dilutive. The following table illustrates the basic and dilutive EPS calculations for the three years ended December 31, 2016 : Year Ended December 31, (In millions, except per share data) 2016 2015 2014 Numerator: Reported net income (Numerator for Diluted EPS) $ 211.6 $ 197.3 $ 166.9 Denominator: Weighted-average common shares outstanding (Basic and Diluted EPS) 82.8 82.7 82.5 Basic and diluted earnings per share $ 2.55 $ 2.39 $ 2.02 As of December 31, 2016 the Company no longer has any stock options outstanding and all equity based instruments were dilutive and immaterial. For the years ended December 31, 2015 and 2014 , all options and equity based instruments were dilutive and immaterial.

Accumulated Other Comprehensive

Accumulated Other Comprehensive Income	12 Months Ended
	Dec. 31, 2016
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]
Accumulated Other Comprehensive Income	Accumulated Other Comprehensive Income A summary of the components of and changes in Accumulated other comprehensive income for the past three years follows: 2014 2015 2016 Beginning of Year Changes During End of Year Changes During End of Year Changes During End of Year (In millions) Balance Year Balance Year Balance Year Balance Pension & other benefit costs (1.2 ) (1.0 ) (2.2 ) 0.1 (2.1 ) (0.1 ) (2.2 ) Deferred income taxes 0.5 0.4 0.9 — 0.9 — 0.9 Accumulated other comprehensive income (loss) $ (0.7 ) $ (0.6 ) $ (1.3 ) $ 0.1 $ (1.2 ) $ (0.1 ) $ (1.3 )

Share-Based Compensation & Defe

Share-Based Compensation & Deferred Compensation Arrangements	12 Months Ended
	Dec. 31, 2016
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Share-Based Compensation and Deferred Compensation Arrangements	Share-Based Compensation & Deferred Compensation Arrangements The Company has share-based compensation programs to encourage corporate and subsidiary officers, key non-officer employees, and non-employee directors to remain with the Company and to more closely align their interests with those of the Company’s shareholders. Under these programs, the Company issues both performance-based and time-vested awards. All share-based compensation programs are shareholder approved. Currently, awards issued to a majority of the officers are performance-based, accrue dividends that are also subject to performance measures, and are settled in cash. In addition, the Company maintains a deferred compensation plan for officers and non-employee directors where participants can invest earned compensation and vested share-based awards in phantom Company stock units, among other options. Certain vesting grants provide for accelerated vesting if there is a change in control or upon the participant’s retirement. Following is a reconciliation of the total cost associated with share-based awards recognized in the Company’s financial statements to its after tax effect on net income: Year Ended December 31, (In millions) 2016 2015 2014 Total cost of share-based compensation $ 30.0 $ 19.4 $ 25.2 Less capitalized cost 7.0 4.8 5.3 Total in other operating expense 23.0 14.6 19.9 Less income tax benefit in earnings 9.0 5.7 7.9 After tax effect of share-based compensation $ 14.0 $ 8.9 $ 12.0 Share-Based Awards & Other Awards The vesting of awards issued to officers is contingent upon meeting total return and return on equity performance objectives. Historically, grants to officers generally vest at the end of a four -year period, with performance measured at the end of the third year. Grants issued to officers in 2015 and beyond will generally vest at the end of a three -year period, with performance continuing to be measured at the end of the third year. Based on performance objectives, the number of awards could double or could be entirely forfeited. A limited number of awards to certain subsidiary officers and awards to non-officer employees are time-vested awards, vest ratably over a three or five -year period, and are primarily settled in cash. In addition, non-employee directors receive a portion of their fees in share-based awards. These awards to non-employee directors are not performance-based and generally vest over one year. The majority of officers and non-employee directors must choose between either settling awards in cash or deferring awards into a deferred compensation plan (where the value is eventually withdrawn in cash). A limited number of subsidiary officers may either settle awards in shares or defer awards into a deferred compensation plan at their discretion. The number of such awards that may settle in shares, but are accounted for as liability awards due to their potential to be taken in cash when withdrawn from the deferred compensation plan, was approximately 100,000 units as of December 31, 2016, and less than 100,000 as of December 31, 2015 and 2014. Most officer, non-officer employee, and non-employee director awards are accounted for as liability awards at their settlement date fair value. The limited number of share awards to certain subsidiary officers that must be settled in shares are accounted for in equity at their grant date fair value. A summary of the status of awards separated between those accounted for as liabilities and equity as of December 31, 2016 and 2015, and changes during the years ended December 31, 2016 and 2015, follow: Equity Awards Wtd. Avg. Grant Date Liability Awards Units Fair value Units Fair value Awards at January 1, 2015 34,273 $ 30.55 693,159 Granted 13,657 30.39 394,967 Vested (29,232 ) 29.87 (389,331 ) Forfeited (3,325 ) 30.95 (52,308 ) Awards at December 31, 2015 15,373 $ 31.63 646,487 $ 42.42 Granted 4,052 30.19 448,176 Vested (11,711 ) 30.19 (462,203 ) Forfeited (1,382 ) 31.87 (20,880 ) Awards at December 31, 2016 6,332 $ 33.42 611,580 $ 52.15 As of December 31, 2016 , there was $14.8 million of total unrecognized compensation cost associated with outstanding grants. That cost is expected to be recognized over a weighted-average period of 1.3 years. The total fair value of shares vested for liability awards during the years ended December 31, 2016 , 2015 , and 2014 , was $23.7 million , $16.6 million , and $15.1 million , respectively. The total fair value of equity awards vesting during the years ended December 31, 2016 , 2015 , and 2014 was $0.6 million , $1.1 million , $0.9 million , respectively. Deferred Compensation Plans The Company has nonqualified deferred compensation plans, which permit eligible officers and non-employee directors to defer portions of their compensation and vested share-based compensation. A record keeping account is established for each participant, and the participant chooses from a variety of measurement funds for the deemed investment of their accounts. The measurement funds are similar to the funds in the Company's defined contribution plan and include an investment in phantom stock units of the Company. The account balance fluctuates with the investment returns on those funds. The liability associated with these plans totaled $40.9 million and $31.2 million at December 31, 2016 and 2015, respectively. Other than $0.9 million and $1.4 million which is classified in Accrued liabilities at December 31, 2016 and 2015 , respectively, the liability is included in Deferred credits & other liabilities . The impact of these plans on Other operating expenses was expense of $4.3 million in 2016 , $0.1 million in 2015 and $5.0 million in 2014 . The amount recorded in earnings related to the investment activities in Vectren phantom stock associated with these plans during the years ended December 31, 2016 , 2015 , and 2014 , was cost of $3.8 million , income of $0.4 million , and cost of $4.0 million , respectively. The Company has certain investments currently funded primarily through corporate-owned life insurance policies. These investments, which are consolidated, are available to pay deferred compensation benefits. These investments are also subject to the claims of the Company's creditors. The cash surrender value of these policies included in Other corporate & utility investments on the Consolidated Balance Sheets were $33.1 million and $30.1 million at December 31, 2016 and 2015 , respectively. Those investments generated earnings of $3.5 million in 2016 , losses of $2.1 million in 2015 , and earnings of $2.8 million in 2014 . This activity is reflected in Other income - net.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2016
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments & Contingencies Commitments Future minimum lease payments required under operating leases that have initial or remaining noncancelable lease terms in excess of one year during the five years following 2016 and thereafter (in millions) are $9.8 in 2017 , $7.3 in 2018 , $4.4 in 2019 , $2.1 in 2020 , $1.8 in 2021 , and $3.9 thereafter. Total lease expense, for these type of commitments, (in millions) was $13.0 in 2016 , $11.1 in 2015 , and $13.2 in 2014 . The Company’s regulated utilities have both firm and non-firm commitments, some of which are between five and twenty year agreements, to purchase natural gas, coal, and electricity, as well as certain transportation and storage rights. 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. Performance Guarantees & Product Warranties In the normal course of business, wholly owned subsidiaries, such as Energy Systems Group, LLC (ESG), a subsidiary of the Energy Services operating segment, issue payment and performance bonds and other forms of assurance that commit them to timely install infrastructure, operate facilities, pay vendors and subcontractors, and support warranty obligations. Specific to ESG's role as a general contractor in the performance contracting industry, at December 31, 2016 , there are 54 open surety bonds supporting future performance. The average face amount of these obligations is $10.6 million , and the largest obligation has a face amount of $75.9 million . The maximum exposure from these obligations is limited to the level of uncompleted work and further limited by bonds issued to ESG by various contractors. At December 31, 2016 , approximately 43 percent o f work was yet to be completed on projects with open surety bonds. A significant portion of these open surety bonds will be released within one year . In instances where ESG operates facilities, project guarantees extend over a longer period. In addition to its performance obligations, ESG also warrants the functionality of certain installed infrastructure generally for one year and the associated energy savings over a specified number of years. Based on a history of meeting performance obligations and installed products operating effectively, no liability or cost has been recognized for the periods presented as the Company assesses the likelihood of loss as remote. Since inception, ESG has paid a de minimis amount on energy savings guarantees. Corporate Guarantees The Company issues parent level guarantees to certain vendors and customers of its wholly owned subsidiaries. These guarantees do not represent incremental consolidated obligations; but rather, represent guarantees of subsidiary obligations in order to allow those subsidiaries the flexibility to conduct business without posting other forms of collateral. At December 31, 2016 , parent level guarantees support a maximum of $319 million of ESG's performance contracting commitments, warranty obligations, project guarantees, and energy savings guarantees. Given the infrequent occurrence of any performance shortfalls historically on any of these commitments, no reserve for a potential liability has been deemed warranted. Further, an energy facility operated by ESG and managed by Keenan Ft. Detrick Energy, LLC (Keenan), is governed by an operations agreement. Under this agreement, all payment obligations to Keenan are also guaranteed by the Company. The Company guarantee of the Keenan operations agreement does not state a maximum guarantee. Due to the nature of work performed under this contract, the Company cannot estimate a maximum potential amount of future payments but assesses the likelihood of loss as remote based on, primarily, the nature of the project. In addition, the Company has other guarantees outstanding, including letters of credit, supporting other consolidated subsidiary operations. The Company has not been called on to perform under these guarantees historically. While there can be no assurance that performance under these provisions will not be required in the future, the Company believes that the likelihood of a material amount being incurred under these provisions is remote given the nature of the projects, the manner in which the savings estimates are developed, and the fact that the value of the guarantees decrease over time as actual savings are achieved. Legal & Regulatory 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.

Gas Rate & Regulatory Matters

Gas Rate & Regulatory Matters	12 Months Ended
	Dec. 31, 2016
Public Utilities, General Disclosures [Abstract]
Gas Rate and Regulatory Matters	Gas Rate and 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's natural gas utilities are currently engaged in programs to replace bare steel and cast iron infrastructure and other activities in both Indiana and Ohio to mitigate risk, improve the system, and comply with applicable regulations, many of which are the result of federal pipeline safety requirements. Laws passed in both Indiana and Ohio 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 that, among other things, requests for recovery include a seven-year project plan. Once the plan is approved by the IURC, 80 percent of such costs are eligible for current recovery using a periodic rate adjustment mechanism. Recoverable costs include a return on the investment that reflects the current capital structure and associated costs, with the exception of the rate of return on equity, which remains fixed at the rate determined in the Company's last rate case. Recoverable costs also include recovery of depreciation and other operating expenses. The remaining 20 percent of project costs are deferred and recovered in the utility’s next general rate case, which must be filed before the expiration of the seven-year plan. The adjustment mechanism is capped at an annual increase in retail revenues of no more than two percent. Ohio House Bill 95 (House Bill 95) permits a natural gas utility to apply for recovery of much of its capital expenditure program. This legislation also allows for the deferral of costs, such as depreciation, property taxes, and debt-related post-in-service carrying costs until recovery is approved by the PUCO. Indiana Recovery and Deferral Mechanisms The Company's Indiana natural gas utilities received Orders in 2008 and 2007 associated with the most recent base rate cases. These Orders authorized the deferral of financial impacts associated with bare steel and cast iron replacement activities. The Orders provide for the deferral of depreciation and post-in-service carrying costs on qualifying projects totaling $20 million annually at Indiana Gas and $3 million annually at SIGECO. 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 three years after being placed into service at SIGECO and four years after being placed into service at Indiana Gas. At December 31, 2016 and December 31, 2015 , the Company has regulatory assets totaling $21.9 million and $19.9 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 Indiana 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 $890 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 $80 million of projects were not approved for recovery through the mechanisms pursuant to these filings. Specifically, Vectren 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 $338 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 $950 million through 2020. The plan increase of $60 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 $51.1 million and $28.6 million , respectively. Ohio Recovery and Deferral Mechanisms The PUCO Order approving the Company's 2009 base rate case in the Ohio service territory authorized a distribution replacement rider (DRR). The DRR's primary purpose is recovery of investments in utility plant and related operating expenses associated with replacing bare steel and cast iron pipelines, as well as certain other infrastructure investments. This rider is updated annually for qualifying capital expenditures and allows for a return on those capital expenditures based on the rate of return approved in the 2009 base rate case. In addition, deferral of depreciation and the ability to accrue debt-related post-in-service carrying costs is also allowed until the related capital expenditures are included in the DRR. The Order also initially established a prospective bill impact evaluation on the annual deferrals. On February 19, 2014, the PUCO issued an Order approving a Stipulation entered into by the PUCO Staff and the Company which provided for the extension of the DRR for the recovery of costs incurred through 2017 and expanded the types of investment covered by the DRR to include recovery of certain other infrastructure investments. The Order limits the resulting DRR fixed charge per month for residential and small general service customers to specific graduated levels through 2017. The capital expenditure plan is subject to the graduated caps on the fixed DRR monthly charge applicable to residential and small general service customers approved in the Order. In the event the Company exceeds these caps, amounts in excess can be deferred for future recovery. The remaining capital expenditure plan to be included for recovery in future DRR filings is estimated to be approximately $100 million to $120 million . The Order also approved the Company's commitment that the DRR can only be further extended as part of a base rate case. In total, the Company has made capital investments on projects that are now in-service under the DRR totaling $259.6 million as of December 31, 2016, of which $204 million has been approved for recovery under the DRR through December 31, 2015. Regulatory assets associated with post-in-service carrying costs and depreciation deferrals were $24.4 million and $18.2 million at December 31, 2016 and December 31, 2015 , respectively. In August 2016, the Company received approval to adjust the DRR rates, effective September 1, 2016, for recovery of investments placed in-service through December 31, 2015. The PUCO has also issued Orders approving the Company's filings under Ohio House Bill 95. These Orders approve deferral of the Company’s Ohio capital expenditure program for items not covered by the DRR as well as expenditures necessary to comply with PUCO rules, regulations, orders, and system expansion to some new customers. Ohio House Bill 95 Orders also established a prospective bill impact evaluation on the cumulative deferrals, limiting the total deferrals at a level which would equal $1.50 per residential and small general service customer per month. At December 31, 2016 and December 31, 2015 , the Company has regulatory assets totaling $41.9 million and $24.1 million , respectively, associated with the deferral of depreciation, post-in-service carrying costs, and property taxes. As of December 31, 2016 , the Company's deferrals have not reached this bill impact cap. On May 2, 2016, the Company submitted its most recent annual report required under its House Bill 95 Order. This report covers the Company's capital expenditure program through calendar year 2016. Given the extension of the DRR through 2017, as discussed above, and the continued ability to defer other capital expenses under House Bill 95, it is anticipated that the Company will file a general rate case for the inclusion in rate base of the above costs in early 2018. 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 that 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 that the cost to comply with these new rules should be recoverable using the regulatory recovery mechanisms referenced above.

Electric Rate and Regulatory Ma

Electric Rate and Regulatory Matters	12 Months Ended
	Dec. 31, 2016
Public Utilities, General Disclosures [Abstract]
Electric Rate and Regulatory Matters	Electric Rate and Regulatory Matters Regulatory Treatment of Investments in Electric Infrastructure On February 23, 2017, the Company filed for authority to recover costs related to its electric system modernization plan, using the mechanism allowed under Senate Bill 560. The electric system modernization plan includes investments to upgrade portions of the Company’s network of substations, transmission and distribution systems, to enhance reliability and allow the grid to accept advanced technology to improve the information and service provided to customers. The filing requests the recovery of associated capital expenditures estimated to be approximately $500 million over the seven -year period beginning in 2017. A procedural schedule has not been set in this proceeding, but under Senate Bill 560, an order is expected within 210 days of filing. Renewable Generation Resources On February 22, 2017, the Company also filed for authority to recover costs related to the construction of three solar projects, using the mechanism allowed under Senate Bill 29, which allows for timely recovery of costs and expenses incurred during the construction and operation of clean energy projects. These investments, presented as part of the Company’s Integrated Resource Plan (IRP) submitted in December 2016, allow the Company to add an initial 4 MW of universal solar generation, rooftop solar generation, and 1 MW of battery storage resources to its portfolio. See more information on the IRP below in Environmental and Sustainability Matters. The cost of the projects is estimated to be approximately $15 million . A procedural schedule has not been set in this proceeding, however an order is expected later in 2017. SIGECO Electric Environmental Compliance Filing In January 2015, the IURC issued an Order approving the Company’s request for approval of capital investments in its coal-fired generation units to comply with new EPA mandates related to mercury and air toxic standards (MATS) effective in 2015 and to address an outstanding Notice of Violation (NOV) related to sulfur trioxide emissions from the EPA. As of December 31, 2016 , $30 million has been spent on equipment to control mercury in both air and water emissions, and $40 million to address the issues raised in the NOV. The Order approved the Company’s request for deferred accounting treatment, as supported by provisions under Indiana Senate Bill 29 and Senate Bill 251. The accounting treatment includes the deferral of depreciation and property tax expense related to these investments, accrual of post-in-service carrying costs, and deferral of incremental operating expenses related to compliance with these standards. The initial phase of the projects went into service in 2014, with the remaining investment going into service in 2016. As of December 31, 2016 , the Company has approximately $6.9 million deferred related to depreciation and operating expense, and $2.8 million deferred related to post-in-service carrying costs. In June 2015, Joint Appellants’ Citizens Action Coalition of Indiana, Inc., Sierra Club, Inc., and Valley Watch, Inc. (the appellants) challenged the IURC's January Order. On October 29, 2015, the Indiana Court of Appeals issued an opinion that affirmed the IURC’s findings with regard to equipment required to comply with MATS and certain national pollutant discharge elimination system rules (approximately $30 million ) but remanded the case to the IURC to determine whether a certificate of public convenience and necessity (CPCN) should be issued for the equipment required by the NOV (approximately $40 million ). On June 22, 2016, the IURC issued an Order granting Vectren a CPCN for the NOV-required equipment. On July 21, 2016, the appellants initiated an appeal of the IURC's June 22, 2016 Order challenging the findings made by the IURC. On February 14, 2017, the Court affirmed the IURC's June 22, 2016 Order. SIGECO Electric Demand Side Management (DSM) Program Filing On August 31, 2011, the IURC issued an Order approving an initial three -year DSM plan in the SIGECO electric service territory that complied with the IURC’s energy saving targets. Consistent with the Company’s proposal, the Order approved, among other items, the following: 1) recovery of costs associated with implementing the DSM Plan; 2) the recovery of a performance incentive mechanism based on measured savings related to certain DSM programs; and 3) lost margin recovery associated with the implementation of DSM programs for large customers. On June 20, 2012, the IURC issued an Order approving a small customer lost margin recovery mechanism, inclusive of all previous deferrals. For the twelve months ended December 31, 2016 , 2015 , and 2014 , the Company recognized electric utility revenue of $11.1 million , $10.1 million and $8.7 million , respectively, associated with this approved lost margin recovery mechanism. On March 28, 2014, Indiana Senate Bill 340 was signed into law. The legislation allows for industrial customers to opt out of participating in energy efficiency programs and as a result of this legislation, most of the Company’s eligible industrial customers have since opted out of participation in the applicable energy efficiency programs. Indiana Senate Bill 412 (Senate Bill 412) requires electricity suppliers to submit energy efficiency plans to the IURC at least once every three years. Senate Bill 412 also permits the recovery of all program costs, including lost revenues and financial incentives associated with those plans and approved by the IURC. The Company made its first filing pursuant to this bill in June 2015, which proposed energy efficiency programs for calendar years 2016 and 2017. On March 23, 2016, the IURC issued an Order approving the Company’s 2016-2017 energy efficiency programs. The Order provides for cost recovery of program and administrative expenses and includes performance incentives for reaching energy savings goals. The Order also included a lost margin recovery mechanism that now limits that recovery related to new programs to the shorter of four years or the life of the installed energy efficiency measure. Prior electric energy efficiency orders did not limit lost margin recovery in this manner. This ruling follows other recent IURC decisions implementing the same lost margin recovery limitation with respect to other electric utilities in Indiana. The Company is committed to continuing to promote and drive participation in its energy efficiency programs and has therefore appealed this lost margin recovery restriction. The Company expects a decision on its appeal in the first half of 2017. FERC Return on Equity (ROE) Complaints On November 12, 2013, certain parties representing a group of industrial customers filed a joint complaint with the FERC under Section 206 of the Federal Power Act against the MISO and various MISO transmission owners, including SIGECO (first complaint case). The joint parties sought to reduce the 12.38 percent ROE used in the MISO transmission owners’ rates, including SIGECO’s formula transmission rates, to 9.15 percent covering the refund period from November 12, 2013 through February 11, 2015 (first refund period). On September 28, 2016, the FERC issued a final order authorizing a 10.32 percent base ROE for the first refund period and prospectively through the date of the order in a second complaint case as detailed below. A second customer complaint case was filed on February 11, 2015 covering the refund period from February 12, 2015 through May 11, 2016 (second refund period). An initial decision from the FERC administrative law judge on June 30, 2016, authorized a base ROE of 9.70 percent for the second refund period. The FERC is expected to rule on the proposed order in the second complaint case in 2017, which will authorize a base ROE for this period and prospectively from the date of the order. Separately, on January 6, 2015, the FERC approved a MISO transmission owner joint request for an adder to the approved ROE. Under FERC regulations, transmission owners that are part of a Regional Transmission Organization (RTO) such as the MISO are authorized to earn an incentive of 50 basis points above the FERC approved ROE. The FERC deferred the implementation of this adder until the pending complaint is resolved. The adder will be applied retroactively from January 6, 2015 through May 11, 2016 and prospectively from the September 28, 2016 order in the first complaint case. The Company has reflected these results in its financial statements. As of December 31, 2016, the Company had invested approximately $157.7 million in qualifying projects. The net plant balance for these projects totaled $136.8 million at December 31, 2016 .

Environmental Matters

Environmental Matters	12 Months Ended
	Dec. 31, 2016
Environmental Matters Disclosure [Abstract]
Environmental Matters	Environmental and Sustainability Matters The Company initiated its corporate sustainability program in 2012 with the publication of its initial corporate sustainability report. Since that time the Company continues to develop strategies that focus on those environmental, social and governance (ESG) factors that contribute to the long-term growth of the Company’s sustainable business model. As detailed further below and in the upcoming corporate sustainability report for 2016, the Company continues to set out its plans, among other things, to upgrade and diversify its generation portfolio. The Company’s sustainability policies and efforts, and in particular its policies and procedures designed to ensure compliance with applicable laws and regulations, are directly overseen by the Board’s Corporate Responsibility and Sustainability Committee, as well as vetted with the full Board of Directors. Further discussion of key goals, strategies, and governance practices can be found in the Company’s latest sustainability report at www.vectren.com/sustainability, which received core level certification from the Global Reporting Initiative. The Company's utility operations and properties are subject to extensive environmental regulation pursuant to a variety of federal, state, and municipal laws and regulations. These environmental regulations impose, among other things, restrictions, liabilities, and obligations in connection with the storage, transportation, treatment, and disposal of hazardous substances and limit airborne emissions from electric generating facilities including particulate matter, sulfur dioxide (SO2), nitrogen oxide (NOx), and mercury, among others. Environmental legislation and regulation also requires that facilities, sites, and other properties associated with the Company's operations be operated, maintained, abandoned, and reclaimed to the satisfaction of applicable regulatory authorities. The Company's current costs to comply with these laws and regulations are significant to its results of operations and financial condition. Similar to the costs associated with federal mandates in the Pipeline Safety Law, Senate Bill 251 is also applicable to federal environmental mandates impacting SIGECO's electric operations. Integrated Resource Planning Process As required by the state of Indiana, the Company completed its 2016 Integrated Resource Plan (IRP) and submitted to the IURC for review on December 16, 2016. The Company anticipates the IURC will, likely in the summer of 2017, release a director’s report to the other state utilities that filed their IRPs in 2016. The state requires each electric utility to perform and submit an IRP that uses economic modeling to consider the costs and risks associated with available resource options to provide reliable electric service for the next twenty year period. During 2016, the Company held three public stakeholder meetings to gather input and feedback as well as communicate results of the IRP process as it progressed. In developing its IRP, the Company considered both the cost to continue operating its existing generation units in a manner that complies with current and anticipated future environmental requirements, as well as various resource alternatives, such as the use of energy efficiency programs and renewable resources as part of its overall generation portfolio. Currently, the Company operates approximately 1,000 MW of coal-fired generation, 245 MW of natural gas peaking units, and 3 MW via a landfill-gas-to-electricity facility. The Company also has 80 MW of wind power through two long-term power purchase agreements and 32 MW of coal generation through its ownership in OVEC. The Company’s 2016 IRP preferred portfolio illustrates a future less reliant on coal. The twenty year plan reflects the retirement of a portion of the Company’s current coal-fired fleet, transitions a significant portion of generation to natural gas and includes new renewable energy sources, specifically universal solar. The detailed plan would introduce approximately 54 MW of universal solar installed by 2019. The plan suggests the Company will exit its joint operations of Warrick Unit 4, a 300 MW unit shared with Alcoa, by 2020. The Company would complete upgrades to its existing coal-fired Culley Unit 3, a 270-megawatt unit, to comply with federal water regulations specific to the Effluent Limitations Guidelines (ELG) around 2023 in order to keep the unit in operation. In 2024, the plan points to the retirement of coal-fired AB Brown plant Units 1 & 2 along with Culley Unit 2, collectively representing 580 MW. This generation would be replaced by a newly constructed combined cycle natural gas plant, with the capability of producing approximately 890 MW by 2024. In addition, the Company intends to continue to offer energy efficiency programs annually. The Company’s plan considered a broad range of potential resources and variables and is focused on ensuring it offers a reliable, reasonably priced generation portfolio as well as a balanced energy mix. The Company plans to finalize this generation portfolio transition plan and submit a regulatory filing, including construction timelines and costs of new generation resources, to the IURC in late 2017 to begin the generation transition process. The Company believes that all compliance costs, including cost of new generation as well as the cost of retiring generation, would be considered a federally mandated cost of providing electricity and therefore should be recoverable either from customers through Senate Bill 251 as referenced above, Senate Bill 29 used by the Company to recover its initial pollution control investments, or through other forms of rate recovery. Coal Ash Waste Disposal, Ash Ponds and Water Coal Combustion Residuals Rule In December 2014, the EPA released its final Coal Combustion Residuals (CCR) rule which regulates ash as non-hazardous material under Subtitle D of the Resource Conservation and Recovery Act (RCRA). On April 17, 2015, the final rule was published in the Federal Register. The final rule allows beneficial reuse of ash and the majority of the ash generated by the Company’s generating plants will continue to be reused. As it relates to the CCR rule, legislation was passed in December 2016 by Congress that would provide for enforcement of the federal program by states rather than through citizen suits. Additionally, the CCR rule is currently being challenged by multiple parties in judicial review proceedings. Under the final CCR rule, the Company is required to complete a series of integrity assessments, including seismic modeling given the Company’s facilities are located within two seismic zones, and groundwater monitoring studies to determine the remaining service life of the ponds and whether a pond must be retrofitted with liners or closed in place, with bottom ash handling conversions completed. In late 2015, using general utility industry data, the Company prepared cost estimates for the retirement of the ash ponds at the end of their useful lives, based on its interpretation of the closure alternatives contemplated in the final rule. The resulting estimates ranged from approximately $35 million to $80 million . These estimates contemplated final capping and monitoring costs of the ponds at both F.B. Culley and A.B. Brown generating stations. These rules are not applicable to the Company's Warrick generating unit, as this unit has historically been part of a larger generating station that predominantly serves an adjacent industrial facility. Throughout 2016, the Company has continued to refine site specific estimates and now estimates the costs to be in the range of $45 million to $100 million . Significant factors impacting the resulting cost estimates include the closure time frame and the method of closure. Current estimates contemplate additional beneficial reuse of the ash, as well as implications of the Company’s preferred IRP. Ongoing analysis, the continued refinement of assumptions, or the inability to beneficially reuse the ash may result in estimated costs in excess of the current range. As of December 31, 2016, the Company had recorded an approximate $40 million asset retirement obligation (ARO). The recorded ARO reflects the present value of the approximate $45 million in estimated costs in the range above. These assumptions and estimations are subject to change in the future and could materially impact the amount of the estimated ARO. In order to maintain current operations of the ponds, the Company has spent approximately $17 million on the reinforcement of the ash pond dams and other operational changes in 2016 to meet the more stringent 2,500 year seismic event structural and safety standard in the CCR rule. Effluent Limitation Guidelines (ELGs) Under the Clean Water Act, the EPA sets technology-based guidelines for water discharges from new and existing electric generation facilities. On September 30, 2015, the EPA released final revisions to the existing steam electric ELGs setting stringent technology-based water discharge limits for the electric power industry. The EPA focused this rulemaking on wastewater generated primarily by pollution control equipment necessitated by the comprehensive air regulations, specifically setting strict water discharge limits for arsenic, mercury and selenium for scrubber waste waters. The ELGs will be implemented when existing water discharge permits for the plants are renewed, with compliance activities expected to commence where operations continue, within the 2018-2023 time frame. The ELGs work in tandem with the aforementioned CCR requirements, effectively prohibiting the use of less costly lined sediment basin options for disposal of coal combustion residuals, and virtually mandate conversions to dry bottom ash handling. The current wastewater discharge permit for the A.B. Brown power plant had an expiration date of October 2016 and, for the F.B. Culley plant, a date of December 2016. The Company is continuing ongoing discussions with the state environmental agency during the first half of 2017 and anticipates final permits will be issued in the second quarter of 2017. During the renewal process, existing permits remain in place. As part of the permit renewals, the Company requested alternate compliance dates for ELGs. Compliance with the ELGs will not be required prior to November 2018, but no later than December 31, 2023. For plants identified in the Company’s preferred IRP to be retired prior to December 31, 2023, the Company has requested those plants would not require new treatment technology. For the F.B. Culley plant, the Company has proposed a 2020 compliance date for dry bottom ash and 2023 compliance date for flue gas desulfurization wastewater. The Company anticipates acceptance of the proposed schedule. Cooling Water Intake Structures Section 316(b) of the Clean Water Act requires generating facilities use the “best technology available” (BTA) to minimize adverse environmental impacts on a body of water. More specifically, Section 316(b) is concerned with impingement and entrainment of aquatic species in once-through cooling water intake structures used at electric generating facilities. A final rule was issued by the EPA on May 19, 2014. The final rule does not mandate cooling water tower retrofits but requires a state level case-by-case assessment of BTA for each facility. The final rule lists seven presumptive technologies which would qualify as BTA. These technologies range from intake screen modifications to cooling water tower retrofits. Ecological and technology assessment studies must be completed prior to determining BTA for the Company’s facilities. The Company is currently undertaking the required ecological studies and anticipates timely compliance in 2021-2022. To comply, the Company believes capital investments will likely be in the range of $4 million to $8 million . Air Quality Mercury and Air Toxics (MATS) Rule On December 21, 2011, the EPA finalized the utility MATS rule. The MATS rule sets emission limits for hazardous air pollutants for existing and new coal-fired power plants and identifies the following broad categories of hazardous air pollutants: mercury, non-mercury hazardous air pollutants (primarily arsenic, chromium, cobalt, and selenium), and acid gases (hydrogen cyanide, hydrogen chloride, and hydrogen fluoride). The rule imposes mercury emission limits for two sub-categories of coal and proposed surrogate limits for non-mercury and acid gas hazardous air pollutants. In July 2014, a coalition of twenty-one states, including Indiana, filed a petition with the U.S. Supreme Court seeking review of the decision of the appellate court that found the EPA appropriately based its decision to list coal and oil fired generation units as a source of the pollutants at issue solely on those pollutants’ impact on public health. On June 29, 2015, the U.S. Supreme Court reversed the appellate court decision on the basis of the EPA’s failure to consider costs before determining whether it was appropriate and necessary to regulate steam electric generating units under Section 112 of the Clean Air Act. The Court did not vacate the rule, but remanded the MATS rule to the appellate court for further proceedings consistent with the opinion. In April 2016, in response to the Court's remand, the EPA affirmed its earlier conclusion in a Supplemental Finding, and in June 2016, a coalition of states and other stakeholders filed challenges to the Supplemental Finding. MATS compliance was required to commence April 16, 2015, and the Company continues to operate in full compliance with the MATS rule. Notice of Violation for A.B. Brown Power Plant The Company received a NOV from the EPA in November 2011 pertaining to its A.B. Brown generating station. The NOV asserts when the facility was equipped with Selective Catalytic Reduction (SCR) systems, the correct permits were not obtained or the best available control technology to control incidental sulfuric acid mist was not installed. While the Company did not agree with the notice, it reached a final settlement with the EPA to resolve the NOV in December 2015. As noted previously, on January 28, 2015, the IURC issued an Order approving the Company’s request for approval of capital investments on its coal-fired generation units to comply with new EPA mandates related to MATS effective in 2015 and to address the outstanding NOV. The total investment was $70 million of which $30 million was spent to control mercury in both air and water emissions, and the remaining investment was made to address the issues raised in the NOV. In June 2015, Joint Appellants’ Citizens Action Coalition of Indiana, Inc., Sierra Club, Inc., and Valley Watch, Inc. (the appellants) challenged the IURC's January Order. On October 29, 2015, the Indiana Court of Appeals issued an opinion that affirmed the IURC’s findings with regard to equipment required to comply with MATS and certain national pollutant discharge elimination system rules (approximately $30 million ) but remanded the case to the IURC to determine whether a certificate of public convenience and necessity (CPCN) should be issued for the equipment required by the NOV (approximately $40 million ). On June 22, 2016, the IURC issued an Order granting Vectren a CPCN for the NOV-required equipment. On July 21, 2016, the appellants initiated an appeal of the IURC's June 22, 2016 Order challenging the findings made by the IURC. On February 14, 2017, the Court affirmed the IURC's June 22, 2016 Order. Ozone NAAQS On November 26, 2014, the EPA proposed to tighten the current National Ambient Air Quality Standard (NAAQS) for ozone from the current standard of 75 parts per billion (ppb) to a level with the range of 65 to 70 ppb. On October 1, 2015, the EPA finalized a new NAAQS for ozone at the high end of the range, or 70 ppb. On September 16, 2016, Indiana submitted its initial determination to the EPA recommending that counties in southwest Indiana, specifically Vanderburgh, Posey and Warrick, be declared in attainment of the new more stringent ozone standard based upon air monitoring data from 2014-2016. The EPA is expected to make final determinations as to whether a region is in attainment for the new NAAQS in 2017. While it is possible that counties in southwest Indiana could be declared in non-attainment with the new standard, and thus could have an effect on future economic development activities in the Company's service territory, the Company does not anticipate any significant compliance cost impacts from the determination given its previous investment in SCR technology for NOx control on its units. In September 2016, the EPA finalized a supplement to the Cross State Air Pollution Rule (CSAPR) that requires further NOx reductions during the ozone season (May - September). The Company is positioned to comply with these NOx reduction requirements through its current investment in SCR technology. One Hour SO2 NAAQS On February 16, 2016, the EPA notified states of the commencement of a 120 day consultation period between the state and the EPA with respect to the EPA's recommendations for new non-attainment designations for the 2010 One Hour SO2 NAAQS. Identified on the list was Posey County, Indiana, where the Company's A.B. Brown Generating Station is located. While the Company is in compliance with all applicable SO2 limits in its permits, the Company reached an agreement with the state of Indiana on voluntary measures that the Company was able to implement without significant incremental costs to ensure that Posey County remains in attainment with the 2010 One Hour SO2 NAAQS. The Company's coal-fired generating fleet is 100 percent scrubbed for SO2 and 90 percent controlled for NOx. Climate Change On August 3, 2015, the EPA released its final CPP rule which requires a 32 percent reduction in carbon emissions from 2005 levels. This results in a final emission rate goal for Indiana of 1,242 lb CO2/MWh to be achieved by 2030. The new rule gives states the option of seeking a two-year extension from the initial deadline of September 2016 to submit a final state implementation plan (SIP). Under the CPP, states have the flexibility to include energy efficiency and other measures should they choose to implement a SIP as provided in the final rule. While states are given an interim goal (1,451 lb CO2/MWh for Indiana), the final rule gives states the flexibility to shape their own emissions reduction over the 2022-2029 time period. The final rule was published in the Federal Register on October 23, 2015 and that action was immediately followed by litigation initiated by Indiana and 23 other states as a coalition challenging the rule. In January of 2016, the reviewing court denied the states’ and other parties requests to stay the implementation of the CPP pending completion of judicial review. On January 26, 2016, 29 states and state agencies, including the 24 state coalition referenced above, filed a request for immediate stay with the U.S. Supreme Court. On February 9, 2016, the U.S. Supreme Court granted a stay to delay the regulation while being challenged in court. Extensive oral argument was held in September. The stay will remain in place while the lower court concludes its review. Among other things, the stay delays the requirement to submit a final SIP by the original September 2016 deadline and could extend implementation to 2024. In the event a state does not submit a SIP, the EPA also released a proposed federal implementation plan (FIP), which would be imposed on those states without an approved SIP. The proposed FIP would apply an emission rate requirement directly on generating units. Under the proposed FIP, the CO2 emission rate limit for coal-fired units would start at 1,671 lbs CO2/MWh in 2022 and decrease to a final emission rate cap of 1,305 lbs CO2/MWh by 2030. While the FIP emission rate cap appears to be slightly less stringent than the state reduction goal for Indiana, the cap would apply directly to generating units and these units would not have the benefit of averaging emission rates with rates from zero-carbon sources as would be available in a SIP. Purchases of emission credits from zero-carbon sources can be made for compliance. The FIP will be subject to extensive public comments prior to finalization. Whether Indiana will file a SIP has yet to be determined. Pending that determination, the electric utilities in Indiana will continue to encourage the state's designated agency to analyze various compliance options and the possible integration into a state plan submittal. At the time of release of the CPP, Indiana was the 5th largest carbon emitter in the nation in tons of CO2 produced from electric generation. The Company’s share of total tons of CO2 generated by Indiana's electric utilities has historically been less than 6 percent . Since 2005 through 2015, the Company has achieved a reduction in emissions of CO2 of 31 percent (on a tonnage basis) through the retirement of F.B. Culley Unit 1, expiration of municipal wholesale power contracts, electric conservation, the addition of renewable generation, and the installation of more efficient dense pack turbine technology. Since emissions are further impacted by coal burn reductions and energy efficiency programs, the Company's emissions of CO2 can vary year to year. With respect to renewable generation, in 2008 and 2009, the Company executed long-term purchase power commitments for a total of 80 MW of wind energy. The Company currently has approximately 4 percent of its electricity being provided by energy sources other than coal and natural gas, due to the long-term wind contracts and landfill gas investment. With respect to CO2 emission rate, since 2005 through 2015, the Company has lowered its CO2 emission rate (as measured in lbs CO2/MWh) from 1,967 lbs CO2/MWh to 1,922 lbs CO2/MWh, for a reduction of 3 percent . The Company’s CO2 emission rate of 1,922 lbs CO2/MWh is basically the same as Indiana's average CO2 emission rate of 1,923 lbs CO2/MWh. The Company plans to consider these reductions in CO2 emissions and renewable generation in future discussions with the state to develop a possible state implementation plan. Impact of Legislative Actions & Other Initiatives is Unknown At this time, compliance costs and other effects associated with reductions in GHG emissions or obtaining renewable energy sources remain uncertain. The Company has gathered preliminary estimates of the costs to control GHG emissions. A preliminary investigation demonstrated costs to comply would be significant, first with regard to operating expenses and later for capital expenditures as technology becomes available to control GHG emissions. However, these compliance cost estimates were based on highly uncertain assumptions, including allowance prices if a cap and trade approach were employed, and energy efficiency targets. The Company is undertaking a detailed review of the requirements of the CPP and the proposed FIP and a review of potential compliance options. The Company will also continue to remain engaged with the Indiana legislators and regulators to assess the final rule and to develop a plan that is the least cost to its customers. In addition to the federal programs, the United States and 194 other countries agreed by consensus to limit GHG emissions beginning after 2020 in the 2015 United Nations Framework Convention on Climate Change Paris Agreement. The United States has proposed a 26-28 percent GHG emission reduction from 2005 levels by 2025. As previously noted, since 2005 through 2015, the Company has achieved reduced emissions of CO2 by 31 percent (on a tonnage basis). While the legislative outcome of the CPP rules remains uncertain, the Company will continue to monitor regulatory activity regarding GHG emission standards that may affect its electric generating units. 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. In the Indiana Gas service territory, the existence, location, and certain general characteristics of 26 gas manufacturing and storage sites have been identified for which the Company may have some remedial responsibility. A remedial investigation/ feasibility study (RI/FS) was completed at one of the sites under an agreed upon order between Indiana Gas and the IDEM, and a Record of Decision was issued by the IDEM in January 2000. The remaining sites have been submitted to the IDEM's Voluntary Remediation Program (VRP). The Company has identified its involvement in five manufactured gas plant sites in SIGECO’s service territory, all of which are currently enrolled in the IDEM’s 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 $44.2 million ( $23.9 million at Indiana Gas and $20.3 million at SIGECO). The estimated accrued costs are limited to the Company’s share of the remediation efforts and are therefore net of exposures of other potentially responsible parties (PRP). With respect to insurance coverage, Indiana Gas has received approximately $20.8 million from all known insurance carriers under insurance policies in effect when these plants were in operation. Likewise, SIGECO has settlement agreements with all known insurance carriers and has received approximately $15.2 million of the expected $15.8 million in insurance recoveries. 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’s utilities have 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 $2.9 million and $3.3 million , respectively, of accrued, but not yet spent, costs are included in Other Liabilities related to the Indiana Gas and SIGECO sites.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2016
Fair Value Disclosures [Abstract]
Fair Value Measurements	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 millions) Carrying Amount Est. Fair Value Carrying Amount Est. Fair Value Long-term debt $ 1,714.0 $ 1,835.8 $ 1,785.9 $ 1,899.6 Short-term borrowings & notes payable 194.4 194.4 14.5 14.5 Cash & cash equivalents 68.6 68.6 74.7 74.7 Restricted cash 0.9 0.9 5.9 5.9 For the balance sheets dates presented in these financial statements, the Company had no material assets or liabilities marked to fair value. 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. Because of the nature of certain other investments and lack of a readily available market, it is not practical to estimate the fair value of these financial instruments at specific dates without considerable effort and cost. At December 31, 2016 and 2015 , the fair value for these financial instruments was not estimated. The carrying value of these investments at December 31, 2016 and 2015 was approximately $16.1 million .

Segment Reporting

Segment Reporting	12 Months Ended
	Dec. 31, 2016
Segment Reporting [Abstract]
Segment Reporting	Segment Reporting The Company segregates its operations into three groups: 1) Utility Group, 2) Nonutility Group, and 3) Corporate and Other. The Utility Group is comprised of Vectren Utility Holdings, Inc.’s operations, which consist of the Company’s regulated operations and other operations that provide information technology and other support services to those regulated operations. The Company segregates its regulated operations between a Gas Utility Services operating segment and an Electric Utility Services operating segment. The Gas Utility Services segment provides natural gas distribution and transportation services to nearly two-thirds of Indiana and to west central Ohio. The Electric Utility Services segment provides electric distribution services primarily to southwestern Indiana, and includes the Company’s power generating and wholesale power operations. Regulated operations supply natural gas and/or electricity to over one million customers. In total, the Utility Group is comprised of three operating segments: Gas Utility Services, Electric Utility Services, and Other operations. During the periods presented, the Nonutility Group had the following operating segments: Infrastructure Services, Energy Services, Coal Mining, and Other Businesses. Energy Services, through the wholly owned subsidiary Energy Systems Group, LLC, provides energy performance contracting and sustainable infrastructure, such as renewables, distributed generation, and combined heat and power projects. The Infrastructure Services segment, through wholly owned subsidiaries Miller Pipeline, LLC and Minnesota Limited, LLC, provides underground pipeline construction and repair services for customers that include Vectren Utility Holdings' utilities. Fees incurred by Vectren Utility Holdings and its subsidiaries for these pipeline construction and repair services totaled $117.8 million in 2016, $109.5 million in 2015, and $94.0 million in 2014. In its 2016 periodic reports, the 2014 results for the Coal Mining segment include the results of Vectren Fuels through August 29, 2014 when it exited the coal mining business through the sale of Vectren Fuels (see Note 6 for more details of this transaction). Corporate and Other includes proceeds from life insurance policies offset by unallocated corporate expenses such as advertising and certain charitable contributions, among other activities, that benefit the Company’s other operating segments. Total assets in all periods presented reflect the retrospective impacts of the adoption in 2015 of ASU 2015-17, Balance Sheet Classification of Deferred Taxes and the retrospective impacts of the adoption in 2016 of ASU 2015-03, Presentation of Debt Issuance Costs. Net income is the measure of profitability used by management for all operations. Information related to the Company’s business segments is summarized as follows: Year Ended December 31, (In millions) 2016 2015 2014 Revenues Utility Group Gas Utility Services $ 771.7 $ 792.6 $ 944.6 Electric Utility Services 605.8 601.6 624.8 Other Operations 42.2 40.7 38.3 Eliminations (41.9 ) (40.4 ) (38.0 ) Total Utility Group 1,377.8 1,394.5 1,569.7 Nonutility Group Infrastructure Services 813.3 843.3 779.0 Energy Services 260.0 199.9 129.8 Coal Mining — — 234.3 Total Nonutility Group 1,073.3 1,043.2 1,143.1 Eliminations, net of Corporate & Other Revenues (2.8 ) (3.0 ) (101.1 ) Consolidated Revenues $ 2,448.3 $ 2,434.7 $ 2,611.7 Profitability Measures - Net Income Utility Group Net Income Gas Utility Services $ 76.1 $ 64.4 $ 57.0 Electric Utility Services 84.7 82.6 79.7 Other Operations 12.8 13.9 11.7 Total Utility Group Net Income 173.6 160.9 148.4 Nonutility Group Net Income (Loss) Infrastructure Services 25.0 29.7 43.1 Energy Services 12.5 7.3 (3.2 ) Coal Mining — — (21.1 ) Other Businesses (0.6 ) (0.7 ) (0.8 ) Total Nonutility Group Net Income 36.9 36.3 18.0 Corporate & Other Net Income 1.1 0.1 0.5 Consolidated Net Income $ 211.6 $ 197.3 $ 166.9 Year Ended December 31, (In millions) 2016 2015 2014 Amounts Included in Profitability Measures Depreciation & Amortization Utility Group Gas Utility Services $ 108.1 $ 98.6 $ 93.3 Electric Utility Services 87.1 85.6 85.7 Other Operations 23.9 24.6 24.1 Total Utility Group 219.1 208.8 203.1 Nonutility Group Infrastructure Services 38.2 44.5 36.2 Energy Services 2.5 2.7 3.9 Coal Mining — — 29.9 Other Businesses 0.2 0.3 0.3 Total Nonutility Group 40.9 47.5 70.3 Consolidated Depreciation & Amortization $ 260.0 $ 256.3 $ 273.4 Interest Expense Utility Group Gas Utility Services $ 40.1 $ 35.8 $ 34.9 Electric Utility Services 27.0 27.8 29.0 Other Operations 2.6 2.7 2.7 Total Utility Group 69.7 66.3 66.6 Nonutility Group Infrastructure Services 12.8 16.0 11.1 Energy Services 1.9 1.2 1.3 Coal Mining — — 7.5 Other Businesses 0.9 1.2 0.9 Total Nonutility Group 15.6 18.4 20.8 Corporate & Other 0.2 (0.2 ) (0.7 ) Consolidated Interest Expense $ 85.5 $ 84.5 $ 86.7 Income Taxes Utility Group Gas Utility Services $ 47.1 $ 40.8 $ 35.7 Electric Utility Services 50.1 49.3 48.1 Other Operations 2.3 (2.0 ) (0.6 ) Total Utility Group 99.5 88.1 83.2 Nonutility Group Infrastructure Services 17.9 19.6 28.9 Energy Services (3.5 ) (7.7 ) (7.8 ) Coal Mining — — (21.8 ) Other Businesses 0.3 1.5 (0.3 ) Total Nonutility Group 14.7 13.4 (1.0 ) Corporate & Other (1.3 ) (1.8 ) (1.1 ) Consolidated Income Taxes $ 112.9 $ 99.7 $ 81.1 Year Ended December 31, (In millions) 2016 2015 2014 Capital Expenditures Utility Group Gas Utility Services $ 358.5 $ 291.2 $ 245.9 Electric Utility Services 106.4 87.6 92.4 Other Operations 39.0 25.7 23.3 Non-cash costs & changes in accruals (7.1 ) (6.2 ) (10.9 ) Total Utility Group 496.8 398.3 350.7 Nonutility Group Infrastructure Services 43.2 78.1 54.1 Energy Services 1.8 0.5 1.6 Coal Mining — — 41.9 Other Businesses, net of eliminations 0.2 — — Total Nonutility Group 45.2 78.6 97.6 Consolidated Capital Expenditures $ 542.0 $ 476.9 $ 448.3 At December 31, (In millions) 2016 2015 2014 Assets Utility Group Gas Utility Services $ 3,091.0 $ 2,706.9 $ 2,604.6 Electric Utility Services 1,788.4 1,778.3 1,656.2 Other Operations, net of eliminations 161.5 107.5 148.5 Total Utility Group 5,040.9 4,592.7 4,409.3 Nonutility Group Infrastructure Services 513.9 554.5 538.5 Energy Services 182.7 160.3 87.1 Other Businesses, net of eliminations and reclassifications 53.3 64.0 120.3 Total Nonutility Group 749.9 778.8 745.9 Corporate & Other 628.4 742.4 654.9 Eliminations (618.5 ) (713.9 ) (672.3 ) Consolidated Assets $ 5,800.7 $ 5,400.0 $ 5,137.8

Additional Balance Sheet & Oper

Additional Balance Sheet & Operational Information	12 Months Ended
	Dec. 31, 2016
Additional Balance Sheet and Operational Information [Abstract]
Additional Balance Sheet and Operational Information	Additional Balance Sheet & Operational Information Inventories consist of the following: At December 31, (In millions) 2016 2015 Gas in storage – at LIFO cost $ 37.0 $ 40.5 Coal & oil for electric generation - at average cost 42.6 45.0 Materials & supplies 48.9 46.9 Other 1.4 1.3 Total inventories $ 129.9 $ 133.7 Based on the average cost of gas purchased during December, the cost of replacing inventories carried at LIFO cost exceeded carrying value at December 31, 2016 by $1.0 million . Based on the average cost of gas purchased during December, the cost of replacing inventories carried at LIFO cost approximated carrying value at December 31, 2015 . Prepayments & other current assets consist of the following: At December 31, (In millions) 2016 2015 Prepaid gas delivery service $ 26.4 $ 30.0 Prepaid taxes 8.2 25.3 Other prepayments & current assets 18.1 25.7 Total prepayments & other current assets $ 52.7 $ 81.0 Investments in unconsolidated affiliates consist of the following: At December 31, (In millions) 2016 2015 ProLiance Holdings, LLC $ 19.2 $ 19.7 Other nonutility partnerships & corporations 1.0 1.0 Other utility investments 0.2 0.2 Total investments in unconsolidated affiliates $ 20.4 $ 20.9 Other utility & corporate investments consist of the following: At December 31, (In millions) 2016 2015 Cash surrender value of life insurance policies $ 33.1 $ 30.1 Restricted cash & other investments 1.0 1.1 Total other utility & corporate investments $ 34.1 $ 31.2 Goodwill by operating segment follows: At December 31, (In millions) 2016 2015 Utility Group Gas Utility Services $ 205.0 $ 205.0 Nonutility Group Infrastructure Services 58.8 58.8 Energy Services 29.7 29.7 Consolidated goodwill $ 293.5 $ 293.5 Accrued liabilities consist of the following: At December 31, (In millions) 2016 2015 Refunds to customers & customer deposits $ 49.4 $ 51.4 Accrued taxes 46.5 39.9 Accrued interest 18.2 19.4 Deferred compensation & post-retirement benefits 6.6 7.2 Accrued salaries & other 87.0 65.7 Total accrued liabilities $ 207.7 $ 183.6 Asset retirement obligations included in Deferred credits and other liabilities in the Consolidated Balance Sheets roll forward as follows: (In millions) 2016 2015 Asset retirement obligation, January 1 $ 82.0 $ 55.0 Accretion 3.8 3.2 Liabilities incurred in current period — 24.2 Changes in estimates, net of cash payments 20.9 (0.4 ) Asset retirement obligation, December 31 106.7 82.0 Equity in earnings (losses) of unconsolidated affiliates consists of the following: Year Ended December 31, (In millions) 2016 2015 2014 ProLiance Holdings, LLC $ (0.5 ) $ (0.8 ) $ (0.3 ) Other 0.3 0.2 0.8 Total equity in earnings (losses) of unconsolidated affiliates $ (0.2 ) $ (0.6 ) $ 0.5 Other income (expense) – net consists of the following: Year Ended December 31, (In millions) 2016 2015 2014 AFUDC – borrowed funds $ 20.3 $ 16.3 $ 11.4 AFUDC – equity funds 2.2 2.6 3.2 Nonutility plant capitalized interest 1.0 0.4 — Interest income, net 1.3 1.3 1.1 Other nonutility investment impairment charges — (0.1 ) (1.0 ) All other income 3.9 (0.2 ) 5.0 Total other income (expense) – net $ 28.7 $ 20.3 $ 19.7 Supplemental Cash Flow Information: Year Ended December 31, (In millions) 2016 2015 2014 Cash paid (received) for: Interest $ 86.6 $ 84.2 $ 87.5 Income taxes (3.6 ) 4.8 69.4 As of December 31, 2016 and 2015 , the Company has accruals related to utility and nonutility plant purchases totaling approximately $30.0 million and $19.4 million , respectively.

Impact of Recently Issued Accou

Impact of Recently Issued Accounting Guidance	12 Months Ended
	Dec. 31, 2016
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
Impact of Recently Issued Accounting Principles	Impact of Recently Issued Accounting Guidance 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. Simplifying the Presentation of Debt Issuance Costs In April 2015, the FASB issued new accounting guidance on accounting for debt issuance costs which changes the presentation of debt issuance costs in financial statements. This ASU requires an entity to present such costs in the balance sheet as a direct reduction from the related debt liability rather than as an asset. Amortization of the costs will continue to be reported as interest expense. This ASU is effective for annual reporting periods beginning after December 15, 2015. The guidance was adopted as of January 1, 2016 and has been applied retrospectively to all periods presented. The effect of the change on the December 31, 2015 balance sheet was the reclassification of $8.6 million from Regulatory assets to Long-term Debt and the reclassification of $1.3 million from Other assets to Long-term Debt . The reclassification had no material impact on the Company's financial condition, results of operations, or cash flows as a result of the adoption. 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. Most of the Company's 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 that 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.

Quarterly Financial Data (Unaud

Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2016
Quarterly Financial Information Disclosure [Abstract]
Quarterly Financial Data (Unaudited)	Quarterly Financial Data (Unaudited) Information in any one quarterly period is not indicative of annual results due to the seasonal variations common to the Company’s utility operations. Summarized quarterly financial data for 2016 and 2015 follows: (In millions, except per share amounts) Q1 Q2 Q3 Q4 2016 Operating revenues $ 584.8 $ 533.7 $ 631.0 $ 699.0 Operating income 92.2 63.9 105.5 120.7 Net income 48.3 32.3 61.4 69.6 Earnings per share: Basic and Diluted $ 0.58 $ 0.39 $ 0.74 $ 0.84 2015 Operating revenues $ 706.2 $ 551.0 $ 573.5 $ 604.0 Operating income 106.1 72.9 79.9 103.0 Net income 57.0 35.8 39.3 65.2 Earnings per share: Basic and Diluted $ 0.69 $ 0.43 $ 0.48 $ 0.79

SCHEDULE II VALUATION AND QUALI

SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES	12 Months Ended
	Dec. 31, 2016
Valuation and Qualifying Accounts [Abstract]
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES	SCHEDULE II Vectren Corporation and Subsidiaries VALUATION AND QUALIFYING ACCOUNTS AND RESERVES Column A Column B Column C Column D Column E Additions Balance at Charged Charged Deductions Balance at Beginning to to Other from End of Description of Year Expenses Accounts Reserves, Net Year (In millions) VALUATION AND QUALIFYING ACCOUNTS: Year 2016 – Accumulated provision for uncollectible accounts $ 5.6 $ 6.9 $ — $ 6.5 $ 6.0 Year 2015 – Accumulated provision for uncollectible accounts $ 6.0 $ 8.1 $ — $ 8.5 $ 5.6 Year 2014 – Accumulated provision for uncollectible accounts $ 6.8 $ 7.3 $ — $ 8.1 $ 6.0 Year 2016 – Reserve for impaired notes receivable $ 0.2 $ 0.4 $ — $ — $ 0.6 Year 2015 – Reserve for impaired notes receivable $ — $ 0.2 $ — $ — $ 0.2 Year 2014 – Reserve for impaired notes receivable $ 0.6 $ — $ — $ 0.6 $ — OTHER RESERVES: Year 2016 - Restructuring costs $ — $ — $ — $ — $ — Year 2015 - Restructuring costs $ — $ — $ — $ — $ — Year 2014 - Restructuring costs $ 0.2 $ — $ — $ 0.2 $ —

Summary of Significant Accoun35

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
Principles of Consolidation	Principles of Consolidation The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries, after appropriate elimination of intercompany transactions.
Subsequent Events Review	Subsequent Events Review Management performs a review of subsequent events for any events occurring after the balance sheet date but prior to the date the financial statements are issued.
Cash and Cash Equivalents	Cash & Cash Equivalents 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	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	Inventories In most circumstances, the Company’s inventory components are recorded using an average cost method; however, natural gas in storage at the Company’s Indiana utilities are recorded using the Last In – First Out (LIFO) method. Inventory related to the Company’s regulated operations 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 and Equipment	Property, Plant & Equipment Both the Company’s Utility Plant and Nonutility 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 Both the IURC and PUCO allow the Company’s utilities to capitalize financing costs associated with Utility Plant based on a computed interest cost and a designated cost of equity funds. These financing costs are commonly referred to as AFUDC and are capitalized for ratemaking purposes and for financial reporting purposes instead of amounts that would otherwise be capitalized when acquiring nonutility plant. The Company reports both the debt and equity components of AFUDC in Other – net in the Consolidated Statements of Income . When property that represents a retirement unit is replaced or removed, the remaining historical value of such property is charged to Utility Plant , with an offsetting charge to Accumulated depreciation , resulting in no gain or loss. Costs to dismantle and remove retired property are recovered through the depreciation rates as determined by the IURC and PUCO. The Company’s portion of jointly owned Utility Plant , along with that plant’s related operating expenses, is presented in these financial statements in proportion to the ownership percentage. Nonutility Plant & Related Depreciation The depreciation of Nonutility Plant is charged against income over its estimated useful life, using the straight-line method of depreciation. When nonutility property is retired, or otherwise disposed of, the asset and accumulated depreciation are removed, and the resulting gain or loss is reflected in income, typically impacting operating expenses. Impairment Reviews Property, plant and equipment along with other long-lived assets are reviewed as facts and circumstances indicate that the carrying amount may be impaired. This impairment review involves the comparison of an asset’s (or group of assets’) carrying value to the estimated future cash flows the asset (or asset group) is expected to generate over a remaining life. If this evaluation were to conclude that the carrying value is impaired, an impairment charge would be recorded based on the difference between the carrying amount and its fair value (less costs to sell for assets to be disposed of by sale) as a charge to operations or discontinued operations.
Investments in Unconsolidated Affiliates	Investments in Unconsolidated Affiliates Investments in unconsolidated affiliates where the Company has significant influence are accounted for using the equity method of accounting. The Company’s share of net income or loss from these investments is recorded in Equity in earnings (losses) of unconsolidated affiliates . Dividends are recorded as a reduction of the carrying value of the investment when received. Investments in unconsolidated affiliates where the Company does not have significant influence are accounted for using the cost method of accounting. Dividends associated with cost method investments are recorded as Other income – net when received. Investments are reviewed as facts and circumstances indicate that the carrying amount may be impaired. This impairment review involves the comparison of an investment's fair value to its carrying value. Investments, when necessary, include adjustments for declines in value judged to be other than temporary.
Goodwill	Goodwill Goodwill recorded on the Consolidated Balance Sheets results from business acquisitions and is based on a fair value allocation of the businesses’ purchase price at the time of acquisition. Goodwill is charged to expense only when it is impaired. The Company tests its goodwill for impairment at an operating segment level because the components within the segments are similar. These tests are performed at least annually and at the beginning of each year. Impairment reviews consist of a comparison of fair value to the carrying amount. If the fair value is less than the carrying amount, an impairment loss is recognized in operations. No goodwill impairments have been recorded during the periods presented.
Regulation	Regulation Retail public utility operations affecting Indiana customers are subject to regulation by the IURC, and retail public utility operations affecting Ohio customers are subject to regulation by the PUCO. The Company’s accounting policies give recognition to the ratemaking and accounting practices authorized by these agencies. Refundable or Recoverable Gas Costs & Cost of Fuel & Purchased Power All metered gas rates in Indiana contain a gas cost adjustment clause that allows the Company to charge for changes in the cost of purchased gas. Metered electric rates contain a fuel adjustment clause that allows for adjustment in charges for electric energy to reflect changes in the cost of fuel. The net energy cost of purchased power, subject to a variable benchmark based on NYMEX natural gas prices, is also recovered through regulatory proceedings. The Company records any under-or-over-recovery resulting from gas and fuel adjustment clauses 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, and the cost of fuel and purchased power for electric generation is charged to operating expense when consumed. 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 that are to be credited to customers through the ratemaking process. The Company continually assesses the recoverability of costs recognized as regulatory assets and liabilities and the ability to recognize new regulatory assets and liabilities associated with its regulated utility operations. Given the current regulatory environment in its jurisdictions, 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.
Postretirement Obligations and Costs	Postretirement Obligations & Costs The Company recognizes the funded status of its pension plans and postretirement plans on its balance sheet. The funded status of a defined benefit plan is its assets (if any) less its projected benefit obligation (PBO), which reflects service accrued to date and includes the impact of projected salary increases (for pay-related benefits). The funded status of a postretirement plan is its assets (if any) less its accumulated postretirement benefit obligation (APBO), which reflects accrued service to date. To the extent this obligation exceeds amounts previously recognized in the statement of income, the Company records a Regulatory asset for that portion related to its rate regulated utilities. To the extent that excess liability does not relate to a rate regulated utility, the offset is recorded as a reduction to equity in Accumulated other comprehensive income . The annual cost of all postretirement plans is recognized in operating expenses or capitalized to plant following the direct labor of current employees. Specific to pension plans, the Company uses the projected unit credit actuarial cost method to calculate service cost and the PBO. This method projects the present value of benefits at retirement and allocates that cost over the projected years of service. Annual service cost represents one year’s benefit accrual while the PBO represents benefits allocated to previously accrued service. For other postretirement plans, service cost is calculated by dividing the present value of a participant’s projected postretirement benefits into equal parts based upon the number of years between a participant’s hire date and first eligible retirement date. Annual service cost represents one year’s benefit accrual while the APBO represents benefit allocated to previously accrued service. To calculate the expected return on pension plan assets, the Company uses the plan assets’ market-related value and an expected long-term rate of return. For the majority of the Company’s pension plans, the fair market value of the assets at the balance sheet date is adjusted to a market-related value by recognizing the change in fair value experienced in a given year ratably over a five-year period. Interest cost represents the annual accretion of the PBO and APBO at the discount rate. Actuarial gains and losses outside of a corridor (equal to 10 percent of the greater of the benefit obligation and the market-related value of assets) are amortized over the expected future working lifetime of active participants (except for plans where almost all participants are inactive). Prior service costs related to plan changes are amortized over the expected future working lifetime (or to full eligibility date for postretirement plan other than pensions) of the active participants at the time of the amendment.
Asset Retirement Obligations	Asset Retirement Obligations A portion of removal costs related to interim retirements of gas utility pipeline and utility poles, certain asbestos-related issues, and reclamation activities 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.
Product Warranties, Performance Guarantees and Other Guarantees	Product Warranties, Performance Guarantees & Other Guarantees Liabilities and expenses associated with product warranties and performance guarantees are recognized based on historical experience at the time the associated revenue is recognized. Adjustments are made as changes become reasonably estimable. The Company does not recognize the fair value of an obligation at inception for these guarantees because they are guarantees of the Company’s own performance and/or product installations. While not significant for the periods presented, the Company does recognize the fair value of an obligation at the inception of a guarantee in certain circumstances. These circumstances would include executing certain indemnification agreements and guaranteeing operating lease residual values, the performance of a third party, or the indebtedness of a third party.
Energy Contracts and Derivatives	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, optimizing its generation assets, 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 Real Time and Day Ahead purchase and sale contracts with the MISO, natural gas purchases, and wind farm and other electric generating contracts. 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 when the contracts are expected to be settled. Contracts and any associated collateral with counter-parties subject to master netting arrangements are presented net in the Consolidated Balance Sheets . The offset resulting from carrying the derivative at fair value on the balance sheet is charged to earnings unless it qualifies as a hedge or is subject to regulatory accounting treatment. When hedge accounting is appropriate, the Company assesses and documents hedging relationships between the derivative contract and underlying risks as well as its risk management objectives and anticipated effectiveness. When the hedging relationship is highly effective, derivatives are designated as hedges. The market value of the effective portion of the hedge is marked to market in Accumulated other comprehensive income for cash flow hedges. Ineffective portions of hedging arrangements are marked to market through earnings. For fair value hedges, both the derivative and the underlying hedged item are marked to market through earnings. The offset to contracts affected by regulatory accounting treatment are marked to market as a regulatory asset or liability. Market value for derivative contracts is determined using quoted market prices from independent sources. The Company rarely enters into contracts that have a significant impact to the financial statements where internal models are used to calculate fair value. As of and for the periods presented, related derivative activity is not material to these financial statements.
Income Taxes	Income Taxes 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 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’s rate regulated utilities recognize 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. Production tax credits (PTCs) are recognized as energy is generated and sold based on a per kilowatt hour rate prescribed in applicable federal and state statutes.
Revenues	Revenues Most revenues are recognized as products and services are delivered to customers. Some nonutility revenues are recognized using the percentage of completion method. The Company records revenues for services and goods delivered but not billed at the end of an accounting period in Accrued unbilled revenues .
MISO Transactions	MISO Transactions With the IURC’s approval, the Company is a member of the MISO, a FERC approved regional transmission organization. The MISO serves the electrical transmission needs of much of the Midcontinent region and maintains operational control over the Company’s electric transmission facilities as well as that of other utilities in the region. The Company is an active participant in the MISO energy markets, bidding its owned generation into the Day Ahead and Real Time markets and procuring power for its retail customers at Locational Marginal Pricing (LMP) as determined by the MISO market. MISO-related purchase and sale transactions are recorded using settlement information provided by the MISO. These purchase and sale transactions are accounted for on a net hourly position. Net purchases in a single hour are recorded in Cost of fuel & purchased power and net sales in a single hour are recorded in Electric utility revenues . On occasion, prior period transactions are resettled outside the routine process due to a change in the MISO’s tariff or a material interpretation thereof. Expenses associated with resettlements are recorded once the resettlement is probable and the resettlement amount can be estimated. Revenues associated with resettlements are recognized when the amount is determinable and collectability is reasonably assured. The Company also receives transmission revenue that results from other members’ use of the Company’s transmission system. These revenues are also included in Electric utility revenues. Generally, these transmission revenues along with costs charged by the MISO are considered components of base rates and any variance from that included in base rates is recovered from / refunded to retail customers through tracking mechanisms.
Share-Based Compensation	Share-Based Compensation The Company grants share-based awards to certain employees and board members. Liability classified share-based compensation awards are re-measured at the end of each period based on an expected settlement date fair value. Equity classified share-based compensation awards are measured at the grant date, based on the fair value of the award. Expense associated with share-based awards is recognized over the requisite service period, which generally begins on the date the award is granted through the earlier of the date the award vests or the date the employee becomes retirement eligible.
Excise and Utility Receipts Taxes	Excise & Utility Receipts Taxes Excise taxes and 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 $28.3 million in 2016 , $29.4 million in 2015 , and $32.3 million in 2014 . Expense associated with excise and utility receipts taxes are recorded as a component of Taxes other than income taxes .
Operating Segments	Operating Segments The Company’s chief operating decision maker is the Chief Executive Officer. The Company uses net income calculated in accordance with generally accepted accounting principles as its most relevant performance measure. The Company has three operating segments within its Utility Group, three operating segments in its Nonutility Group, and a Corporate and Other segment.
Fair Value Measurements	Fair Value Measurements Certain assets and liabilities are valued and disclosed at fair value. Financial assets include securities held in trust by the Company’s pension plans. Nonfinancial assets and liabilities include the initial measurement of an asset retirement obligation or the use of fair value in goodwill, intangible assets, and long-lived assets impairment tests. FASB guidance provides the framework for measuring fair value. That framework provides a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of the fair value hierarchy are described as follows: Level 1 Inputs to the valuation methodology are unadjusted quoted prices for identical assets or liabilities in active markets that the Company has the ability to access. Level 2 Inputs to the valuation methodology include · quoted prices for similar assets or liabilities in active markets; · quoted prices for identical or similar assets or liabilities in inactive markets; · inputs other than quoted prices that are observable for the asset or liability; · inputs that are derived principally from or corroborated by observable market data by correlation or other means If the asset or liability has a specified (contractual) term, the Level 2 input must be observable for substantially the full term of the asset or liability. Level 3 Inputs to the valuation methodology are unobservable and significant to the fair value measurement. 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.

Utility & Nonutility Plant (Tab

Utility & Nonutility Plant (Tables)	12 Months Ended
	Dec. 31, 2016
Property, Plant and Equipment [Abstract]
Cost of Utility Plant, together with depreciation rates expressed as a percentage of original costs	The original cost of Utility Plant , together with depreciation rates expressed as a percentage of original cost, follows: At December 31, (In millions) 2016 2015 Original Cost Depreciation Rates as a Percent of Original Cost Original Cost Depreciation Rates as a Percent of Original Cost Gas utility plant $ 3,627.0 3.4 % $ 3,279.7 3.4 % Electric utility plant 2,799.1 3.4 % 2,695.8 3.3 % Common utility plant 56.3 3.2 % 55.0 3.2 % Construction work in progress 63.0 — 59.9 — Total original cost $ 6,545.4 $ 6,090.4
Nonutility Plant, Net of Depreciation and Amortization	Nonutility Plant , net of accumulated depreciation and amortization follows: At December 31, (In millions) 2016 2015 Computer hardware & software $ 121.8 $ 108.8 Land & buildings 77.9 86.4 Vehicles & equipment 207.4 203.0 All other 16.8 16.4 Nonutility plant - net $ 423.9 $ 414.6
Property, Plant and Equipment Disclosure [Text Block]	Utility & Nonutility Plant The original cost of Utility Plant , together with depreciation rates expressed as a percentage of original cost, follows: At December 31, (In millions) 2016 2015 Original Cost Depreciation Rates as a Percent of Original Cost Original Cost Depreciation Rates as a Percent of Original Cost Gas utility plant $ 3,627.0 3.4 % $ 3,279.7 3.4 % Electric utility plant 2,799.1 3.4 % 2,695.8 3.3 % Common utility plant 56.3 3.2 % 55.0 3.2 % Construction work in progress 63.0 — 59.9 — Total original cost $ 6,545.4 $ 6,090.4 SIGECO and Alcoa Generating Corporation (AGC), a subsidiary of Alcoa, Inc. (Alcoa), own a 300 MW unit at the Warrick Power Plant (Warrick Unit 4) as tenants in common. SIGECO's share of the cost of this unit at December 31, 2016 , is $190.4 million with accumulated depreciation totaling $110.8 million . AGC and SIGECO share equally in the cost of operation and output of the unit. SIGECO's share of operating costs is included in Other operating expenses in the Consolidated Statements of Income . In the first quarter of 2016, Alcoa closed its smelter operations. Historically, on-site generation owned and operated by AGC has been used to provide power to the smelter, as well as other mill operations, which will continue. Generation from Alcoa's share of the Warrick Unit 4 has historically been sold into the MISO market. The Company is actively working with Alcoa on plans related to continued operation of this generation. Nonutility Plant , net of accumulated depreciation and amortization follows: At December 31, (In millions) 2016 2015 Computer hardware & software $ 121.8 $ 108.8 Land & buildings 77.9 86.4 Vehicles & equipment 207.4 203.0 All other 16.8 16.4 Nonutility plant - net $ 423.9 $ 414.6 Nonutility Plant is presented net of accumulated depreciation and amortization totaling $460.8 million and $420.3 million as of December 31, 2016 and 2015 , respectively. For the years ended December 31, 2016 , 2015 , and 2014 , the Company capitalized interest totaling $1.0 million , $0.4 million , and $0.6 million , respectively, on nonutility plant construction projects. In 2016, the estimated depreciable lives for certain pieces of equipment at Minnesota Limited, LLC were reevaluated and extended due to a change in service life of the equipment. As a result of this evaluation, the Company extended the estimated useful life of certain pieces of equipment effective January 1 of the current year. The effect of this change in estimate was a reduction of annual depreciation expense of approximately $9.6 million in 2016.

Regulatory Assets & Liabiliti37

Regulatory Assets & Liabilities (Tables)	12 Months Ended
	Dec. 31, 2016
Regulatory Assets and Liabilities Disclosure [Abstract]
Schedule of Regulatory Assets	Regulatory assets consist of the following: At December 31, (In millions) 2016 2015 Future amounts recoverable from ratepayers related to: Benefit obligations (See Note 11) $ 102.6 $ 97.3 Net deferred income taxes (See Note 10) (17.1 ) (16.9 ) 85.5 80.4 Amounts deferred for future recovery related to: Cost recovery riders & other 91.6 54.6 91.6 54.6 Amounts currently recovered in customer rates related to: Loss on reacquired debt & hedging proceeds 24.1 25.8 Indiana authorized trackers 64.2 42.6 Deferred coal costs and other 21.2 28.3 Ohio authorized trackers 22.2 17.6 Other base rate recoveries — 0.1 131.7 114.4 Total regulatory assets $ 308.8 $ 249.4

ProLiance Holdings, LLC (Tables

ProLiance Holdings, LLC (Tables)	12 Months Ended
	Dec. 31, 2016
Equity Method Investments and Joint Ventures [Abstract]
Summarized Financial Information of Equity Investment [Table Text Block]	The Company's remaining investment at December 31, 2016 , shown at its 61 percent ownership share of the individual net assets of ProLiance, is as follows. As of December 31, (In millions) 2016 Cash $ 1.6 Investment in LA Storage 22.4 Other midstream asset investment 5.3 Total investment in ProLiance $ 29.3 Included in: Investments in unconsolidated affiliates 19.2 Other nonutility investments 10.1

Intangible Assets (Tables)

Intangible Assets (Tables)	12 Months Ended
	Dec. 31, 2016
Goodwill and Intangible Assets Disclosure [Abstract]
Intangible Assets	Intangible assets, which are included in Other assets , consist of the following: (In millions) At December 31, 2016 2015 Amortizing Non-amortizing Amortizing Non-amortizing Customer-related assets $ 20.9 $ — $ 23.1 $ — Market-related assets — 13.0 0.2 13.0 Intangible assets, net $ 20.9 $ 13.0 $ 23.3 $ 13.0

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Reconciliation of the federal statutory rate to the effective income tax rate	A reconciliation of the federal statutory rate to the effective income tax rate follows: Year Ended December 31, 2016 2015 2014 Statutory rate: 35.0 % 35.0 % 35.0 % State & local taxes-net of federal benefit 2.8 3.6 4.1 Amortization of investment tax credit (0.3 ) (0.2 ) (0.3 ) Depletion — — (2.6 ) Domestic production deduction (0.4 ) (1.0 ) (1.1 ) Energy efficiency building deductions (1.7 ) (2.3 ) (1.6 ) Research and development credit (0.6 ) (1.6 ) (0.3 ) Other tax credits (0.1 ) (0.1 ) (0.2 ) All other-net 0.1 0.2 (0.3 ) Effective tax rate 34.8 % 33.6 % 32.7 %
Significant components of the net deferred tax liability (assets)	Significant components of the net deferred tax liability follow: At December 31, (In millions) 2016 2015 Noncurrent deferred tax liabilities (assets): Depreciation & cost recovery timing differences $ 902.4 $ 827.6 Regulatory assets recoverable through future rates 17.6 31.6 Alternative minimum tax carryforward (29.3 ) (34.5 ) Employee benefit obligations (8.1 ) (9.3 ) Net operating loss & other carryforwards (3.2 ) (3.7 ) Regulatory liabilities to be settled through future rates (15.9 ) (29.9 ) Impairments (2.5 ) (3.0 ) Deferred fuel costs-net 25.9 14.2 Other-net 18.8 12.4 Net noncurrent deferred tax liability $ 905.7 $ 805.4
Components of income tax expense and utilization of investment tax credits	The components of income tax expense follow: Year Ended December 31, (In millions) 2016 2015 2014 Current: Federal $ 6.8 $ 10.8 $ 24.7 State 6.0 8.5 18.5 Total current taxes 12.8 19.3 43.2 Deferred: Federal 97.6 79.0 42.7 State 3.6 2.0 (4.2 ) Total deferred taxes 101.2 81.0 38.5 Amortization of investment tax credits (1.1 ) (0.6 ) (0.6 ) Total income tax expense $ 112.9 $ 99.7 $ 81.1

Retirement Plans & Other Post41

Retirement Plans & Other Postretirement Benefits (Tables)	12 Months Ended
	Dec. 31, 2016
Compensation and Retirement Disclosure [Abstract]
Summary of components of net periodic benefit cost	A summary of the components of net periodic benefit cost for the three years ended December 31, 2016 follows: Pension Benefits Other Benefits (In millions) 2016 2015 2014 2016 2015 2014 Service cost $ 7.0 $ 7.9 $ 7.4 $ 0.3 $ 0.4 $ 0.4 Interest cost 14.7 14.6 15.5 1.7 2.0 2.3 Expected return on plan assets (22.8 ) (22.5 ) (22.7 ) — — — Amortization of prior service cost (benefit) 0.4 0.7 1.0 (2.9 ) (3.0 ) (3.0 ) Amortization of actuarial loss 7.2 8.5 5.0 — 0.7 0.4 Settlement charge — 0.6 3.1 — — — Net periodic benefit cost (benefit) $ 6.5 $ 9.8 $ 9.3 $ (0.9 ) $ 0.1 $ 0.1
Schedule of assumptions used	The benefit obligation as of December 31, 2016 and 2015 was calculated using the following weighted average assumptions: Pension Benefits Other Benefits 2016 2015 2016 2015 Discount rate 4.07 % 4.31 % 4.04 % 4.21 % Rate of compensation increase 3.50 % 3.50 % N/A N/A Expected increase in Consumer Price Index N/A N/A 2.50 % 2.50 % The weighted averages of significant assumptions used to determine net periodic benefit costs follow: Pension Benefits Other Benefits 2016 2015 2014 2016 2015 2014 Discount rate 4.31 % 4.05 % 4.74 % 4.21 % 3.95 % 4.66 % Rate of compensation increase 3.50 % 3.50 % 3.50 % N/A N/A N/A Expected return on plan assets 7.50 % 7.50 % 7.75 % N/A N/A N/A Expected increase in Consumer Price Index N/A N/A N/A 2.50 % 2.50 % 2.75 %
Schedule of changes in projected benefit obligations	A reconciliation of the Company’s benefit obligations at December 31, 2016 and 2015 follows: Pension Benefits Other Benefits (In millions) 2016 2015 2016 2015 Benefit obligation, beginning of period $ 348.3 $ 371.9 $ 43.5 $ 53.3 Service cost – benefits earned during the period 7.0 7.9 0.3 0.4 Interest cost on projected benefit obligation 14.7 14.6 1.7 2.0 Plan participants' contributions — — 1.1 1.0 Plan amendments — 0.5 — — Actuarial loss (gain) 8.7 (17.0 ) (1.6 ) (8.6 ) Benefit payments (28.3 ) (27.9 ) (4.5 ) (4.6 ) Settlement payments — (1.7 ) — — Benefit obligation, end of period $ 350.4 $ 348.3 $ 40.5 $ 43.5
Schedule of changes in fair value of plan assets	A reconciliation of the Company’s plan assets at December 31, 2016 and 2015 follows: Pension Benefits Other Benefits (In millions) 2016 2015 2016 2015 Plan assets at fair value, beginning of period $ 296.9 $ 305.6 $ — $ — Actual return on plan assets 19.7 (2.0 ) — — Employer contributions 16.2 22.9 3.4 3.6 Plan participants' contributions — — 1.1 1.0 Benefit payments (28.3 ) (27.9 ) (4.5 ) (4.6 ) Settlement payments — (1.7 ) — — Fair value of plan assets, end of period $ 304.5 $ 296.9 $ — $ —
Fair values of pension and other retirement plan assets by category and fair value hierarchy	The fair values of the Company’s pension and other retirement plan assets at December 31, 2016 and December 31, 2015 by asset category and by fair value hierarchy are as follows: As of December 31, 2016 (In millions) Level 1 Level 2 Level 3 Total Domestic equities & equity funds $ 135.1 $ — $ — $ 135.1 International equities & equity funds 42.0 — — 42.0 Domestic bonds & bond funds 44.6 — — 44.6 Real estate, commodities & other 6.0 — 4.4 10.4 Investments measured at net asset value (a) — — — 72.4 Total plan investments $ 227.7 $ — $ 4.4 $ 304.5 As of December 31, 2015 (In millions) Level 1 Level 2 Level 3 Total Domestic equities & equity funds $ 113.5 $ — $ — $ 113.5 International equities & equity funds 38.2 — — 38.2 Domestic bonds & bond funds 36.6 — — 36.6 Real estate, commodities & other 4.8 — 4.3 9.1 Investments measured at net asset value (a) — — — 99.5 Total plan investments $ 193.1 $ — $ 4.3 $ 296.9
Schedule of effect of significant unobservable inputs, changes in plan assets	A roll forward of the fair value of the guaranteed annuity contract calculated using Level 3 valuation assumptions follows: (In millions) 2016 2015 Fair value, beginning of year $ 4.3 $ 4.2 Unrealized gains related to investments still held at reporting date 0.2 0.2 Purchases, sales & settlements, net (0.1 ) (0.1 ) Fair value, end of year $ 4.4 $ 4.3
Schedule of net funded status of plans	The funded status of the plans as of December 31, 2016 and 2015 follows: Pension Benefits Other Benefits (In millions) 2016 2015 2016 2015 Qualified Plans Benefit obligation, end of period $ (329.7 ) $ (328.7 ) $ (40.5 ) $ (43.5 ) Fair value of plan assets, end of period 304.5 296.9 — — Funded Status of Qualified Plans, end of period (25.2 ) (31.8 ) (40.5 ) (43.5 ) Benefit obligation of SERP Plan, end of period (20.6 ) (19.6 ) — — Total funded status, end of period $ (45.8 ) $ (51.4 ) $ (40.5 ) $ (43.5 ) Accrued liabilities $ 1.2 $ 1.2 $ 4.5 $ 4.6 Deferred credits & other liabilities $ 44.6 $ 50.2 $ 36.0 $ 38.9
Schedule of net periodic benefit cost not yet recognized	Following is a roll forward of prior service cost and actuarial gains and losses. Pensions Other Benefits (In millions) Prior Service Cost Net Gain or Loss Prior Service Cost Net Gain or Loss Balance at January 1, 2014 $ 3.0 $ 67.3 $ (20.1 ) $ 8.1 Amounts arising during the period — 49.4 — 3.2 Reclassification to benefit costs (1.0 ) (5.0 ) 3.0 (0.4 ) Balance at December 31, 2014 $ 2.0 $ 111.7 $ (17.1 ) $ 10.9 Amounts arising during the period 0.5 6.9 — (8.6 ) Reclassification to benefit costs (0.7 ) (8.5 ) 3.0 (0.7 ) Balance at December 31, 2015 $ 1.8 $ 110.1 $ (14.1 ) $ 1.6 Amounts arising during the period — 11.7 — (1.6 ) Reclassification to benefit costs (0.4 ) (7.2 ) 2.9 — Balance at December 31, 2016 $ 1.4 $ 114.6 $ (11.2 ) $ —
Reconciliation of the amounts in Accumulated other comprehensive income (AOCI) and Regulatory assets related to retirement plan obligations	Following is a reconciliation of the amounts in Accumulated other comprehensive income (AOCI) and Regulatory assets related to retirement plan obligations at December 31, 2016 and 2015 . (In millions) 2016 2015 Pensions Other Benefits Pensions Other Benefits Prior service cost $ 1.4 $ (11.2 ) $ 1.8 $ (14.1 ) Unamortized actuarial gain/(loss) 114.6 — 110.1 1.6 116.0 (11.2 ) 111.9 (12.5 ) Less: Regulatory asset deferral (113.6 ) 11.0 (109.6 ) 12.3 AOCI before taxes $ 2.4 $ (0.2 ) $ 2.3 $ (0.2 )
Schedule of Multiemployer Contributions In Current Year [Table Text Block]	The multiemployer contributions listed in the table below are the Company's multiemployer contributions made in 2016 , 2015 , and 2014 . (In millions) Pension Protection Act Zone Status Multiemployer Contributions Pension Fund EIN/Pension Plan Number 2016 2015 FIP/RP Status Pending/Implemented 2016 2015 2014 Surcharge Imposed Central Pension Fund 36-6052390-001 Green Green No $7.4 $7.2 $7.7 No Pipeline Industry Benefit Fund 73-0742835-001 Green Green No 3.0 4.0 5.1 No Indiana Laborers Pension Fund (1) 35-6027150-001 Yellow Yellow Implemented 4.4 4.1 3.5 No Ohio Operating Engineers Pension Fund 31-6129968-001 Green Green No 2.1 2.2 1.7 No Minnesota Laborers Pension Fund 41-6159599-001 Green Green No 1.2 1.8 2.2 No Laborers District Fund of Ohio 31-6129964-001 Green Green No 2.0 1.5 1.1 No Other 14.9 11.9 11.1 Total Contributions $35.0 $32.7 $32.4

Borrowing Arrangements (Tables)

Borrowing Arrangements (Tables)	12 Months Ended
	Dec. 31, 2016
Debt Disclosure [Abstract]
Short term borrowing arrangements	Utility Group Borrowings Nonutility Group Borrowings (In millions) 2016 2015 2014 2016 2015 2014 As of Year End Balance Outstanding $ 194.4 $ 14.5 $ 156.4 $ — $ — $ — Weighted Average Interest Rate 1.05 % 0.55 % 0.50 % N/A N/A N/A Annual Average Balance Outstanding $ 59.8 $ 53.8 $ 35.6 $ 0.2 $ 24.8 $ 34.5 Weighted Average Interest Rate 0.71 % 0.38 % 0.34 % 1.60 % 1.33 % 1.29 % Maximum Month End Balance Outstanding $ 194.4 $ 121.5 $ 156.4 $ 6.3 $ 69.1 $ 76.3
Long term senior unsecured obligations and first mortgage bonds outstanding by subsidiary	Long-term senior unsecured obligations and first mortgage bonds outstanding by subsidiary follow: At December 31, (In millions) 2016 2015 Utility Holdings Fixed Rate Senior Unsecured Notes 2018, 5.75% $ 100.0 $ 100.0 2020, 6.28% 100.0 100.0 2021, 4.67% 55.0 55.0 2023, 3.72% 150.0 150.0 2026, 5.02% 60.0 60.0 2028, 3.20% 45.0 45.0 2035, 6.10% 75.0 75.0 2035, 3.90% 25.0 25.0 2041, 5.99% 35.0 35.0 2042, 5.00% 100.0 100.0 2043, 4.25% 80.0 80.0 2045, 4.36% 135.0 135.0 2055, 4.51% 40.0 40.0 Total Utility Holdings 1,000.0 1,000.0 Indiana Gas Fixed Rate Senior Unsecured Notes 2025, Series E, 6.53% 10.0 10.0 2027, Series E, 6.42% 5.0 5.0 2027, Series E, 6.68% 1.0 1.0 2027, Series F, 6.34% 20.0 20.0 2028, Series F, 6.36% 10.0 10.0 2028, Series F, 6.55% 20.0 20.0 2029, Series G, 7.08% 30.0 30.0 Total Indiana Gas 96.0 96.0 SIGECO First Mortgage Bonds 2016, 1986 Series, 8.875% — 13.0 2022, 2013 Series C, 1.95%, tax-exempt 4.6 4.6 2024, 2013 Series D, 1.95%, tax-exempt 22.5 22.5 2025, 2014 Series B, current adjustable rate 1.045%, tax-exempt 41.3 41.3 2029, 1999 Series, 6.72% 80.0 80.0 2037, 2013 Series E, 1.95%, tax-exempt 22.0 22.0 2038, 2013 Series A, 4.00%, tax-exempt 22.2 22.2 2043, 2013 Series B, 4.05%, tax-exempt 39.6 39.6 2044, 2014 Series A, 4.00% tax-exempt 22.3 22.3 2055, 2015 Series Mt. Vernon, 2.375%, tax-exempt 23.0 23.0 2055, 2015 Series Warrick County, 2.375%, tax-exempt 15.2 15.2 Total SIGECO 292.7 305.7 At December 31, (In millions) 2016 2015 Vectren Capital Corp. Fixed Rate Senior Unsecured Notes 2016, 6.92% $ — $ 60.0 2017, 3.48% 75.0 75.0 2019, 7.30% 60.0 60.0 2022, 3.33% 75.0 75.0 2025, 4.53% 50.0 50.0 2030, 3.90% 75.0 75.0 Total Vectren Capital Corp. 335.0 395.0 Total long-term debt outstanding 1,723.7 1,796.7 Current maturities of long-term debt (124.1 ) (73.0 ) Debt issuance costs (9.0 ) (9.9 ) Unamortized debt premium & discount-net (0.7 ) (0.9 ) Total long-term debt-net $ 1,589.9 $ 1,712.9

Earnings Per Share (Tables)

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2016
Earnings Per Share [Abstract]
Basic and dilutive earnings per share calculation	The following table illustrates the basic and dilutive EPS calculations for the three years ended December 31, 2016 : Year Ended December 31, (In millions, except per share data) 2016 2015 2014 Numerator: Reported net income (Numerator for Diluted EPS) $ 211.6 $ 197.3 $ 166.9 Denominator: Weighted-average common shares outstanding (Basic and Diluted EPS) 82.8 82.7 82.5 Basic and diluted earnings per share $ 2.55 $ 2.39 $ 2.02

Accumulated Other Comprehensi44

Accumulated Other Comprehensive Income (Tables)	12 Months Ended
	Dec. 31, 2016
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]
Components and changes in accumulated other comprehensive income	A summary of the components of and changes in Accumulated other comprehensive income for the past three years follows: 2014 2015 2016 Beginning of Year Changes During End of Year Changes During End of Year Changes During End of Year (In millions) Balance Year Balance Year Balance Year Balance Pension & other benefit costs (1.2 ) (1.0 ) (2.2 ) 0.1 (2.1 ) (0.1 ) (2.2 ) Deferred income taxes 0.5 0.4 0.9 — 0.9 — 0.9 Accumulated other comprehensive income (loss) $ (0.7 ) $ (0.6 ) $ (1.3 ) $ 0.1 $ (1.2 ) $ (0.1 ) $ (1.3 )

Share-Based Compensation & De45

Share-Based Compensation & Deferred Compensation Arrangements (Tables)	12 Months Ended
	Dec. 31, 2016
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Reconciliation of total cost of share-based awards to the after tax effect on net income	Following is a reconciliation of the total cost associated with share-based awards recognized in the Company’s financial statements to its after tax effect on net income: Year Ended December 31, (In millions) 2016 2015 2014 Total cost of share-based compensation $ 30.0 $ 19.4 $ 25.2 Less capitalized cost 7.0 4.8 5.3 Total in other operating expense 23.0 14.6 19.9 Less income tax benefit in earnings 9.0 5.7 7.9 After tax effect of share-based compensation $ 14.0 $ 8.9 $ 12.0
Performance based units outstanding	A summary of the status of awards separated between those accounted for as liabilities and equity as of December 31, 2016 and 2015, and changes during the years ended December 31, 2016 and 2015, follow: Equity Awards Wtd. Avg. Grant Date Liability Awards Units Fair value Units Fair value Awards at January 1, 2015 34,273 $ 30.55 693,159 Granted 13,657 30.39 394,967 Vested (29,232 ) 29.87 (389,331 ) Forfeited (3,325 ) 30.95 (52,308 ) Awards at December 31, 2015 15,373 $ 31.63 646,487 $ 42.42 Granted 4,052 30.19 448,176 Vested (11,711 ) 30.19 (462,203 ) Forfeited (1,382 ) 31.87 (20,880 ) Awards at December 31, 2016 6,332 $ 33.42 611,580 $ 52.15

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2016
Fair Value Disclosures [Abstract]
Fair Value, by Balance Sheet Grouping [Table Text Block]	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 millions) Carrying Amount Est. Fair Value Carrying Amount Est. Fair Value Long-term debt $ 1,714.0 $ 1,835.8 $ 1,785.9 $ 1,899.6 Short-term borrowings & notes payable 194.4 194.4 14.5 14.5 Cash & cash equivalents 68.6 68.6 74.7 74.7 Restricted cash 0.9 0.9 5.9 5.9

Segment Reporting (Tables)

Segment Reporting (Tables)	12 Months Ended
	Dec. 31, 2016
Segment Reporting [Abstract]
Schedule of Segment Reporting Information, by Segment [Table Text Block]	Corporate and Other includes proceeds from life insurance policies offset by unallocated corporate expenses such as advertising and certain charitable contributions, among other activities, that benefit the Company’s other operating segments. Total assets in all periods presented reflect the retrospective impacts of the adoption in 2015 of ASU 2015-17, Balance Sheet Classification of Deferred Taxes and the retrospective impacts of the adoption in 2016 of ASU 2015-03, Presentation of Debt Issuance Costs. Net income is the measure of profitability used by management for all operations. Information related to the Company’s business segments is summarized as follows: Year Ended December 31, (In millions) 2016 2015 2014 Revenues Utility Group Gas Utility Services $ 771.7 $ 792.6 $ 944.6 Electric Utility Services 605.8 601.6 624.8 Other Operations 42.2 40.7 38.3 Eliminations (41.9 ) (40.4 ) (38.0 ) Total Utility Group 1,377.8 1,394.5 1,569.7 Nonutility Group Infrastructure Services 813.3 843.3 779.0 Energy Services 260.0 199.9 129.8 Coal Mining — — 234.3 Total Nonutility Group 1,073.3 1,043.2 1,143.1 Eliminations, net of Corporate & Other Revenues (2.8 ) (3.0 ) (101.1 ) Consolidated Revenues $ 2,448.3 $ 2,434.7 $ 2,611.7 Profitability Measures - Net Income Utility Group Net Income Gas Utility Services $ 76.1 $ 64.4 $ 57.0 Electric Utility Services 84.7 82.6 79.7 Other Operations 12.8 13.9 11.7 Total Utility Group Net Income 173.6 160.9 148.4 Nonutility Group Net Income (Loss) Infrastructure Services 25.0 29.7 43.1 Energy Services 12.5 7.3 (3.2 ) Coal Mining — — (21.1 ) Other Businesses (0.6 ) (0.7 ) (0.8 ) Total Nonutility Group Net Income 36.9 36.3 18.0 Corporate & Other Net Income 1.1 0.1 0.5 Consolidated Net Income $ 211.6 $ 197.3 $ 166.9 Year Ended December 31, (In millions) 2016 2015 2014 Amounts Included in Profitability Measures Depreciation & Amortization Utility Group Gas Utility Services $ 108.1 $ 98.6 $ 93.3 Electric Utility Services 87.1 85.6 85.7 Other Operations 23.9 24.6 24.1 Total Utility Group 219.1 208.8 203.1 Nonutility Group Infrastructure Services 38.2 44.5 36.2 Energy Services 2.5 2.7 3.9 Coal Mining — — 29.9 Other Businesses 0.2 0.3 0.3 Total Nonutility Group 40.9 47.5 70.3 Consolidated Depreciation & Amortization $ 260.0 $ 256.3 $ 273.4 Interest Expense Utility Group Gas Utility Services $ 40.1 $ 35.8 $ 34.9 Electric Utility Services 27.0 27.8 29.0 Other Operations 2.6 2.7 2.7 Total Utility Group 69.7 66.3 66.6 Nonutility Group Infrastructure Services 12.8 16.0 11.1 Energy Services 1.9 1.2 1.3 Coal Mining — — 7.5 Other Businesses 0.9 1.2 0.9 Total Nonutility Group 15.6 18.4 20.8 Corporate & Other 0.2 (0.2 ) (0.7 ) Consolidated Interest Expense $ 85.5 $ 84.5 $ 86.7 Income Taxes Utility Group Gas Utility Services $ 47.1 $ 40.8 $ 35.7 Electric Utility Services 50.1 49.3 48.1 Other Operations 2.3 (2.0 ) (0.6 ) Total Utility Group 99.5 88.1 83.2 Nonutility Group Infrastructure Services 17.9 19.6 28.9 Energy Services (3.5 ) (7.7 ) (7.8 ) Coal Mining — — (21.8 ) Other Businesses 0.3 1.5 (0.3 ) Total Nonutility Group 14.7 13.4 (1.0 ) Corporate & Other (1.3 ) (1.8 ) (1.1 ) Consolidated Income Taxes $ 112.9 $ 99.7 $ 81.1 Year Ended December 31, (In millions) 2016 2015 2014 Capital Expenditures Utility Group Gas Utility Services $ 358.5 $ 291.2 $ 245.9 Electric Utility Services 106.4 87.6 92.4 Other Operations 39.0 25.7 23.3 Non-cash costs & changes in accruals (7.1 ) (6.2 ) (10.9 ) Total Utility Group 496.8 398.3 350.7 Nonutility Group Infrastructure Services 43.2 78.1 54.1 Energy Services 1.8 0.5 1.6 Coal Mining — — 41.9 Other Businesses, net of eliminations 0.2 — — Total Nonutility Group 45.2 78.6 97.6 Consolidated Capital Expenditures $ 542.0 $ 476.9 $ 448.3 At December 31, (In millions) 2016 2015 2014 Assets Utility Group Gas Utility Services $ 3,091.0 $ 2,706.9 $ 2,604.6 Electric Utility Services 1,788.4 1,778.3 1,656.2 Other Operations, net of eliminations 161.5 107.5 148.5 Total Utility Group 5,040.9 4,592.7 4,409.3 Nonutility Group Infrastructure Services 513.9 554.5 538.5 Energy Services 182.7 160.3 87.1 Other Businesses, net of eliminations and reclassifications 53.3 64.0 120.3 Total Nonutility Group 749.9 778.8 745.9 Corporate & Other 628.4 742.4 654.9 Eliminations (618.5 ) (713.9 ) (672.3 ) Consolidated Assets $ 5,800.7 $ 5,400.0 $ 5,137.8

Additional Balance Sheet & Op48

Additional Balance Sheet & Operational Information (Tables)	12 Months Ended
	Dec. 31, 2016
Additional Balance Sheet and Operational Information [Abstract]
Summary of inventories	Inventories consist of the following: At December 31, (In millions) 2016 2015 Gas in storage – at LIFO cost $ 37.0 $ 40.5 Coal & oil for electric generation - at average cost 42.6 45.0 Materials & supplies 48.9 46.9 Other 1.4 1.3 Total inventories $ 129.9 $ 133.7
Summary of prepayments and other current assets	Prepayments & other current assets consist of the following: At December 31, (In millions) 2016 2015 Prepaid gas delivery service $ 26.4 $ 30.0 Prepaid taxes 8.2 25.3 Other prepayments & current assets 18.1 25.7 Total prepayments & other current assets $ 52.7 $ 81.0
Schedule of investments in unconsolidated affiliates	Investments in unconsolidated affiliates consist of the following: At December 31, (In millions) 2016 2015 ProLiance Holdings, LLC $ 19.2 $ 19.7 Other nonutility partnerships & corporations 1.0 1.0 Other utility investments 0.2 0.2 Total investments in unconsolidated affiliates $ 20.4 $ 20.9
Other utility and corporate investments in the consolidated balance sheets	Other utility & corporate investments consist of the following: At December 31, (In millions) 2016 2015 Cash surrender value of life insurance policies $ 33.1 $ 30.1 Restricted cash & other investments 1.0 1.1 Total other utility & corporate investments $ 34.1 $ 31.2
Goodwill by operating segment	Goodwill by operating segment follows: At December 31, (In millions) 2016 2015 Utility Group Gas Utility Services $ 205.0 $ 205.0 Nonutility Group Infrastructure Services 58.8 58.8 Energy Services 29.7 29.7 Consolidated goodwill $ 293.5 $ 293.5
Accrued Liabilities	Accrued liabilities consist of the following: At December 31, (In millions) 2016 2015 Refunds to customers & customer deposits $ 49.4 $ 51.4 Accrued taxes 46.5 39.9 Accrued interest 18.2 19.4 Deferred compensation & post-retirement benefits 6.6 7.2 Accrued salaries & other 87.0 65.7 Total accrued liabilities $ 207.7 $ 183.6
Asset retirement obligation	Asset retirement obligations included in Deferred credits and other liabilities in the Consolidated Balance Sheets roll forward as follows: (In millions) 2016 2015 Asset retirement obligation, January 1 $ 82.0 $ 55.0 Accretion 3.8 3.2 Liabilities incurred in current period — 24.2 Changes in estimates, net of cash payments 20.9 (0.4 ) Asset retirement obligation, December 31 106.7 82.0
Equity in earnings (losses) of unconsolidated affiliates	Equity in earnings (losses) of unconsolidated affiliates consists of the following: Year Ended December 31, (In millions) 2016 2015 2014 ProLiance Holdings, LLC $ (0.5 ) $ (0.8 ) $ (0.3 ) Other 0.3 0.2 0.8 Total equity in earnings (losses) of unconsolidated affiliates $ (0.2 ) $ (0.6 ) $ 0.5
Other, net in the consolidated statements of income	Other income (expense) – net consists of the following: Year Ended December 31, (In millions) 2016 2015 2014 AFUDC – borrowed funds $ 20.3 $ 16.3 $ 11.4 AFUDC – equity funds 2.2 2.6 3.2 Nonutility plant capitalized interest 1.0 0.4 — Interest income, net 1.3 1.3 1.1 Other nonutility investment impairment charges — (0.1 ) (1.0 ) All other income 3.9 (0.2 ) 5.0 Total other income (expense) – net $ 28.7 $ 20.3 $ 19.7
Supplemental cash flow information	Supplemental Cash Flow Information: Year Ended December 31, (In millions) 2016 2015 2014 Cash paid (received) for: Interest $ 86.6 $ 84.2 $ 87.5 Income taxes (3.6 ) 4.8 69.4

Quarterly Financial Data (Una49

Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2016
Quarterly Financial Information Disclosure [Abstract]
Summarized quarterly financial data	Information in any one quarterly period is not indicative of annual results due to the seasonal variations common to the Company’s utility operations. Summarized quarterly financial data for 2016 and 2015 follows: (In millions, except per share amounts) Q1 Q2 Q3 Q4 2016 Operating revenues $ 584.8 $ 533.7 $ 631.0 $ 699.0 Operating income 92.2 63.9 105.5 120.7 Net income 48.3 32.3 61.4 69.6 Earnings per share: Basic and Diluted $ 0.58 $ 0.39 $ 0.74 $ 0.84 2015 Operating revenues $ 706.2 $ 551.0 $ 573.5 $ 604.0 Operating income 106.1 72.9 79.9 103.0 Net income 57.0 35.8 39.3 65.2 Earnings per share: Basic and Diluted $ 0.69 $ 0.43 $ 0.48 $ 0.79

Organization and Nature of Op50

Organization and Nature of Operations (Details)	12 Months Ended
	Dec. 31, 2016
Number of public utility subsidiaries owned by wholly owned subsidiary, Vectren Utility Holdings, Inc. (in number of subsidiaries)	3
Natural Gas Customers [Member] | INDIANA | Indiana Gas [Member]
Approximate number of customers (in number of customers)	587,000
Natural Gas Customers [Member] | INDIANA | SIGECO [Member]
Approximate number of customers (in number of customers)	111,000
Natural Gas Customers [Member] | OHIO | Vectren Energy Delivery of Ohio [Member]
Approximate number of customers (in number of customers)	316,000
Electric Customers [Member] | INDIANA | SIGECO [Member]
Approximate number of customers (in number of customers)	144,000

Summary of Significant Accoun51

Summary of Significant Accounting Policies (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Accounting Policies [Abstract]
Excise taxes and a portion of utility receipts taxes	$ 28.3	$ 29.4	$ 32.3
Number of operating segments in Utility group	3
Number of operating segments in Nonutility group	4

Utility & Nonutility Plant (Det

Utility & Nonutility Plant (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)MW	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Utility & Nonutility Plant
Original Cost	$ 6,545.4	$ 6,090.4
Cost of Non-Utility plant, net of depreciation and amortization	423.9	414.6
Utility Group [Member]
Utility & Nonutility Plant
Original Cost	$ 6,545.4	6,090.4
Utility Group [Member] | Warrick Power Plant [Member]
Utility & Nonutility Plant
Size of Unit 4 Warrick Power Plant (in megawatts) | MW	300
Utility Group [Member] | Gas Utility Plant [Member]
Utility & Nonutility Plant
Original Cost	$ 3,627	$ 3,279.7
Depreciation Rates as a Percent of Original Cost (in hundredths)	3.40%	3.40%
Utility Group [Member] | Electric Utility Plant [Member]
Utility & Nonutility Plant
Original Cost	$ 2,799.1	$ 2,695.8
Depreciation Rates as a Percent of Original Cost (in hundredths)	3.40%	3.30%
Utility Group [Member] | Common Utility Plant [Member]
Utility & Nonutility Plant
Original Cost	$ 56.3	$ 55
Depreciation Rates as a Percent of Original Cost (in hundredths)	3.20%	3.20%
Utility Group [Member] | Construction Work in Progress [Member]
Utility & Nonutility Plant
Original Cost	$ 63	$ 59.9
Depreciation Rates as a Percent of Original Cost (in hundredths)	0.00%	0.00%
Utility Group [Member] | SIGECO [Member]
Utility & Nonutility Plant
Southern Indiana Gas And Electric Company's Share Of Cost Of Unit 4	$ 190.4
Southern Indiana Gas And Electric Company's Share Of Accumulated Depreciation Of Unit 4	110.8
Nonutility Group [Member]
Utility & Nonutility Plant
Cost of Non-Utility plant, net of depreciation and amortization	423.9	$ 414.6
Nonutility plant accumulated depreciation and amortization	460.8	420.3
Capitalized interest on nonutility plant construction projects	1	0.4	$ 0.6
Nonutility Group [Member] | Computer Hardware and Software [Member]
Utility & Nonutility Plant
Cost of Non-Utility plant, net of depreciation and amortization	121.8	108.8
Nonutility Group [Member] | Land and Buildings [Member]
Utility & Nonutility Plant
Cost of Non-Utility plant, net of depreciation and amortization	77.9	86.4
Nonutility Group [Member] | Vehicles and Equipment [Member]
Utility & Nonutility Plant
Cost of Non-Utility plant, net of depreciation and amortization	207.4	203
Nonutility Group [Member] | All Other [Member]
Utility & Nonutility Plant
Cost of Non-Utility plant, net of depreciation and amortization	16.8	$ 16.4
Change in Accounting Method Accounted for as Change in Estimate [Member] | Infastructure Services [Member] | Nonutility Group [Member]
Utility & Nonutility Plant
Depreciation	$ 9.6

Regulatory Assets & Liabiliti53

Regulatory Assets & Liabilities (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Regulatory Assets [Line Items]
Regulatory assets	$ 308.8	$ 249.4
Regulatory Assets Currently Being Recovered in Base Rates	$ 24
Weighted average recovery period of regulatory assets currently being recovered (in years)	24
Regulatory Liabilities [Abstract]
Regulatory liabilities	$ 453.7	433.9
Future Amounts Recoverable From Ratepayers [Member]
Regulatory Assets [Line Items]
Regulatory assets	85.5	80.4
Future Amounts Recoverable From Ratepayers [Member] | Deferred Income Taxes [Member]
Regulatory Assets [Line Items]
Regulatory Liabilities	(17.1)	(16.9)
Future Amounts Recoverable From Ratepayers [Member] | Benefit Obligations [Member]
Regulatory Assets [Line Items]
Regulatory assets	102.6	97.3
Amounts Deferred for Future Recovery [Member]
Regulatory Assets [Line Items]
Regulatory assets	91.6	54.6
Amounts Deferred for Future Recovery [Member] | Cost Recovery Riders Other [Member]
Regulatory Assets [Line Items]
Regulatory assets	91.6	54.6
Amounts Currently Recovered in Customer Rates [Member]
Regulatory Assets [Line Items]
Regulatory assets	131.7	114.4
Amounts Currently Recovered in Customer Rates [Member] | Unamortized Debt Issue Costs, Reaquisition Premiums and Hedging Proceeds [Member]
Regulatory Assets [Line Items]
Regulatory assets	24.1	25.8
Amounts Currently Recovered in Customer Rates [Member] | Indiana Authorized Trackers [Member]
Regulatory Assets [Line Items]
Regulatory assets	64.2	42.6
Amounts Currently Recovered in Customer Rates [Member] | Deferred Coal Costs [Member]
Regulatory Assets [Line Items]
Regulatory assets	21.2	28.3
Amounts Currently Recovered in Customer Rates [Member] | Ohio Authorized Trackers [Member]
Regulatory Assets [Line Items]
Regulatory assets	22.2	17.6
Amounts Currently Recovered in Customer Rates [Member] | Other Base Rate Recoveries [Member]
Regulatory Assets [Line Items]
Regulatory assets	$ 0	$ 0.1

Federal Business Unit Acquisi54

Federal Business Unit Acquisition Federal Business Unit Acquisition (Details) - USD ($) $ in Millions	Apr. 01, 2014	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Business Acquisition [Line Items]
Effective Date of Acquisition	Apr. 1, 2014
Amount of Transaction Costs in Other Cost and Expense, Operating		$ 932.2	$ 909.2	$ 943.4
Federal Business Unit [Member]
Business Acquisition [Line Items]
Business Combination, Liabilities Arising from Contingencies, Amount Recognized				14.8
Total Purchase Consideration				42.1
Transaction Costs				1.7
Amount of Transaction Costs in Other Cost and Expense, Operating				0.8	$ 0.9
Pro Forma Revenue				$ 17.7

Sale of Vectren Fuels, Inc. (De

Sale of Vectren Fuels, Inc. (Details) - USD ($) $ in Millions	3 Months Ended									12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Sep. 30, 2014	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash received at closing										$ 0	$ 0	$ 311.2
Net income (loss)	$ 69.6	$ 61.4	$ 32.3	$ 48.3	$ 65.2	$ 39.3	$ 35.8	$ 57		$ 211.6	$ 197.3	166.9
Vectren Fuels, Inc. [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash received at closing									$ 311
Disposal Group, Including Discontinued Operation, Other Expense												42
Disposal Group, Including Discontinued Operation, Depreciation and Amortization												10
Net income (loss)												$ (21.1)

ProLiance Holdings, LLC (Detail

ProLiance Holdings, LLC (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Equity Method Investment, Ownership Percentage	61.00%
Equity Method Investment, Voting and Governance Rights	50.00%
Summarized balance sheet information [Abstract]
Investments in unconsolidated affiliates	$ 20.4	$ 20.9
Other nonutility investments	16.1	16.2
ProLiance Holdings, LLC [Member]
Summarized balance sheet information [Abstract]
Equity method investment, summarized financial information, cash	1.6
Equity method investment,summarized financial information, storage assets	22.4
Equity method investment, summarized financial information, other asset investment	5.3
Equity method investment, gross investment in equity method investee	29.3
Investments in unconsolidated affiliates	19.2
Other nonutility investments	10.1
LA Storage [Member] | ProLiance Holdings, LLC [Member]
Equity Method Investments	$ 36.7	$ 36.4
LA Storage [Member] | Affiliated Entity [Member]
Equity Method Investment, Ownership Percentage	25.00%
LA Storage [Member] | Corporate Joint Venture [Member]
Combined Joint Venture Ownership Percentage	100.00%

Nonutility Real Estate & Othe57

Nonutility Real Estate & Other Legacy Holdings (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Investments by type [Abstract]
Other nonutility investments	$ 16.1	$ 16.2
Nonutility Group [Member]
Investments by type [Abstract]
Other nonutility investments	1.9
Held-to-maturity Securities	$ 5.1

Intangible Assets (Details)

Intangible Assets (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Indefinite-lived Intangible Assets [Line Items]
Non-amortizing	$ 13	$ 13
Finite-Lived Intangible Assets [Line Items]
Amortizing	$ 20.9	23.3
Weighted average remaining life for amortizing customer-related assets and all amortizing intangibles (in years)	11 years
Amortization expense	$ 2.5	3.1	$ 2.8
Amortization expense - year one	2.6
Amortization expense - year two	2.6
Amortization expense - year three	2.6
Amortization expense - year four	2.6
Amortization expense - year five	2.6
Customer Related Assets [Member]
Indefinite-lived Intangible Assets [Line Items]
Non-amortizing	0	0
Market Related Assets [Member]
Indefinite-lived Intangible Assets [Line Items]
Non-amortizing	13	13
Customer Related Assets [Member]
Finite-Lived Intangible Assets [Line Items]
Amortizing	20.9	23.1
Accumulated amortization	12	9.8
Market Related Assets [Member]
Finite-Lived Intangible Assets [Line Items]
Amortizing	0	0.2
Accumulated amortization	$ 4.5	$ 4.3

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Reconciliation of the federal statutory rate to the effective income tax rate [Abstract]
Statutory rate: (in hundredths)	35.00%	35.00%	35.00%
State and local taxes-net of federal benefit (in hundredths)	2.80%	3.60%	4.10%
Amortization of investment tax credit (in hundredths)	(0.30%)	(0.20%)	(0.30%)
Depletion (in hundredths)	0.00%	0.00%	(2.60%)
Domestic production deduction (in hundredths)	(0.40%)	(1.00%)	(1.10%)
Energy efficiency building deductions (in hundredths)	(1.70%)	(2.30%)	(1.60%)
Research and development credit (in hundredths)	(0.60%)	(1.60%)	(0.30%)
Other tax credits (in hundredths)	(0.10%)	(0.10%)	(0.20%)
All other-net (in hundredths)	0.10%	0.20%	(0.30%)
Effective tax rate (in hundredths)	34.80%	33.60%	32.70%
Noncurrent deferred tax liabilities (assets) [Abstract]
Depreciation and cost recovery timing differences	$ 902.4	$ 827.6
Regulatory assets recoverable through future rates	17.6	31.6
Alternative minimum tax carryforward	(29.3)	(34.5)
Employee benefit obligations	(8.1)	(9.3)
Net operating loss and other carryforwards	(3.2)	(3.7)
Regulatory liabilities to be settled through future rates	(15.9)	(29.9)
Impairments	(2.5)	(3)
Deferred fuel costs-net	25.9	14.2
Other - net	18.8	12.4
Net noncurrent deferred tax liability	905.7	805.4
Investment tax credits	$ 1.6	4.1
Remaining life of NOL's and business credit carryforwards (in years)	5 to 20 years
Operating Loss Carryforwards, Valuation Allowance	$ 8.3	8.1
Current: [Abstract]
Federal	6.8	10.8	$ 24.7
State	6	8.5	18.5
Total current taxes	12.8	19.3	43.2
Deferred: [Abstract]
Federal	97.6	79	42.7
State	3.6	2	(4.2)
Total deferred taxes	101.2	81	38.5
Amortization of investment tax credits	(1.1)	(0.6)	(0.6)
Total income tax expense	112.9	99.7	$ 81.1
Uncertain tax positions [Abstract]
Net liability for unrecognized tax benefits inclusive of interest, penalties and net of secondary impacts which are a component of the deferred income taxes and are benefits	$ 1.2	$ 0.9

Retirement Plans & Other Post60

Retirement Plans & Other Postretirement Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2012	Dec. 31, 2016	Dec. 31, 2015
Multiemployer Plans [Line Items]
Approximate number of unions the Company contributed to on behalf of employees	280
Average contributions to each union	.2
Largest union multiemployer plan contribution	$ 2.9
Expense for the Multiemployer Benefit plan	35	$ 32.7	$ 32.4
Net periodic benefit costs [Abstract]
Portion of benefit costs capitalized as Utility plant	1.9	3.1	2.8
Plan Assets [Roll Forward]
Plan assets at fair value, beginning of period [Roll Forward]	296.9
Fair value of plan assets, end of period	304.5	296.9
Fair Value of guaranteed annuity contract [Roll Forward]
Guaranteed Annuity Contract - estimate of undiscounted funds necessary to satisfy John Hancock's remaining obligation					$ 4	$ 3.9
Guaranteed Annuity Contract - percent of composite investment return, net of manger fees and other charges (in hundredths)					3.60%	3.65%
Fair value, beginning of year	4.3	4.2
Unrealized gains related to investments still held at reporting date	0.2	0.2
Purchases, sales and settlements, net	(0.1)	(0.1)
Fair value, end of year	4.4	4.3
Qualified Plans
Fair value of plan assets, end of period	296.9	296.9			$ 304.5	$ 296.9
Payments expected to be made to SERP participants in the next fiscal year					1.2
Reconciliation of amounts in Accumulated other comprehensive income and Regulatory assets
Less: Regulatory asset deferral					308.8	249.4
Defined Contribution Plan [Abstract]
Contributions to Defined Contribution Plan	12.1	11	9.1
Domestic equities and equity funds [Member]
Plan Assets [Roll Forward]
Plan assets at fair value, beginning of period [Roll Forward]	113.5
Fair value of plan assets, end of period	135.1	113.5
Qualified Plans
Fair value of plan assets, end of period	113.5	113.5			135.1	113.5
International equities and equity funds [Member]
Plan Assets [Roll Forward]
Plan assets at fair value, beginning of period [Roll Forward]	38.2
Fair value of plan assets, end of period	42	38.2
Qualified Plans
Fair value of plan assets, end of period	38.2	38.2			42	38.2
Domestic bonds and bond funds [Member]
Plan Assets [Roll Forward]
Plan assets at fair value, beginning of period [Roll Forward]	36.6
Fair value of plan assets, end of period	44.6	36.6
Qualified Plans
Fair value of plan assets, end of period	36.6	36.6			44.6	36.6
Real estate, commodities and other [Member]
Plan Assets [Roll Forward]
Plan assets at fair value, beginning of period [Roll Forward]	9.1
Fair value of plan assets, end of period	10.4	9.1
Qualified Plans
Fair value of plan assets, end of period	9.1	9.1			10.4	9.1
Investments Measured at Net Asset Value [Member]
Plan Assets [Roll Forward]
Plan assets at fair value, beginning of period [Roll Forward]	99.5
Fair value of plan assets, end of period	72.4	99.5
Qualified Plans
Fair value of plan assets, end of period	99.5	99.5			$ 72.4	99.5
Central Pension Fund [Member]
Multiemployer Plans [Line Items]
Expense for the Multiemployer Benefit plan	7.4	7.2	7.7
Pipeline Industry Benefit Fund [Member]
Multiemployer Plans [Line Items]
Expense for the Multiemployer Benefit plan	3	4	5.1
Indiana Laborers Pension Fund [Member]
Multiemployer Plans [Line Items]
Expense for the Multiemployer Benefit plan	4.4	4.1	3.5
Multiemployer Plan, Funded Ratio					72.00%
Ohio Operating Engineers Pension Fund [Member]
Multiemployer Plans [Line Items]
Expense for the Multiemployer Benefit plan	2.1	2.2	1.7
Minnesota Laborers Pension Fund [Member]
Multiemployer Plans [Line Items]
Expense for the Multiemployer Benefit plan	1.2	1.8	2.2
Laborers District Fund of Ohio [Member]
Multiemployer Plans [Line Items]
Expense for the Multiemployer Benefit plan	2	1.5	1.1
Other Pension Funds [Member]
Multiemployer Plans [Line Items]
Expense for the Multiemployer Benefit plan	14.9	11.9	11.1
Fair Value, Inputs, Level 1 [Member]
Plan Assets [Roll Forward]
Plan assets at fair value, beginning of period [Roll Forward]	193.1
Fair value of plan assets, end of period	227.7	193.1
Qualified Plans
Fair value of plan assets, end of period	193.1	193.1			$ 227.7	193.1
Fair Value, Inputs, Level 1 [Member] | Domestic equities and equity funds [Member]
Plan Assets [Roll Forward]
Plan assets at fair value, beginning of period [Roll Forward]	113.5
Fair value of plan assets, end of period	135.1	113.5
Qualified Plans
Fair value of plan assets, end of period	113.5	113.5			135.1	113.5
Fair Value, Inputs, Level 1 [Member] | International equities and equity funds [Member]
Plan Assets [Roll Forward]
Plan assets at fair value, beginning of period [Roll Forward]	38.2
Fair value of plan assets, end of period	42	38.2
Qualified Plans
Fair value of plan assets, end of period	38.2	38.2			42	38.2
Fair Value, Inputs, Level 1 [Member] | Domestic bonds and bond funds [Member]
Plan Assets [Roll Forward]
Plan assets at fair value, beginning of period [Roll Forward]	36.6
Fair value of plan assets, end of period	44.6	36.6
Qualified Plans
Fair value of plan assets, end of period	36.6	36.6			44.6	36.6
Fair Value, Inputs, Level 1 [Member] | Real estate, commodities and other [Member]
Plan Assets [Roll Forward]
Plan assets at fair value, beginning of period [Roll Forward]	4.8
Fair value of plan assets, end of period	6	4.8
Qualified Plans
Fair value of plan assets, end of period	4.8	4.8			6	4.8
Fair Value, Inputs, Level 1 [Member] | Investments Measured at Net Asset Value [Member]
Plan Assets [Roll Forward]
Plan assets at fair value, beginning of period [Roll Forward]	0
Fair value of plan assets, end of period	0	0
Qualified Plans
Fair value of plan assets, end of period	0	0			$ 0	0
Fair Value, Inputs, Level 2 [Member]
Plan Assets [Roll Forward]
Plan assets at fair value, beginning of period [Roll Forward]	0
Fair value of plan assets, end of period	0	0
Common Collective Trust Funds [Abstract]
Maximum number of days restriction for exchange of shares in Common Collective Trust Funds (in days)					31
Qualified Plans
Fair value of plan assets, end of period	0	0			$ 0	0
Fair Value, Inputs, Level 2 [Member] | Domestic equities and equity funds [Member]
Plan Assets [Roll Forward]
Plan assets at fair value, beginning of period [Roll Forward]	0
Fair value of plan assets, end of period	0	0
Qualified Plans
Fair value of plan assets, end of period	0	0			0	0
Fair Value, Inputs, Level 2 [Member] | International equities and equity funds [Member]
Plan Assets [Roll Forward]
Plan assets at fair value, beginning of period [Roll Forward]	0
Fair value of plan assets, end of period	0	0
Qualified Plans
Fair value of plan assets, end of period	0	0			0	0
Fair Value, Inputs, Level 2 [Member] | Domestic bonds and bond funds [Member]
Plan Assets [Roll Forward]
Plan assets at fair value, beginning of period [Roll Forward]	0
Fair value of plan assets, end of period	0	0
Qualified Plans
Fair value of plan assets, end of period	0	0			0	0
Fair Value, Inputs, Level 2 [Member] | Real estate, commodities and other [Member]
Plan Assets [Roll Forward]
Plan assets at fair value, beginning of period [Roll Forward]	0
Fair value of plan assets, end of period	0	0
Qualified Plans
Fair value of plan assets, end of period	0	0			0	0
Fair Value, Inputs, Level 2 [Member] | Investments Measured at Net Asset Value [Member]
Plan Assets [Roll Forward]
Plan assets at fair value, beginning of period [Roll Forward]	0
Fair value of plan assets, end of period	0	0
Qualified Plans
Fair value of plan assets, end of period	0	0			0	0
Fair Value, Inputs, Level 3 [Member]
Plan Assets [Roll Forward]
Plan assets at fair value, beginning of period [Roll Forward]	4.3
Fair value of plan assets, end of period	4.4	4.3
Qualified Plans
Fair value of plan assets, end of period	4.3	4.3			4.4	4.3
Fair Value, Inputs, Level 3 [Member] | Domestic equities and equity funds [Member]
Plan Assets [Roll Forward]
Plan assets at fair value, beginning of period [Roll Forward]	0
Fair value of plan assets, end of period	0	0
Qualified Plans
Fair value of plan assets, end of period	0	0			0	0
Fair Value, Inputs, Level 3 [Member] | International equities and equity funds [Member]
Plan Assets [Roll Forward]
Plan assets at fair value, beginning of period [Roll Forward]	0
Fair value of plan assets, end of period	0	0
Qualified Plans
Fair value of plan assets, end of period	0	0			0	0
Fair Value, Inputs, Level 3 [Member] | Domestic bonds and bond funds [Member]
Plan Assets [Roll Forward]
Plan assets at fair value, beginning of period [Roll Forward]	0
Fair value of plan assets, end of period	0	0
Qualified Plans
Fair value of plan assets, end of period	0	0			0	0
Fair Value, Inputs, Level 3 [Member] | Real estate, commodities and other [Member]
Plan Assets [Roll Forward]
Plan assets at fair value, beginning of period [Roll Forward]	4.3
Fair value of plan assets, end of period	4.4	4.3
Qualified Plans
Fair value of plan assets, end of period	4.3	4.3			4.4	4.3
Fair Value, Inputs, Level 3 [Member] | Investments Measured at Net Asset Value [Member]
Plan Assets [Roll Forward]
Plan assets at fair value, beginning of period [Roll Forward]	0
Fair value of plan assets, end of period	0	0
Qualified Plans
Fair value of plan assets, end of period	$ 0	0			$ 0	$ 0
Multiemployer Plans, Pension [Member]
Multiemployer Plans [Line Items]
Number of multiemployer plans contributed to	60
Defined benefit plan, number of significant plans	6
Number of plans in red zone status receiving company contributions	9
Number of plans in red zone status considered significant by the Company	2
Number of plans whereby company contributions exceed 5% of plan balance	7
Percentage threshold by which plan contributions are considered significant					5.00%
Other Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Other Information	3
Net periodic benefit costs [Abstract]
Service cost	$ 7	7.9	7.4
Interest cost	14.7	14.6	15.5
Defined Benefit Plan, Expected Return on Plan Assets	(22.8)	(22.5)	(22.7)
Amortization of prior service cost (benefit)	0.4	0.7	1
Amortization of actuarial loss (gain)	7.2	8.5	5
Settlement (credit) charge	0	0.6	3.1
Net periodic benefit cost	$ 6.5	$ 9.8	$ 9.3
Discount Rate (in hundredths)	4.31%	4.05%	4.74%
Rate of compensation increase (in hundredths)	3.50%	3.50%	3.50%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets	7.50%	7.50%	7.75%
Expected return on plan assets (in hundredths)	7.00%
Assumptions used to calculate benefit obligations [Abstract]
Discount rate (in hundredths)					4.07%	4.31%
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Rate of Compensation Increase					3.50%	3.50%
Benefit Obligation [Roll Forward]
Benefit obligation, beginning of period	$ 348.3	$ 371.9
Service cost - benefits earned during the period	7	7.9	$ 7.4
Interest cost on projected benefit obligation	14.7	14.6	15.5
Plan participants' contributions	0	0
Plan amendments	0	0.5
Actuarial loss (gain)	8.7	(17)
Benefit payments	(28.3)	(27.9)
Defined Benefit Plan, Settlements, Benefit Obligation	0	(1.7)
Benefit obligation, end of period	350.4	348.3	371.9
Accumulated benefit obligation for all defined benefit pension plans					$ 339.8	$ 336.1
Plan Assets [Roll Forward]
Plan assets at fair value, beginning of period [Roll Forward]	296.9	305.6
Actual return on plan assets	19.7	(2)
Employer contributions	16.2	22.9
Plan participants' contributions	0	0
Benefit payments	(28.3)	(27.9)
Settlement payments	0	(1.7)
Fair value of plan assets, end of period	304.5	296.9	305.6
Qualified Plans
Benefit obligation, end of period					(329.7)	(328.7)
Fair value of plan assets, end of period	296.9	305.6	305.6		304.5	296.9
Funded Status of Qualified Plans					(25.2)	(31.8)
Benefit obligation of SERP Plan, end of period					(20.6)	(19.6)
Total funded status, end of period					(45.8)	(51.4)
Accrued liabilities					1.2	1.2
Deferred credits and other liabilities					44.6	50.2
Estimated future benefit payments [Abstract]
Expected future benefit payments, year one					26.3
Expected future benefit payments, year two					38
Expected future benefit payments, year three					26.8
Expected future benefit payments, year four					29.1
Expected future benefit payments, year five					26.6
Expected future benefit payments, years six through ten					132.4
Prior service costs [Roll Forward]
Balance, beginning of year	1.8	2	3
Amounts arising during the period	0	0.5	0
Reclassification to benefit costs	(0.4)	(0.7)	(1)
Balance, end of year	1.4	1.8	2
Net gain or loss [Roll Forward]
Balance, beginning of year	110.1	111.7	67.3
Amounts arising during the period	11.7	6.9	49.4
Reclassification to benefit costs	(7.2)	(8.5)	(5)
Balance, end of year	114.6	110.1	111.7
Reconciliation of amounts in Accumulated other comprehensive income and Regulatory assets
Prior service cost	1.8	2	3		1.4	1.8
Unamortized actuarial gain/(loss)	110.1	111.7	67.3		114.6	110.1
Sub total					116	111.9
Less: Regulatory asset deferral					113.6	109.6
AOCI before taxes					$ 2.4	$ 2.3
Amounts that will be amortized from Accumulated Other Comprehensive Income (Loss) in next year [Abstract]
Prior service cost expected to be amortized in next year	0.4
Actuarial gain/loss expected to be amortized in next year	$ 7.6
Other Pension Plans, Defined Benefit [Member] | Real estate, commodities and other [Member]
Plan Assets [Roll Forward]
Target percentage of investments in equity instruments (in hundredths)	3.00%
Other Pension Plans, Defined Benefit [Member] | Equity Securities [Member]
Plan Assets [Roll Forward]
Target percentage of investments in equity instruments (in hundredths)	62.00%
Other Pension Plans, Defined Benefit [Member] | Debt Securities [Member]
Plan Assets [Roll Forward]
Target percentage of investments in equity instruments (in hundredths)	35.00%
Other Postretirement Benefit Plans, Defined Benefit [Member]
Net periodic benefit costs [Abstract]
Service cost	$ 0.3	0.4	0.4
Interest cost	1.7	2	2.3
Defined Benefit Plan, Expected Return on Plan Assets	0	0	0
Amortization of prior service cost (benefit)	(2.9)	(3)	(3)
Amortization of actuarial loss (gain)	0	0.7	0.4
Settlement (credit) charge	0	0	0
Net periodic benefit cost	$ (0.9)	$ 0.1	$ 0.1
Discount Rate (in hundredths)	4.21%	3.95%	4.66%
Expected increase in Consumer Price Index (in hundredths)	2.50%	2.50%	2.75%
Assumptions used to calculate benefit obligations [Abstract]
Discount rate (in hundredths)					4.04%	4.21%
Expected increase in Consumer Price Index (in hundredths)					2.50%	2.50%
Benefit Obligation [Roll Forward]
Benefit obligation, beginning of period	$ 43.5	$ 53.3
Service cost - benefits earned during the period	0.3	0.4	$ 0.4
Interest cost on projected benefit obligation	1.7	2	2.3
Plan participants' contributions	1.1	1
Plan amendments	0	0
Actuarial loss (gain)	(1.6)	(8.6)
Benefit payments	(4.5)	(4.6)
Defined Benefit Plan, Settlements, Benefit Obligation	0	0
Benefit obligation, end of period	$ 40.5	43.5	53.3
Assumption of percentage increase in medical claims cost for next fiscal year (in hundredths)	5.50%
Ultimate trending increase of medical claims cost (in hundredths)	5.00%			8.00%
Year that rate reaches ultimate trend rate					2,018
Dollar impact of a one-percentage point change in assumed health care cost trend rates	$ 0.2
Plan Assets [Roll Forward]
Plan assets at fair value, beginning of period [Roll Forward]	0	0
Actual return on plan assets	0	0
Employer contributions	3.4	3.6
Plan participants' contributions	1.1	1
Benefit payments	(4.5)	(4.6)
Settlement payments	0	0
Fair value of plan assets, end of period	0	0	0
Qualified Plans
Benefit obligation, end of period					$ (40.5)	$ (43.5)
Fair value of plan assets, end of period	0	0	0		0	0
Funded Status of Qualified Plans					(40.5)	(43.5)
Benefit obligation of SERP Plan, end of period					0	0
Total funded status, end of period					(40.5)	(43.5)
Accrued liabilities					4.5	4.6
Deferred credits and other liabilities					36	38.9
Other postretirement benefit payments to be made during the next fiscal year					3.1
Estimated future benefit payments [Abstract]
Expected future benefit payments, year one					4.5
Expected future benefit payments, year two					4.6
Expected future benefit payments, year three					4.7
Expected future benefit payments, year four					5
Expected future benefit payments, year five					5.1
Expected future benefit payments, years six through ten					24
Prior service costs [Roll Forward]
Balance, beginning of year	(14.1)	(17.1)	(20.1)
Amounts arising during the period	0	0	0
Reclassification to benefit costs	2.9	3	3
Balance, end of year	(11.2)	(14.1)	(17.1)
Net gain or loss [Roll Forward]
Balance, beginning of year	1.6	10.9	8.1
Amounts arising during the period	(1.6)	(8.6)	3.2
Reclassification to benefit costs	0	(0.7)	(0.4)
Balance, end of year	0	1.6	10.9
Reconciliation of amounts in Accumulated other comprehensive income and Regulatory assets
Prior service cost	(14.1)	(17.1)	(20.1)		(11.2)	(14.1)
Unamortized actuarial gain/(loss)	1.6	$ 10.9	$ 8.1		0	1.6
Sub total					(11.2)	(12.5)
Less: Regulatory asset deferral					11	12.3
AOCI before taxes					$ (0.2)	$ (0.2)
Amounts that will be amortized from Accumulated Other Comprehensive Income (Loss) in next year [Abstract]
Prior service cost expected to be amortized in next year	(2.4)
Actuarial gain/loss expected to be amortized in next year	$ 0

Borrowing Arrangements (Details

Borrowing Arrangements (Details) - USD ($)

Jun. 01, 2016

Mar. 11, 2016

Dec. 29, 2015

Dec. 21, 2015

Dec. 15, 2015

Dec. 01, 2015

Mar. 15, 2015

Mar. 11, 2014

Sep. 30, 2014

Dec. 31, 2016

Dec. 31, 2015

Sep. 09, 2015

Dec. 31, 2014

Sep. 24, 2014

Jun. 30, 2013

Jun. 01, 1986

Long term debt [Abstract]

Total long term debt outstanding

$ 1,723,700,000

$ 1,796,700,000

Current maturities of long-term debt

(124,100,000)

(73,000,000)

Debt Issuance Costs, Net

(9,000,000)

(9,900,000)

Unamortized debt premium and discount - net

(700,000)

(900,000)

Long-term debt - net of current maturities and debt subject to tender

1,589,900,000

1,712,900,000

Short-term borrowings

194,400,000

14,500,000

Maturities of long term debt [Abstract]

Debt maturing within 12 months following date of latest balance sheet

124,000,000

Debt maturing within two years following date of latest balance sheet

100,000,000

Debt maturing within three years following date of latest balance sheet

60,000,000

Debt maturing within four years following date of latest balance sheet

100,000,000

Debt maturing within five years following date of latest balance sheet

55,000,000

Debt maturing thereafter 5 years following date of the latest balance sheet

$ 1,275,000,000

Covenants [Abstract]

Debt to consolidated total capitalization - maximum ratio

65.00%

Nonutility Group [Member]

Long term debt [Abstract]

Short-term borrowings

$ 0

0

$ 0

Utility Holdings [Member]

Long term debt [Abstract]

Long-term Debt

996,000,000

Short-term borrowings

194,000,000

Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member]

Long term debt [Abstract]

Total long term debt outstanding

1,000,000,000

1,000,000,000

Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2015, 5.45% [Member]

Long term debt [Abstract]

Extinguishment of Debt, Amount

$ 75,000,000

Fixed rate stated percentage (in hundredths)

5.45%

Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2018, 5.75% [Member]

Long term debt [Abstract]

Total long term debt outstanding

100,000,000

100,000,000

Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2020, 6.28% [Member]

Long term debt [Abstract]

Total long term debt outstanding

100,000,000

100,000,000

Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2021, 4.67 [Member]

Long term debt [Abstract]

Total long term debt outstanding

55,000,000

55,000,000

Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2023, 3.72% [Member]

Long term debt [Abstract]

Total long term debt outstanding

150,000,000

150,000,000

Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2026, 5.02% [Member]

Long term debt [Abstract]

Total long term debt outstanding

60,000,000

60,000,000

Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2028, 3.20% [Member]

Long term debt [Abstract]

Total long term debt outstanding

45,000,000

45,000,000

Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2035, 6.10% [Member]

Long term debt [Abstract]

Total long term debt outstanding

75,000,000

75,000,000

Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2035,3.90% [Member]

Long term debt [Abstract]

Debt Issuance

$ 25,000,000

Fixed rate stated percentage (in hundredths)

3.90%

Total long term debt outstanding

25,000,000

25,000,000

Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2041, 5.99% [Member]

Long term debt [Abstract]

Total long term debt outstanding

35,000,000

35,000,000

Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2042, 5.00% [Member]

Long term debt [Abstract]

Total long term debt outstanding

100,000,000

100,000,000

Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2043, 4.25% [Member]

Long term debt [Abstract]

Total long term debt outstanding

80,000,000

80,000,000

Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2045,4.36% [Member]

Long term debt [Abstract]

Debt Issuance

$ 135,000,000

Fixed rate stated percentage (in hundredths)

4.36%

Total long term debt outstanding

135,000,000

135,000,000

Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2055,4.51% [Member]

Long term debt [Abstract]

Debt Issuance

$ 40,000,000

Fixed rate stated percentage (in hundredths)

4.51%

Total long term debt outstanding

40,000,000

40,000,000

Indiana Gas [Member] | Fixed Rate Senior Unsecured Notes [Member]

Long term debt [Abstract]

Total long term debt outstanding

96,000,000

96,000,000

Indiana Gas [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2015, Series E, 7.15% [Member]

Long term debt [Abstract]

Extinguishment of Debt, Amount

$ 5,000,000

Fixed rate stated percentage (in hundredths)

7.15%

Indiana Gas [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2015, Series E, 6.69% [Member]

Long term debt [Abstract]

Extinguishment of Debt, Amount

$ 5,000,000

Fixed rate stated percentage (in hundredths)

6.69%

Indiana Gas [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2015, Series E1, 6.69% [Member]

Long term debt [Abstract]

Extinguishment of Debt, Amount

$ 10,000,000

Fixed rate stated percentage (in hundredths)

6.69%

Indiana Gas [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2025, Series E, 6.53% [Member]

Long term debt [Abstract]

Total long term debt outstanding

10,000,000

10,000,000

Indiana Gas [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2027, Series E, 6.42% [Member]

Long term debt [Abstract]

Total long term debt outstanding

5,000,000

5,000,000

Indiana Gas [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2027, Series E, 6.68% [Member]

Long term debt [Abstract]

Total long term debt outstanding

1,000,000

1,000,000

Indiana Gas [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2027, Series F, 6.34% [Member]

Long term debt [Abstract]

Total long term debt outstanding

20,000,000

20,000,000

Indiana Gas [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2028, Series F, 6.36% [Member]

Long term debt [Abstract]

Total long term debt outstanding

10,000,000

10,000,000

Indiana Gas [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2028, Series F, 6.55% [Member]

Long term debt [Abstract]

Total long term debt outstanding

20,000,000

20,000,000

Indiana Gas [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2029, Series G, 7.08% [Member]

Long term debt [Abstract]

Total long term debt outstanding

30,000,000

30,000,000

SIGECO [Member] | Mortgages [Member]

Long term debt [Abstract]

Extinguishment of Debt, Amount

$ 63,600,000

Debt Issuance

$ 63,600,000

Total long term debt outstanding

292,700,000

305,700,000

Financial Instruments Subject to Mandatory Redemption, Settlement Terms, Maximum Amount

$ 87,300,000

Future long term debt sinking fund fund requirements and maturities [Abstract]

Annual sinking fund requirement fixed percentage (in hundredths)

1.00%

Utility plant remaining unfunded under mortgage indenture

$ 1,400,000,000

Gross utility plant balance subject to the mortgage indenture

3,300,000,000

SIGECO [Member] | Mortgages [Member] | Bonds subject to mandatory tender in September 2020 [Member]

Long term debt [Abstract]

Financial Instruments Subject to Mandatory Redemption, Settlement Terms, Maximum Amount

38,200,000

SIGECO [Member] | Mortgages [Member] | 2016, 1986 Series, 8.875% [Member]

Long term debt [Abstract]

Extinguishment of Debt, Amount

$ 13,000,000

Debt Issuance

$ 25,000,000

Fixed rate stated percentage (in hundredths)

8.875%

Total long term debt outstanding

0

13,000,000

SIGECO [Member] | Mortgages [Member] | 2022, 2013 Series C, 1.95% tax exempt [Member]

Long term debt [Abstract]

Total long term debt outstanding

4,600,000

4,600,000

SIGECO [Member] | Mortgages [Member] | 2024, 2013 Series D, 1.95% tax exempt [Member]

Long term debt [Abstract]

Total long term debt outstanding

22,500,000

22,500,000

SIGECO [Member] | Mortgages [Member] | 2025, 2014 Series B, 1.045% tax exempt [Member]

Long term debt [Abstract]

Debt Issuance

41,300,000

Total long term debt outstanding

41,300,000

41,300,000

Financial Instruments Subject to Mandatory Redemption, Settlement Terms, Maximum Amount

41,300,000

SIGECO [Member] | Mortgages [Member] | 2029, 1999 Senior Notes, 6.72% [Member]

Long term debt [Abstract]

Total long term debt outstanding

80,000,000

80,000,000

SIGECO [Member] | Mortgages [Member] | 2037, 2013 Series E 1.95% Tax Exempt [Member]

Long term debt [Abstract]

Total long term debt outstanding

22,000,000

22,000,000

SIGECO [Member] | Mortgages [Member] | 2038, 2013 Series A, 4.00% Tax Exempt [Member]

Long term debt [Abstract]

Total long term debt outstanding

22,200,000

22,200,000

SIGECO [Member] | Mortgages [Member] | 2043, 2013 Series B 4.05% Tax Exempt [Member]

Long term debt [Abstract]

Total long term debt outstanding

39,600,000

39,600,000

SIGECO [Member] | Mortgages [Member] | 2044, 2014 Series A 4.00% Tax Exempt [Member]

Long term debt [Abstract]

Debt Issuance

$ 22,300,000

Fixed rate stated percentage (in hundredths)

4.00%

Total long term debt outstanding

22,300,000

22,300,000

SIGECO [Member] | Mortgages [Member] | Environmental Improvement Revenue Bonds, Mount Vernon, 2055, 2.375%, Series 2015 [Member]

Long term debt [Abstract]

Total long term debt outstanding

23,000,000

23,000,000

SIGECO [Member] | Mortgages [Member] | Environmental Improvement Revenue Bonds, Warrick County, 2055, 2.375%, Series 2015 [Member]

Long term debt [Abstract]

Total long term debt outstanding

15,200,000

15,200,000

SIGECO [Member] | Mortgages [Member] | Bonds subject to mandatory tender in September 2017 [Member]

Long term debt [Abstract]

Financial Instruments Subject to Mandatory Redemption, Settlement Terms, Maximum Amount

49,100,000

SIGECO [Member] | Mortgages [Member] | Environmental Improvement Revenue Bonds, Warrick County, 2055, 2.375%, Series 2015 [Member]

Long term debt [Abstract]

Debt Issuance

$ 15,200,000

Fixed rate stated percentage (in hundredths)

2.375%

SIGECO [Member] | Mortgages [Member] | Environmental Improvement Revenue Bonds, Mount Vernon, 2055, 2.375%, Series 2015 [Member]

Long term debt [Abstract]

Debt Issuance

$ 23,000,000

Fixed rate stated percentage (in hundredths)

2.375%

Vectren Capital Corp. [Member]

Long term debt [Abstract]

Long-term Debt

334,000,000

Short-term borrowings

0

Vectren Capital Corp. [Member] | Fixed Rate Senior Unsecured Notes [Member]

Long term debt [Abstract]

Total long term debt outstanding

335,000,000

395,000,000

Vectren Capital Corp. [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2015, 5.31% [Member]

Long term debt [Abstract]

Extinguishment of Debt, Amount

$ 75,000,000

Fixed rate stated percentage (in hundredths)

5.31%

Vectren Capital Corp. [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2016, 6.92% [Member]

Long term debt [Abstract]

Extinguishment of Debt, Amount

$ 60,000,000

Fixed rate stated percentage (in hundredths)

6.92%

Total long term debt outstanding

0

60,000,000

Vectren Capital Corp. [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2017, 3.48% [Member]

Long term debt [Abstract]

Total long term debt outstanding

75,000,000

75,000,000

Vectren Capital Corp. [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2019, 7.30% [Member]

Long term debt [Abstract]

Total long term debt outstanding

60,000,000

60,000,000

Vectren Capital Corp. [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2022, 3.33% [Member]

Long term debt [Abstract]

Debt Issuance

$ 75,000,000

Fixed rate stated percentage (in hundredths)

3.33%

Total long term debt outstanding

75,000,000

75,000,000

Vectren Capital Corp. [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2025, 4.53% [Member]

Long term debt [Abstract]

Total long term debt outstanding

50,000,000

50,000,000

Vectren Capital Corp. [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2030,3.90% [Member]

Long term debt [Abstract]

Debt Issuance

$ 75,000,000

Fixed rate stated percentage (in hundredths)

3.90%

Total long term debt outstanding

$ 75,000,000

$ 75,000,000

Vectren Capital Corp. [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2014, 6.37% [Member]

Long term debt [Abstract]

Extinguishment of Debt, Amount

$ 30,000,000

Fixed rate stated percentage (in hundredths)

6.37%

Borrowing Arrangements Short-Te

Borrowing Arrangements Short-Term Borrowings (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Short-term borrowings [Abstract]
Short-term borrowing capacity	$ 600
Balance Outstanding, end of period	194.4	$ 14.5
Utility Group [Member]
Short-term borrowings [Abstract]
Short-term borrowing capacity	350
Short term borrowings available	156
Balance Outstanding, end of period	$ 194.4	$ 14.5	$ 156.4
Weighted Average Interest Rate, end of period (in hundredths)	1.05%	0.55%	0.50%
Balance Outstanding, annual average	$ 59.8	$ 53.8	$ 35.6
Weighted Average Interest Rate, annual average (in hundredths)	0.71%	0.38%	0.34%
Maximum Month End Balance Outstanding	$ 194.4	$ 121.5	$ 156.4
Nonutility Group [Member]
Short-term borrowings [Abstract]
Short-term borrowing capacity	250
Short term borrowings available	250
Balance Outstanding, end of period	0	0	0
Balance Outstanding, annual average	$ 0.2	$ 24.8	$ 34.5
Weighted Average Interest Rate, annual average (in hundredths)	1.60%	1.33%	1.29%
Maximum Month End Balance Outstanding	$ 6.3	$ 69.1	$ 76.3

Common Shareholder's Equity (De

Common Shareholder's Equity (Details) - shares shares in Millions	Dec. 31, 2016	Dec. 31, 2015
Authorized, reserved common and preferred shares [Abstract]
Common stock, shares authorized for issue (in shares)	480	480
Preferred stock , shares authorized for issue (in shares)	20	20
Authorized shares of common stock available for issuance (in shares)	392.5	392.1
Authorized shares of preferred stock available for issuance (in shares)	20	20
Number of shares reserved for issuance under share-based compensation plans, benefit plans, and dividend reinvestment plan	4.6	5.1

Earnings Per Share (Details)

Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Earnings Per Share [Abstract]
Reported net income (Numerator for diluted earnings per share)									$ 211.6	$ 197.3	$ 166.9
Weighted average common shares outstanding (Basic earnings per share) (in shares)									82.8	82.7	82.5
Adjusted weighted average shares outstanding and assumed conversions outstanding (Diluted earnings per share) (in shares)									82.8	82.7	82.5
Earnings Per Share, Basic	$ 0.84	$ 0.74	$ 0.39	$ 0.58	$ 0.79	$ 0.48	$ 0.43	$ 0.69	$ 2.55	$ 2.39	$ 2.02

Accumulated Other Comprehensi65

Accumulated Other Comprehensive Income (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Accumulated Other Comprehensive Income (Loss) [Line Items]
Balance, beginning of period	$ (1.2)	$ (1.3)	$ (0.7)
Changes during period	(0.1)	0.1	(0.6)
Balance, end of period	(1.3)	(1.2)	(1.3)
Deferred Income Taxes [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Balance, beginning of period	0.9	0.9	0.5
Changes during period	0	0	0.4
Balance, end of period	0.9	0.9	0.9
Pension and Other Benefit Costs [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Balance, beginning of period	(2.1)	(2.2)	(1.2)
Changes during period	(0.1)	0.1	(1)
Balance, end of period	$ (2.2)	$ (2.1)	$ (2.2)

Share-Based Compensation & De66

Share-Based Compensation & Deferred Compensation Arrangements (Details) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)$ / sharesshares	Dec. 31, 2015USD ($)$ / sharesshares	Dec. 31, 2014USD ($)$ / sharesshares
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Total cost of share-based compensation	$ 30	$ 19.4	$ 25.2
Less capitalized cost	7	4.8	5.3
Total in other operating expense	23	14.6	19.9
Less income tax benefit in earnings	9	5.7	7.9
After tax effect of share-based compensation	$ 14	$ 8.9	$ 12
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period for performance-based awards to executives and key non-officer employees (in years)	4
Performance Measurement Time Frame For Grants To Executives And Key Nonofficer Emplyees In Years	third
Upper range of share based awards that may potentially be taken in cash (in units)	100,000	100,000	100,000
Total unrecognized compensation cost related to performance based awards	$ 14.8
Weighted-average life of unrecognized compensation cost (in years)	1 year 4 months
Deferred Compensation Plans [Abstract]
Liability associated with deferred compensation plans	$ 40.9	$ 31.2
Portion of liability classified in Accrued liabilities	0.9	1.4
Impact of deferred compensation plans on Other operating expenses	4.3	0.1	$ 5
Amount recorded in earnings related to the investment activities in phantom stock associated with deferred compensation plans	3.8	(0.4)	4
Cash surrender value of life insurance policies	33.1	30.1
Earnings (loss) from investments in corporate-owned life insurance policies	$ 3.5	(2.1)	2.8
Performance Based Units Equity Method [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period for awards to certain non-utility employees (in years)	5
Total fair value of equity awards vested	$ 0.6	$ 1.1	$ 0.9
Share Based Payment Award Equity Instruments Other Than Options [Roll Forward]
Performance based awards at beginning of period (in shares) | shares	15,373	34,273
Granted (in shares) | shares	4,052	13,657
Vested (in shares) | shares	(11,711)	(29,232)
Forfeited (in shares) | shares	(1,382)	(3,325)
Performance based awards at end of period (in shares) | shares	6,332	15,373	34,273
Weighted average grant date fair value at beginning of period (in dollars per share) | $ / shares	$ 31.63	$ 30.55
Weighted average grant date fair value of shares granted during period (in dollars per share) | $ / shares	30.19	30.39
Weighted average grant date fair value of shares vested during period (in dollars per share) | $ / shares	30.19	29.87
Weighted average grant date fair value of shares forfeited during period (in dollars per share) | $ / shares	31.87	30.95
Weighted average grant date fair value at end of period (in dollars per share) | $ / shares	$ 33.42	$ 31.63	$ 30.55
Performance Based Units Liability Method [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period for time-vested awards to non-officer employees (in years)	3
Vesting period for awards to non-employee directors (in years)	1
Total fair value of liability awards vested	$ 23.7	$ 16.6	$ 15.1
Share Based Payment Award Equity Instruments Other Than Options [Roll Forward]
Performance based awards at beginning of period (in shares) | shares	646,487	693,159
Granted (in shares) | shares	448,176	394,967
Vested (in shares) | shares	(462,203)	(389,331)
Forfeited (in shares) | shares	(20,880)	(52,308)
Performance based awards at end of period (in shares) | shares	611,580	646,487	693,159
Weighted average grant date fair value at beginning of period (in dollars per share) | $ / shares	$ 42.42
Weighted average grant date fair value at end of period (in dollars per share) | $ / shares	$ 52.15	$ 42.42

Commitments and Contingencies (

Commitments and Contingencies (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Commitments [Abstract]
Future minimum operating lease payments due within one year of the balance sheet date	$ 9.8
Future minimum operating lease payments due within the second year of the balance sheet date	7.3
Future minimum operating lease payments due within the third year of the balance sheet date	4.4
Future minimum operating lease payments due within the fourth year of the balance sheet date	2.1
Future minimum operating lease payments due within the fifth year of the balance sheet date	1.8
Future minimum operating lease payments due within after the fifth year of the balance sheet date	3.9
Operating Leases, Rent Expense	13	$ 11.1	$ 13.2
Performance Guarantees and Product Warranties [Abstract]
Product Warranty Accrual		$ 0
Energy Systems Group [Member]
Corporate Guarantees [Abstract]
Maximum exposure by parent company on guarantees.	$ 319
Energy Systems Group [Member] | Performance Guarantee [Member]
Performance Guarantees and Product Warranties [Abstract]
Number of surety bonds wholly owned subsidiary has outstanding in role as general contractor (in number of surety bonds)	54
Performance Guarantee Obligations Outstanding Face Amount	$ 10.6
Percentage Of Work Yet to be Completed On Projects With Open Surety Bonds	43.00%
Timeframe when significant portion of performance guarantee commitments will be fulfilled	within one year
Energy Systems Group [Member] | Maximum [Member] | Performance Guarantee [Member]
Performance Guarantees and Product Warranties [Abstract]
Performance Guarantee Obligations Outstanding Face Amount	$ 75.9

Gas Rate & Regulatory Matters (

Gas Rate & Regulatory Matters (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)$ / customer
Public Utilities, General Disclosures [Line Items]
Regulatory assets	$ 308.8	$ 249.4
INDIANA | Indiana Recovery and Deferral Mechanisms [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory assets	$ 21.9	19.9
Length of project plan required for recovery under new legislation	7 years
INDIANA | Senate Bill 251 and 560 [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory assets	$ 51.1	28.6
Percentage of costs eligible for recovery using periodic rate recovery mechanism	80.00%
Percentage of project costs to be deferred for future recovery	20.00%
Amount of projects not approved for recovery	$ 80
Amount of single project excluded from recovery	65
Payments for capital improvements	338
Capital Expenditure Increases	60
Total Capital Expenditures Under Seven Year Plan	950
INDIANA | SIGECO [Member] | Indiana Recovery and Deferral Mechanisms [Member]
Public Utilities, General Disclosures [Line Items]
Allowable capital expenditures under Vectren programs	$ 3
Limitations of deferrals of debt-related post in service carrying costs	3
INDIANA | Indiana Gas [Member] | Indiana Recovery and Deferral Mechanisms [Member]
Public Utilities, General Disclosures [Line Items]
Allowable capital expenditures under Vectren programs	$ 20
Limitations of deferrals of debt-related post in service carrying costs	4
OHIO | Ohio Recovery and Deferral Mechanisms [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory assets	$ 24.4	18.2
Payments for capital improvements	259.6	204
OHIO | Ohio Recovery and Deferral Mechanisms [Member] | Maximum [Member]
Public Utilities, General Disclosures [Line Items]
Amount of Capital Investment Expected Over Next Five Years Recoverable Under DRR	120
OHIO | Ohio Recovery and Deferral Mechanisms [Member] | Minimum [Member]
Public Utilities, General Disclosures [Line Items]
Amount of Capital Investment Expected Over Next Five Years Recoverable Under DRR	100
OHIO | Ohio House Bill95 [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory assets	$ 41.9	$ 24.1
Bill impact per customer per month | $ / customer		1.50

Electric Rate and Regulatory 69

Electric Rate and Regulatory Matters (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Amount of capital investments to date in equipment for mercury control	$ 30
Regulatory assets	308.8	$ 249.4
Electric Domestic Regulated Revenue	$ 605.8	601.6	$ 624.8
FERC Return On Equity Complaint [Abstract]
Current return on equity used in MISO transmission owners rates	12.38%
Reduced return on equity percentage sought by third party through joint complaint	9.15%
FERC authorized base ROE percentage for first refund period	10.32%
FERC authorized base ROE percentage for second refund period	9.70%
Number of incentive basis point above the FERC approved ROE	50
Gross Investment In Qualifying Transmission Projects	$ 157.7
Net Investment in Qualifying Transmission Projects	136.8
Electric Modernization Program - SB 560 [Member]
Total Capital Expenditures Under Seven Year Plan	$ 500
Length of project plan required for recovery under new legislation	7 years
Renewable Generation - SB 29 [Member]
Estimated Capital Expenditures Under Project Plan	$ 15
SIGECO Electric Environmental Compliance Filing [Member]
Amount of capital investments to date in equipment for mercury control	30
Amount of capital investments to date in equipment to control sulfur trioxide emissions	40
SIGECO Electric Environmental Compliance Filing [Member] | Depreciation, property taxes and operating expense [Member]
Regulatory assets	6.9
SIGECO Electric Environmental Compliance Filing [Member] | Post-in service carrying costs [Member]
Regulatory assets	2.8
Estimated cost of equipment to comply with MATS	30
Estimated cost of equipment required by the NOV	$ 40
Electric Demand Side Management Program [Member]
Number of Years in Initial Demand Side Management Program	3 years
Electric Domestic Regulated Revenue	$ 11.1	$ 10.1	$ 8.7
Maximum period for recovery under energy efficiency program	4 years

Environmental Matters (Details)

Environmental Matters (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)MW	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Site Contingency [Line Items]
Amount approved for capital investments on coal-fired generation units	$ 70
Amount of capital investments to date in equipment for mercury control	$ 30
Air Quality [Abstract]
Percentage of coal fired generating fleet currently being scrubbed for SO2 (in hundredths)	100.00%
Percentage of coal fired generating fleet currently controlled for NOx (in hundredths)	90.00%
Coal Ash Waste Disposal, Ash Ponds and Water [Abstract]
Asset Retirement Obligation	$ 106.7	$ 82	$ 55
Estimated spend for ash pond dam reinforcement and other operational changes	$ 17
Climate Changes [Abstract]
Vectren's share of Indiana's CO2 emissions in 2013 (as a percent)	6.00%
Percent reduction of Vectren's CO2 emissions since 2005		31.00%
Long term contract for purchase of electric power generated by wind energy (in megawatts) | MW	80
Percentage of total electricity obtained by the supplier to meet the energy needs of its retail customers provided by clean energy sources (in hundredths)	4.00%
Vectren's emission rate (as measured in lbs CO2/MWh) prior to installation of new technology		1,967
Vectren's emission rate (as measured in lbs CO2/MWh) after installation of new technology		1,922
Percentage reduction of lbs CO2/MWh since 2005		3.00%
Manufactured Gas Plants
Environmental Remediation Expense	$ 44.2
Accrual for Environmental Loss Contingencies Included In Other Liabilities	$ 2.9	$ 3.3
Indiana Gas [Member]
Manufactured Gas Plants
Number of sites identified with potential remedial responsibility for entity (in number of sites)	26
Environmental Remediation Expense	$ 23.9
Insurance Recoveries	$ 20.8
SIGECO [Member]
Manufactured Gas Plants
Number of sites identified with potential remedial responsibility for entity (in number of sites)	5
Environmental Remediation Expense	$ 20.3
Insurance Recoveries	15.2
Total estimated insurance recoveries	15.8
SIGECO [Member] | Ash Ponds [Member]
Coal Ash Waste Disposal, Ash Ponds and Water [Abstract]
Asset Retirement Obligation	40
Minimum [Member]
Coal Ash Waste Disposal, Ash Ponds and Water [Abstract]
Estimated capital expenditures to comply with Clean Water Act	4
Ash Pond and Coal Ash Disposal Exit Costs Initial Anticipated Cost	35
Ash Pond and Coal Ash Disposal Exit Costs Revised Anticipated Cost	45
Maximum [Member]
Coal Ash Waste Disposal, Ash Ponds and Water [Abstract]
Estimated capital expenditures to comply with Clean Water Act	8
Ash Pond and Coal Ash Disposal Exit Costs Initial Anticipated Cost	80
Ash Pond and Coal Ash Disposal Exit Costs Revised Anticipated Cost	$ 100

Fair Value Measurements (Detail

Fair Value Measurements (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Notes receivable included in Other Nonutility Investments, Fair Value Disclosure	$ 16.1	$ 16.1
Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	1,714	1,785.9
Short-term borrowings	194.4	14.5
Cash and cash equivalents	68.6	74.7
Restricted cash	0.9	5.9
Estimated Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	1,835.8	1,899.6
Short-term borrowings	194.4	14.5
Cash and cash equivalents	68.6	74.7
Restricted cash	$ 0.9	$ 5.9

Segment Reporting (Details)

Segment Reporting (Details) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2016USD ($)	Sep. 30, 2016USD ($)	Jun. 30, 2016USD ($)	Mar. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Sep. 30, 2015USD ($)	Jun. 30, 2015USD ($)	Mar. 31, 2015USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Additions									$ 542	$ 476.9	$ 448.3
Number of reporting segments	3								3
Number of operating segments in the Nonutility Group	4								4
Portion Of Indiana That Is Provided Natural Gas Distribution And Transportation Services By Gas Utility Services Segment	66.66667%								66.66667%
Revenues	$ 699	$ 631	$ 533.7	$ 584.8	$ 604	$ 573.5	$ 551	$ 706.2	$ 2,448.3	2,434.7	2,611.7
Net income (loss)	69.6	$ 61.4	$ 32.3	$ 48.3	65.2	$ 39.3	$ 35.8	$ 57	211.6	197.3	166.9
Amounts Included in Profitability Measures [Abstract]
Depreciation and Amortization									260	256.3	273.4
Interest Expense									85.5	84.5	86.7
Income Taxes									112.9	99.7	81.1
Assets	5,800.7				5,400				5,800.7	5,400	5,137.8
Utility Group [Member]
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Additions									496.8	398.3	350.7
Revenues									1,377.8	1,394.5	1,569.7
Net income (loss)									173.6	160.9	148.4
Amounts Included in Profitability Measures [Abstract]
Depreciation and Amortization									219.1	208.8	203.1
Interest Expense									69.7	66.3	66.6
Income Taxes									99.5	88.1	83.2
Assets	5,040.9				4,592.7				5,040.9	4,592.7	4,409.3
Related Party Transaction, Expenses from Transactions with Related Party									117.8	109.5	94
Utility Group [Member] | Gas Utility Services [Member]
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Additions									358.5	291.2	245.9
Revenues									771.7	792.6	944.6
Net income (loss)									76.1	64.4	57
Amounts Included in Profitability Measures [Abstract]
Depreciation and Amortization									108.1	98.6	93.3
Interest Expense									40.1	35.8	34.9
Income Taxes									47.1	40.8	35.7
Assets	3,091				2,706.9				3,091	2,706.9	2,604.6
Utility Group [Member] | Electric Utility Services [Member]
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Additions									106.4	87.6	92.4
Revenues									605.8	601.6	624.8
Net income (loss)									84.7	82.6	79.7
Amounts Included in Profitability Measures [Abstract]
Depreciation and Amortization									87.1	85.6	85.7
Interest Expense									27	27.8	29
Income Taxes									50.1	49.3	48.1
Assets	1,788.4				1,778.3				1,788.4	1,778.3	1,656.2
Utility Group [Member] | Eliminations, Intersegment [Member]
Segment Reporting Information [Line Items]
Revenues									(41.9)	(40.4)	(38)
Utility Group [Member] | Non-Cash Cost and Change in Accruals [Member]
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Additions									(7.1)	(6.2)	(10.9)
Utility Group [Member] | Other Operations [Member]
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Additions									39	25.7	23.3
Revenues									42.2	40.7	38.3
Net income (loss)									12.8	13.9	11.7
Amounts Included in Profitability Measures [Abstract]
Depreciation and Amortization									23.9	24.6	24.1
Interest Expense									2.6	2.7	2.7
Income Taxes									2.3	(2)	(0.6)
Assets	161.5				107.5				161.5	107.5	148.5
Nonutility Group [Member]
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Additions									45.2	78.6	97.6
Revenues									1,073.3	1,043.2	1,143.1
Net income (loss)									36.9	36.3	18
Amounts Included in Profitability Measures [Abstract]
Depreciation and Amortization									40.9	47.5	70.3
Interest Expense									15.6	18.4	20.8
Income Taxes									14.7	13.4	(1)
Assets	749.9				778.8				749.9	778.8	745.9
Nonutility Group [Member] | Infrastructure Services [Member]
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Additions									43.2	78.1	54.1
Revenues									813.3	843.3	779
Net income (loss)									25	29.7	43.1
Amounts Included in Profitability Measures [Abstract]
Depreciation and Amortization									38.2	44.5	36.2
Interest Expense									12.8	16	11.1
Income Taxes									17.9	19.6	28.9
Assets	513.9				554.5				513.9	554.5	538.5
Nonutility Group [Member] | Energy Services [Member]
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Additions									1.8	0.5	1.6
Revenues									260	199.9	129.8
Net income (loss)									12.5	7.3	(3.2)
Amounts Included in Profitability Measures [Abstract]
Depreciation and Amortization									2.5	2.7	3.9
Interest Expense									1.9	1.2	1.3
Income Taxes									(3.5)	(7.7)	(7.8)
Assets	182.7				160.3				182.7	160.3	87.1
Nonutility Group [Member] | Coal Mining [Member]
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Additions									0	0	41.9
Revenues									0	0	234.3
Net income (loss)									0	0	(21.1)
Amounts Included in Profitability Measures [Abstract]
Depreciation and Amortization									0	0	29.9
Interest Expense									0	0	7.5
Income Taxes									0	0	(21.8)
Nonutility Group [Member] | Other Businesses [Member]
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Additions									0.2	0	0
Net income (loss)									(0.6)	(0.7)	(0.8)
Amounts Included in Profitability Measures [Abstract]
Depreciation and Amortization									0.2	0.3	0.3
Interest Expense									0.9	1.2	0.9
Income Taxes									0.3	1.5	(0.3)
Assets	53.3				64				53.3	64	120.3
Corporate and Other [Member]
Segment Reporting Information [Line Items]
Net income (loss)									1.1	0.1	0.5
Amounts Included in Profitability Measures [Abstract]
Interest Expense									0.2	(0.2)	(0.7)
Income Taxes									(1.3)	(1.8)	(1.1)
Assets	628.4				742.4				628.4	742.4	654.9
Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues									(2.8)	(3)	(101.1)
Amounts Included in Profitability Measures [Abstract]
Assets	$ (618.5)				$ (713.9)				$ (618.5)	$ (713.9)	$ (672.3)

Additional Balance Sheet & Op73

Additional Balance Sheet & Operational Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Inventory, Net [Abstract]
Gas in storage - at LIFO cost	$ 37	$ 40.5
Coal and Oil for electric generation - at average cost	42.6	45
Materials and supplies	48.9	46.9
Other	1.4	1.3
Total inventories	129.9	133.7
Amount by which cost of replacing inventories carried at LIFO cost exceeded carrying value	1
Prepayments and other current assets [Abstract]
Prepaid gas delivery service	26.4	30
Prepaid taxes	8.2	25.3
Other prepayments and current assets	18.1	25.7
Total prepayments and other current assets	52.7	81
Investments in unconsolidated affiliates [Abstract]
Total investments in unconsolidated affiliates	20.4	20.9
Equity in earnings (loss) of unconsolidated affiliates [Abstract]
Equity in earnings (losses) of unconsolidated affiliates	(0.2)	(0.6)	$ 0.5
Other utility and corporate investments [Abstract]
Cash surrender value of life insurance policies	33.1	30.1
Restricted cash & other investments	1	1.1
Other utility and corporate investments	34.1	31.2
Goodwill	293.5	293.5
Accrued liabilities [Abstract]
Refunds to customers and customer deposits	49.4	51.4
Accrued taxes	46.5	39.9
Accrued interest	18.2	19.4
Deferred compensation & post-retirement benefits	6.6	7.2
Accrued salaries and other	87	65.7
Total accrued liabilities	207.7	183.6
Asset Retirement Obligation [Roll Forward]
Asset retirement obligation, beginning balance	82	55
Accretion	3.8	3.2
Asset Retirement Obligation, Liabilities Incurred	0	24.2
Changes in estimates, net of cash payments	20.9	(0.4)
Asset retirement obligation, ending balance	106.7	82	55
Other - income (expense) - net [Abstract]
AFUDC - borrowed funds	20.3	16.3	11.4
AFUDC - equity funds	2.2	2.6	3.2
Interest Costs Capitalized Adjustment	1	0.4	0
Interest income, net	1.3	1.3	1.1
Other nonutility investment impairment charges	0	(0.1)	(1)
All other income	3.9	(0.2)	5
Other income (expense) - net	28.7	20.3	19.7
Cash paid (received) for [Abstract]
Interest	86.6	84.2	87.5
Income taxes	(3.6)	4.8	69.4
Accruals related to utility and nonutility plant purchases [Abstract]
Accruals related to utility and nonutility plant purchases	30	19.4
ProLiance Holdings, LLC [Member]
Investments in unconsolidated affiliates [Abstract]
Total investments in unconsolidated affiliates	19.2	19.7
Equity in earnings (loss) of unconsolidated affiliates [Abstract]
Equity in earnings (losses) of unconsolidated affiliates	(0.5)	(0.8)	(0.3)
Other Nonutility Partnerships and Corporations [Member]
Investments in unconsolidated affiliates [Abstract]
Total investments in unconsolidated affiliates	1	1
Other Utility Investments [Member]
Investments in unconsolidated affiliates [Abstract]
Total investments in unconsolidated affiliates	0.2	0.2
Other Unconsolidated Affiliates [Member]
Equity in earnings (loss) of unconsolidated affiliates [Abstract]
Equity in earnings (losses) of unconsolidated affiliates	0.3	0.2	$ 0.8
Utility Group [Member] | Gas Utility Services [Member]
Other utility and corporate investments [Abstract]
Goodwill	205	205
Nonutility Group [Member] | Infrastructure Services [Member]
Other utility and corporate investments [Abstract]
Goodwill	58.8	58.8
Nonutility Group [Member] | Energy Services [Member]
Other utility and corporate investments [Abstract]
Goodwill	$ 29.7	$ 29.7

Impact of Recently Issued Acc74

Impact of Recently Issued Accounting Guidance (Details) - Accounting Standards Update 2015-03 [Member] $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)
Impact on Regulatory Assets [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification, Debt Issuance Costs	$ 8.6
Other Assets [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification, Debt Issuance Costs	$ 1.3

Quarterly Financial Data (Una75

Quarterly Financial Data (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]
Operating revenues	$ 699	$ 631	$ 533.7	$ 584.8	$ 604	$ 573.5	$ 551	$ 706.2	$ 2,448.3	$ 2,434.7	$ 2,611.7
Operating income	120.7	105.5	63.9	92.2	103	79.9	72.9	106.1	381.5	361.8	314.5
Net Income	$ 69.6	$ 61.4	$ 32.3	$ 48.3	$ 65.2	$ 39.3	$ 35.8	$ 57	$ 211.6	$ 197.3	$ 166.9
Earnings per share [Abstract]
Basic	$ 0.84	$ 0.74	$ 0.39	$ 0.58	$ 0.79	$ 0.48	$ 0.43	$ 0.69	$ 2.55	$ 2.39	$ 2.02

SCHEDULE II VALUATION AND QUA76

SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Accumulated Provision for Uncollectible Accounts [Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
Balance, at beginning of year	$ 5.6	$ 6	$ 6.8
Additions charged to expenses	6.9	8.1	7.3
Additions charged to other accounts	0	0	0
Deductions from Reserves, Net	6.5	8.5	8.1
Balance, at end of period	6	5.6	6
Reserve for Impaired Notes Receivable [Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
Balance, at beginning of year	0.2	0	0.6
Additions charged to expenses	0.4	0.2	0
Additions charged to other accounts	0	0	0
Deductions from Reserves, Net	0	0	0.6
Balance, at end of period	0.6	0.2	0
Business Restructuring Reserves [Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
Balance, at beginning of year	0	0	0.2
Additions charged to expenses	0	0	0
Additions charged to other accounts	0	0	0
Deductions from Reserves, Net	0	0	0.2
Balance, at end of period	$ 0	$ 0	$ 0