Vectren (VVC) Inactive 10-K23 Feb 162015 FY Annual reportFinancial data

Company Profile

Document And Entity Information

Document And Entity Information - USD ($)	12 Months Ended
Document And Entity Information - USD ($)	Dec. 31, 2015	Jan. 29, 2016	Jun. 30, 2015
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			$ 3,174,747,149
Entity Common Stock, Shares Outstanding		82,772,393
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	FY
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2015
Current Fiscal Year End Date	--12-31

Balance Sheet

Balance Sheet - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Current Assets
Cash and cash equivalents	$ 74.7	$ 86.4
Accounts receivable - less reserves of $5.6 & $6.0, respectively	227.5	196
Accrued unbilled revenues	142.5	164.8
Inventories	133.7	118.5
Recoverable fuel and natural gas costs	0	9.8
Prepayments and other current assets	81	94.6
Total current assets	659.4	670.1
Utility Plant
Original cost	6,090.4	5,718.7
Less: accumulated depreciation and amortization	2,415.5	2,279.7
Net utility plant	3,674.9	3,439
Investments in unconsolidated affiliates	20.9	23.4
Other utility and corporate investments	31.2	37.2
Other nonutility investments	16.2	33.6
Nonutility plant - net	414.6	378
Goodwill	293.5	289.9
Regulatory assets	258	233.6
Other assets	41.2	41.2
TOTAL ASSETS	5,409.9	5,146
Current Liabilities
Accounts payable	248.8	248.9
Refundable fuel and natural gas costs	7.9	2.5
Accrued liabilities	183.6	184.9
Short-term borrowings	14.5	156.4
Current maturities of long-term debt	73	170
Total current liabilities	527.8	762.7
Long-term Debt - Net of Current Maturities	1,722.8	1,407.3
Deferred Income Taxes and Other Liabilities
Deferred income taxes	805.4	724.9
Regulatory liabilities	433.9	410.3
Deferred credits and other liabilities	236.2	234.2
Total deferred credits and other liabilities	$ 1,475.5	$ 1,369.4
Commitments & Contingencies (Notes 7, 17-20)
Common Shareholders' Equity
Common stock (no par value) - issued & outstanding 82.8 & 82.6 shares, respectively	$ 722.8	$ 715.7
Retained earnings	962.2	892.2
Accumulated other comprehensive income/(loss)	(1.2)	(1.3)
Total common shareholders' equity	1,683.8	1,606.6
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$ 5,409.9	$ 5,146

Income Statement

Income Statement - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
OPERATING REVENUES
Gas utility	$ 792.6	$ 944.6	$ 810
Electric utility	601.6	624.8	619.3
Nonutility	1,040.5	1,042.3	1,061.9
Total operating revenues	2,434.7	2,611.7	2,491.2
OPERATING EXPENSES
Cost of gas sold	305.4	468.7	358.1
Cost of fuel and purchased power	187.5	201.8	202.9
Cost of nonutility revenues	355	346.4	366.7
Other operating	909.2	943.4	891.6
Depreciation and amortization	256.3	273.4	277.8
Taxes other than income taxes	59.5	63.5	60.5
Total operating expenses	2,072.9	2,297.2	2,157.6
OPERATING INCOME	361.8	314.5	333.6
OTHER INCOME (EXPENSE)
Equity in earnings (losses) of unconsolidated affiliates	(0.6)	0.5	(59.7)
Other income (expense) - net	20.3	19.7	17.7
Total other income (expense)	19.7	20.2	(42)
Interest expense	84.5	86.7	87.9
INCOME BEFORE INCOME TAXES	297	248	203.7
Income taxes	99.7	81.1	67.1
Net income	$ 197.3	$ 166.9	$ 136.6
AVERAGE COMMON SHARES OUTSTANDING (in shares)	82.7	82.5	82.3
DILUTED COMMON SHARES OUTSTANDING (in shares)	82.7	82.5	82.4
EARNINGS PER SHARE OF COMMON STOCK:
BASIC (in dollars per share)	$ 2.39	$ 2.02	$ 1.66
DILUTED (in dollars per share)	$ 2.39	$ 2.02	$ 1.66

Balance Sheet (Parenthetical)

Balance Sheet (Parenthetical) - USD ($) shares in Millions, $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Current Assets
Reserves	$ 5.6	$ 6
Common Shareholders' Equity
Common stock Shares, Issued (in shares)	82.8	82.6
Common stock, Shares Outstanding (in shares)	82.8	82.6

CONSOLIDATED CONDENSED STATEMEN

CONSOLIDATED CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Net Income	$ 197.3	$ 166.9	$ 136.6
Other comprehensive income	0.1	(0.6)	3.6
TOTAL COMPREHENSIVE INCOME	197.4	166.3	140.2
AOCI of Unconsolidated Affiliates [Member]
Net amount arising during the year before tax	0	0	4.6
Income taxes	0	0	(1.8)
Other comprehensive income	0	0	2.8
Pensions and Other Benefits [Member]
Amounts arising during the year before tax	1.2	(52.6)	61.4
Reclassifications to periodic cost before tax	6.9	3.4	9.1
Deferrals to regulatory assets	(8)	48.2	(69.1)
Income taxes	0	0.4	(0.6)
Other comprehensive income	$ 0.1	$ (0.6)	$ 0.8

Statement of Cash Flows

Statement of Cash Flows - USD ($) $ in Millions	12 Months Ended
Statement of Cash Flows - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$ 197.3	$ 166.9	$ 136.6
Adjustments to reconcile net income to cash from operating activities:
Depreciation and amortization	256.3	273.4	277.8
Deferred income taxes and investment tax credits	80.4	37.9	43.3
Equity in (earnings) losses of unconsolidated affiliates	0.6	(0.5)	59.7
Provision for uncollectible accounts	8.1	7.3	6.8
Expense portion of pension and postretirement benefit cost	6.8	6.6	9.9
Other non-cash charges - net	6.7	5.8	5.8
Loss on Sale of Business (pretax)	0	41.8	0
Gain on Revaluation of Contingent Consideration	0	(14.8)	0
Changes in working capital accounts:
Accounts receivable & accrued unbilled revenues	(15.4)	11.8	1.5
Inventories	(15.2)	(22.5)	24.2
Recoverable/refundable fuel and natural gas costs	15.2	(4.4)	22.4
Prepayments and other current assets	20.3	(35.2)	12.8
Accounts payable, including to affiliated companies	(0.5)	20.2	6.8
Accrued liabilities	(0.9)	12.3	(1.2)
Unconsolidated affiliate dividends	1.3	0	1.1
Employer contributions to pension and postretirement plans	(26.5)	(5.1)	(13.7)
Changes in noncurrent assets	(23.2)	0.1	(2.1)
Changes in noncurrent liabilities	(6.1)	(13.4)	(4.7)
Net cash flows from operating activities	505.2	488.2	587
Proceeds from:
Long-term debt, net of issuance costs	385.5	62.4	481.7
Dividend reinvestment plan and other common stock issuances	6.2	6.1	6.9
Requirements for:
Dividends on common stock	(127.3)	(120.4)	(117.3)
Retirement of long-term debt	(170)	(293.6)	(338.9)
Other financing activities	0.2	0.1	(2.1)
Net change in short-term borrowings	(141.9)	87.8	(210.2)
Net cash flows from financing activities	(47.3)	(257.6)	(179.9)
Proceeds from:
Sale of business	0	311.2	0
Sale of Assets and Other collections	27.5	9.5	5.6
Requirements for:
Capital expenditures, excluding AFUDC equity	(476.9)	(448.3)	(393.4)
Business Acquisitions and Other Costs	(14.3)	(38.1)	0
Other investments	0	0	(17.3)
Changes in Restricted Cash	(5.9)	0	0
Net cash flows from investing activities	(469.6)	(165.7)	(405.1)
Net change in cash and cash equivalents	(11.7)	64.9	2
Cash and cash equivalents at beginning of period	86.4	21.5	19.5
Cash and cash equivalents at end of period	$ 74.7	$ 86.4	$ 21.5

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, 2012	$ 1,526.1	$ 700.5	$ 829.9	$ (4.3)
Balance at beginning of period (in shares) at Dec. 31, 2012		82.2
Comprehensive income:
Net Income	136.6		136.6
Other comprehensive income	3.6			3.6
Common stock:
Issuance: option exercises and dividend reinvestment plan (in shares)		0.2
Issuance: option exercised and dividend reinvestment plan	6.9	$ 6.9
Dividends ($1.425, $1.460 and $1.540 per share)	(117.3)		(117.3)
Other	(1.6)	1.9	(3.5)
Balance at end of period at Dec. 31, 2013	1,554.3	$ 709.3	845.7	(0.7)
Balance at end of period (in shares) at Dec. 31, 2013		82.4
Comprehensive income:
Net Income	166.9		166.9
Other comprehensive income	(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 ($1.425, $1.460 and $1.540 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	82.6
Comprehensive income:
Net Income	$ 197.3		197.3
Other comprehensive income	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 ($1.425, $1.460 and $1.540 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

Statement of Shareholders' Equ8

Statement of Shareholders' Equity (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Statement of Stockholders' Equity [Abstract]
Dividends (in dollars per share)	$ 1.540	$ 1.460	$ 1.425

Organization and Nature of Oper

Organization and Nature of Operations	12 Months Ended
Organization and Nature of Operations	Dec. 31, 2015
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 580,000 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 314,000 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 its 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. Further, prior to June 18, 2013, the Company had activities in its Energy Marketing business. Energy Marketing marketed and supplied natural gas and provided energy management services through ProLiance Holdings, LLC (ProLiance or ProLiance Holdings). In June 2013, ProLiance exited the gas marketing business through the disposition of certain net assets of its energy marketing subsidiary, ProLiance Energy, LLC (ProLiance Energy). Other minor operating results of the remaining ProLiance investment and Coal Mining are reflected in Other Businesses. 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
Summary of Significant Accounting Policies	Dec. 31, 2015
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 elimination of intercompany transactions. Subsequent Events Review Management performs a review of subsequent events for any events occurring after the balance sheet date but prior to the date the financial statements are issued. Cash & Cash Equivalents All highly liquid investments with an original maturity of three months or less at the date of purchase are considered cash equivalents. Cash and cash equivalents are stated at cost plus accrued interest to approximate fair value. Allowance for Uncollectible Accounts The Company maintains allowances for uncollectible accounts for estimated losses resulting from the inability of its customers to make required payments. The Company estimates the allowance for uncollectible accounts based on a variety of factors including the length of time receivables are past due, the financial health of its customers, unusual macroeconomic conditions, and historical experience. If the financial condition of its customers deteriorates or other circumstances occur that result in an impairment of customers’ ability to make payments, the Company records additional allowances as needed. Inventories In most circumstances, the Company’s inventory components are recorded using an average cost method; however, natural gas in storage 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 is performed 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 on when the contracts are expected to be settled. Contracts and any associated collateral with counter-parties subject to master netting arrangements are presented net in the Consolidated Balance Sheets . The offset resulting from carrying the derivative at fair value on the balance sheet is charged to earnings unless it qualifies as a hedge or is subject to regulatory accounting treatment. When hedge accounting is appropriate, the Company assesses and documents hedging relationships between the derivative contract and underlying risks as well as its risk management objectives and anticipated effectiveness. When the hedging relationship is highly effective, derivatives are designated as hedges. The market value of the effective portion of the hedge is marked to market in Accumulated other comprehensive income for cash flow hedges. Ineffective portions of hedging arrangements are marked to market through earnings. For fair value hedges, both the derivative and the underlying hedged item are marked to market through earnings. The offset to contracts affected by regulatory accounting treatment are marked to market as a regulatory asset or liability. Market value for derivative contracts is determined using quoted market prices from independent sources. The Company rarely enters into contracts that have a significant impact to the 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 . Substantially all revenue sources are subject to unbillled accruals. 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 their 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 $29.4 million in 2015 , $32.3 million in 2014 , and $29.6 million in 2013 . 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 need to maximize the use of observable inputs and minimize the use of unobservable inputs.

Utility & Nonutility Plant

Utility & Nonutility Plant	12 Months Ended
Utility & Nonutility Plant	Dec. 31, 2015
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) 2015 2014 Original Cost Depreciation Rates as a Percent of Original Cost Original Cost Depreciation Rates as a Percent of Original Cost Gas utility plant $ 3,279.7 3.4 % $ 3,011.0 3.4 % Electric utility plant 2,695.8 3.3 % 2,602.5 3.3 % Common utility plant 55.0 3.2 % 54.3 3.2 % Construction work in progress 59.9 — 50.9 — Total original cost $ 6,090.4 $ 5,718.7 SIGECO and Alcoa Generating Corporation (AGC), a subsidiary of Alcoa, Inc. (Alcoa), own the 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, 2015 , is $190.3 million with accumulated depreciation totaling $101.9 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 January 2016, Alcoa announced plans to close its smelter operations by the end of the first quarter 2016. 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 their generation, anticipating that more will be known toward the end of 2016. Nonutility Plant , net of accumulated depreciation and amortization follows: At December 31, (In millions) 2015 2014 Computer hardware & software $ 108.8 $ 106.1 Land & buildings 86.4 72.1 Vehicles & equipment 203.0 182.7 All other 16.4 17.1 Nonutility plant - net $ 414.6 $ 378.0 Nonutility Plant is presented net of accumulated depreciation and amortization totaling $420.3 million and $361.9 million as of December 31, 2015 and 2014 , respectively. For the years ended December 31, 2015 , 2014 , and 2013 , the Company capitalized interest totaling $0.4 million , $0.6 million , and $0.5 million , respectively, on nonutility plant construction projects.

Regulatory Assets & Liabilities

Regulatory Assets & Liabilities	12 Months Ended
Regulatory Assets & Liabilities	Dec. 31, 2015
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) 2015 2014 Future amounts recoverable from ratepayers related to: Benefit obligations (See Note 11) $ 97.3 $ 105.3 Net deferred income taxes (See Note 10) (16.9 ) (14.8 ) 80.4 90.5 Amounts deferred for future recovery related to: Cost recovery riders & other 54.6 33.3 54.6 33.3 Amounts currently recovered in customer rates related to: Unamortized debt issue costs, reacquisition premiums & hedging proceeds 34.4 35.2 Demand side management programs — 0.6 Indiana authorized trackers 42.6 25.6 Deferred coal costs 28.3 35.3 Ohio authorized trackers 17.6 12.7 Other base rate recoveries 0.1 0.4 123.0 109.8 Total regulatory assets $ 258.0 $ 233.6 Of the $123 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 $35 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 decrease in 2015 of approximately $8 million is primarily a result of an increase in discount rate used to value the projected benefit obligation. These decreases were somewhat offset by asset returns that were less than the assumed rate of return. The Company records a Regulatory asset for that portion related to its rate regulated utilities. See Note 11. Regulatory Liabilities At December 31, 2015 and 2014 , the Company has approximately $433.9 million and $410.3 million , respectively, in Regulatory liabilities . Of these amounts, $399.1 million and $373.5 million relate to cost of removal obligations. The remaining amounts primarily relate to timing differences associated with asset retirement obligations and deferred financing costs.

Federal Business Unit Acquisiti

Federal Business Unit Acquisition Federal Business Unit Acquisition	12 Months Ended
	Dec. 31, 2015
Business Combinations [Abstract]
Business Combination Disclosure [Text Block]	Federal Business Unit Acquisition On April 1, 2014 , the Company, through its wholly owned subsidiary Energy Systems Group (ESG), 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 operation and maintenance and repair 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. The Company recognized the assets acquired and the liabilities assumed, measured at their fair values as of the date of acquisition. The following table summarizes the allocation of the purchase price to the fair value of the assets acquired and liabilities assumed as of April 1, 2014. (In millions) Adjusted Net Working Capital $ 2.2 Depreciable Fixed Assets 0.4 Customer Relationships (Sales Funnel) 7.1 ESPC Licenses 6.0 Deferred Tax Asset 0.8 Goodwill 27.7 Total Assets acquired $ 44.2 Less: Unfavorable Contract Liabilities Assumed (2.1 ) Total Purchase Consideration $ 42.1 Level 3 market inputs, such as discounted cash flows and revenue growth rates were used to derive the preliminary fair values of the identifiable intangible assets. Identifiable intangible assets include long-term customer relationships and licenses. Goodwill arising from the purchase represents intangible value the Company expects to realize over time. This value includes but is not limited to: 1) expected customer growth beyond what is in the current sales funnel and 2) the experience of the acquired work force. The goodwill, which does not amortize pursuant to accounting guidance, is deductible over a 15 -year period for purposes of computing current income tax expense, and will be included in the Energy Services operating segment. 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 twelve months 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 and 2013, unaudited proforma results of the combined companies, assuming the acquisition closed on January 1, 2013, would have added approximately $17.7 million and $27.6 million to consolidated revenues, respectively. For the periods presented, 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
Sale of Vectren Fuels, Inc.	Dec. 31, 2015
Discontinued Operations and Disposal Groups [Abstract]
Disposal Groups, Including Discontinued Operations, Disclosure [Text Block]	Sale of Vectren Fuels, Inc. On July 1, 2014, the Company announced that it had reached an agreement to sell its wholly owned coal mining subsidiary, Vectren Fuels, to Sunrise Coal, LLC (Sunrise Coal), an Indiana-based wholly owned subsidiary of Hallador Energy Company. Sunrise Coal owns and operates coal mines in the Illinois Basin. On August 29, 2014, the transaction closed. Total cash received was approximately $311 million , inclusive of a $15 million change in working capital from December 31, 2013, through closing. At June 30, 2014, the Company recorded an estimated loss on the transaction, including costs to sell, of approximately $32 million , or $20 million after tax. At December 31, 2014, the pre-tax loss 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 ceased for the assets classified as held for sale at 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, compared to a loss of $16.0 million for the year ended December 31, 2013. 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.

Investment in ProLiance Holding

Investment in ProLiance Holdings, LLC	12 Months Ended
Investment in ProLiance Holdings, LLC	Dec. 31, 2015
Equity Method Investments and Joint Ventures [Abstract]
Investment in 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). On June 18, 2013, ProLiance exited the natural gas marketing business through the disposition of certain of the net assets, along with the long-term pipeline and storage commitments, of its energy marketing business, ProLiance Energy, LLC (ProLiance Energy), to a subsidiary of Energy Transfer Partners, ETC Marketing, Ltd (ETC). Other minor operating results of the remaining ProLiance investments are reflected in Other Businesses. 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. As a result of ProLiance exiting the natural gas marketing business on June 18, 2013, the Company recorded its share of the loss on the disposition, termination of long-term pipeline and storage commitments, and related transaction and other costs totaling $43.6 million pre-tax, or $26.8 million net of tax, during the second quarter of 2013. At the time of sale, ProLiance Holdings funded an estimated equity shortfall at ProLiance Energy of $16.6 million . To fund this estimated shortfall, the Company issued a note to ProLiance Holdings for its 61 percent ownership share of the $16.6 million shortfall, or $10.1 million , which was utilized by ProLiance Holdings to invest additional equity in ProLiance Energy. This interest-bearing note is classified as Other nonutility investments in the Consolidated Balance Sheets . The Company's remaining investment in ProLiance at December 31, 2015 , shown at its 61 percent ownership share, is as follows and reflects that it relates primarily to ProLiance's investment in LA Storage discussed below. As of December 31, (In millions) 2015 Cash $ 2.7 Investment in LA Storage 22.2 Other midstream asset investment 4.9 Total investment in ProLiance $ 29.8 Included in: Investments in unconsolidated affiliates 19.7 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 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 will 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 is dependent on market conditions, including pricing, need for storage capacity, and development of the liquefied natural gas market, among other factors. To date, development activity has been modest due to 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, 2015 , ProLiance's investment in the joint venture was $36.4 million . The joint venture received a demand for arbitration from Williams Midstream Natural Gas Liquids, Inc. (Williams) in February 2011 related to a sublease agreement. Williams alleged that the joint venture was negligent in its attempt to convert certain salt caverns to natural gas storage and seeks damages of $56.7 million . In August 2015, the joint venture and Williams agreed to settle the dispute. The Company's share of the settlement was not material to its results of operations or statement of financial condition. Transactions with ProLiance Purchases from ProLiance for resale and for injections into storage for the year ended December 31, 2013 totaled $200.5 million . The Company did not have any purchases from ProLiance for the year ended December 31, 2015 or 2014. The 2013 purchases from ProLiance all occurred prior to June 18, 2013 when ProLiance exited the natural gas marketing business.

Nonutility Real Estate & Other

Nonutility Real Estate & Other Legacy Holdings	12 Months Ended
Nonutility Real Estate & Other Legacy Holdings	Dec. 31, 2015
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 December 31, 2015 and 2014 , total remaining legacy investments, other than the investment in ProLiance, included in the Other Businesses portfolio total $7.0 million and $25.0 million , respectively. Further separation by type of investment follows: At December 31, 2015 At December 31, 2014 Value Included In Value Included In (In millions) Carrying Value Other Nonutility Investments Investments in Unconsolidated Affiliates Carrying Other Nonutility Investments Investments in Unconsolidated Affiliates Commercial real estate investment $ — $ — $ — $ 8.0 $ 8.0 $ — Leveraged lease — — — 15.2 15.2 — Other investments 7.0 6.0 1.0 1.8 0.2 1.6 $ 7.0 $ 6.0 $ 1.0 $ 25.0 $ 23.4 $ 1.6 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. At December 31, 2015, 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
Intangible Assets	Dec. 31, 2015
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, 2015 2014 Amortizing Non-amortizing Amortizing Non-amortizing Customer-related assets $ 23.1 $ — $ 22.5 $ — Market-related assets 0.2 13.0 1.1 13.0 Intangible assets, net $ 23.3 $ 13.0 $ 23.6 $ 13.0 As of December 31, 2015 , the weighted average remaining life for amortizing customer-related assets and all amortizing intangibles is 12 years. These amortizing intangible assets have no significant residual values. Intangible assets are presented net of accumulated amortization totaling $9.8 million for customer-related assets and $4.3 million for market-related assets at December 31, 2015 and $10.0 million for customer-related assets and $3.4 million for market-related assets at December 31, 2014 . Annual amortization associated with intangible assets totaled $3.1 million in 2015 , $2.8 million in 2014 and $2.3 million in 2013 . Amortization should approximate (in millions) $2.5 , $2.3 , $2.3 , $2.3 , and $2.3 in 2016 , 2017 , 2018 , 2019 , and 2020 , respectively. Intangible assets are primarily in the Nonutility Group.

Income Taxes

Income Taxes	12 Months Ended
Income Taxes	Dec. 31, 2015
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, 2015 2014 2013 Statutory rate: 35.0 % 35.0 % 35.0 % State & local taxes-net of federal benefit 3.6 4.1 4.6 Amortization of investment tax credit (0.2 ) (0.3 ) (0.3 ) Depletion — (2.6 ) (1.5 ) Domestic production deduction (1.0 ) (1.1 ) — Energy efficiency building deductions (2.3 ) (1.6 ) (3.8 ) Research and development credit (1.6 ) (0.3 ) (0.6 ) Other tax credits (0.1 ) (0.2 ) (1.1 ) All other-net 0.2 (0.3 ) 0.7 Effective tax rate 33.6 % 32.7 % 33.0 % Significant components of the net deferred tax liability follow: At December 31, (In millions) 2015 2014 Noncurrent deferred tax liabilities (assets): Depreciation & cost recovery timing differences $ 827.6 $ 757.9 Leveraged lease — 9.8 Regulatory assets recoverable through future rates 31.6 29.2 Alternative minimum tax carryforward (34.5 ) (51.4 ) Employee benefit obligations (9.3 ) (14.5 ) Net operating loss & other carryforwards (3.7 ) (2.0 ) Regulatory liabilities to be settled through future rates (29.9 ) (27.5 ) Impairments (3.0 ) (5.6 ) Deferred fuel costs - net 14.2 22.0 Other – net 12.4 7.0 Net noncurrent deferred tax liability $ 805.4 $ 724.9 The Company has presented its deferred tax assets and deferred tax liabilities as non-current in the tables above and in the balance sheet, in accordance with ASU 2015-17, Balance Sheet Classification of Deferred Taxes. The Company early adopted ASU 2015-17 in the current year as the new standard simplifies current accounting guidance, which required entities to separately present deferred tax assets and deferred tax liabilities as current and non-current. This guidance was adopted for the year ended December 31, 2015, and has been applied retrospectively to all periods presented. The effect of this change on the December 31, 2015 and 2014 balance sheets is the reclassification of $15.3 million and $16.3 million in current deferred tax assets to long-term deferred tax liabilities, respectively. The amounts reclassified primarily represent the net of deferred tax assets arising from alternative minimum tax carryforwards and deferred tax liabilities arising from deferred fuels costs. At December 31, 2015 and 2014 , investment tax credits totaling $4.1 million and $4.7 million respectively, are included in Deferred credits & other liabilities . At December 31, 2015 , the Company has alternative minimum tax carryforwards which do not expire. In addition, the Company has $3.7 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, 2015 and 2014 , the valuation allowance was $8.1 million and $7.3 million , respectively. The components of income tax expense follow: Year Ended December 31, (In millions) 2015 2014 2013 Current: Federal $ 10.8 $ 24.7 $ 12.4 State 8.5 18.5 11.4 Total current taxes 19.3 43.2 23.8 Deferred: Federal 79.0 42.7 43.4 State 2.0 (4.2 ) 0.5 Total deferred taxes 81.0 38.5 43.9 Amortization of investment tax credits (0.6 ) (0.6 ) (0.6 ) Total income tax expense $ 99.7 $ 81.1 $ 67.1 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, penalties and net of secondary impacts which are a component of the Deferred income taxes and are benefits, totaled $1.0 million and $1.1 million , respectively, at December 31, 2015 and 2014 . 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 2011 except to the extent of refunds claimed on amended tax returns. The statutes of limitations for assessment of the 2009-2011 tax years related to the amended federal and Indiana income tax returns will expire in 2016 and 2017. Final Federal Income Tax Regulations In September 2013, the IRS released final tangible property regulations regarding the deduction and capitalization of expenditures related to tangible property. The final regulations are generally effective for tax years beginning on or after January 1, 2014, and were adopted on the 2014 federal income tax return. The IRS has been working with the utility industry to provide industry specific guidance concerning the deductibility and capitalization of expenditures related to tangible property. The IRS has indicated that it expects to issue updated or new guidance with respect to electric and natural gas transmission and distribution assets during 2016. The Company continues to evaluate the impact adoption and industry guidance will have on its consolidated financial statements. As of this date, the Company does not expect the industry guidance to have a material impact on its consolidated financial statements. 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
Retirement Plans & Other Postretirement Benefits	Dec. 31, 2015
Compensation and Retirement Disclosure [Abstract]
Retirement Plans and Other Postretirement Benefits	Retirement Plans & Other Postretirement Benefits At December 31, 2015 , 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, 2015 follows: Pension Benefits Other Benefits (In millions) 2015 2014 2013 2015 2014 2013 Service cost $ 7.9 $ 7.4 $ 8.6 $ 0.4 $ 0.4 $ 0.5 Interest cost 14.6 15.5 14.7 2.0 2.3 2.0 Expected return on plan assets (22.5 ) (22.7 ) (22.1 ) — — — Amortization of prior service cost (benefit) 0.7 1.0 1.5 (3.0 ) (3.0 ) (3.2 ) Amortization of actuarial loss 8.5 5.0 10.1 0.7 0.4 0.7 Settlement charge 0.6 3.1 1.3 — — — Net periodic benefit cost $ 9.8 $ 9.3 $ 14.1 $ 0.1 $ 0.1 $ — A portion of the net periodic benefit cost disclosed in the table above is capitalized as Utility Plant . Costs capitalized in 2015 , 2014 , and 2013 are estimated at $3.1 million , $2.8 million , and $4.2 million , respectively. The Company decreased the discount rate used to measure periodic cost from 4.74 percent in 2014 to 4.05 percent in 2015 due to lower 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 2016 , the weighted average discount rate assumption will increase to 4.31 percent for the defined benefit pension plans, based on increased benchmark interest rates. The weighted averages of significant assumptions used to determine net periodic benefit costs follow: Pension Benefits Other Benefits 2015 2014 2013 2015 2014 2013 Discount rate 4.05 % 4.74 % 4.03 % 3.95 % 4.66 % 3.91 % Rate of compensation increase 3.50 % 3.50 % 3.50 % N/A N/A N/A Expected return on plan assets 7.50 % 7.75 % 7.75 % N/A N/A N/A Expected increase in Consumer Price Index N/A N/A N/A 2.50 % 2.75 % 2.75 % The Company uses a "building block" approach to develop an expected long-term rate of return. 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, 2015 and 2014 follows: Pension Benefits Other Benefits (In millions) 2015 2014 2015 2014 Benefit obligation, beginning of period $ 371.9 $ 338.4 $ 53.3 $ 51.3 Service cost – benefits earned during the period 7.9 7.4 0.4 0.4 Interest cost on projected benefit obligation 14.6 15.5 2.0 2.3 Plan participants' contributions — — 1.0 0.9 Plan amendments 0.5 — — — Actuarial loss (gain) (17.0 ) 48.5 (8.6 ) 3.2 Settlement loss — 1.7 — — Benefit payments (27.9 ) (25.3 ) (4.6 ) (4.8 ) Settlement payments (1.7 ) (14.3 ) — — Benefit obligation, end of period $ 348.3 $ 371.9 $ 43.5 $ 53.3 The accumulated benefit obligation for all defined benefit pension plans was $336.1 million and $356.4 million at December 31, 2015 and 2014 , respectively. The decrease in the pension benefit obligation in 2015 is primarily due to an increase 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, 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. These changes are reflected in the Company's benefit obligation as of December 31, 2015. Other Material Assumptions The benefit obligation as of December 31, 2015 and 2014 was calculated using the following weighted average assumptions: Pension Benefits Other Benefits 2015 2014 2015 2014 Discount rate 4.31 % 4.05 % 4.21 % 3.95 % 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 2015 ending postretirement benefit obligation, medical claims costs in 2016 were assumed to be 6.0 percent higher than those incurred in 2015 . 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, 2015 and 2014 follows: Pension Benefits Other Benefits (In millions) 2015 2014 2015 2014 Plan assets at fair value, beginning of period $ 305.6 $ 323.9 $ — $ — Actual return on plan assets (2.0 ) 20.1 — — Employer contributions 22.9 1.2 3.6 3.9 Plan participants' contributions — — 1.0 0.9 Benefit payments (27.9 ) (25.3 ) (4.6 ) (4.8 ) Settlement payments (1.7 ) (14.3 ) — — Fair value of plan assets, end of period $ 296.9 $ 305.6 $ — $ — 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 60 percent equities, 35 percent debt, and 5 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 quoted market prices or net asset values 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 fair values of these trusts are derived from Level 2 market inputs based on a daily calculated unit value as determined by the issuer. This daily calculated value is based on the fair market value of the underlying investments. These funds are primarily comprised of investments in equity and fixed income securities which represent approximately 30 percent and 60 percent , respectively, of their fair value as of December 31, 2015 and approximately 56 percent and 37 percent , respectively, as of December 31, 2014 . Equity securities within these funds are primarily valued using quoted market prices as these instruments have active markets. From time to time, less liquid equity securities are valued using Level 2 inputs, such as bid prices or a closing price, as determined in good faith by the investment manager. Fixed income securities are valued at the last available bid prices quoted by an independent pricing service. When valuations are not readily available, fixed income securities are valued using primarily other Level 2 inputs as determined in good faith by the investment manager. The fair value of these funds totals $99.5 million at December 31, 2015 and $155.6 million at December 31, 2014 . In 2015, approximately $54 million of Level 2 investments were reallocated to Level 1 investments to maximize performance. 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. 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, 2015 and 2014 , the estimate of undiscounted funds necessary to satisfy John Hancock’s remaining obligation was $3.9 million and $3.8 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, 2015 and 2014 was 3.65 percent and 4.12 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. The fair values of the Company’s pension and other retirement plan assets at December 31, 2015 and December 31, 2014 by asset category and by fair value hierarchy are as follows: As of December 31, 2015 (In millions) Level 1 Level 2 Level 3 Total Domestic equities & equity funds $ 113.5 $ 29.8 $ — $ 143.3 International equities & equity funds 38.2 — — 38.2 Domestic bonds & bond funds 36.6 48.0 — 84.6 Inflation protected security fund — 11.2 — 11.2 Real estate, commodities & other 4.8 10.5 4.3 19.6 Total plan investments $ 193.1 $ 99.5 $ 4.3 $ 296.9 As of December 31, 2014 (In millions) Level 1 Level 2 Level 3 Total Domestic equities & equity funds $ 62.8 $ 87.3 $ — $ 150.1 International equities & equity funds 38.4 — — 38.4 Domestic bonds & bond funds 38.8 47.1 — 85.9 Inflation protected security fund — 11.1 — 11.1 Real estate, commodities & other 5.8 10.1 4.2 20.1 Total plan investments $ 145.8 $ 155.6 $ 4.2 $ 305.6 A roll forward of the fair value of the guaranteed annuity contract calculated using Level 3 valuation assumptions follows: (In millions) 2015 2014 Fair value, beginning of year $ 4.2 $ 4.1 Unrealized gains related to investments still held at reporting date 0.2 0.1 Purchases, sales & settlements, net (0.1 ) — Fair value, end of year $ 4.3 $ 4.2 Funded Status The funded status of the plans as of December 31, 2015 and 2014 follows: Pension Benefits Other Benefits (In millions) 2015 2014 2015 2014 Qualified Plans Benefit obligation, end of period $ (328.7 ) $ (351.7 ) $ (43.5 ) $ (53.3 ) Fair value of plan assets, end of period 296.9 305.6 — — Funded Status of Qualified Plans, end of period (31.8 ) (46.1 ) (43.5 ) (53.3 ) Benefit obligation of SERP Plan, end of period (19.6 ) (20.2 ) — — Total funded status, end of period $ (51.4 ) $ (66.3 ) $ (43.5 ) $ (53.3 ) Accrued liabilities $ 1.2 $ 1.2 $ 4.6 $ 4.6 Deferred credits & other liabilities $ 50.2 $ 65.1 $ 38.9 $ 48.7 Expected Cash Flows The Company currently anticipates making contributions of $15.0 million to qualified pension plans in 2016. In addition, the Company expects to make contributions totaling approximately $1.2 million into the SERP plan and approximately $3.3 million into the postretirement plan. Estimated retiree pension benefit payments, including the SERP, projected to be required during the years following 2015 are approximately (in millions) $25.1 in 2016 , $35.9 in 2017 , $25.8 in 2018 , $27.0 in 2019 , $29.6 in 2020 , and $135.2 in years 2021-2025 . Expected benefit payments projected to be required for postretirement benefits during the years following 2015 (in millions) are approximately $4.6 in 2016 , $4.4 in 2017 , $4.6 in 2018 , $4.8 in 2019 , $5.1 in 2020 , and $25.5 in years 2021-2025 . 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, 2013 $ 4.5 $ 136.2 $ (23.1 ) $ 11.2 Amounts arising during the period — (58.8 ) (0.2 ) (2.4 ) Reclassification to benefit costs (1.5 ) (10.1 ) 3.2 (0.7 ) Balance at December 31, 2013 $ 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 Following is a reconciliation of the amounts in Accumulated other comprehensive income (AOCI) and Regulatory assets related to retirement plan obligations at December 31, 2015 and 2014 . (In millions) 2015 2014 Pensions Other Benefits Pensions Other Benefits Prior service cost $ 1.8 $ (14.1 ) $ 2.0 $ (17.1 ) Unamortized actuarial gain/(loss) 110.1 1.6 111.7 10.9 111.9 (12.5 ) 113.7 (6.2 ) Less: Regulatory asset deferral (109.6 ) 12.3 (111.4 ) 6.1 AOCI before taxes $ 2.3 $ (0.2 ) $ 2.3 $ (0.1 ) Related to pension plans, $0.4 million of prior service cost and $7.2 million of actuarial gain/loss is expected to be amortized to cost in 2016 . Related to other benefits, no actuarial gain/loss is expected to be amortized to periodic cost in 2016 , and $3.0 million of prior service cost is expected to reduce costs in 2016 . 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 $32.7 million , $32.4 million and $33.2 million for the years ended December 31, 2015 , 2014 , and 2013 , respectively. During 2015 , the Company made contributions to these multiemployer plans on behalf of employees that participate in approximately 250 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 2016 through 2020. The average contribution related to these local unions was less than $0.1 million , and the largest contribution was $3.5 million . Multiple unions can contribute to a single multiemployer plan. The Company made contributions to at least 62 plans in 2015 , five 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 2015 and 2014 is for the plan year end at January 31, 2014 and 2013 for the Central Pension Fund, December 31, 2014 and 2013 for the Pipeline Industry Benefit Fund, May 31, 2014 and 2013 for the Indiana Laborers Pension Fund, August 1, 2014 and 2013 for the Ohio Operating Engineers Pension Fund, and December 31, 2014 and 2013 for the Minnesota Laborers Pension Fund, 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 2015 , 2014 , and 2013 . (In millions) Pension Protection Act Zone Status Multiemployer Contributions Pension Fund EIN/Pension Plan Number 2015 2014 FIP/RP Status Pending/Implemented 2015 2014 2013 Surcharge Imposed Central Pension Fund 36-6052390-001 Green Green No $7.2 $7.7 $8.5 No Pipeline Industry Benefit Fund 73-0742835-001 Green Green No 4.0 5.1 5.3 No Indiana Laborers Pension Fund (1) 35-6027150-001 Yellow Yellow Implemented 4.1 3.5 2.4 No Ohio Operating Engineers Pension Fund 31-6129968-001 Green Green No 2.2 1.7 1.5 No Minnesota Laborers Pension Fund 41-6159599-001 Green Green No 1.8 2.2 2.8 No Other 13.4 12.2 12.7 Total Contributions $32.7 $32.4 $33.2 (1) Federal law requires pension plans in endangered status to adopt a funding improvement plan 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. Since the Indiana Laborers Pension Fund became endangered as of June 1, 2008, a funding improvement plan was previously set in place to begin June 1, 2009. The funding improvement plan requires that the plan's funded percentage improve at least 33 percent of the way to 100 percent over a 10 -year period. The target for this plan under the law is a funded percentage of 78 percent by 2019. The plan must also meet the federal minimum funding requirements during this 10-year period. As of December 31, 2015, the plan has met these funding requirements and is expected to meet the target funded percentage by 2019. While not considered significant to the Company, there are nine plans in red zone status receiving Company contributions. There are also nine other plans where Company contributions exceed 5 percent of each plan's total contributions and one of these plans was considered significant to the Company. Defined Contribution Plan The Company also has defined contribution retirement savings plans that are 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 2015 , 2014 and 2013 , the Company made contributions to these plans of $11.0 million , $9.1 million , and $7.5 million , respectively.

Borrowing Arrangements

Borrowing Arrangements	12 Months Ended
Borrowing Arrangements	Dec. 31, 2015
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) 2015 2014 Utility Holdings Fixed Rate Senior Unsecured Notes 2015, 5.45% — 75.0 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 — 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 — 2055, 4.51% 40.0 — Total Utility Holdings 1,000.0 875.0 Indiana Gas Fixed Rate Senior Unsecured Notes 2015, Series E, 7.15% — 5.0 2015, Series E, 6.69% — 5.0 2015, Series E, 6.69% — 10.0 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 96.0 116.0 SIGECO First Mortgage Bonds 2016, 1986 Series, 8.875% 13.0 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 0.784%, 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 — 2055, 2015 Series Warrick County, 2.375%, tax-exempt 15.2 — Total SIGECO 305.7 267.5 At December 31, (In millions) 2015 2014 Vectren Capital Corp. Fixed Rate Senior Unsecured Notes 2015, 5.31% — 75.0 2016, 6.92% 60.0 60.0 2017, 3.48% 75.0 75.0 2019, 7.30% 60.0 60.0 2022, 3.33% 75.0 — 2025, 4.53% 50.0 50.0 2030, 3.90% 75.0 — Total Vectren Capital Corp. 395.0 320.0 Total long-term debt outstanding 1,796.7 1,578.5 Current maturities of long-term debt (73.0 ) (170.0 ) Unamortized debt premium & discount - net (0.9 ) (1.2 ) Total long-term debt-net $ 1,722.8 $ 1,407.3 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. Vectren Capital 2013 Term Loan On August 6, 2013 , Vectren Capital entered into a $100 million three -year term loan agreement. Loans under the term loan agreement bore interest at either a Eurodollar rate or base rate plus an additional margin which was based on the Company's credit rating. Interest periods were variable and could have ranged from seven days to six months. The proceeds from this debt transaction were used to repay short-term borrowings outstanding under Vectren Capital's credit facility. The loan agreement was guaranteed by Vectren Corporation and included customary representations, warranties, and covenants, including a leverage covenant consistent with leverage covenants contained in other Vectren Capital borrowing arrangements. The Company received net proceeds of approximately $100 million in August 2013 and repaid the loan in August of 2014. SIGECO 2013 Debt Refund and Reissuance During the second quarter of 2013, approximately $111 million of SIGECO's tax-exempt long-term debt was redeemed at par plus accrued interest. Approximately $62 million of tax-exempt long-term debt was reissued on April 26, 2013 at interest rates that are fixed to maturity, receiving proceeds, net of issuance costs, of approximately $60 million . The terms are $22.2 million at 4.00 percent per annum due 2038 , and $39.6 million at 4.05 percent per annum due 2043 . The remaining approximately $49 million of the called debt was remarketed on August 13, 2013 . The remarketed tax-exempt debt has a fixed interest rate of 1.95 percent per annum until September 13, 2017 . SIGECO closed on this remarketing and received net proceeds of $48.3 million on August 28, 2013 . Utility Holdings 2013 Debt Call and Reissuance On April 1, 2013 , VUHI exercised a call option at par on Utility Holdings' $121.6 million 6.25 percent senior unsecured notes due in 2039 . This debt was refinanced on June 5, 2013 , with proceeds from a private placement note purchase agreement entered into on December 20, 2012 with a delayed draw feature. It provides for the following tranches of notes: (i) $45 million , 3.20 percent senior guaranteed notes, due June 5, 2028 and (ii) $80 million , 4.25 percent senior guaranteed notes, due June 5, 2043 . Total proceeds received from these notes, net of issuance costs, were $44.8 million and $79.6 million , respectively. The notes are unconditionally guaranteed by Indiana Gas, SIGECO and VEDO. On August 22, 2013 , VUHI entered into a private placement note purchase agreement with a delayed draw feature, pursuant to which institutional investors agreed to purchase $150 million of senior guaranteed notes with a fixed interest rate of 3.72 percent per annum, due December 5, 2023 . The notes were unconditionally guaranteed by Indiana Gas, SIGECO, and VEDO. On December 5, 2013 , the Company received net proceeds of $149.1 million from the issuance of the senior guaranteed notes, which were used to refinance $100 million of 5.25 percent senior notes that matured August 1, 2013 , for capital expenditures, and for general corporate purposes. Mandatory Tenders At December 31, 2015 , 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 2015 sinking fund requirement by this means and, accordingly, the sinking fund requirement for 2015 is excluded from Current liabilities in the Consolidated Balance Sheets . At December 31, 2015 , $1.3 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 $3.1 billion at December 31, 2015 . Consolidated maturities of long-term debt during the five years following 2015 (in millions) are $73.0 in 2016 , $75.0 in 2017 , $100.0 in 2018 , $60.0 in 2019 , $100.0 in 2020 , and $1,387.8 thereafter. Debt Guarantees Vectren Corporation guarantees Vectren Capital’s long-term debt, including current maturities, and short-term debt. Vectren Capital’s long-term debt, including current maturities outstanding at December 31, 2015 totaled $395 million . Vectren Capital had no short-term obligations outstanding at December 31, 2015. Utility Holdings’ currently outstanding long-term and short-term debt is jointly and severally guaranteed by Indiana Gas, SIGECO, and VEDO. Utility Holdings’ long-term debt and short-term debt outstanding at December 31, 2015 , totaled $1 billion and $15 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, 2015 the Company was in compliance with all financial covenants. Short-Term Borrowings At December 31, 2015 , 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 $335 million was available for the Utility Group operations and $250 million was available for the wholly owned Nonutility Group and corporate operations. On October 31, 2014, Vectren Capital’s and Utility Holdings’ short-term credit facilities, totaling $600 million in borrowing capacity, were amended to extend their maturity until October 31, 2019. These facilities are used to supplement working capital needs and also to fund capital investments and debt redemptions until financed on a long-term basis. The Vectren Capital facility has a letter of credit limit of $50 million and the Utility Holdings' facility has a letter of credit limit of $100 million . As of December 31, 2015, there were no letters of credit outstanding under the facilities. Following is certain information regarding these short-term borrowing arrangements. Utility Group Borrowings Nonutility Group Borrowings (In millions) 2015 2014 2013 2015 2014 2013 As of Year End Balance Outstanding $ 14.5 $ 156.4 $ 28.6 $ — $ — $ 40.0 Weighted Average Interest Rate 0.55 % 0.50 % 0.29 % N/A N/A 1.27 % Annual Average Balance Outstanding $ 53.8 $ 35.6 $ 119.6 $ 24.8 $ 34.5 $ 119.3 Weighted Average Interest Rate 0.38 % 0.34 % 0.34 % 1.33 % 1.29 % 1.35 % Maximum Month End Balance Outstanding $ 121.5 $ 156.4 $ 176.1 $ 69.1 $ 76.3 $ 173.8 Throughout the years presented, Utility Holdings has successfully placed commercial paper as needed.

Common Shareholder's Equity

Common Shareholder's Equity	12 Months Ended
Common Shareholder's Equity	Dec. 31, 2015
Stockholders' Equity Note [Abstract]
Common Shareholder's Equity	Common Shareholders’ Equity Authorized, Reserved Common and Preferred Shares At December 31, 2015 and 2014 , 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 5.1 million shares at December 31, 2015 and 5.3 million shares at December 31, 2014 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, 2015 and 2014 , there were 392.1 million and 392.2 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
Earnings Per Share	Dec. 31, 2015
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, 2015 : Year Ended December 31, (In millions, except per share data) 2015 2014 2013 Numerator: Reported net income (Numerator for Diluted EPS) $ 197.3 $ 166.9 $ 136.6 Denominator: Weighted-average common shares outstanding (Basic EPS) 82.7 82.5 82.3 Conversion of share-based compensation arrangements 0.0 0.0 0.1 Adjusted weighted-average shares outstanding and assumed conversions outstanding (Diluted EPS) 82.7 82.5 82.4 Basic earnings per share $ 2.39 $ 2.02 $ 1.66 Diluted earnings per share $ 2.39 $ 2.02 $ 1.66 For the years ended December 31, 2015 , 2014 , and 2013 , all options and equity based instruments were dilutive but immaterial.

Accumulated Other Comprehensive

Accumulated Other Comprehensive Income	12 Months Ended
Accumulated Other Comprehensive Income	Dec. 31, 2015
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: 2013 2014 2015 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 Unconsolidated affiliates $ (4.6 ) $ 4.6 $ — $ — $ — $ — $ — Pension & other benefit costs (2.6 ) 1.4 (1.2 ) (1.0 ) (2.2 ) 0.1 (2.1 ) Deferred income taxes 2.9 (2.4 ) 0.5 0.4 0.9 — 0.9 Accumulated other comprehensive income (loss) $ (4.3 ) $ 3.6 $ (0.7 ) $ (0.6 ) $ (1.3 ) $ 0.1 $ (1.2 ) Accumulated other comprehensive income arising from unconsolidated affiliates was previously primarily the Company’s portion of ProLiance Holdings, LLC’s accumulated comprehensive income related to use of cash flow hedges. (See Note 7 for more information on ProLiance.)

Share-Based Compensation & Defe

Share-Based Compensation & Deferred Compensation Arrangements	12 Months Ended
	Dec. 31, 2015
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) 2015 2014 2013 Total cost of share-based compensation $ 19.4 $ 25.2 $ 14.8 Less capitalized cost 4.8 5.3 2.8 Total in other operating expense 14.6 19.9 12.0 Less income tax benefit in earnings 5.7 7.9 4.8 After tax effect of share-based compensation $ 8.9 $ 12.0 $ 7.2 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 less than 100,000 units as of December 31, 2015, 2014 or 2013. 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, 2015 and 2014, and changes during the years ended December 31, 2015 and 2014, follow: Equity Awards Wtd. Avg. Grant Date Liability Awards Units Fair value Units Fair value Awards at January 1, 2014 79,957 $ 29.12 731,251 Granted 5,910 31.24 331,344 Vested (51,594 ) 28.36 (347,031 ) Forfeited — — (22,405 ) Awards at December 31, 2014 34,273 $ 30.55 693,159 $ 46.23 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 As of December 31, 2015 , there was $15.4 million of total unrecognized compensation cost associated with outstanding grants. That cost is expected to be recognized over a weighted-average period of 1.6 years. The total fair value of shares vested for liability awards during the years ended December 31, 2015 , 2014 , and 2013 , was $16.6 million , $15.1 million , and $5.7 million , respectively. The total fair value of equity awards vesting during the years ended December 31, 2015 , 2014 , and 2013 was $1.1 million , $0.9 million , $0.4 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 $31.2 million at both December 31, 2015 and 2014. Other than $1.4 million , which is classified in Accrued liabilities at both December 31, 2015 and 2014 , the liability is included in Deferred credits & other liabilities . The impact of these plans on Other operating expenses was expense of $0.1 million in 2015 , $5.0 million in 2014 and $4.0 million in 2013 . The amount recorded in earnings related to the investment activities in Vectren phantom stock associated with these plans during the years ended December 31, 2015 , 2014 , and 2013 , was income of $0.4 million , and cost of $4.0 million and $2.6 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 $30.1 million and $32.3 million at December 31, 2015 and 2014 , respectively. Those investments generated losses of $2.1 million in 2015 , and earnings of $2.8 million in 2014 , and $4.8 million in 2013 . This activity is reflected in Other income - net.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
Commitments and Contingencies	Dec. 31, 2015
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 2015 and thereafter (in millions) are $8.6 in 2016 , $5.7 in 2017 , $3.8 in 2018 , $2.1 in 2019 , $1.9 in 2020 , and $8.3 thereafter. Total lease expense, for these type of commitments, (in millions) was $11.1 in 2015 , $13.2 in 2014 , and $9.9 in 2013 . The Company’s regulated utilities have both firm and non-firm commitments to purchase natural gas, electricity, and coal as well as certain transportation and storage rights and certain contracts are firm commitments under five and ten-year arrangements. Costs arising from these commitments, while significant, are pass-through costs, generally collected dollar-for-dollar from retail customers through regulator-approved cost recovery mechanisms. Performance Guarantees & Product Warranties In the normal course of business, wholly owned subsidiaries, such as Energy Systems Group (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, in its role as a general contractor in the performance contracting industry, at December 31, 2015 , there are 42 open surety bonds supporting future performance. The average face amount of these obligations is $9.8 million , and the largest obligation has a face amount of $51.0 million . The maximum exposure from these obligations is limited by the level of work already completed and guarantees issued to ESG by various subcontractors. At December 31, 2015 , approximately 39 percent of work was 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. 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; rather, they represent parental guarantees of subsidiary obligations to allow those subsidiaries the flexibility to conduct business without posting other forms of collateral. At December 31, 2015 , parent level guarantees support a maximum of $185 million of ESG's performance contracting commitments, warranty obligations, project guarantees, and energy savings guarantees. Further, an energy facility operated by ESG and managed by Keenan Ft. Detrick Energy, LLC (Keenan), is governed by an operations agreement. All payment obligations to Keenan under this agreement are also guaranteed by the Company. The Company guarantee of the Keenan Ft. Detrick Energy 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. In addition, the Company also has other guarantees outstanding, including letters of credit, supporting other consolidated subsidiary operations. While there can be no assurance that the Company guarantee provisions will not be called upon, the Company believes that the likelihood of a material amount being triggered under any of these provisions is remote. 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
Gas Rate & Regulatory Matters	Dec. 31, 2015
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 a 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. In April 2011, Indiana Senate Bill 251 (Senate Bill 251) was signed into Indiana law. The law provides a framework to recover 80 percent of federally mandated costs through a periodic rate adjustment mechanism outside of a general rate case. Such costs include a return on the federally mandated capital investment, based on the overall rate of return most recently approved by the Commission, along with recovery of depreciation and other operating costs associated with these mandates. The remaining 20 percent of those costs is deferred for future recovery in the utility's next general rate case. In April 2013, Indiana Senate Bill 560 (Senate Bill 560) was signed into Indiana law. This legislation supplements Senate Bill 251 described above, and provides for cost recovery outside of a base rate proceeding for projects that either improve electric and gas system reliability and safety or are economic development projects that provide rural areas with access to gas service. Provisions of the legislation require that, among other things, requests for recovery include a seven-year project plan. Once the plan is approved by the IURC, 80 percent of such costs are eligible for current recovery using a periodic rate adjustment mechanism. Recoverable costs include a return on the investment that reflects the current capital structure and associated costs, with the exception of the rate of return on equity, which remains fixed at the rate determined in the Company's last rate case. Recoverable costs also include recovery of depreciation and other operating expenses. The remaining 20 percent of project costs are deferred and recovered in the utility’s next general rate case, which must be filed before the expiration of the seven-year plan. The adjustment mechanism is capped at an annual increase in retail revenues of no more than two percent. In June 2011, Ohio House Bill 95 (House Bill 95) was signed into law. Outside of a base rate proceeding, this legislation permits a natural gas utility to apply for recovery of much of its capital expenditure program. The 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 recognized in the Consolidated Statements of Income currently. The recording of post-in-service carrying costs and depreciation deferral is limited by individual qualifying projects to three years after being placed into service at SIGECO and four years after being placed into service at Indiana Gas. At December 31, 2015 and December 31, 2014 , the Company has regulatory assets totaling $19.9 million and $16.4 million , respectively, associated with the deferral of depreciation and debt-related post-in-service carrying cost activities. Beginning in 2014, all bare steel and cast iron replacement activities are now part of the Company’s seven -year capital investment plan filed pursuant to Senate Bill 251 and 560, discussed further below. Requests for Recovery under Indiana Regulatory Mechanisms On August 27, 2014, the IURC issued an Order (August 2014 Order) approving the Company’s seven-year capital infrastructure replacement and improvement plan, beginning in 2014, and the proposed accounting authority and recovery. Compliance projects and other infrastructure improvement projects were approved pursuant to Senate Bill 251 and 560, respectively. As provided in the two laws, the Order approved semi-annual filings for rate recovery of 100 percent of the costs, inclusive of return, related to these capital investments and operating expenses, with 80 percent of the costs, including a return, recovered currently via an approved tracking mechanism and 20 percent of the costs deferred and recovered in the Company’s next base rate proceeding. In addition, the Order established guidelines to annually update the seven-year capital investment plan. Finally, the Order approved the Company’s proposal to recover eligible costs via a fixed monthly charge per residential customer. On September 26, 2014, the OUCC filed an appeal of the IURC's finding that the remaining value of retired assets replaced during the infrastructure projects should not be netted against the cost being recovered in the tracking mechanism. In June 2015, the Indiana Court of Appeals issued an opinion in favor of the Company that affirmed the IURC's August 2014 Order approving the infrastructure plan. On January 14, 2015, the IURC issued an Order approving the Company’s initial request for recovery of the revenue requirement through June 30, 2014 as part of its approved seven-year plan. Also, consistent with the guidelines set forth in the original August 2014 Order, the IURC approved the Company’s update to its seven-year plan, to reflect changes to project prioritization as a result of both additional risk modeling and changes to estimated project costs. On April 1, 2015, the Company filed its second request for recovery of the revenue requirement associated with capital investment and applicable operating costs through December 31, 2014. On June 1, 2015, the Company amended its case to delay the recovery of a portion of the investment associated with Senate Bill 560 made from July 2014 to December 2014, until its third filing when it committed to provide additional project detail for the later years of the plan. This commitment was as a result of an Indiana Court of Appeals decision regarding the approval of Northern Indiana Public Service Company's (NIPSCO) proposed electric Transmission, Distribution, and Storage Improvement Charge (TDSIC) plan, and challenges to TDSIC plans filed by other Indiana utilities. On July 22, 2015, the IURC issued an Order, approving the recovery of these investments consistent with the Company's proposal, with modification, specifically to the rate of return applicable to the Senate Bill 251 compliance component. The IURC found that the overall rate of return to be applied to the investment in determining the revenue requirement is to be updated with each filing, reflecting the current capital structure and associated costs, with the exception of the rate of return on equity, which remains fixed at the rate determined in the Company's last base rate case. This IURC interpretation of the overall rate of return to be used is the same as that already in place for the Senate Bill 560 component. On October 1, 2015, the Company filed its third request for recovery of the revenue requirement associated with capital investment and applicable operating costs through June 30, 2015, including investment associated with Senate Bill 560 made from July 2014 to December 2014 that had been delayed in the second request. The Company provided an update to its seven-year plan, as well as additional detail on the planned investments included in the plan. The updated plan reflects capital expenditures of approximately $1 billion , an increase of $100 million from the previous plan, of which $272 million has been spent as of December 31, 2015 . The ability to include new projects as part of an updated Senate Bill 560 plan has been challenged in this case. As of December 31, 2015, the Commission has approved project categories that encompass planned infrastructure investments during the plan term of approximately $800 million of the proposed $1 billion of capital spend. The remaining proposed amount is now pending approval in the third request for recovery. Pursuant to the process outlined in Senate Bill 560, the Company expects an order in early 2016. At December 31, 2015 and December 31, 2014 , the Company has regulatory assets totaling $28.6 million and $11.4 million , respectively, associated with the return on investment as well as the deferral of depreciation and other operating expenses. 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 and certain other infrastructure. 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. To date, the Company has made capital investments under this rider totaling $202.5 million . Regulatory assets associated with post-in-service carrying costs and depreciation deferrals were $18.2 million and $13.1 million at December 31, 2015 and December 31, 2014 , respectively. Due to the expiration of the initial five -year term for the DRR in early 2014, the Company filed a request in August 2013 to extend and expand the DRR. 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 other infrastructure investments. The Order limits the resulting DRR fixed charge per month for residential and small general service customers to specific graduated levels over the next five years. The Company's five-year capital expenditure plan related to these infrastructure investments for calendar years 2013 through 2017 totals approximately $200 million . 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; however, the plan is not expected to exceed those caps. In addition, the Order approved the Company's commitment that the DRR can only be further extended as part of a base rate case. On August 26, 2015, the Company received an Order approving its adjustment to the DRR for recovery of costs incurred through December 31, 2014. 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 near the expiration of the DRR. As such, the bill impact limits discussed below are not expected to be reached given the Company's capital expenditure plan during the remaining two-year time frame. 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 have 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. As of December 31, 2015, the Company's deferrals have not reached this bill impact cap. In addition, the Orders approved the Company's proposal that subsequent requests for accounting authority will be filed annually in April. The Company submitted its most recent annual filing on April 30, 2015, which covers the Company’s capital expenditure program through calendar year 2015. During 2015 and 2014 , these approved capital expenditure programs under House Bill 95 generated Other income associated with the debt-related post-in-service carrying costs totaling $6.4 million and $3.9 million , respectively. Deferral of deprecation and property tax expenses related to these programs in 2015 and 2014 totaled $5.4 million and $3.1 million , respectively. Other Regulatory Matters Indiana Gas GCA Cost Recovery Issue On July 1, 2014, Indiana Gas filed its recurring quarterly Gas Cost Adjustment (GCA) mechanism, which included recovery of gas cost variances incurred for the period January through March 2014. In August 2014, the OUCC filed testimony opposing the recovery of approximately $3.9 million of natural gas commodity purchases incurred during this period on the basis that a gas cost incentive calculation had not been properly performed. The calculation at issue is performed by the Company's supply administrator. In the winter period at issue, a pipeline force majeure event caused the gas to be priced at a location that was impacted by the extreme winter temperatures. After further review, the OUCC modified its position in testimony filed on November 5, 2014, and suggested a reduced disallowance of $3 million . The IURC moved this specific issue to a sub-docket proceeding. On April 1, 2015, a stipulation and settlement agreement between the Company, the OUCC, and the Company’s supply administrator was filed in this proceeding. The IURC issued an Order on June 10, 2015 which approved the stipulation and settlement agreement, which resulted in recovery of approximately $1.4 million of the disputed amount via the Company’s GCA mechanism, with the remaining $1.6 million received from the gas supply administrator. Indiana Gas & SIGECO Gas Decoupling Extension Filing On September 9, 2015, the IURC issued an Order granting the extension of the current decoupling mechanism in place at both Indiana gas companies and recovery of conservation program costs through December 2019.

Electric Rate and Regulatory Ma

Electric Rate and Regulatory Matters	12 Months Ended
Electric Rate and Regulatory Matters	Dec. 31, 2015
Public Utilities, General Disclosures [Abstract]
Electric Rate and Regulatory Matters	Electric Rate and Regulatory Matters SIGECO Electric Environmental Compliance Filing On January 28, 2015, the IURC issued an Order (January 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 mercury and air toxic standards (MATS) effective in 2015 and to address an outstanding Notice of Violation (NOV) from the EPA. As of December 31, 2015, approximately $30 million has been spent on equipment to control mercury in both air and water emissions, and $29 million to address the issues raised in the NOV proceeding on the increase in sulfur trioxide emissions. The total investment is estimated to be between $75 million and $85 million . The Order approved the Company’s request for deferred accounting treatment, as supported by provisions under Indiana Senate Bill 29 (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 occurring in 2015 and 2016. As of December 31, 2015 , the Company has approximately $2.7 million deferred related to depreciation, property tax, and operating expense, and $1.1 million deferred related to post-in-service carrying costs. In March 2015, the Company was notified that certain parties had filed a Notice of Appeal with the Indiana Court of Appeals in response to the IURC's Order. In June 2015, Joint Appellants’ Citizens Action Coalition of Indiana, Inc., Sierra Club, Inc., and Valley Watch, Inc. (the appellants) filed a brief which challenged the sufficiency of the findings in the IURC's January Order approving the Company’s investments and proposed accounting treatment in terms of whether that Order made certain findings required by statute. On October 29, 2015, the Indiana Court of Appeals issued its opinion affirming the IURC’s findings with regard to equipment required to comply with MATS and certain national pollutant discharge elimination system rules (approximately $35 million ). The Court remanded the case back to the IURC so that it can make the findings required by statute with regard to equipment required by the NOV (approximately $40 million ). On February 12, 2016, the appellants filed a petition to reopen the evidentiary record in the case in order to submit additional evidence. The Company has opposed the motion and believes the IURC already has a sufficient record in this case. As it pertains to the equipment requirement required by the NOV, given the Commission’s previous approval of this project, the Company believes the Commission will make these findings and issue a new order in support of the project. 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; 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 year ended December 31, 2015 , 2014, and 2013, the Company recognized electric utility revenue of $10.1 million , $8.7 million , and $5.0 million , respectively, associated with this approved lost margin recovery mechanism. On March 28, 2014, Indiana Senate Bill 340 was signed into law. This legislation ended electric DSM programs on December 31, 2014 that had been conducted to meet the energy savings requirements established by the IURC in 2009. The legislation also allows for industrial customers to opt out of participating in energy efficiency programs. As of January 1, 2015, approximately 80 percent of the Company’s eligible industrial load has opted out of participation in the applicable energy efficiency programs. The Company filed a request for IURC approval of a new portfolio of DSM programs on May 29, 2014 to be offered in 2015. On October 15, 2014, the IURC issued an Order approving a Settlement between the OUCC and the Company regarding the new portfolio of DSM programs effective January 2015, and new programs were implemented during the first quarter of 2015. On May 6, 2015, Indiana's governor signed Indiana Senate Bill 412 (Senate Bill 412) into law requiring electricity suppliers to submit energy efficiency plans to the IURC at least once every three years. Senate Bill 412 also supports 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. In September 2015, the Company received an Order to continue offering and recovering the associated cost of its 2015 programs until March 31, 2016. In October 2015, the OUCC and Citizens Action Coalition of Indiana filed testimony recommending the rejection of the Company’s plan, contending it was not reasonable under the terms of Senate Bill 412 due to the program design and the Company’s proposal to recover lost revenues and incentives associated with the measures. Vectren filed rebuttal testimony in October 2015 defending the plan’s compliance with Senate Bill 412. The Company expects an order in the first quarter of 2016. 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. The joint parties seek to reduce the 12.38 percent ROE used in the MISO transmission owners’ rates, including SIGECO’s formula transmission rates, to 9.15 percent , and to set a capital structure in which the equity component does not exceed 50 percent . A second customer complaint case was filed on February 11, 2015 as the maximum FERC-allowed refund period for the November 12, 2013 case ended February 11, 2015. As of December 31, 2015 , the Company had invested approximately $157.7 million in qualifying projects. The net plant balance for these projects totaled $140.2 million at December 31, 2015 . These joint complaints are similar to a complaint against the New England Transmission Owners (NETO) filed in September 2011, which requested that the 11.14 percent incentive return granted on qualifying investments in NETO be lowered. On October 16, 2014, the FERC issued an Order in the NETO case approving a 10.57 percent return on equity and a calculation methodology. The FERC acknowledged that the pending complaint raised against the MISO transmission owners is reasonable and denied the portion of the complaint addressing the equity component of the capital structure. An initial decision from its administrative law judge was received on December 22, 2015, authorizing the transmission owners to collect a Base ROE of 10.32 percent from November 12, 2013 through February 11, 2015 (the “first refund period”). The FERC is expected to rule on the proposed order in late 2016. A procedural schedule has been established for the second customer complaint case, establishing a target date of June 30, 2016 for the initial decision. 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. Once the FERC sets a new ROE in the complaint case, this adder will be applied to that ROE, with retroactive billing to occur back to January 7, 2015. The Company has established a reserve considering both the initial decision and the approved 50 basis points adder.

Environmental Matters

Environmental Matters	12 Months Ended
Environmental Matters	Dec. 31, 2015
Environmental Matters Disclosure [Abstract]
Environmental Matters	Environmental Matters 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. With the trend toward stricter standards, greater regulation, and more extensive permit requirements, the Company's investment in compliant infrastructure, and the associated operating costs have increased and are expected to increase in the future. Similar to the costs associated with federal mandates in the Pipeline Safety Law, Indiana Senate Bill 251 (Senate Bill 251) is also applicable to federal environmental mandates impacting SIGECO's electric operations. 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 back to the appellate court for further proceedings consistent with the opinion. MATS compliance was required to commence April 16, 2015, and the Company continues to operate in full compliance with the MATS rule. On December 15, 2015, the appellate court agreed to keep the current MATS rule in place while the agency completes the supplemental cost analysis ordered by the Court. 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 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 regarding SO3 emissions from the EPA. The total investment is estimated to be between $75 million and $85 million , roughly half of which has been spent to control mercury in both air and water emissions, and the remaining investment has been made to address the issues raised in the NOV. In March 2015, the Company was notified that certain parties had filed a Notice of Appeal with the Indiana Court of Appeals in response to the IURC's Order. In June 2015, Joint Appellants’ Citizens Action Coalition of Indiana, Inc., Sierra Club, Inc., and Valley Watch, Inc. (the appellants) filed a brief which challenged the sufficiency of the findings in the IURC's January Order approving the Company’s investments and proposed accounting treatment in terms of whether that Order made certain findings required by statute. On October 29, 2015, the Indiana Court of Appeals issued its opinion affirming the IURC’s findings with regard to equipment required to comply with MATS and certain national pollutant discharge elimination system rules (approximately $35 million ). The Court remanded the case back to the IURC so that it can make the findings required by statute with regard to equipment required by the NOV (approximately $40 million ). On February 12, 2016, the appellants filed a petition to reopen the evidentiary record in the case in order to submit additional evidence. The Company has opposed the motion and believes the IURC already has a sufficient record in this case. As it pertains to the equipment requirement required by the NOV, given the Commission’s previous approval of this project, the Company believes the Commission will make these findings and issue a new order in support of the project. 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. The EPA is expected to make final determinations as to whether a region is in attainment for the new NAAQS in 2018 based upon monitoring data from 2014-2016. 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. 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, in which 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 is currently working with the state of Indiana on voluntary measures that the Company may take 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 SO 2 and 90 percent controlled for NOx. 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 Company will continue to reuse a majority of its ash. Legislation is currently being considered 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. Opening briefs were filed by those parties in December of 2015, with full briefing not expected to be complete until May 2016. 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, the Company prepared preliminary cost estimates to retire the ash ponds at the end of their useful lives based on interpretation of the available closure alternatives contemplated in the final rule that 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. At this time the Company does not believe that these rules are applicable to its Warrick generating unit, as this unit is part of a larger generating station that predominantly serves an adjacent industrial facility. The Company continues to refine the assumptions, engineering analyses and resulting cost estimates. Further analysis and the refinement of assumptions may result in estimated costs that could be significantly in excess of the current range of $35 million to $80 million. At September 30, 2015, the Company recorded an approximate $25 million asset retirement obligation (ARO). The recorded ARO reflected the present value of the approximate $35 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. Effluent Limitation Guidelines (ELGs) Under the Clean Water Act, the EPA sets technology-based guidelines for water discharges from new and existing 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 within the 2018-2023 time frame. Current wastewater discharge permits for the Brown and Culley power plants expire in October and December 2016, respectively. The Company is working with the State on permit renewals which will include a compliance schedule for ELGs. In no event will compliance with the ELGs be required prior to November 2018. The ELGs work in tandem with the recently released 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. Cooling Water Intake Structures Section 316(b) of the Clean Water Act requires that 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. To comply, the Company believes that capital investments will likely be in the range of $4 million to $8 million . Climate Change On August 3, 2015, the EPA released its final Clean Power Plan (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 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 it 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 the State of 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. The stay will remain in place while the lower court concludes its review, with oral arguments to be heard in June 2016 under the existing accelerated schedule. Among other things, the stay is anticipated to delay the requirement to submit a final SIP by the September 2016 deadline. Apart from the delay, the Court's action creates additional uncertainty as to the future of the rule and presents further challenges as the Company proceeds with its integrated resource planning process later this year. In the event that 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 the State of Indiana will file a SIP has yet to be finally determined. Pending that determination, the electric utilities in Indiana are working with the state's designated agency to analyze various compliance options for consideration and possible integration into a state plan submittal. Indiana is the 5th largest carbon emitter in the nation in tons of CO2 produced from electric generation. In 2013, Indiana’s electric utilities generated 105.6 million tons of CO2. The Company’s share of that total was 6.3 million , or less than 6 percent . From 2005 to 2014, the Company’s emissions of CO2 have declined 27 percent (on a tonnage basis). These reductions have come from the retirement of F.B. Culley Unit 1, expiration of municipal contracts, electric conservation, the addition of renewable generation, and the installation of more efficient dense pack turbine technology. 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 clean energy sources due to the long-term wind contracts and landfill gas investment. See further details on these clean energy sources in Item 1. With respect to CO2 emission rate, since 2005 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 the State’s average CO2 emission rate of 1,923 lbs CO2/MWh. The Company plans to consider these reductions in CO2 emissions and renewable generation when working 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 State of Indiana to assess the final rule and to develop a plan that is the least cost to its customers. While the Company cannot reasonably estimate the total cost to comply with the CCR, ELG and CPP regulations at this time, the Company is exploring various compliance options ranging from continued compliance to retirement of units. The cost of compliance with these new regulations could be significant. The Company believes that such compliance costs would be considered a federally mandated cost of providing electricity, and therefore, should be recoverable from customers through Senate Bill 251 as referenced above, Senate Bill 29, which was used by the Company to recover its initial pollution control investments, or through other forms of rate recovery. These compliance alternatives, including the impact on customer rates, will be fully considered as part of the Company’s public integrated resource planning process to be conducted in 2016. 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 $43.4 million ( $23.2 million at Indiana Gas and $20.2 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 to date approximately $14.8 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, 2015 and December 31, 2014 , approximately $3.3 million and $3.6 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
Fair Value Measurements	Dec. 31, 2015
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, 2015 2014 (In millions) Carrying Amount Est. Fair Value Carrying Amount Est. Fair Value Long-term debt $ 1,795.8 $ 1,909.5 $ 1,577.3 $ 1,754.5 Short-term borrowings & notes payable 14.5 14.5 156.4 156.4 Cash & cash equivalents 74.7 74.7 86.4 86.4 For the balance sheets presented, 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 long-term debt are generally recovered in customer rates over the life of the refunding issue or over a 15 -year period. Accordingly, any reacquisition 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, 2015 and 2014 , the fair value for these financial instruments was not estimated. The carrying value of these investments at December 31, 2015 and 2014 was approximately $16.1 million and $10.4 million respectively. The increase in carrying value from December 31, 2014 is primarily related to a debt security and note received from the sale of a commercial real estate investment in June 2015.

Segment Reporting

Segment Reporting	12 Months Ended
Segment Reporting	Dec. 31, 2015
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. The Nonutility Group has historically reported five operating segments: Infrastructure Services, Energy Services, Coal Mining, Energy Marketing, and Other Businesses. Energy Services provides energy performance contracting and sustainable infrastructure, such as renewables, distributed generation, and combined heat and power projects. The Infrastructure Services segment 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 $109.5 million in 2015, $94.0 million in 2014, and $54.2 million in 2013. In its 2015 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). Additionally, ProLiance exited the energy marketing business in 2013. The Company reports the Energy Marketing segment information for 2013, which is inclusive of the Company's share of the loss from operations and its share of the loss on sale as recorded by ProLiance Energy. Assets related to the investment in ProLiance Holdings, LLC as described in Note 7 are reported in Other Businesses. Corporate and Other includes 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. 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) 2015 2014 2013 Revenues Utility Group Gas Utility Services $ 792.6 $ 944.6 $ 810.0 Electric Utility Services 601.6 624.8 619.3 Other Operations 40.7 38.3 38.1 Eliminations (40.4 ) (38.0 ) (37.8 ) Total Utility Group 1,394.5 1,569.7 1,429.6 Nonutility Group Infrastructure Services 843.3 779.0 783.5 Energy Services 199.9 129.8 91.3 Coal Mining — 234.3 292.8 Total Nonutility Group 1,043.2 1,143.1 1,167.6 Eliminations, net of Corporate & Other Revenues (3.0 ) (101.1 ) (106.0 ) Consolidated Revenues $ 2,434.7 $ 2,611.7 $ 2,491.2 Profitability Measures - Net Income Utility Group Net Income Gas Utility Services $ 64.4 $ 57.0 $ 55.7 Electric Utility Services 82.6 79.7 75.8 Other Operations 13.9 11.7 10.3 Total Utility Group Net Income 160.9 148.4 141.8 Nonutility Group Net Income (Loss) Infrastructure Services 29.7 43.1 49.0 Energy Services 7.3 (3.2 ) 1.0 Coal Mining — (21.1 ) (16.0 ) Energy Marketing — — (37.5 ) Other Businesses (0.7 ) (0.8 ) (1.0 ) Total Nonutility Group Net Income (Loss) 36.3 18.0 (4.5 ) Corporate & Other Net Income (Loss) 0.1 0.5 (0.7 ) Consolidated Net Income $ 197.3 $ 166.9 $ 136.6 Year Ended December 31, (In millions) 2015 2014 2013 Amounts Included in Profitability Measures Depreciation & Amortization Utility Group Gas Utility Services $ 98.6 $ 93.3 $ 90.5 Electric Utility Services 85.6 85.7 84.0 Other Operations 24.6 24.1 21.9 Total Utility Group 208.8 203.1 196.4 Nonutility Group Infrastructure Services 44.5 36.2 28.8 Energy Services 2.7 3.9 1.7 Coal Mining — 29.9 50.8 Other Businesses 0.3 0.3 0.1 Total Nonutility Group 47.5 70.3 81.4 Consolidated Depreciation & Amortization $ 256.3 $ 273.4 $ 277.8 Interest Expense Utility Group Gas Utility Services $ 35.8 $ 34.9 $ 30.6 Electric Utility Services 27.8 29.0 29.2 Other Operations 2.7 2.7 5.2 Total Utility Group 66.3 66.6 65.0 Nonutility Group Infrastructure Services 16.0 11.1 10.1 Energy Services 1.2 1.3 0.6 Coal Mining — 7.5 9.8 Energy Marketing — — 2.2 Other Businesses 1.2 0.9 0.5 Total Nonutility Group 18.4 20.8 23.2 Corporate & Other (0.2 ) (0.7 ) (0.3 ) Consolidated Interest Expense $ 84.5 $ 86.7 $ 87.9 Income Taxes Utility Group Gas Utility Services $ 40.8 $ 35.7 $ 36.6 Electric Utility Services 49.3 48.1 48.3 Other Operations (2.0 ) (0.6 ) 0.4 Total Utility Group 88.1 83.2 85.3 Nonutility Group Infrastructure Services 19.6 28.9 34.3 Energy Services (7.7 ) (7.8 ) (11.9 ) Coal Mining — (21.8 ) (14.6 ) Energy Marketing — — (23.3 ) Other Businesses 1.5 (0.3 ) (1.6 ) Total Nonutility Group 13.4 (1.0 ) (17.1 ) Corporate & Other (1.8 ) (1.1 ) (1.1 ) Consolidated Income Taxes $ 99.7 $ 81.1 $ 67.1 Year Ended December 31, (In millions) 2015 2014 2013 Capital Expenditures Utility Group Gas Utility Services $ 291.2 $ 245.9 $ 150.5 Electric Utility Services 87.6 92.4 100.0 Other Operations 25.7 23.3 25.8 Non-cash costs & changes in accruals (6.2 ) (10.9 ) (15.2 ) Total Utility Group 398.3 350.7 261.1 Nonutility Group Infrastructure Services 78.1 54.1 79.2 Energy Services 0.5 1.6 6.9 Coal Mining — 41.9 46.2 Total Nonutility Group 78.6 97.6 132.3 Consolidated Capital Expenditures $ 476.9 $ 448.3 $ 393.4 At December 31, (In millions) 2015 2014 2013 Assets Utility Group Gas Utility Services $ 2,707.5 $ 2,605.1 $ 2,286.6 Electric Utility Services 1,782.2 1,659.3 1,679.0 Other Operations, net of eliminations 111.6 152.4 169.7 Total Utility Group 4,601.3 4,416.8 4,135.3 Nonutility Group Infrastructure Services 554.5 538.5 461.7 Energy Services 160.3 87.1 63.0 Coal Mining — — 433.0 Other Businesses, net of eliminations and reclassifications 64.0 120.3 68.4 Total Nonutility Group 778.8 745.9 1,026.1 Corporate & Other 743.7 655.6 824.2 Eliminations (713.9 ) (672.3 ) (896.9 ) Consolidated Assets $ 5,409.9 $ 5,146.0 $ 5,088.7

Additional Balance Sheet & Oper

Additional Balance Sheet & Operational Information	12 Months Ended
Additional Balance Sheet & Operational Information	Dec. 31, 2015
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) 2015 2014 Gas in storage – at LIFO cost $ 40.5 $ 40.5 Coal & oil for electric generation - at average cost 45.0 33.8 Materials & supplies 46.9 42.5 Other 1.3 1.7 Total inventories $ 133.7 $ 118.5 Based on the average cost of gas purchased during December, the cost of replacing inventories carried at LIFO cost approximated that carrying value at December 31, 2015 . Based on the average cost of gas purchased during December, the cost of replacing inventories carried at LIFO cost exceeded that carrying value at December 31, 2014 by $3.0 million . Prepayments & other current assets consist of the following: At December 31, (In millions) 2015 2014 Prepaid gas delivery service $ 30.0 $ 40.7 Prepaid taxes 25.3 37.5 Other prepayments & current assets 25.7 16.4 Total prepayments & other current assets $ 81.0 $ 94.6 Investments in unconsolidated affiliates consist of the following: At December 31, (In millions) 2015 2014 ProLiance Holdings, LLC $ 19.7 $ 20.5 Other nonutility partnerships & corporations 1.0 2.7 Other utility investments 0.2 0.2 Total investments in unconsolidated affiliates $ 20.9 $ 23.4 Other utility & corporate investments consist of the following: At December 31, (In millions) 2015 2014 Cash surrender value of life insurance policies $ 30.1 $ 32.3 Municipal bond — 3.1 Restricted cash & other investments 1.1 1.8 Total other utility & corporate investments $ 31.2 $ 37.2 Goodwill by operating segment follows: At December 31, (In millions) 2015 2014 Utility Group Gas Utility Services $ 205.0 $ 205.0 Nonutility Group Infrastructure Services 58.8 55.2 Energy Services 29.7 29.7 Consolidated goodwill $ 293.5 $ 289.9 Accrued liabilities consist of the following: At December 31, (In millions) 2015 2014 Refunds to customers & customer deposits $ 51.4 $ 51.3 Accrued taxes 39.9 35.8 Accrued interest 19.4 19.1 Deferred compensation & post-retirement benefits 7.2 7.3 Accrued salaries & other 65.7 71.4 Total accrued liabilities $ 183.6 $ 184.9 Asset retirement obligations included in Deferred credits and other liabilities in the Consolidated Balance Sheets roll forward as follows: (In millions) 2015 2014 Asset retirement obligation, January 1 $ 55.0 $ 41.3 Accretion 3.2 1.7 Liabilities incurred in current period 24.2 — Changes in estimates, net of cash payments (0.4 ) 23.8 Vectren Fuels Retirement Obligation — (11.8 ) Asset retirement obligation, December 31 82.0 55.0 Equity in earnings (losses) of unconsolidated affiliates consists of the following: Year Ended December 31, (In millions) 2015 2014 2013 ProLiance Holdings, LLC $ (0.8 ) $ (0.3 ) $ (57.7 ) Other 0.2 0.8 (2.0 ) Total equity in earnings (losses) of unconsolidated affiliates $ (0.6 ) $ 0.5 $ (59.7 ) Other income (expense) – net consists of the following: Year Ended December 31, (In millions) 2015 2014 2013 AFUDC – borrowed funds $ 16.3 $ 11.4 $ 5.9 AFUDC – equity funds 2.6 3.2 0.8 Nonutility plant capitalized interest 0.4 — 0.5 Interest income, net 1.3 1.1 1.1 Other nonutility investment impairment charges (0.1 ) (1.0 ) — Cash surrender value of life insurance policies (2.1 ) 2.8 4.8 All other income 1.9 2.2 4.6 Total other income (expense) – net $ 20.3 $ 19.7 $ 17.7 Supplemental Cash Flow Information: Year Ended December 31, (In millions) 2015 2014 2013 Cash paid (received) for: Interest $ 84.2 $ 87.5 $ 91.0 Income taxes 4.8 69.4 6.8 As of December 31, 2015 and 2014 , the Company has accruals related to utility and nonutility plant purchases totaling approximately $19.4 million and $20.2 million , respectively.

Impact of Recently Issued Accou

Impact of Recently Issued Accounting Guidance	12 Months Ended
Impact of Recently Issued Accounting Guidance	Dec. 31, 2015
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
Recently Issued Accounting Standards	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 and IFRS. The amendments in this guidance state that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This new guidance requires improved disclosures to help users of financial statements better understand the nature, amount, timing, and uncertainty of revenue that is recognized. On July 9, 2015, the FASB approved a one year deferral that became effective through an Accounting Standard Update in August and changed the effective date to annual reporting periods beginning after December 15, 2017, including interim periods, with early adoption permitted, but not before the original effective date of December 15, 2016. The Company is currently evaluating the standard to determine application date, transition method, and impact the standard will have on the financial statements. Financial Reporting of Discontinued Operations In April 2014, the FASB issued new accounting guidance on reporting discontinued operations and disclosures of disposals of a company or entity. The guidance changes the criteria for reporting discontinued operations and provides for enhanced disclosures in this area. Under the new guidance, only disposals representing a strategic shift in operations should be presented as discontinued operations. Those strategic shifts should have a major effect on the organization's operations and financial results. Additionally, the new guidance requires expanded disclosures to provide more information about the assets, liabilities, income, and expenses of discontinued operations. The new guidance also requires disclosure of the pre-tax income attributable to a disposal of a significant part of an organization that does not qualify for discontinued operations reporting. This guidance is effective for fiscal years beginning on or after December 15, 2014, with early adoption permitted. The Company adopted this guidance on January 1, 2015. The Company did not early adopt this guidance in accounting for the sale of its Coal Mining assets. The adoption of this guidance had no impact on the Company's financial statements. 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 deduction from the related debt liability rather than as an asset. Amortization of the costs will continue to be reported as interest expense. This ASU is effective for annual reporting periods beginning after December 15, 2015. Early adoption is permitted. The new guidance will be applied retrospectively to each prior period presented. Upon adoption, the Company will revise its current presentation of debt issuance costs in the Consolidated Balance Sheets; however, the Company does not expect a material impact on its future financial condition, results of operations, or cash flows as a result of the adoption. Balance Sheet Classification of Deferred Taxes In November 2015, the FASB issued new accounting guidance on the presentation of deferred income taxes that requires deferred tax assets and liabilities, along with related valuation allowances, to be classified as noncurrent on the balance sheet. As a result, each tax jurisdiction will now only have one net noncurrent deferred tax asset or liability. The new guidance does not change the existing requirement that prohibits offsetting deferred tax liabilities from one jurisdiction against deferred tax assets of another jurisdiction. This guidance was adopted for the year ended December 31, 2015, and has been applied retrospectively to all periods presented. The effect of this change on the December 31, 2015 and 2014 balance sheets is the reclassification of $15.3 million and $16.3 million in current deferred tax assets to long-term deferred tax liabilities, respectively. The amounts reclassified primarily represent the net of deferred tax assets arising from alternative minimum tax carryforwards and deferred tax liabilities arising from deferred fuels costs. 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
Quarterly Financial Data (Unaudited)	Dec. 31, 2015
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. Note that at June 30, 2014, the Company recorded an estimated loss on the transaction related to the Vectren Fuels sale to Sunrise Coal, including costs to sell, of approximately $32 million, or $20 million after tax. Summarized quarterly financial data for 2015 and 2014 follows: (In millions, except per share amounts) Q1 Q2 Q3 Q4 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 2014 Operating revenues $ 796.8 $ 542.5 $ 595.6 $ 676.8 Operating income 99.0 33.9 84.5 97.1 Net income 51.2 11.9 47.3 56.5 Earnings per share: Basic and Diluted $ 0.62 $ 0.14 $ 0.57 $ 0.68

SCHEDULE II VALUATION AND QUALI

SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES	12 Months Ended
SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES	Dec. 31, 2015
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 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 2013 – Accumulated provision for uncollectible accounts $ 6.8 $ 6.8 $ — $ 6.8 $ 6.8 Year 2015 – Reserve for impaired notes receivable $ — $ 0.2 $ — $ — $ 0.2 Year 2014 – Reserve for impaired notes receivable $ 0.6 $ — $ — $ 0.6 $ — Year 2013 – Reserve for impaired notes receivable $ 0.6 $ — $ — $ — $ 0.6

Summary of Significant Accoun35

Summary of Significant Accounting Policies (Policies)	12 Months Ended
Summary of Significant Accounting Policies (Policies)	Dec. 31, 2015
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 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 All highly liquid investments with an original maturity of three months or less at the date of purchase are considered cash equivalents. Cash and cash equivalents are stated at cost plus accrued interest to approximate fair value.
Allowance for Uncollectible Accounts	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 is performed 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 on when the contracts are expected to be settled. Contracts and any associated collateral with counter-parties subject to master netting arrangements are presented net in the Consolidated Balance Sheets . The offset resulting from carrying the derivative at fair value on the balance sheet is charged to earnings unless it qualifies as a hedge or is subject to regulatory accounting treatment. When hedge accounting is appropriate, the Company assesses and documents hedging relationships between the derivative contract and underlying risks as well as its risk management objectives and anticipated effectiveness. When the hedging relationship is highly effective, derivatives are designated as hedges. The market value of the effective portion of the hedge is marked to market in Accumulated other comprehensive income for cash flow hedges. Ineffective portions of hedging arrangements are marked to market through earnings. For fair value hedges, both the derivative and the underlying hedged item are marked to market through earnings. The offset to contracts affected by regulatory accounting treatment are marked to market as a regulatory asset or liability. Market value for derivative contracts is determined using quoted market prices from independent sources. The Company rarely enters into contracts that have a significant impact to the 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 their 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 $29.4 million in 2015 , $32.3 million in 2014 , and $29.6 million in 2013 . 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 need to maximize the use of observable inputs and minimize the use of unobservable inputs.

Utility & Nonutility Plant (Tab

Utility & Nonutility Plant (Tables)	12 Months Ended
Utility & Nonutility Plant (Tables)	Dec. 31, 2015
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) 2015 2014 Original Cost Depreciation Rates as a Percent of Original Cost Original Cost Depreciation Rates as a Percent of Original Cost Gas utility plant $ 3,279.7 3.4 % $ 3,011.0 3.4 % Electric utility plant 2,695.8 3.3 % 2,602.5 3.3 % Common utility plant 55.0 3.2 % 54.3 3.2 % Construction work in progress 59.9 — 50.9 — Total original cost $ 6,090.4 $ 5,718.7
Nonutility Plant, Net of Depreciation and Amortization	Nonutility Plant , net of accumulated depreciation and amortization follows: At December 31, (In millions) 2015 2014 Computer hardware & software $ 108.8 $ 106.1 Land & buildings 86.4 72.1 Vehicles & equipment 203.0 182.7 All other 16.4 17.1 Nonutility plant - net $ 414.6 $ 378.0

Regulatory Assets & Liabiliti37

Regulatory Assets & Liabilities (Tables)	12 Months Ended
Regulatory Assets & Liabilities (Tables)	Dec. 31, 2015
Regulatory Assets and Liabilities Disclosure [Abstract]
Schedule of Regulatory Assets	Regulatory assets consist of the following: At December 31, (In millions) 2015 2014 Future amounts recoverable from ratepayers related to: Benefit obligations (See Note 11) $ 97.3 $ 105.3 Net deferred income taxes (See Note 10) (16.9 ) (14.8 ) 80.4 90.5 Amounts deferred for future recovery related to: Cost recovery riders & other 54.6 33.3 54.6 33.3 Amounts currently recovered in customer rates related to: Unamortized debt issue costs, reacquisition premiums & hedging proceeds 34.4 35.2 Demand side management programs — 0.6 Indiana authorized trackers 42.6 25.6 Deferred coal costs 28.3 35.3 Ohio authorized trackers 17.6 12.7 Other base rate recoveries 0.1 0.4 123.0 109.8 Total regulatory assets $ 258.0 $ 233.6

Federal Business Unit Acquisi38

Federal Business Unit Acquisition Federal Business Unit Acquisition (Tables)	12 Months Ended
	Dec. 31, 2015
Business Combinations [Abstract]
Schedule of Business Acquisitions, by Acquisition [Table Text Block]	The following table summarizes the allocation of the purchase price to the fair value of the assets acquired and liabilities assumed as of April 1, 2014. (In millions) Adjusted Net Working Capital $ 2.2 Depreciable Fixed Assets 0.4 Customer Relationships (Sales Funnel) 7.1 ESPC Licenses 6.0 Deferred Tax Asset 0.8 Goodwill 27.7 Total Assets acquired $ 44.2 Less: Unfavorable Contract Liabilities Assumed (2.1 ) Total Purchase Consideration $ 42.1

Investment in ProLiance Holdi39

Investment in ProLiance Holdings, LLC (Tables)	12 Months Ended
Investment in ProLiance Holdings, LLC (Tables)	Dec. 31, 2015
Equity Method Investments and Joint Ventures [Abstract]
Summarized Financial Information of Equity Investment [Table Text Block]	The Company's remaining investment in ProLiance at December 31, 2015 , shown at its 61 percent ownership share, is as follows and reflects that it relates primarily to ProLiance's investment in LA Storage discussed below. As of December 31, (In millions) 2015 Cash $ 2.7 Investment in LA Storage 22.2 Other midstream asset investment 4.9 Total investment in ProLiance $ 29.8 Included in: Investments in unconsolidated affiliates 19.7 Other nonutility investments 10.1

Nonutility Real Estate & Othe40

Nonutility Real Estate & Other Legacy Holdings (Tables)	12 Months Ended
Nonutility Real Estate & Other Legacy Holdings (Tables)	Dec. 31, 2015
Nonutility Real Estate Other Legacy Holdings [Abstract]
Investment by type of investment	Further separation by type of investment follows: At December 31, 2015 At December 31, 2014 Value Included In Value Included In (In millions) Carrying Value Other Nonutility Investments Investments in Unconsolidated Affiliates Carrying Other Nonutility Investments Investments in Unconsolidated Affiliates Commercial real estate investment $ — $ — $ — $ 8.0 $ 8.0 $ — Leveraged lease — — — 15.2 15.2 — Other investments 7.0 6.0 1.0 1.8 0.2 1.6 $ 7.0 $ 6.0 $ 1.0 $ 25.0 $ 23.4 $ 1.6

Intangible Assets (Tables)

Intangible Assets (Tables)	12 Months Ended
Intangible Assets (Tables)	Dec. 31, 2015
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, 2015 2014 Amortizing Non-amortizing Amortizing Non-amortizing Customer-related assets $ 23.1 $ — $ 22.5 $ — Market-related assets 0.2 13.0 1.1 13.0 Intangible assets, net $ 23.3 $ 13.0 $ 23.6 $ 13.0

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
Income Taxes (Tables)	Dec. 31, 2015
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, 2015 2014 2013 Statutory rate: 35.0 % 35.0 % 35.0 % State & local taxes-net of federal benefit 3.6 4.1 4.6 Amortization of investment tax credit (0.2 ) (0.3 ) (0.3 ) Depletion — (2.6 ) (1.5 ) Domestic production deduction (1.0 ) (1.1 ) — Energy efficiency building deductions (2.3 ) (1.6 ) (3.8 ) Research and development credit (1.6 ) (0.3 ) (0.6 ) Other tax credits (0.1 ) (0.2 ) (1.1 ) All other-net 0.2 (0.3 ) 0.7 Effective tax rate 33.6 % 32.7 % 33.0 %
Significant components of the net deferred tax liability (assets)	Significant components of the net deferred tax liability follow: At December 31, (In millions) 2015 2014 Noncurrent deferred tax liabilities (assets): Depreciation & cost recovery timing differences $ 827.6 $ 757.9 Leveraged lease — 9.8 Regulatory assets recoverable through future rates 31.6 29.2 Alternative minimum tax carryforward (34.5 ) (51.4 ) Employee benefit obligations (9.3 ) (14.5 ) Net operating loss & other carryforwards (3.7 ) (2.0 ) Regulatory liabilities to be settled through future rates (29.9 ) (27.5 ) Impairments (3.0 ) (5.6 ) Deferred fuel costs - net 14.2 22.0 Other – net 12.4 7.0 Net noncurrent deferred tax liability $ 805.4 $ 724.9
Components of income tax expense and utilization of investment tax credits	The components of income tax expense follow: Year Ended December 31, (In millions) 2015 2014 2013 Current: Federal $ 10.8 $ 24.7 $ 12.4 State 8.5 18.5 11.4 Total current taxes 19.3 43.2 23.8 Deferred: Federal 79.0 42.7 43.4 State 2.0 (4.2 ) 0.5 Total deferred taxes 81.0 38.5 43.9 Amortization of investment tax credits (0.6 ) (0.6 ) (0.6 ) Total income tax expense $ 99.7 $ 81.1 $ 67.1

Retirement Plans & Other Post43

Retirement Plans & Other Postretirement Benefits (Tables)	12 Months Ended
Retirement Plans & Other Postretirement Benefits (Tables)	Dec. 31, 2015
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, 2015 follows: Pension Benefits Other Benefits (In millions) 2015 2014 2013 2015 2014 2013 Service cost $ 7.9 $ 7.4 $ 8.6 $ 0.4 $ 0.4 $ 0.5 Interest cost 14.6 15.5 14.7 2.0 2.3 2.0 Expected return on plan assets (22.5 ) (22.7 ) (22.1 ) — — — Amortization of prior service cost (benefit) 0.7 1.0 1.5 (3.0 ) (3.0 ) (3.2 ) Amortization of actuarial loss 8.5 5.0 10.1 0.7 0.4 0.7 Settlement charge 0.6 3.1 1.3 — — — Net periodic benefit cost $ 9.8 $ 9.3 $ 14.1 $ 0.1 $ 0.1 $ —
Schedule of assumptions used	The weighted averages of significant assumptions used to determine net periodic benefit costs follow: Pension Benefits Other Benefits 2015 2014 2013 2015 2014 2013 Discount rate 4.05 % 4.74 % 4.03 % 3.95 % 4.66 % 3.91 % Rate of compensation increase 3.50 % 3.50 % 3.50 % N/A N/A N/A Expected return on plan assets 7.50 % 7.75 % 7.75 % N/A N/A N/A Expected increase in Consumer Price Index N/A N/A N/A 2.50 % 2.75 % 2.75 % The benefit obligation as of December 31, 2015 and 2014 was calculated using the following weighted average assumptions: Pension Benefits Other Benefits 2015 2014 2015 2014 Discount rate 4.31 % 4.05 % 4.21 % 3.95 % 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 %
Schedule of changes in projected benefit obligations	A reconciliation of the Company’s benefit obligations at December 31, 2015 and 2014 follows: Pension Benefits Other Benefits (In millions) 2015 2014 2015 2014 Benefit obligation, beginning of period $ 371.9 $ 338.4 $ 53.3 $ 51.3 Service cost – benefits earned during the period 7.9 7.4 0.4 0.4 Interest cost on projected benefit obligation 14.6 15.5 2.0 2.3 Plan participants' contributions — — 1.0 0.9 Plan amendments 0.5 — — — Actuarial loss (gain) (17.0 ) 48.5 (8.6 ) 3.2 Settlement loss — 1.7 — — Benefit payments (27.9 ) (25.3 ) (4.6 ) (4.8 ) Settlement payments (1.7 ) (14.3 ) — — Benefit obligation, end of period $ 348.3 $ 371.9 $ 43.5 $ 53.3
Schedule of changes in fair value of plan assets	A reconciliation of the Company’s plan assets at December 31, 2015 and 2014 follows: Pension Benefits Other Benefits (In millions) 2015 2014 2015 2014 Plan assets at fair value, beginning of period $ 305.6 $ 323.9 $ — $ — Actual return on plan assets (2.0 ) 20.1 — — Employer contributions 22.9 1.2 3.6 3.9 Plan participants' contributions — — 1.0 0.9 Benefit payments (27.9 ) (25.3 ) (4.6 ) (4.8 ) Settlement payments (1.7 ) (14.3 ) — — Fair value of plan assets, end of period $ 296.9 $ 305.6 $ — $ —
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, 2015 and December 31, 2014 by asset category and by fair value hierarchy are as follows: As of December 31, 2015 (In millions) Level 1 Level 2 Level 3 Total Domestic equities & equity funds $ 113.5 $ 29.8 $ — $ 143.3 International equities & equity funds 38.2 — — 38.2 Domestic bonds & bond funds 36.6 48.0 — 84.6 Inflation protected security fund — 11.2 — 11.2 Real estate, commodities & other 4.8 10.5 4.3 19.6 Total plan investments $ 193.1 $ 99.5 $ 4.3 $ 296.9 As of December 31, 2014 (In millions) Level 1 Level 2 Level 3 Total Domestic equities & equity funds $ 62.8 $ 87.3 $ — $ 150.1 International equities & equity funds 38.4 — — 38.4 Domestic bonds & bond funds 38.8 47.1 — 85.9 Inflation protected security fund — 11.1 — 11.1 Real estate, commodities & other 5.8 10.1 4.2 20.1 Total plan investments $ 145.8 $ 155.6 $ 4.2 $ 305.6
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) 2015 2014 Fair value, beginning of year $ 4.2 $ 4.1 Unrealized gains related to investments still held at reporting date 0.2 0.1 Purchases, sales & settlements, net (0.1 ) — Fair value, end of year $ 4.3 $ 4.2
Schedule of net funded status of plans	The funded status of the plans as of December 31, 2015 and 2014 follows: Pension Benefits Other Benefits (In millions) 2015 2014 2015 2014 Qualified Plans Benefit obligation, end of period $ (328.7 ) $ (351.7 ) $ (43.5 ) $ (53.3 ) Fair value of plan assets, end of period 296.9 305.6 — — Funded Status of Qualified Plans, end of period (31.8 ) (46.1 ) (43.5 ) (53.3 ) Benefit obligation of SERP Plan, end of period (19.6 ) (20.2 ) — — Total funded status, end of period $ (51.4 ) $ (66.3 ) $ (43.5 ) $ (53.3 ) Accrued liabilities $ 1.2 $ 1.2 $ 4.6 $ 4.6 Deferred credits & other liabilities $ 50.2 $ 65.1 $ 38.9 $ 48.7
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, 2013 $ 4.5 $ 136.2 $ (23.1 ) $ 11.2 Amounts arising during the period — (58.8 ) (0.2 ) (2.4 ) Reclassification to benefit costs (1.5 ) (10.1 ) 3.2 (0.7 ) Balance at December 31, 2013 $ 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
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, 2015 and 2014 . (In millions) 2015 2014 Pensions Other Benefits Pensions Other Benefits Prior service cost $ 1.8 $ (14.1 ) $ 2.0 $ (17.1 ) Unamortized actuarial gain/(loss) 110.1 1.6 111.7 10.9 111.9 (12.5 ) 113.7 (6.2 ) Less: Regulatory asset deferral (109.6 ) 12.3 (111.4 ) 6.1 AOCI before taxes $ 2.3 $ (0.2 ) $ 2.3 $ (0.1 )
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 2015 , 2014 , and 2013 . (In millions) Pension Protection Act Zone Status Multiemployer Contributions Pension Fund EIN/Pension Plan Number 2015 2014 FIP/RP Status Pending/Implemented 2015 2014 2013 Surcharge Imposed Central Pension Fund 36-6052390-001 Green Green No $7.2 $7.7 $8.5 No Pipeline Industry Benefit Fund 73-0742835-001 Green Green No 4.0 5.1 5.3 No Indiana Laborers Pension Fund (1) 35-6027150-001 Yellow Yellow Implemented 4.1 3.5 2.4 No Ohio Operating Engineers Pension Fund 31-6129968-001 Green Green No 2.2 1.7 1.5 No Minnesota Laborers Pension Fund 41-6159599-001 Green Green No 1.8 2.2 2.8 No Other 13.4 12.2 12.7 Total Contributions $32.7 $32.4 $33.2

Borrowing Arrangements (Tables)

Borrowing Arrangements (Tables)	12 Months Ended
Borrowing Arrangements (Tables)	Dec. 31, 2015
Debt Disclosure [Abstract]
Short term borrowing arrangements	Following is certain information regarding these short-term borrowing arrangements. Utility Group Borrowings Nonutility Group Borrowings (In millions) 2015 2014 2013 2015 2014 2013 As of Year End Balance Outstanding $ 14.5 $ 156.4 $ 28.6 $ — $ — $ 40.0 Weighted Average Interest Rate 0.55 % 0.50 % 0.29 % N/A N/A 1.27 % Annual Average Balance Outstanding $ 53.8 $ 35.6 $ 119.6 $ 24.8 $ 34.5 $ 119.3 Weighted Average Interest Rate 0.38 % 0.34 % 0.34 % 1.33 % 1.29 % 1.35 % Maximum Month End Balance Outstanding $ 121.5 $ 156.4 $ 176.1 $ 69.1 $ 76.3 $ 173.8
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) 2015 2014 Utility Holdings Fixed Rate Senior Unsecured Notes 2015, 5.45% — 75.0 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 — 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 — 2055, 4.51% 40.0 — Total Utility Holdings 1,000.0 875.0 Indiana Gas Fixed Rate Senior Unsecured Notes 2015, Series E, 7.15% — 5.0 2015, Series E, 6.69% — 5.0 2015, Series E, 6.69% — 10.0 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 96.0 116.0 SIGECO First Mortgage Bonds 2016, 1986 Series, 8.875% 13.0 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 0.784%, 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 — 2055, 2015 Series Warrick County, 2.375%, tax-exempt 15.2 — Total SIGECO 305.7 267.5 At December 31, (In millions) 2015 2014 Vectren Capital Corp. Fixed Rate Senior Unsecured Notes 2015, 5.31% — 75.0 2016, 6.92% 60.0 60.0 2017, 3.48% 75.0 75.0 2019, 7.30% 60.0 60.0 2022, 3.33% 75.0 — 2025, 4.53% 50.0 50.0 2030, 3.90% 75.0 — Total Vectren Capital Corp. 395.0 320.0 Total long-term debt outstanding 1,796.7 1,578.5 Current maturities of long-term debt (73.0 ) (170.0 ) Unamortized debt premium & discount - net (0.9 ) (1.2 ) Total long-term debt-net $ 1,722.8 $ 1,407.3

Earnings Per Share (Tables)

Earnings Per Share (Tables)	12 Months Ended
Earnings Per Share (Tables)	Dec. 31, 2015
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, 2015 : Year Ended December 31, (In millions, except per share data) 2015 2014 2013 Numerator: Reported net income (Numerator for Diluted EPS) $ 197.3 $ 166.9 $ 136.6 Denominator: Weighted-average common shares outstanding (Basic EPS) 82.7 82.5 82.3 Conversion of share-based compensation arrangements 0.0 0.0 0.1 Adjusted weighted-average shares outstanding and assumed conversions outstanding (Diluted EPS) 82.7 82.5 82.4 Basic earnings per share $ 2.39 $ 2.02 $ 1.66 Diluted earnings per share $ 2.39 $ 2.02 $ 1.66

Accumulated Other Comprehensi46

Accumulated Other Comprehensive Income (Tables)	12 Months Ended
Accumulated Other Comprehensive Income (Tables)	Dec. 31, 2015
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: 2013 2014 2015 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 Unconsolidated affiliates $ (4.6 ) $ 4.6 $ — $ — $ — $ — $ — Pension & other benefit costs (2.6 ) 1.4 (1.2 ) (1.0 ) (2.2 ) 0.1 (2.1 ) Deferred income taxes 2.9 (2.4 ) 0.5 0.4 0.9 — 0.9 Accumulated other comprehensive income (loss) $ (4.3 ) $ 3.6 $ (0.7 ) $ (0.6 ) $ (1.3 ) $ 0.1 $ (1.2 )

Share-Based Compensation & De47

Share-Based Compensation & Deferred Compensation Arrangements (Tables)	12 Months Ended
	Dec. 31, 2015
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) 2015 2014 2013 Total cost of share-based compensation $ 19.4 $ 25.2 $ 14.8 Less capitalized cost 4.8 5.3 2.8 Total in other operating expense 14.6 19.9 12.0 Less income tax benefit in earnings 5.7 7.9 4.8 After tax effect of share-based compensation $ 8.9 $ 12.0 $ 7.2
Performance based units outstanding	A summary of the status of awards separated between those accounted for as liabilities and equity as of December 31, 2015 and 2014, and changes during the years ended December 31, 2015 and 2014, follow: Equity Awards Wtd. Avg. Grant Date Liability Awards Units Fair value Units Fair value Awards at January 1, 2014 79,957 $ 29.12 731,251 Granted 5,910 31.24 331,344 Vested (51,594 ) 28.36 (347,031 ) Forfeited — — (22,405 ) Awards at December 31, 2014 34,273 $ 30.55 693,159 $ 46.23 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

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
Fair Value Measurements (Tables)	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Carrying value and estimated fair value of other financial instruments	The carrying values and estimated fair values using primarily Level 2 assumptions of the Company's other financial instruments follow: At December 31, 2015 2014 (In millions) Carrying Amount Est. Fair Value Carrying Amount Est. Fair Value Long-term debt $ 1,795.8 $ 1,909.5 $ 1,577.3 $ 1,754.5 Short-term borrowings & notes payable 14.5 14.5 156.4 156.4 Cash & cash equivalents 74.7 74.7 86.4 86.4

Segment Reporting (Tables)

Segment Reporting (Tables)	12 Months Ended
Segment Reporting (Tables)	Dec. 31, 2015
Segment Reporting [Abstract]
Schedule of Segment Reporting Information, by Segment [Table Text Block]	Corporate and Other includes 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. 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) 2015 2014 2013 Revenues Utility Group Gas Utility Services $ 792.6 $ 944.6 $ 810.0 Electric Utility Services 601.6 624.8 619.3 Other Operations 40.7 38.3 38.1 Eliminations (40.4 ) (38.0 ) (37.8 ) Total Utility Group 1,394.5 1,569.7 1,429.6 Nonutility Group Infrastructure Services 843.3 779.0 783.5 Energy Services 199.9 129.8 91.3 Coal Mining — 234.3 292.8 Total Nonutility Group 1,043.2 1,143.1 1,167.6 Eliminations, net of Corporate & Other Revenues (3.0 ) (101.1 ) (106.0 ) Consolidated Revenues $ 2,434.7 $ 2,611.7 $ 2,491.2 Profitability Measures - Net Income Utility Group Net Income Gas Utility Services $ 64.4 $ 57.0 $ 55.7 Electric Utility Services 82.6 79.7 75.8 Other Operations 13.9 11.7 10.3 Total Utility Group Net Income 160.9 148.4 141.8 Nonutility Group Net Income (Loss) Infrastructure Services 29.7 43.1 49.0 Energy Services 7.3 (3.2 ) 1.0 Coal Mining — (21.1 ) (16.0 ) Energy Marketing — — (37.5 ) Other Businesses (0.7 ) (0.8 ) (1.0 ) Total Nonutility Group Net Income (Loss) 36.3 18.0 (4.5 ) Corporate & Other Net Income (Loss) 0.1 0.5 (0.7 ) Consolidated Net Income $ 197.3 $ 166.9 $ 136.6 Year Ended December 31, (In millions) 2015 2014 2013 Amounts Included in Profitability Measures Depreciation & Amortization Utility Group Gas Utility Services $ 98.6 $ 93.3 $ 90.5 Electric Utility Services 85.6 85.7 84.0 Other Operations 24.6 24.1 21.9 Total Utility Group 208.8 203.1 196.4 Nonutility Group Infrastructure Services 44.5 36.2 28.8 Energy Services 2.7 3.9 1.7 Coal Mining — 29.9 50.8 Other Businesses 0.3 0.3 0.1 Total Nonutility Group 47.5 70.3 81.4 Consolidated Depreciation & Amortization $ 256.3 $ 273.4 $ 277.8 Interest Expense Utility Group Gas Utility Services $ 35.8 $ 34.9 $ 30.6 Electric Utility Services 27.8 29.0 29.2 Other Operations 2.7 2.7 5.2 Total Utility Group 66.3 66.6 65.0 Nonutility Group Infrastructure Services 16.0 11.1 10.1 Energy Services 1.2 1.3 0.6 Coal Mining — 7.5 9.8 Energy Marketing — — 2.2 Other Businesses 1.2 0.9 0.5 Total Nonutility Group 18.4 20.8 23.2 Corporate & Other (0.2 ) (0.7 ) (0.3 ) Consolidated Interest Expense $ 84.5 $ 86.7 $ 87.9 Income Taxes Utility Group Gas Utility Services $ 40.8 $ 35.7 $ 36.6 Electric Utility Services 49.3 48.1 48.3 Other Operations (2.0 ) (0.6 ) 0.4 Total Utility Group 88.1 83.2 85.3 Nonutility Group Infrastructure Services 19.6 28.9 34.3 Energy Services (7.7 ) (7.8 ) (11.9 ) Coal Mining — (21.8 ) (14.6 ) Energy Marketing — — (23.3 ) Other Businesses 1.5 (0.3 ) (1.6 ) Total Nonutility Group 13.4 (1.0 ) (17.1 ) Corporate & Other (1.8 ) (1.1 ) (1.1 ) Consolidated Income Taxes $ 99.7 $ 81.1 $ 67.1 Year Ended December 31, (In millions) 2015 2014 2013 Capital Expenditures Utility Group Gas Utility Services $ 291.2 $ 245.9 $ 150.5 Electric Utility Services 87.6 92.4 100.0 Other Operations 25.7 23.3 25.8 Non-cash costs & changes in accruals (6.2 ) (10.9 ) (15.2 ) Total Utility Group 398.3 350.7 261.1 Nonutility Group Infrastructure Services 78.1 54.1 79.2 Energy Services 0.5 1.6 6.9 Coal Mining — 41.9 46.2 Total Nonutility Group 78.6 97.6 132.3 Consolidated Capital Expenditures $ 476.9 $ 448.3 $ 393.4 At December 31, (In millions) 2015 2014 2013 Assets Utility Group Gas Utility Services $ 2,707.5 $ 2,605.1 $ 2,286.6 Electric Utility Services 1,782.2 1,659.3 1,679.0 Other Operations, net of eliminations 111.6 152.4 169.7 Total Utility Group 4,601.3 4,416.8 4,135.3 Nonutility Group Infrastructure Services 554.5 538.5 461.7 Energy Services 160.3 87.1 63.0 Coal Mining — — 433.0 Other Businesses, net of eliminations and reclassifications 64.0 120.3 68.4 Total Nonutility Group 778.8 745.9 1,026.1 Corporate & Other 743.7 655.6 824.2 Eliminations (713.9 ) (672.3 ) (896.9 ) Consolidated Assets $ 5,409.9 $ 5,146.0 $ 5,088.7

Additional Balance Sheet & Op50

Additional Balance Sheet & Operational Information (Tables)	12 Months Ended
Additional Balance Sheet & Operational Information (Tables)	Dec. 31, 2015
Additional Balance Sheet and Operational Information [Abstract]
Summary of inventories	Inventories consist of the following: At December 31, (In millions) 2015 2014 Gas in storage – at LIFO cost $ 40.5 $ 40.5 Coal & oil for electric generation - at average cost 45.0 33.8 Materials & supplies 46.9 42.5 Other 1.3 1.7 Total inventories $ 133.7 $ 118.5
Summary of prepayments and other current assets	Prepayments & other current assets consist of the following: At December 31, (In millions) 2015 2014 Prepaid gas delivery service $ 30.0 $ 40.7 Prepaid taxes 25.3 37.5 Other prepayments & current assets 25.7 16.4 Total prepayments & other current assets $ 81.0 $ 94.6
Schedule of investments in unconsolidated affiliates	Investments in unconsolidated affiliates consist of the following: At December 31, (In millions) 2015 2014 ProLiance Holdings, LLC $ 19.7 $ 20.5 Other nonutility partnerships & corporations 1.0 2.7 Other utility investments 0.2 0.2 Total investments in unconsolidated affiliates $ 20.9 $ 23.4
Other utility and corporate investments in the consolidated balance sheets	Other utility & corporate investments consist of the following: At December 31, (In millions) 2015 2014 Cash surrender value of life insurance policies $ 30.1 $ 32.3 Municipal bond — 3.1 Restricted cash & other investments 1.1 1.8 Total other utility & corporate investments $ 31.2 $ 37.2
Goodwill by operating segment	Goodwill by operating segment follows: At December 31, (In millions) 2015 2014 Utility Group Gas Utility Services $ 205.0 $ 205.0 Nonutility Group Infrastructure Services 58.8 55.2 Energy Services 29.7 29.7 Consolidated goodwill $ 293.5 $ 289.9
Accrued Liabilities	Accrued liabilities consist of the following: At December 31, (In millions) 2015 2014 Refunds to customers & customer deposits $ 51.4 $ 51.3 Accrued taxes 39.9 35.8 Accrued interest 19.4 19.1 Deferred compensation & post-retirement benefits 7.2 7.3 Accrued salaries & other 65.7 71.4 Total accrued liabilities $ 183.6 $ 184.9
Asset retirement obligation	Asset retirement obligations included in Deferred credits and other liabilities in the Consolidated Balance Sheets roll forward as follows: (In millions) 2015 2014 Asset retirement obligation, January 1 $ 55.0 $ 41.3 Accretion 3.2 1.7 Liabilities incurred in current period 24.2 — Changes in estimates, net of cash payments (0.4 ) 23.8 Vectren Fuels Retirement Obligation — (11.8 ) Asset retirement obligation, December 31 82.0 55.0
Equity in earnings (losses) of unconsolidated affiliates	Equity in earnings (losses) of unconsolidated affiliates consists of the following: Year Ended December 31, (In millions) 2015 2014 2013 ProLiance Holdings, LLC $ (0.8 ) $ (0.3 ) $ (57.7 ) Other 0.2 0.8 (2.0 ) Total equity in earnings (losses) of unconsolidated affiliates $ (0.6 ) $ 0.5 $ (59.7 )
Other, net in the consolidated statements of income	Other income (expense) – net consists of the following: Year Ended December 31, (In millions) 2015 2014 2013 AFUDC – borrowed funds $ 16.3 $ 11.4 $ 5.9 AFUDC – equity funds 2.6 3.2 0.8 Nonutility plant capitalized interest 0.4 — 0.5 Interest income, net 1.3 1.1 1.1 Other nonutility investment impairment charges (0.1 ) (1.0 ) — Cash surrender value of life insurance policies (2.1 ) 2.8 4.8 All other income 1.9 2.2 4.6 Total other income (expense) – net $ 20.3 $ 19.7 $ 17.7
Supplemental cash flow information	Supplemental Cash Flow Information: Year Ended December 31, (In millions) 2015 2014 2013 Cash paid (received) for: Interest $ 84.2 $ 87.5 $ 91.0 Income taxes 4.8 69.4 6.8

Quarterly Financial Data (Una51

Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
Quarterly Financial Data (Unaudited) (Tables)	Dec. 31, 2015
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. Note that at June 30, 2014, the Company recorded an estimated loss on the transaction related to the Vectren Fuels sale to Sunrise Coal, including costs to sell, of approximately $32 million, or $20 million after tax. Summarized quarterly financial data for 2015 and 2014 follows: (In millions, except per share amounts) Q1 Q2 Q3 Q4 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 2014 Operating revenues $ 796.8 $ 542.5 $ 595.6 $ 676.8 Operating income 99.0 33.9 84.5 97.1 Net income 51.2 11.9 47.3 56.5 Earnings per share: Basic and Diluted $ 0.62 $ 0.14 $ 0.57 $ 0.68

Organization and Nature of Op52

Organization and Nature of Operations (Details)	12 Months Ended
Organization and Nature of Operations (Details)	Dec. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of public utility subsidiaries owned by wholly owned subsidiary, Vectren Utility Holdings, Inc. (in number of subsidiaries)	3
Estimated number of natural gas customers located in central and southern Indiana serviced by Indiana Gas Company (in number of customers)	580,000
Estimated number of electric customers located near Evansville in southwestern Indiana serviced by Southern Indiana Gas and Electric Company (in number of customers)	144,000
Estimated number of natural gas customers located near Evansville in southwestern Indiana serviced by Southern Indiana Gas and Electric Company (in number of customers)	111,000
Estimated number of natural gas customers located near Dayton in west central Ohio serviced by the Ohio operations (in number of customers)	314,000

Summary of Significant Accoun53

Summary of Significant Accounting Policies (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Accounting Policies [Abstract]
Excise taxes and a portion of utility receipts taxes	$ 29.4	$ 32.3	$ 29.6
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
Utility & Nonutility Plant (Details) $ in Millions	Dec. 31, 2015USD ($)MW	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Utility & Nonutility Plant
Original Cost	$ 6,090.4	$ 5,718.7
Cost of Non-Utility plant, net of depreciation and amortization	414.6	378
Utility Group [Member]
Utility & Nonutility Plant
Original Cost	$ 6,090.4	5,718.7
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	$ 3,279.7	$ 3,011
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	$ 2,695.8	$ 2,602.5
Depreciation Rates as a Percent of Original Cost (in hundredths)	3.30%	3.30%
Utility Group [Member] \| Common Utility Plant [Member]
Utility & Nonutility Plant
Original Cost	$ 55	$ 54.3
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	$ 59.9	$ 50.9
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	$ 190.3
Southern Indiana Gas And Electric Company's Share Of Accumulated Depreciation Of Unit 4	101.9
Nonutility Group [Member]
Utility & Nonutility Plant
Cost of Non-Utility plant, net of depreciation and amortization	414.6	$ 378
Nonutility plant accumulated depreciation and amortization	420.3	361.9
Capitalized interest on nonutility plant construction projects	0.4	0.6	$ 0.5
Nonutility Group [Member] \| Computer Hardware and Software [Member]
Utility & Nonutility Plant
Cost of Non-Utility plant, net of depreciation and amortization	108.8	106.1
Nonutility Group [Member] \| Land and Buildings [Member]
Utility & Nonutility Plant
Cost of Non-Utility plant, net of depreciation and amortization	86.4	72.1
Nonutility Group [Member] \| Vehicles and Equipment [Member]
Utility & Nonutility Plant
Cost of Non-Utility plant, net of depreciation and amortization	203	182.7
Nonutility Group [Member] \| All Other [Member]
Utility & Nonutility Plant
Cost of Non-Utility plant, net of depreciation and amortization	$ 16.4	$ 17.1

Regulatory Assets & Liabiliti55

Regulatory Assets & Liabilities (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Regulatory Assets [Line Items]
Regulatory assets	$ 258	$ 233.6
Regulatory Assets Currently Being Recovered in Base Rates	$ 35
Weighted average recovery period of regulatory assets currently being recovered (in years)	24
Defined Benefit Plan, increase (decrease) in benefit obligation recoverable from ratepayers	$ (8)
Regulatory Liabilities [Abstract]
Regulatory liabilities	433.9	410.3
Asset Retirement Obligations and Other [Member]
Regulatory Liabilities [Abstract]
Regulatory liabilities	399.1	373.5
Future Amounts Recoverable From Ratepayers [Member]
Regulatory Assets [Line Items]
Regulatory assets	80.4	90.5
Future Amounts Recoverable From Ratepayers [Member] \| Benefit Obligations [Member]
Regulatory Assets [Line Items]
Regulatory assets	97.3	105.3
Future Amounts Recoverable From Ratepayers [Member] \| Deferred Income Taxes [Member]
Regulatory Assets [Line Items]
Regulatory assets	(16.9)	(14.8)
Amounts Deferred for Future Recovery [Member]
Regulatory Assets [Line Items]
Regulatory assets	54.6	33.3
Amounts Deferred for Future Recovery [Member] \| Cost Recovery Riders Other [Member]
Regulatory Assets [Line Items]
Regulatory assets	54.6	33.3
Amounts Currently Recovered in Customer Rates [Member]
Regulatory Assets [Line Items]
Regulatory assets	123	109.8
Amounts Currently Recovered in Customer Rates [Member] \| Deferred Coal Costs [Member]
Regulatory Assets [Line Items]
Regulatory assets	28.3	35.3
Amounts Currently Recovered in Customer Rates [Member] \| Unamortized Debt Issue Costs, Reaquisition Premiums and Hedging Proceeds [Member]
Regulatory Assets [Line Items]
Regulatory assets	34.4	35.2
Amounts Currently Recovered in Customer Rates [Member] \| Demand Side Management Programs [Member]
Regulatory Assets [Line Items]
Regulatory assets	0	0.6
Amounts Currently Recovered in Customer Rates [Member] \| Indiana Authorized Trackers [Member]
Regulatory Assets [Line Items]
Regulatory assets	42.6	25.6
Amounts Currently Recovered in Customer Rates [Member] \| Ohio Authorized Trackers [Member]
Regulatory Assets [Line Items]
Regulatory assets	17.6	12.7
Amounts Currently Recovered in Customer Rates [Member] \| Other Base Rate Recoveries [Member]
Regulatory Assets [Line Items]
Regulatory assets	$ 0.1	$ 0.4

Federal Business Unit Acquisi56

Federal Business Unit Acquisition Federal Business Unit Acquisition (Details) - USD ($) $ in Millions	Apr. 01, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Business Acquisition [Line Items]
Effective Date of Acquisition	Apr. 1, 2014
Goodwill deductibility period for income tax purposes		15 years
Amount of Transaction Costs in Other Cost and Expense, Operating		$ 909.2	$ 943.4	$ 891.6
Federal Business Unit [Member]
Business Acquisition [Line Items]
Business Combination, Liabilities Arising from Contingencies, Amount Recognized			14.8
Adjusted net working capital	$ 2.2
Depreciable fixed assets	0.4
Customer Relationships (Sales Funnel)	7.1
ESPC Licenses	6
Deferred Tax Asset	0.8
Goodwill	27.7
Total assets acquired	44.2
Less: Unfavorable Contract Liabilities Assumed	(2.1)
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	$ 27.6

Sale of Vectren Fuels, Inc. (De

Sale of Vectren Fuels, Inc. (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash received at closing									$ 0	$ 311.2	$ 0
Net income (loss)	$ 65.2	$ 39.3	$ 35.8	$ 57	$ 56.5	$ 47.3	$ 11.9	$ 51.2	$ 197.3	166.9	136.6
Vectren Fuels, Inc. [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash received at closing						311
Change in working capital						$ 15
Disposal Group, Including Discontinued Operation, Gross Profit (Loss)							(32)
Loss on disposal, after tax							$ (20)
Disposal Group, Including Discontinued Operation, Other Expense										42
Disposal Group, Including Discontinued Operation, Depreciation and Amortization										10
Net income (loss)										$ (21.1)	$ (16)

Investment in ProLiance Holdi58

Investment in ProLiance Holdings, LLC (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Jun. 30, 2013	Dec. 31, 2015	Dec. 31, 2013	Dec. 31, 2014
Schedule of Equity Method Investments [Line Items]
Other nonutility investments		$ 16.2		$ 33.6
Equity method investment, investment in equity method investee's subsidiary (ProLiance Energy)		2.7
Equity method investment, investment in storage assets and cash from sale of storage assets		22.2
Equity method investment, minority interest in joint venture, investor's portion of interest		4.9
Equity method investment, gross investment in equity method investee		$ 29.8
Purchases from ProLiance for resale and for injections into storage			$ 200.5
ProLiance Holdings, LLC [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investee funding of equity shortfall of ProLiance Energy	$ 16.6
ProLiance Holdings, LLC [Member] \| Vectren Corp [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investment, ownership percentage (in hundredths)		61.00%
Equity Method Investment Governance and Voting Right Percentage		50.00%
Equity method investment, loss on sale of ProLiance Energy, before tax	43.6
Equity method investment, loss on sale of ProLiance Energy, after tax	$ 26.8
Other nonutility investments		$ 10.1
LA Storage [Member] \| ProLiance Holdings, LLC [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investment, ownership percentage (in hundredths)		25.00%
Combined Joint Venture Ownership Percentage		100.00%
Equity Method Investment, Aggregate Cost		$ 36.4
Sublease Agreement [Member] \| LA Storage [Member]
Schedule of Equity Method Investments [Line Items]
Loss contingency, gross damages sought from a party that entered into a sub-lease agreement with a party that is an investment of an equity method investee.		$ 56.7

Nonutility Real Estate & Othe59

Nonutility Real Estate & Other Legacy Holdings (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Investments by type [Abstract]
Other nonutility investments	$ 16.2	$ 33.6
Investments in unconsolidated affiliates	20.9	23.4
ProLiance Holdings, LLC [Member]
Investments by type [Abstract]
Investments in unconsolidated affiliates	19.7	20.5
Nonutility Group [Member]
Investments by type [Abstract]
Total carrying value by type of investment	7	25
Other nonutility investments	6	23.4
Investments in unconsolidated affiliates	1	1.6
Commercial Real Estate Investments [Member] \| Nonutility Group [Member]
Investments by type [Abstract]
Total carrying value by type of investment	0	8
Other nonutility investments	0	8
Investments in unconsolidated affiliates	0	0
Leveraged Leases [Member] \| Nonutility Group [Member]
Investments by type [Abstract]
Total carrying value by type of investment	0	15.2
Other nonutility investments	0	15.2
Investments in unconsolidated affiliates	0	0
Other Investments [Member] \| Nonutility Group [Member]
Investments by type [Abstract]
Total carrying value by type of investment	7	1.8
Other nonutility investments	6	0.2
Investments in unconsolidated affiliates	1	$ 1.6
Held-to-maturity Securities	5.1
Equity Method Investments	$ 1.9

Intangible Assets (Details)

Intangible Assets (Details) - USD ($) $ in Millions	12 Months Ended
Intangible Assets (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Schedule of intangible assets, excluding goodwill [Line Items]
Amortizing	$ 23.3	$ 23.6
Non-amortizing	$ 13	13
Weighted average remaining life for amortizing customer-related assets and all amortizing intangibles (in years)	12 years
Amortization expense	$ 3.1	2.8	$ 2.3
Amortization expense - year one	2.5
Amortization expense - year two	2.3
Amortization expense - year three	2.3
Amortization expense - year four	2.3
Amortization expense - year five	2.3
Customer Related Assets [Member]
Schedule of intangible assets, excluding goodwill [Line Items]
Amortizing	23.1	22.5
Non-amortizing	0	0
Accumulated amortization	9.8	10
Market Related Assets [Member]
Schedule of intangible assets, excluding goodwill [Line Items]
Amortizing	0.2	1.1
Non-amortizing	13	13
Accumulated amortization	$ 4.3	$ 3.4

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Millions	12 Months Ended
Income Taxes (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
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)	3.60%	4.10%	4.60%
Amortization of investment tax credit (in hundredths)	(0.20%)	(0.30%)	(0.30%)
Depletion (in hundredths)	0.00%	(2.60%)	(1.50%)
Domestic production deduction (in hundredths)	(1.00%)	(1.10%)	0.00%
Energy efficiency building deductions (in hundredths)	(2.30%)	(1.60%)	(3.80%)
Research and development credit (in hundredths)	(1.60%)	(0.30%)	(0.60%)
Other tax credits (in hundredths)	(0.10%)	(0.20%)	(1.10%)
All other-net (in hundredths)	0.20%	(0.30%)	0.70%
Effective tax rate (in hundredths)	33.60%	32.70%	33.00%
Noncurrent deferred tax liabilities (assets) [Abstract]
Depreciation and cost recovery timing differences	$ 827.6	$ 757.9
Leveraged lease	0	9.8
Regulatory assets recoverable through future rates	31.6	29.2
Alternative minimum tax carryforward	(34.5)	(51.4)
Employee benefit obligations	(9.3)	(14.5)
Net operating loss and other carryforwards		(2)
Regulatory liabilities to be settled through future rates	(29.9)	(27.5)
Impairments	(3)	(5.6)
Deferred fuel costs-net	14.2	22
Other - net	12.4	7
Net noncurrent deferred tax liability	805.4	724.9
Deferred Tax Assets, Net of Valuation Allowance, Current	15.3	16.3
Investment tax credits	4.1	4.7
Deferred Tax Assets Operating Loss Carryforwards And General Business CreditsCurrent	$ 3.7
Remaining life of NOL's and business credit carryforwards (in years)	5 to 20 years
Operating Loss Carryforwards, Valuation Allowance	$ 8.1	7.3
Current: [Abstract]
Federal	10.8	24.7	$ 12.4
State	8.5	18.5	11.4
Total current taxes	19.3	43.2	23.8
Deferred: [Abstract]
Federal	79	42.7	43.4
State	2	(4.2)	0.5
Total deferred taxes	81	38.5	43.9
Amortization of investment tax credits	(0.6)	(0.6)	(0.6)
Total income tax expense	99.7	81.1	$ 67.1
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	$ 1.1

Retirement Plans & Other Post62

Retirement Plans & Other Postretirement Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2015	Dec. 31, 2014
Multiemployer Plans [Line Items]
Approximate number of unions the Company contributed to on behalf of employees	250
Average contributions to each union	.1
Largest union multiemployer plan contribution	$ 3.5
Expense for the Multiemployer Benefit plan	32.7	$ 32.4	$ 33.2
Net periodic benefit costs [Abstract]
Portion of benefit costs capitalized as Utility plant	3.1	2.8	4.2
Plan Assets [Roll Forward]
Plan assets at fair value, beginning of period [Roll Forward]	305.6
Fair value of plan assets, end of period	296.9	305.6
Fair Value of guaranteed annuity contract [Roll Forward]
Guaranteed Annuity Contract - estimate of undiscounted funds necessary to satisfy John Hancock's remaining obligation					$ 3.9	$ 3.8
Guaranteed Annuity Contract - percent of composite investment return, net of manger fees and other charges (in hundredths)					3.65%	4.12%
Fair value, beginning of year	4.2	4.1
Unrealized gains related to investments still held at reporting date	0.2	0.1
Purchases, sales and settlements, net	(0.1)	0
Fair value, end of year	4.3	4.2
Qualified Plans
Fair value of plan assets, end of period	305.6	305.6			$ 296.9	$ 305.6
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					258	233.6
Defined Contribution Plan [Abstract]
Contributions to Defined Contribution Plan	11	9.1	7.5
Domestic equities and equity funds [Member]
Plan Assets [Roll Forward]
Plan assets at fair value, beginning of period [Roll Forward]	150.1
Fair value of plan assets, end of period	143.3	150.1
Qualified Plans
Fair value of plan assets, end of period	150.1	150.1			143.3	150.1
International equities and equity funds [Member]
Plan Assets [Roll Forward]
Plan assets at fair value, beginning of period [Roll Forward]	38.4
Fair value of plan assets, end of period	38.2	38.4
Qualified Plans
Fair value of plan assets, end of period	38.4	38.4			38.2	38.4
Domestic bonds and bond funds [Member]
Plan Assets [Roll Forward]
Plan assets at fair value, beginning of period [Roll Forward]	85.9
Fair value of plan assets, end of period	84.6	85.9
Qualified Plans
Fair value of plan assets, end of period	85.9	85.9			84.6	85.9
Inflation protected security fund [Member]
Plan Assets [Roll Forward]
Plan assets at fair value, beginning of period [Roll Forward]	11.1
Fair value of plan assets, end of period	11.2	11.1
Qualified Plans
Fair value of plan assets, end of period	11.1	11.1			11.2	11.1
Real estate, commodities and other [Member]
Plan Assets [Roll Forward]
Plan assets at fair value, beginning of period [Roll Forward]	20.1
Fair value of plan assets, end of period	19.6	20.1
Qualified Plans
Fair value of plan assets, end of period	20.1	20.1			19.6	20.1
Other Pension Funds [Member]
Multiemployer Plans [Line Items]
Expense for the Multiemployer Benefit plan	13.4	12.2	12.7
Minnesota Laborers Pension Fund [Member]
Multiemployer Plans [Line Items]
Expense for the Multiemployer Benefit plan	1.8	2.2	2.8
Ohio Operating Engineers Pension Fund [Member]
Multiemployer Plans [Line Items]
Expense for the Multiemployer Benefit plan	2.2	1.7	1.5
Indiana Laborers Pension Fund [Member]
Multiemployer Plans [Line Items]
Expense for the Multiemployer Benefit plan	4.1	3.5	2.4
Pipeline Industry Benefit Fund [Member]
Multiemployer Plans [Line Items]
Expense for the Multiemployer Benefit plan	4	5.1	5.3
Central Pension Fund [Member]
Multiemployer Plans [Line Items]
Expense for the Multiemployer Benefit plan	7.2	7.7	8.5
Fair Value, Inputs, Level 1 [Member]
Plan Assets [Roll Forward]
Plan assets at fair value, beginning of period [Roll Forward]	145.8
Fair value of plan assets, end of period	193.1	145.8
Qualified Plans
Fair value of plan assets, end of period	145.8	145.8			193.1	145.8
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]	62.8
Fair value of plan assets, end of period	113.5	62.8
Qualified Plans
Fair value of plan assets, end of period	62.8	62.8			113.5	62.8
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]	38.4
Fair value of plan assets, end of period	38.2	38.4
Qualified Plans
Fair value of plan assets, end of period	38.4	38.4			38.2	38.4
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]	38.8
Fair value of plan assets, end of period	36.6	38.8
Qualified Plans
Fair value of plan assets, end of period	38.8	38.8			36.6	38.8
Fair Value, Inputs, Level 1 [Member] \| Inflation protected security fund [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 1 [Member] \| Real estate, commodities and other [Member]
Plan Assets [Roll Forward]
Plan assets at fair value, beginning of period [Roll Forward]	5.8
Fair value of plan assets, end of period	4.8	5.8
Qualified Plans
Fair value of plan assets, end of period	5.8	5.8			$ 4.8	$ 5.8
Fair Value, Inputs, Level 2 [Member]
Plan Assets [Roll Forward]
Plan assets at fair value, beginning of period [Roll Forward]	155.6
Fair value of plan assets, end of period	99.5	155.6
Common Collective Trust Funds [Abstract]
Portion of Common Collective Trust Funds comprised of equity funds (in hundredths)					30.00%	56.00%
Portion of Common Collective Trust Funds comprised of fixed income funds (in hundredths)					60.00%	37.00%
Fair value of Common Collective Trust Funds					$ 99.5	$ 155.6
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	155.6	155.6			$ 99.5	155.6
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]	87.3
Fair value of plan assets, end of period	29.8	87.3
Qualified Plans
Fair value of plan assets, end of period	87.3	87.3			29.8	87.3
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]	47.1
Fair value of plan assets, end of period	48	47.1
Qualified Plans
Fair value of plan assets, end of period	47.1	47.1			48	47.1
Fair Value, Inputs, Level 2 [Member] \| Inflation protected security fund [Member]
Plan Assets [Roll Forward]
Plan assets at fair value, beginning of period [Roll Forward]	11.1
Fair value of plan assets, end of period	11.2	11.1
Qualified Plans
Fair value of plan assets, end of period	11.1	11.1			11.2	11.1
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]	10.1
Fair value of plan assets, end of period	10.5	10.1
Qualified Plans
Fair value of plan assets, end of period	10.1	10.1			10.5	10.1
Fair Value, Inputs, Level 3 [Member]
Plan Assets [Roll Forward]
Plan assets at fair value, beginning of period [Roll Forward]	4.2
Fair value of plan assets, end of period	4.3	4.2
Qualified Plans
Fair value of plan assets, end of period	4.2	4.2			4.3	4.2
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] \| Inflation protected security fund [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]	4.2
Fair value of plan assets, end of period	4.3	4.2
Qualified Plans
Fair value of plan assets, end of period	$ 4.2	4.2			$ 4.3	$ 4.2
Multiemployer Plans, Pension [Member]
Multiemployer Plans [Line Items]
Number of multiemployer plans contributed to	62
Defined benefit plan, number of significant plans	5
Required percentage improvement of plans in funding improvement plans					33.00%
Number of years in period of funding improvement plan	10
Target funding percentage at the end of funding improvement time period					78.00%
Number of plans in red zone status receiving company contributions	9
Number of plans in red zone status considered significant by the Company	1
Number of plans whereby company contributions exceed 5% of plan balance	9
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	$ 7.9	7.4	8.6
Interest cost	14.6	15.5	14.7
Expected return on plan assets	(22.5)	(22.7)	(22.1)
Amortization of prior service cost (benefit)	0.7	1	1.5
Amortization of actuarial loss (gain)	8.5	5	10.1
Settlement (credit) charge	0.6	3.1	1.3
Net periodic benefit cost	$ 9.8	$ 9.3	$ 14.1
Discount Rate (in hundredths)	4.05%	4.74%	4.03%
Rate of compensation increase (in hundredths)	3.50%	3.50%	3.50%
Expected return on plan assets (in hundredths)	7.50%	7.75%	7.75%
Assumptions used to calculate benefit obligations [Abstract]
Discount rate (in hundredths)					4.31%	4.05%
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	$ 371.9	$ 338.4
Service cost - benefits earned during the period	7.9	7.4	$ 8.6
Interest cost on projected benefit obligation	14.6	15.5	14.7
Plan participants' contributions	0	0
Plan amendments	0.5	0
Actuarial loss (gain)	(17)	48.5
Settlement loss	0	1.7
Benefit payments	(27.9)	(25.3)
Settlement payments	(1.7)	(14.3)
Benefit obligation, end of period	348.3	371.9	338.4
Accumulated benefit obligation for all defined benefit pension plans					$ 336.1	$ 356.4
Plan Assets [Roll Forward]
Plan assets at fair value, beginning of period [Roll Forward]	305.6	323.9
Actual return on plan assets	(2)	20.1
Employer contributions	22.9	1.2
Plan participants' contributions	0	0
Benefit payments	(27.9)	(25.3)
Settlement payments	(1.7)	(14.3)
Fair value of plan assets, end of period	296.9	305.6	323.9
Qualified Plans
Benefit obligation, end of period					(328.7)	(351.7)
Fair value of plan assets, end of period	305.6	323.9	323.9		296.9	305.6
Funded Status of Qualified Plans, end of period					(31.8)	(46.1)
Benefit obligation of SERP Plan, end of period					(19.6)	(20.2)
Total funded status, end of period					(51.4)	(66.3)
Accrued liabilities					1.2	1.2
Deferred credits and other liabilities					50.2	65.1
Contributions expected to be made to pension plan trusts in the next fiscal year					15
Estimated future benefit payments [Abstract]
Expected future benefit payments, year one					25.1
Expected future benefit payments, year two					35.9
Expected future benefit payments, year three					25.8
Expected future benefit payments, year four					27
Expected future benefit payments, year five					29.6
Expected future benefit payments, years six through ten					135.2
Prior service costs [Roll Forward]
Balance, beginning of year	2	3	4.5
Amounts arising during the period	0.5	0	0
Reclassification to benefit costs	(0.7)	(1)	(1.5)
Balance, end of year	1.8	2	3	$ 4.5
Net gain or loss [Roll Forward]
Balance, beginning of year	111.7	67.3	136.2
Amounts arising during the period	6.9	49.4	(58.8)
Reclassification to benefit costs	(8.5)	(5)	(10.1)
Balance, end of year	110.1	111.7	67.3	136.2
Reconciliation of amounts in Accumulated other comprehensive income and Regulatory assets
Prior service cost	2	3	4.5	4.5	1.8	2
Unamortized actuarial gain/(loss)	111.7	67.3	136.2	$ 136.2	110.1	111.7
Sub total					111.9	113.7
Less: Regulatory asset deferral					109.6	111.4
AOCI before taxes					$ 2.3	$ 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	$ 7.2
Other Pension Plans, Defined Benefit [Member] \| Equity Securities [Member]
Plan Assets [Roll Forward]
Target percentage of investments in equity instruments (in hundredths)	60.00%
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 Pension Plans, Defined Benefit [Member] \| Real estate, commodities and other [Member]
Plan Assets [Roll Forward]
Target percentage of investments in equity instruments (in hundredths)	5.00%
Other Postretirement Benefit Plans, Defined Benefit [Member]
Net periodic benefit costs [Abstract]
Service cost	$ 0.4	0.4	0.5
Interest cost	2	2.3	2
Expected return on plan assets	0	0	0
Amortization of prior service cost (benefit)	(3)	(3)	(3.2)
Amortization of actuarial loss (gain)	0.7	0.4	0.7
Settlement (credit) charge	0	0	0
Net periodic benefit cost	$ 0.1	$ 0.1	$ 0
Discount Rate (in hundredths)	3.95%	4.66%	3.91%
Expected increase in Consumer Price Index (in hundredths)	2.50%	2.75%	2.75%
Assumptions used to calculate benefit obligations [Abstract]
Discount rate (in hundredths)					4.21%	3.95%
Expected increase in Consumer Price Index (in hundredths)					2.50%	2.50%
Benefit Obligation [Roll Forward]
Benefit obligation, beginning of period	$ 53.3	$ 51.3
Service cost - benefits earned during the period	0.4	0.4	$ 0.5
Interest cost on projected benefit obligation	2	2.3	2
Plan participants' contributions	1	0.9
Plan amendments	0	0
Actuarial loss (gain)	(8.6)	3.2
Settlement loss	0	0
Benefit payments	(4.6)	(4.8)
Settlement payments	0	0
Benefit obligation, end of period	$ 43.5	53.3	51.3
Assumption of percentage increase in medical claims cost for next fiscal year (in hundredths)	6.00%
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	3.6	3.9
Plan participants' contributions	1	0.9
Benefit payments	(4.6)	(4.8)
Settlement payments	0	0
Fair value of plan assets, end of period	0	0	0
Qualified Plans
Benefit obligation, end of period					$ (43.5)	$ (53.3)
Fair value of plan assets, end of period	0	0	0		0	0
Funded Status of Qualified Plans, end of period					(43.5)	(53.3)
Benefit obligation of SERP Plan, end of period					0	0
Total funded status, end of period					(43.5)	(53.3)
Accrued liabilities					4.6	4.6
Deferred credits and other liabilities					38.9	48.7
Other postretirement benefit payments to be made during the next fiscal year					3.3
Estimated future benefit payments [Abstract]
Expected future benefit payments, year one					4.6
Expected future benefit payments, year two					4.4
Expected future benefit payments, year three					4.6
Expected future benefit payments, year four					4.8
Expected future benefit payments, year five					5.1
Expected future benefit payments, years six through ten					25.5
Prior service costs [Roll Forward]
Balance, beginning of year	(17.1)	(20.1)	(23.1)
Amounts arising during the period	0	0	(0.2)
Reclassification to benefit costs	3	3	3.2
Balance, end of year	(14.1)	(17.1)	(20.1)	$ (23.1)
Net gain or loss [Roll Forward]
Balance, beginning of year	10.9	8.1	11.2
Amounts arising during the period	(8.6)	3.2	(2.4)
Reclassification to benefit costs	(0.7)	(0.4)	(0.7)
Balance, end of year	1.6	10.9	8.1	11.2
Reconciliation of amounts in Accumulated other comprehensive income and Regulatory assets
Prior service cost	(17.1)	(20.1)	(23.1)	(23.1)	(14.1)	(17.1)
Unamortized actuarial gain/(loss)	10.9	$ 8.1	$ 11.2	$ 11.2	1.6	10.9
Sub total					(12.5)	(6.2)
Less: Regulatory asset deferral					(12.3)	(6.1)
AOCI before taxes					$ (0.2)	$ (0.1)
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	3
Actuarial gain/loss expected to be amortized in next year	$ 0

Borrowing Arrangements (Details

Borrowing Arrangements (Details) - USD ($)

Dec. 29, 2015

Dec. 21, 2015

Dec. 15, 2015

Dec. 01, 2015

Mar. 15, 2015

Mar. 11, 2014

Dec. 05, 2013

Aug. 28, 2013

Aug. 01, 2013

Apr. 26, 2013

Sep. 30, 2014

Sep. 30, 2013

Jun. 30, 2013

Dec. 31, 2013

Dec. 31, 2015

Sep. 09, 2015

Dec. 31, 2014

Sep. 24, 2014

Aug. 22, 2013

Aug. 13, 2013

Apr. 16, 2013

Apr. 01, 2013

Long term debt [Abstract]

Debt Issuance

$ 62,000,000

Total long term debt outstanding

$ 1,796,700,000

$ 1,578,500,000

Current maturities of long-term debt

(73,000,000)

(170,000,000)

Unamortized debt premium and discount - net

(900,000)

(1,200,000)

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

1,722,800,000

1,407,300,000

Short-term borrowings

14,500,000

156,400,000

Maturities of long term debt [Abstract]

Debt maturing within 12 months following date of latest balance sheet

73,000,000

Debt maturing within two years following date of latest balance sheet

75,000,000

Debt maturing within three years following date of latest balance sheet

100,000,000

Debt maturing within four years following date of latest balance sheet

60,000,000

Debt maturing within five years following date of latest balance sheet

100,000,000

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

$ 1,387,800,000

Covenants [Abstract]

Debt to consolidated total capitalization - maximum ratio

65.00%

Nonutility Group [Member]

Long term debt [Abstract]

Short-term borrowings

$ 40,000,000

$ 0

Utility Holdings [Member]

Long term debt [Abstract]

Long-term Debt

1,000,000,000

Short-term borrowings

15,000,000

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

Long term debt [Abstract]

Total long term debt outstanding

1,000,000,000

875,000,000

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%

Total long term debt outstanding

75,000,000

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

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

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

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

Long term debt [Abstract]

Fixed rate stated percentage (in hundredths)

3.72%

Total long term debt outstanding

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

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

Long term debt [Abstract]

Fixed rate stated percentage (in hundredths)

3.20%

Total long term debt outstanding

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

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

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

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

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

Long term debt [Abstract]

Fixed rate stated percentage (in hundredths)

4.25%

Total long term debt outstanding

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

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

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

Long term debt [Abstract]

Total long term debt outstanding

96,000,000

116,000,000

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%

Total long term debt outstanding

5,000,000

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%

Total long term debt outstanding

5,000,000

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%

Total long term debt outstanding

10,000,000

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

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

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

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

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

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

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

SIGECO [Member] | First Mortgage Bonds [Member]

Long term debt [Abstract]

Proceeds from debt issuance

$ 60,000,000

SIGECO [Member] | First Mortgage Bonds [Member] | Tax Exempt Debt, 1.95 Percent [Member]

Long term debt [Abstract]

Proceeds from debt issuance

$ 48,300,000

Fixed rate stated percentage (in hundredths)

1.95%

Amount of debt to be re-marketed

$ 49,000,000

SIGECO [Member] | Mortgages [Member]

Long term debt [Abstract]

Extinguishment of Debt, Amount

$ 63,600,000

$ 111,000,000

Debt Issuance

$ 63,600,000

Total long term debt outstanding

305,700,000

267,500,000

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

$ 1,300,000,000

Gross utility plant balance subject to the mortgage indenture

3,100,000,000

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]

Total long term debt outstanding

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

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

SIGECO [Member] | Mortgages [Member] | 2025, 2014 Series B, 0.784% tax exempt [Member]

Long term debt [Abstract]

Debt Issuance

41,300,000

Total long term debt outstanding

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

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

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

Long term debt [Abstract]

Debt Issuance

$ 22,200,000

Fixed rate stated percentage (in hundredths)

4.00%

Total long term debt outstanding

22,200,000

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

Long term debt [Abstract]

Debt Issuance

$ 39,600,000

Fixed rate stated percentage (in hundredths)

4.05%

Total long term debt outstanding

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

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

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

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

395,000,000

Short-term borrowings

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

Long term debt [Abstract]

Total long term debt outstanding

395,000,000

320,000,000

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%

Total long term debt outstanding

75,000,000

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

Long term debt [Abstract]

Total long term debt outstanding

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

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

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

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

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

$ 0

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%

Vectren Capital Corp. [Member] | Variable Rate Term Loan [Member] | 2016 Term Loan [Member]

Long term debt [Abstract]

Debt Issuance

$ 100,000,000

Proceeds from debt issuance

$ 100,000,000

Debt Instrument, Term

3 years

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

Long term debt [Abstract]

Debt Issuance

$ 150,000,000

Proceeds from debt issuance

$ 149,100,000

Vectren Utility Holdings Inc [Member] | Fixed Rate Senior Unsecured Notes [Member] | Fixed Rate Senior Unsecured Notes 2013525 [Member]

Long term debt [Abstract]

Extinguishment of Debt, Amount

$ 100,000,000

Fixed rate stated percentage (in hundredths)

5.25%

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

Long term debt [Abstract]

Debt Issuance

$ 45,000,000

Proceeds from debt issuance

44,800,000

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

Long term debt [Abstract]

Debt Issuance

80,000,000

Proceeds from debt issuance

$ 79,600,000

Vectren Utility Holdings Inc [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2039, 6.25% [Member]

Long term debt [Abstract]

Debt Issuance

$ 121,600,000

Fixed rate stated percentage (in hundredths)

6.25%

Current maturities of long-term debt

$ (121,600,000)

Borrowing Arrangements Short-Te

Borrowing Arrangements Short-Term Borrowings (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Short-term borrowings [Abstract]
Short-term borrowing capacity	$ 600
Balance Outstanding, end of period	14.5	$ 156.4
Letters of Credit Outstanding, Amount	0
Utility Group [Member]
Short-term borrowings [Abstract]
Short-term borrowing capacity	350
Short term borrowings available	335
Balance Outstanding, end of period	$ 14.5	$ 156.4	$ 28.6
Weighted Average Interest Rate, end of period (in hundredths)	0.55%	0.50%	0.29%
Balance Outstanding, annual average	$ 53.8	$ 35.6	$ 119.6
Weighted Average Interest Rate, annual average (in hundredths)	0.38%	0.34%	0.34%
Maximum Month End Balance Outstanding	$ 121.5	$ 156.4	$ 176.1
Utility Group [Member] \| Vectren Utility Holdings Inc [Member]
Short-term borrowings [Abstract]
Letter of credit, within debt facility, maximum borrowing capacity	100
Nonutility Group [Member]
Short-term borrowings [Abstract]
Short-term borrowing capacity	250
Short term borrowings available	250
Balance Outstanding, end of period	0	0	$ 40
Weighted Average Interest Rate, end of period (in hundredths)			1.27%
Balance Outstanding, annual average	$ 24.8	$ 34.5	$ 119.3
Weighted Average Interest Rate, annual average (in hundredths)	1.33%	1.29%	1.35%
Maximum Month End Balance Outstanding	$ 69.1	$ 76.3	$ 173.8
Nonutility Group [Member] \| Vectren Capital [Member]
Short-term borrowings [Abstract]
Letter of credit, within debt facility, maximum borrowing capacity	$ 50

Common Shareholder's Equity (De

Common Shareholder's Equity (Details) - shares shares in Millions	Dec. 31, 2015	Dec. 31, 2014
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)	392.1	392.2
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	5.1	5.3

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, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Earnings Per Share [Abstract]
Reported net income (Numerator for diluted earnings per share)									$ 197.3	$ 166.9	$ 136.6
Weighted average common shares outstanding (Basic earnings per share) (in shares)									82.7	82.5	82.3
Conversion of share-based compensation arrangements									0	0	0.1
Adjusted weighted average shares outstanding and assumed conversions outstanding (Diluted earnings per share) (in shares)									82.7	82.5	82.4
Earnings Per Share, Basic	$ 0.79	$ 0.48	$ 0.43	$ 0.69	$ 0.68	$ 0.57	$ 0.14	$ 0.62	$ 2.39	$ 2.02	$ 1.66
Earnings Per Share, Diluted									$ 2.39	$ 2.02	$ 1.66

Accumulated Other Comprehensi67

Accumulated Other Comprehensive Income (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Accumulated Other Comprehensive Income (Loss) [Line Items]
Balance, beginning of period	$ (1.3)	$ (0.7)	$ (4.3)
Changes during period	0.1	(0.6)	3.6
Balance, end of period	(1.2)	(1.3)	(0.7)
Unconsolidated Affiliates [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Balance, beginning of period	0	0	(4.6)
Changes during period	0	0	4.6
Balance, end of period	0	0	0
Pension and Other Benefit Costs [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Balance, beginning of period	(2.2)	(1.2)	(2.6)
Changes during period	0.1	(1)	1.4
Balance, end of period	(2.1)	(2.2)	(1.2)
Deferred Income Taxes [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Balance, beginning of period	0.9	0.5	2.9
Changes during period	0	0.4	(2.4)
Balance, end of period	$ 0.9	$ 0.9	$ 0.5

Share-Based Compensation & De68

Share-Based Compensation & Deferred Compensation Arrangements (Details) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)$ / sharesshares	Dec. 31, 2014USD ($)$ / sharesshares	Dec. 31, 2013USD ($)$ / sharesshares
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Total cost of share-based compensation	$ 19.4	$ 25.2	$ 14.8
Less capitalized cost	4.8	5.3	2.8
Total in other operating expense	14.6	19.9	12
Less income tax benefit in earnings	5.7	7.9	4.8
After tax effect of share-based compensation	$ 8.9	$ 12	$ 7.2
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	$ 15.4
Weighted-average life of unrecognized compensation cost (in years)	1 year 7 months
Deferred Compensation Plans [Abstract]
Liability associated with deferred compensation plans	$ 31.2	$ 31.2
Portion of liability classified in Accrued liabilities	1.4	1.4
Impact of deferred compensation plans on Other operating expenses	0.1	5	$ 4
Amount recorded in earnings related to the investment activities in phantom stock associated with deferred compensation plans	(0.4)	4	2.6
Cash surrender value of life insurance policies	30.1	32.3
Earnings (loss) from investments in corporate-owned life insurance policies	$ (2.1)	2.8	4.8
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	$ 1.1	$ 0.9	$ 0.4
Share Based Payment Award Equity Instruments Other Than Options [Roll Forward]
Performance based awards at beginning of period (in shares) \| shares	34,273	79,957
Granted (in shares) \| shares	13,657	5,910
Vested (in shares) \| shares	(29,232)	(51,594)
Forfeited (in shares) \| shares	(3,325)	0
Performance based awards at end of period (in shares) \| shares	15,373	34,273	79,957
Weighted average grant date fair value at beginning of period (in dollars per share) \| $ / shares	$ 30.55	$ 29.12
Weighted average grant date fair value of shares granted during period (in dollars per share) \| $ / shares	30.39	31.24
Weighted average grant date fair value of shares vested during period (in dollars per share) \| $ / shares	29.87	28.36
Weighted average grant date fair value of shares forfeited during period (in dollars per share) \| $ / shares	30.95	0
Weighted average grant date fair value at end of period (in dollars per share) \| $ / shares	$ 31.63	$ 30.55	$ 29.12
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	$ 16.6	$ 15.1	$ 5.7
Share Based Payment Award Equity Instruments Other Than Options [Roll Forward]
Performance based awards at beginning of period (in shares) \| shares	693,159	731,251
Granted (in shares) \| shares	394,967	331,344
Vested (in shares) \| shares	(389,331)	(347,031)
Forfeited (in shares) \| shares	(52,308)	(22,405)
Performance based awards at end of period (in shares) \| shares	646,487	693,159	731,251
Weighted average grant date fair value at beginning of period (in dollars per share) \| $ / shares	$ 46.23
Weighted average grant date fair value at end of period (in dollars per share) \| $ / shares	$ 42.42	$ 46.23

Commitments and Contingencies (

Commitments and Contingencies (Details) $ in Millions	12 Months Ended
Commitments and Contingencies (Details) $ in Millions	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Commitments [Abstract]
Future minimum operating lease payments due within one year of the balance sheet date	$ 8.6
Future minimum operating lease payments due within the second year of the balance sheet date	5.7
Future minimum operating lease payments due within the third year of the balance sheet date	3.8
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	1.9
Future minimum operating lease payments due within after the fifth year of the balance sheet date	8.3
Total lease expense	$ 11.1	$ 13.2	$ 9.9
Guarantees for ESG [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)	42
Average face amount of surety bonds wholly owned subsidiary has outstanding	$ 9.8
Maximum face amount of surety bond wholly owned subsidiary had outstanding	$ 51
Percent of work completed on projects covered by open surety bonds (in hundredths)	39.00%
Timeframe when significant portion of performance guarantee commitments will be fulfilled	within one year
Product Warranty Accrual	$ 0
Performance Guarantee [Member] \| Guarantees for ESG [Member]
Corporate Guarantees [Abstract]
Maximum exposure by parent company on guarantees.	$ 185

Gas Rate & Regulatory Matters (

Gas Rate & Regulatory Matters (Details)	12 Months Ended
Gas Rate & Regulatory Matters (Details)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)	Aug. 27, 2014
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items]
Other Nonoperating Income (Expense)	$ 20,300,000	$ 19,700,000	$ 17,700,000
OHIO \| Ohio Recovery and Deferral Mechanisms [Member]
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items]
Cumulative gross plant invesment made under Distribution Replacement Rider	202,500,000
Regulatory Asset associated with DRR deferrals of depreciation and post in-service carrying costs	$ 18,200,000	13,100,000
Initial DRR Term	5
Amount of Capital Investment Expected Over Next Five Years Recoverable Under DRR	$ 200,000,000
OHIO \| Ohio House Bill95 [Member]
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items]
Bill impact per customer per month	1.50
Other Nonoperating Income (Expense)	6,400,000	3,900,000
Amount of deferral related to depreciation and property tax expense	5,400,000	3,100,000
INDIANA \| Indiana Recovery and Deferral Mechanisms [Member]
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items]
Regulatory Assset balance associated with Vectren north and south programs	$ 19,900,000	16,400,000
INDIANA \| Senate Bill 251 and 560 [Member]
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items]
Length of project plan required for recovery under new legislation	7 years
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%
Expected Seven Year Period Modernization Investment	$ 1,000,000,000
Capital Expenditure Increases	100,000,000
Project spend life to date	272,000,000
Regulatory assets related to return on investment, depreciation deferral, and other operating expenses	28,600,000	$ 11,400,000
Amount approved by the Commission for planned infrastructure investments	800,000,000
SIGECO [Member] \| INDIANA \| Indiana Recovery and Deferral Mechanisms [Member]
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items]
Allowable capital expenditures under Vectren South program	$ 3,000,000
Limitations of deferrals of debt-related post in service carrying costs	3
Indiana Gas [Member] \| INDIANA \| Indiana Recovery and Deferral Mechanisms [Member]
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items]
Allowable capital expenditures under Vectren North Program	$ 20,000,000
Limitations of deferrals of debt-related post in service carrying costs	4
INDIANA \| Indiana Gas [Member] \| Indiana Gas GCA Cost Recovery [Member]
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items]
Original amount of recovery opposed by OUCC	$ 3,900,000
Amount of recovery supported by OUCC	3,000,000
Estimated amount of settlement recoverable through the Company's GCA mechanism	1,400,000
Estimated amount of settlement recoverable through the gas supply administrator	$ 1,600,000

Electric Rate and Regulatory 71

Electric Rate and Regulatory Matters (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Vectren South Electric Environmental Compliance Filing [Abstract]
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	29
Lower range of request for approval of capital investments on coal-fired generation units	75
Upper range of request for approval of capital investments on coal-fired generation units	85
Amount of deferred costs to date related to depreciation, property tax, and operating expenses under Senate Bill 29 and Senate Bill 251	2.7
Amount of deferred costs to date related to post in-service carrying costs under Senate Bill 29 and Senate Bill 251.	1.1
Estimated cost of equipment to comply with MATS	35
Estimated cost of equipment required by the NOV	$ 40
Number Of Years In Initial Demand Side Management Program	3
Vectren South Electric Demand Side Management Program Filing [Abstract]
Electric revenue recognized associated with lost margin recovery	$ 10.1	$ 8.7	$ 5
Percent of industrial load opt out of applicable energy efficiency programs	80.00%
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%
Equity component, upper limit, as a percentage, sought by third party through joint complaint	50.00%
Gross Investment In Qualifying Transmission Projects	$ 157.7
Net Investment in Qualifying Transmission Projects	$ 140.2
Incentive return granted on qualifying investments in NETO	11.14%
Percentage return approved by FERC on ROE complaint against NETO	10.57%
FERC authorized base ROE percentage for first refund period	10.32%
Number of incentive basis point above and beyond approved FERC approved ROE	50

Environmental Matters (Details)

Environmental Matters (Details) $ in Millions	12 Months Ended
Environmental Matters (Details) $ in Millions	Dec. 31, 2015USD ($)MW	Dec. 31, 2013USD ($)	Sep. 30, 2015USD ($)	Dec. 31, 2014USD ($)
Air Quality [Abstract]
Estimated cost of equipment to comply with MATS	$ 35
Estimated cost of equipment required by the NOV	$ 40
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]
Estimated Capital Expenditures to Comply With Ash Pond and Coal Ash Disposal Regulations - Lower Range	$ 35
Estimated Capital Expenditures to Comply With Ash Pond and Coal Ash Disposal Regulations - Upper Range	80
Asset Retirement Obligation	82	$ 41.3	$ 25	$ 55
Estimated capital expenditures to comply with Clean Water Act (Lower Range)	4
Estimated capital expenditures to comply with Clean Water Act (Upper Range)	$ 8
Climate Changes [Abstract]
Vectren's share of Indiana's total CO2 emmisions in 2013 (in tons)		6,300,000
Vectren's share of Indiana's CO2 emissions in 2013 (as a percent)		6.00%
Percent reduction of Vectren's CO2 emissions since 2005	27.00%
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
Site contingency, accrual, undiscounted amount	$ 43.4
Accrual for Environmental Loss Contingencies	$ 3.3			$ 3.6
Indiana Gas [Member]
Manufactured Gas Plants
Number of sites identified with potential remedial responsibility for entity (in number of sites)	26
Site contingency, accrual, undiscounted amount	$ 23.2
Environmental cost recognized, recover from insurance carriers credited to expense	$ 20.8
SIGECO [Member]
Manufactured Gas Plants
Number of sites identified with potential remedial responsibility for entity (in number of sites)	5
Site contingency, accrual, undiscounted amount	$ 20.2
Environmental cost recognized, recover from insurance carriers credited to expense	14.8
Expected Site Contingency Recovery from Insurance Carriers of Environmental Remediation Costs	$ 15.8

Fair Value Measurements (Detail

Fair Value Measurements (Details) - USD ($) $ in Millions	12 Months Ended
Fair Value Measurements (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other Assets, Fair Value Disclosure		$ 16.1	$ 10.4
Period to recover call premiums on reacquisition of long-term debt	15
Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	$ 1,795.8	1,577.3
Short-term borrowings & notes payable	14.5	156.4
Cash and cash equivalents	74.7	86.4
Estimated Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	1,909.5	1,754.5
Short-term borrowings & notes payable	14.5	156.4
Cash and cash equivalents	$ 74.7	$ 86.4

Segment Reporting (Details)

Segment Reporting (Details) $ in Millions	3 Months Ended								12 Months Ended
Segment Reporting (Details) $ in Millions	Dec. 31, 2015USD ($)	Sep. 30, 2015USD ($)	Jun. 30, 2015USD ($)	Mar. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Sep. 30, 2014USD ($)	Jun. 30, 2014USD ($)	Mar. 31, 2014USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Additions									$ 476.9	$ 448.3	$ 393.4
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	$ 604	$ 573.5	$ 551	$ 706.2	$ 676.8	$ 595.6	$ 542.5	$ 796.8	$ 2,434.7	2,611.7	2,491.2
Net income (loss)	65.2	$ 39.3	$ 35.8	$ 57	56.5	$ 47.3	$ 11.9	$ 51.2	197.3	166.9	136.6
Amounts Included in Profitability Measures [Abstract]
Depreciation and Amortization									256.3	273.4	277.8
Interest Expense									84.5	86.7	87.9
Income Taxes									99.7	81.1	67.1
Assets	5,409.9				5,146				5,409.9	5,146	5,088.7
Related Party Transaction, Expenses from Transactions with Related Party											200.5
Utility Group [Member]
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Additions									398.3	350.7	261.1
Revenues									1,394.5	1,569.7	1,429.6
Net income (loss)									160.9	148.4	141.8
Amounts Included in Profitability Measures [Abstract]
Depreciation and Amortization									208.8	203.1	196.4
Interest Expense									66.3	66.6	65
Income Taxes									88.1	83.2	85.3
Assets	4,601.3				4,416.8				4,601.3	4,416.8	4,135.3
Related Party Transaction, Expenses from Transactions with Related Party									109.5	94	54.2
Utility Group [Member] \| Gas Utility Services [Member]
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Additions									291.2	245.9	150.5
Revenues									792.6	944.6	810
Net income (loss)									64.4	57	55.7
Amounts Included in Profitability Measures [Abstract]
Depreciation and Amortization									98.6	93.3	90.5
Interest Expense									35.8	34.9	30.6
Income Taxes									40.8	35.7	36.6
Assets	2,707.5				2,605.1				2,707.5	2,605.1	2,286.6
Utility Group [Member] \| Electric Utility Services [Member]
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Additions									87.6	92.4	100
Revenues									601.6	624.8	619.3
Net income (loss)									82.6	79.7	75.8
Amounts Included in Profitability Measures [Abstract]
Depreciation and Amortization									85.6	85.7	84
Interest Expense									27.8	29	29.2
Income Taxes									49.3	48.1	48.3
Assets	1,782.2				1,659.3				1,782.2	1,659.3	1,679
Utility Group [Member] \| Intersegment Elimination [Member]
Segment Reporting Information [Line Items]
Revenues									(40.4)	(38)	(37.8)
Utility Group [Member] \| Non-Cash Cost and Change in Accruals [Member]
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Additions									6.2	10.9	15.2
Utility Group [Member] \| Other Segments [Member]
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Additions									25.7	23.3	25.8
Revenues									40.7	38.3	38.1
Net income (loss)									13.9	11.7	10.3
Amounts Included in Profitability Measures [Abstract]
Depreciation and Amortization									24.6	24.1	21.9
Interest Expense									2.7	2.7	5.2
Income Taxes									(2)	(0.6)	0.4
Assets	111.6				152.4				111.6	152.4	169.7
Nonutility Group [Member]
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Additions									78.6	97.6	132.3
Revenues									1,043.2	1,143.1	1,167.6
Net income (loss)									36.3	18	(4.5)
Amounts Included in Profitability Measures [Abstract]
Depreciation and Amortization									47.5	70.3	81.4
Interest Expense									18.4	20.8	23.2
Income Taxes									13.4	(1)	(17.1)
Assets	778.8				745.9				778.8	745.9	1,026.1
Nonutility Group [Member] \| Infrastructure Services [Member]
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Additions									78.1	54.1	79.2
Revenues									843.3	779	783.5
Net income (loss)									29.7	43.1	49
Amounts Included in Profitability Measures [Abstract]
Depreciation and Amortization									44.5	36.2	28.8
Interest Expense									16	11.1	10.1
Income Taxes									19.6	28.9	34.3
Assets	554.5				538.5				554.5	538.5	461.7
Nonutility Group [Member] \| Energy Services [Member]
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Additions									0.5	1.6	6.9
Revenues									199.9	129.8	91.3
Net income (loss)									7.3	(3.2)	1
Amounts Included in Profitability Measures [Abstract]
Depreciation and Amortization									2.7	3.9	1.7
Interest Expense									1.2	1.3	0.6
Income Taxes									(7.7)	(7.8)	(11.9)
Assets	160.3				87.1				160.3	87.1	63
Nonutility Group [Member] \| Coal Mining [Member]
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Additions									0	41.9	46.2
Revenues									0	234.3	292.8
Net income (loss)									0	(21.1)	(16)
Amounts Included in Profitability Measures [Abstract]
Depreciation and Amortization									0	29.9	50.8
Interest Expense									0	7.5	9.8
Income Taxes									0	(21.8)	(14.6)
Assets	0				0				0	0	433
Nonutility Group [Member] \| Energy Marketing [Member]
Segment Reporting Information [Line Items]
Net income (loss)									0	0	(37.5)
Amounts Included in Profitability Measures [Abstract]
Interest Expense									0	0	2.2
Income Taxes									0	0	(23.3)
Nonutility Group [Member] \| Other Businesses [Member]
Segment Reporting Information [Line Items]
Net income (loss)									(0.7)	(0.8)	(1)
Amounts Included in Profitability Measures [Abstract]
Depreciation and Amortization									0.3	0.3	0.1
Interest Expense									1.2	0.9	0.5
Income Taxes									1.5	(0.3)	(1.6)
Assets	64				120.3				64	120.3	68.4
Corporate and Other [Member]
Segment Reporting Information [Line Items]
Net income (loss)									0.1	0.5	(0.7)
Amounts Included in Profitability Measures [Abstract]
Interest Expense									0.2	0.7	0.3
Income Taxes									(1.8)	(1.1)	(1.1)
Assets	743.7				655.6				743.7	655.6	824.2
Intersegment Elimination [Member]
Segment Reporting Information [Line Items]
Revenues									(3)	(101.1)	(106)
Amounts Included in Profitability Measures [Abstract]
Assets	$ (713.9)				$ (672.3)				$ (713.9)	$ (672.3)	$ (896.9)

Additional Balance Sheet & Op75

Additional Balance Sheet & Operational Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Inventory, Net [Abstract]
Gas in storage - at LIFO cost	$ 40.5	$ 40.5
Coal and Oil for electric generation - at average cost	45	33.8
Materials and supplies	46.9	42.5
Other	1.3	1.7
Total inventories	133.7	118.5
Amount by which cost of replacing inventories carried at LIFO cost exceeded carrying value		3
Prepayments and other current assets [Abstract]
Prepaid gas delivery service	30	40.7
Deferred income taxes	15.3	16.3
Prepaid taxes	25.3	37.5
Other prepayments and current assets	25.7	16.4
Total prepayments and other current assets	81	94.6
Investments in unconsolidated affiliates [Abstract]
Total investments in unconsolidated affiliates	20.9	23.4
Equity in earnings (loss) of unconsolidated affiliates [Abstract]
Equity in earnings (losses) of unconsolidated affiliates	(0.6)	0.5	$ (59.7)
Other utility and corporate investments [Abstract]
Cash surrender value of life insurance policies	30.1	32.3
Municipal bond	0	3.1
Restricted cash & other investments	1.1	1.8
Other utility and corporate investments	31.2	37.2
Goodwill	293.5	289.9
Accrued liabilities [Abstract]
Refunds to customers and customer deposits	51.4	51.3
Accrued taxes	39.9	35.8
Accrued interest	19.4	19.1
Deferred compensation & post-retirement benefits	7.2	7.3
Accrued salaries and other	65.7	71.4
Total accrued liabilities	183.6	184.9
Asset Retirement Obligation [Roll Forward]
Asset retirement obligation, beginning balance	55	41.3
Accretion	3.2	1.7
Asset Retirement Obligation, Liabilities Incurred	24.2	0
Changes in estimates, net of cash payments	(0.4)	23.8
Asset Retirement Obligation, Liabilities Settled	0	(11.8)
Asset retirement obligation, ending balance	82	55	41.3
Other - net in the consolidated statement of income [Abstract]
AFUDC - borrowed funds	16.3	11.4	5.9
AFUDC - equity funds	2.6	3.2	0.8
Nonutility plant capitalized interest	0.4	0	0.5
Interest income, net	1.3	1.1	1.1
Other nonutility investment impairment charges	(0.1)	(1)	0
Cash surrender value of life insurance policies	(2.1)	2.8	4.8
All other income	1.9	2.2	4.6
Total other income (expense) – net	20.3	19.7	17.7
Cash paid (received) for [Abstract]
Interest	84.2	87.5	91
Income taxes	4.8	69.4	6.8
Accruals related to utility and nonutility plant purchases [Abstract]
Accruals related to utility and nonutility plant purchases	19.4	20.2
ProLiance Holdings, LLC [Member]
Investments in unconsolidated affiliates [Abstract]
Total investments in unconsolidated affiliates	19.7	20.5
Equity in earnings (loss) of unconsolidated affiliates [Abstract]
Equity in earnings (losses) of unconsolidated affiliates	(0.8)	(0.3)	(57.7)
Other Nonutility Partnerships and Corporations [Member]
Investments in unconsolidated affiliates [Abstract]
Total investments in unconsolidated affiliates	1	2.7
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	0.2	0.8	$ (2)
Utility Group [Member] \| Gas Utility Services [Member]
Other utility and corporate investments [Abstract]
Goodwill	205	205
Nonutility Group [Member]
Investments in unconsolidated affiliates [Abstract]
Total investments in unconsolidated affiliates	1	1.6
Nonutility Group [Member] \| Infrastructure Services [Member]
Other utility and corporate investments [Abstract]
Goodwill	58.8	55.2
Nonutility Group [Member] \| Energy Services [Member]
Other utility and corporate investments [Abstract]
Goodwill	$ 29.7	$ 29.7

Quarterly Financial Data (Una76

Quarterly Financial Data (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Quarterly Financial Information Disclosure [Abstract]
Operating revenues	$ 604	$ 573.5	$ 551	$ 706.2	$ 676.8	$ 595.6	$ 542.5	$ 796.8	$ 2,434.7	$ 2,611.7	$ 2,491.2
Operating income	103	79.9	72.9	106.1	97.1	84.5	33.9	99	361.8	314.5	333.6
Net Income	$ 65.2	$ 39.3	$ 35.8	$ 57	$ 56.5	$ 47.3	$ 11.9	$ 51.2	$ 197.3	$ 166.9	$ 136.6
Earnings per share [Abstract]
Basic	$ 0.79	$ 0.48	$ 0.43	$ 0.69	$ 0.68	$ 0.57	$ 0.14	$ 0.62	$ 2.39	$ 2.02	$ 1.66
DILUTED (in dollars per share)									$ 2.39	$ 2.02	$ 1.66

SCHEDULE II VALUATION AND QUA77

SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Accumulated Provision for Uncollectible Accounts [Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
Balance, at beginning of year	$ 6	$ 6.8	$ 6.8
Additions charged to expenses	8.1	7.3	6.8
Additions charged to other accounts	0	0	0
Deductions from Reserves, Net	8.5	8.1	6.8
Balance, at end of period	5.6	6	6.8
Reserve for Impaired Notes Receivable [Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
Balance, at beginning of year	0	0.6	0.6
Additions charged to expenses	0.2	0	0
Additions charged to other accounts	0	0	0
Deductions from Reserves, Net	0	0.6	0
Balance, at end of period	$ 0.2	$ 0	$ 0.6