Vectren Utility 10-K 9 Mar 16 2015 FY Annual report Financial data

Document And Entity Information

Document And Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2015	Feb. 29, 2016	Jun. 30, 2015
Entity Information [Line Items]
Entity Registrant Name	VECTREN UTILITY HOLDINGS INC
Entity Central Index Key	1,129,542
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Document Type	10-K
Document Period End Date	Dec. 31, 2015
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 0
Entity Common Stock, Shares Outstanding		10

CONSOLIDATED CONDENSED BALANCE

CONSOLIDATED CONDENSED BALANCE SHEETS (Unaudited) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Assets, Current [Abstract]
Cash & cash equivalents	$ 6.2	$ 19.3
Accounts receivable - less reserves of $3.0 & $3.9, respectively	92.3	113
Accrued unbilled revenues	85.7	122.4
Inventories	125.3	113.2
Recoverable fuel & natural gas costs	0	9.8
Prepayments & other current assets	49	72.2
Total current assets	358.5	449.9
Utility Plant [Abstract]
Original Cost	6,090.4	5,718.7
Less: accumulated depreciation & amortization	2,415.5	2,279.7
Net utility plant	3,674.9	3,439
Investments in unconsolidated affiliates	0.2	0.2
Other investments	20.1	25.6
Nonutility plant - net	149.7	149.2
Goodwill - net	205	205
Regulatory assets	160.7	128.3
Other assets	32.2	19.6
TOTAL ASSETS	4,601.3	4,416.8
Current Liabilities [Abstract]
Accounts payable	168.5	180.4
Payables to other Vectren companies	25.7	28.6
Accrued liabilities	128.4	122.3
Short-term borrowings	14.5	156.4
Current maturities of long-term debt	13	95
Total current liabilities	350.1	582.7
Long-Term Debt - Net of Current Maturities	1,387.8	1,162.3
Deferred Income Taxes & Other Liabilities [Abstract]
Deferred income taxes	758.4	673.8
Regulatory liabilities	433.9	410.3
Deferred credits & other liabilities	135.9	109.2
Total deferred credits and other liabilities	$ 1,328.2	$ 1,193.3
Commitments & Contingencies (Notes 8-11)
Common Shareholder's Equity [Abstract]
Common stock (no par value)	$ 799.9	$ 793.7
Retained earnings	735.3	684.8
Total common shareholders' equity	1,535.2	1,478.5
TOTAL LIABILITIES and SHAREHOLDERS' EQUITY	$ 4,601.3	$ 4,416.8

CONSOLIDATED CONDENSED BALANCE3

CONSOLIDATED CONDENSED BALANCE SHEETS (Unaudited) (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Assets, Current [Abstract]
Allowance for Doubtful Accounts Receivable, Current	$ 3	$ 3.9

CONSOLIDATED CONDENSED STATEMEN

CONSOLIDATED CONDENSED STATEMENTS OF INCOME (Unaudited) - 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
OPERATING REVENUES [Abstract]
Gas utility									$ 792.6	$ 944.6	$ 810
Electric utility									601.6	624.8	619.3
Other									0.3	0.3	0.3
Total operating revenues	$ 338.1	$ 273	$ 276.5	$ 506.9	$ 407.5	$ 271.1	$ 284.5	$ 606.6	1,394.5	1,569.7	1,429.6
OPERATING EXPENSES [Abstract]
Cost of gas sold									305.4	468.7	358.1
Cost of fuel & purchased power									187.5	201.8	202.9
Other operating									339.1	354.5	333.4
Depreciation & Amortization									208.8	203.1	196.4
Taxes other than income taxes									57.1	60.2	57.2
Total operating expenses									1,097.9	1,288.3	1,148
OPERATING INCOME	81.3	54.1	50.5	110.8	73.4	49.4	48.1	110.4	296.6	281.4	281.6
Nonoperating Income (Expense) [Abstract]
Other income - net									18.7	16.8	10.5
Interest Expense									66.3	66.6	65
INCOME BEFORE INCOME TAXES									249	231.6	227.1
Income taxes									88.1	83.2	85.3
Net Income	$ 46.6	$ 26.9	$ 24.4	$ 63	$ 39.8	$ 24.3	$ 22.9	$ 61.3	$ 160.9	$ 148.4	$ 141.8

CONSOLIDATED CONDENSED STATEME5

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
CASH FLOWS FROM OPERATING ACTIVITIES [Abstract]
Net Income	$ 160.9	$ 148.4	$ 141.8
Adjustments to Reconcile Net Income to Cash from Operating Activities [Abstract]
Depreciation & Amortization	208.8	203.1	196.4
Deferred income taxes & investment tax credits	85.8	55.7	26.4
Expense portion of pension & postretirement periodic benefit cost	4.8	4.7	5.6
Provision for uncollectible accounts	6.9	6.1	6.5
Other non-cash expense - net	7	3.2	2.5
Changes in working capital accounts [Abstract]
Accounts receivable, including to Vectren companies and accrued unbilled revenues	50.5	(15.8)	(56.8)
Inventories	(12.1)	(23.3)	24.1
Recoverable/refundable fuel & natural gas costs	15.2	(4.4)	22.4
Prepayments & other current assets	30	(34.4)	15.5
Accounts payable, including to Vectren companies & affiliated companies	(15.2)	7.5	10.1
Accrued liabilities	0.7	(2.2)	4.9
Changes in noncurrent ssets	(43.3)	6.4	11.4
Changes in noncurrent liabilities	(7.1)	(17.5)	(10.9)
Net cash flows from operating activities	492.9	337.5	399.9
Proceeds from:
Long-term debt - net of issuance costs	236.3	62.4	381.7
Additional capital contribution	6.2	6	6.1
Requirements for:
Payments of Dividends	(110.4)	(108.7)	(105.1)
Retirement of long-term debt	(95)	(63.6)	(337.5)
Net change in short-term borrowings	(141.9)	127.8	(88.1)
Net cash flows from financing activities	(104.8)	23.9	(142.9)
CASH FLOWS FROM INVESTING ACTIVITIES [Abstract]
Proceeds from other investing activities	3.9	0.3	0.8
Requirements for:
Capital expenditures, excluding AFUDC equity	(399.2)	(351)	(262.5)
Changes in Restricted Cash	(5.9)	0	0
Net cash flows from investing activities	(401.2)	(350.7)	(261.7)
Net change in cash and cash equivalents	(13.1)	10.7	(4.7)
Cash and cash equivalents at beginning of period	19.3	8.6	13.3
Cash and cash equivalents at end of period	$ 6.2	$ 19.3	$ 8.6

Statement of Shareholders' Equi

Statement of Shareholders' Equity - USD ($) $ in Millions	Total	Common Stock [Member]	Retained Earnings [Member]
Balance at beginning of period at Dec. 31, 2012	$ 1,390	$ 781.6	$ 608.4
Balance at end of period at Dec. 31, 2013	1,432.8	787.7	645.1
Net Income	141.8		141.8
Common stock:
Additional Capital Contribution	6.1	6.1
Payments of Dividends	(105.1)		(105.1)
Balance at end of period at Dec. 31, 2014	1,478.5	793.7	684.8
Net Income	148.4		148.4
Common stock:
Additional Capital Contribution	6	6
Payments of Dividends	(108.7)		(108.7)
Balance at end of period at Dec. 31, 2015	1,535.2	799.9	735.3
Net Income	160.9		160.9
Common stock:
Additional Capital Contribution	6.2	$ 6.2
Payments of Dividends	$ (110.4)		$ (110.4)

Organization and Nature of Oper

Organization and Nature of Operations	12 Months Ended
	Dec. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization and Nature of Operations	Organization and Nature of Operations Vectren Utility Holdings, Inc. (the Company, Utility Holdings or VUHI), an Indiana corporation, was formed on March 31, 2000, to serve as the intermediate holding company for Vectren Corporation’s (Vectren) three operating 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. Vectren, an Indiana corporation, is an energy holding company headquartered in Evansville, Indiana, and was organized on June 10, 1999. Both Vectren and Utility Holdings are holding companies as defined by the Energy Policy Act of 2005 (Energy Act). 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.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	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 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. 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. 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. 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. Revenues Revenues are recorded as products and services are delivered to customers. To more closely match revenues and expenses, the Company records revenues for all gas and electricity delivered to customers 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. 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’s operations consist of 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. Fair Value Measurements Certain assets and liabilities are valued and disclosed at fair value. Nonfinancial assets and liabilities include the initial measurement of an asset retirement obligation or the use of fair value in 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. 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. Earnings Per Share Earnings per share are not presented as Utility Holdings’ common stock is wholly owned by Vectren. Other Significant Policies Included elsewhere in these notes are significant accounting policies related to retirement plans and other postretirement benefits, intercompany allocations and income taxes (Note 5).

Utility & Nonutility Plant

Utility & Nonutility Plant	12 Months Ended
	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 and For the Year Ended 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 a 300 MW unit at the Warrick Power Plant (Warrick Unit 4) as tenants in common. SIGECO's share of the cost of this unit at December 31, 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 $ 107.6 $ 105.0 Land & buildings 35.0 35.8 All other 7.1 8.4 Nonutility plant - net $ 149.7 $ 149.2 Nonutility plant is presented net of accumulated depreciation and amortization totaling $248.0 million and $226.7 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 $0.4 million , respectively, on nonutility plant construction projects.

Regulatory Assets & Liabilities

Regulatory Assets & Liabilities	12 Months Ended
	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: Net deferred income taxes (See Note 5) $ (16.9 ) $ (14.8 ) (16.9 ) (14.8 ) 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 $ 160.7 $ 128.3 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. 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.

Transactions with Other Vectren

Transactions with Other Vectren Companies and Affiliates	12 Months Ended
	Dec. 31, 2015
Transactions with Other Vectren Companies and Affiliates [Abstract]
Transactions With Other Vectren Companies and Affiliates [Text Block]	Transactions with Other Vectren Companies and Affiliates Vectren Infrastructure Services Corporation (VISCO) VISCO, a wholly owned subsidiary of Vectren, provides underground pipeline construction and repair services. VISCO’s customers include Utility Holdings’ utilities and fees incurred by Utility Holdings and its subsidiaries totaled $109.5 million in 2015 , $94.0 million in 2014 , and $54.2 million in 2013 . Amounts owed to VISCO at December 31, 2015 and 2014 are included in Payables to other Vectren companies. Vectren Fuels, Inc . On August 29, 2014, Vectren closed on a transaction to sell its wholly-owned coal mining subsidiary, Vectren Fuels, Inc. (Vectren Fuels), to Sunrise Coal, LLC (Sunrise), an Indiana-based wholly-owned subsidiary of Hallador Energy Company. Prior to the sale date, SIGECO purchased coal used for electric generation from Vectren Fuels. Amounts purchased for the years ended December 31, 2014 and 2013 , totaled $98.6 million and $103.7 million , respectively. After the exit of the coal mining business by Vectren, Sunrise has assumed Vectren Fuels' supply contracts and has also negotiated new contracts for similar quality coal that will result in the Company purchasing most of its coal supply from Sunrise. ProLiance Holdings, LLC (ProLiance) Vectren has an investment in ProLiance, a nonutility affiliate of Vectren 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 of its energy marketing business, ProLiance Energy, LLC (ProLiance Energy). ProLiance Energy's customers included, among others, Vectren's Indiana utilities as well as Citizens’ utilities. The Company had no purchases from ProLiance for resale and for injections into storage for the year ended December 31, 2015 and 2014 as a result of ProLiance exiting the natural gas marketing business. For the year ended December 31, 2013 the Company had purchases totaling $200.5 million . Amounts charged by ProLiance for gas supply services were established by supply agreements with each utility. After the exit of the energy marketing business by ProLiance, the Company purchases gas supply from third parties and 78 percent is from a single third party for the year ended December 31, 2015 . Support Services & Purchases Vectren provides corporate and general and administrative services to the Company and allocates certain costs to the Company, including costs for share-based compensation and for pension and other postretirement benefits that are not directly charged to subsidiaries. These costs are allocated using various allocators, including number of employees, number of customers and/or the level of payroll, revenue contribution and capital expenditures. Allocations are at cost. Utility Holdings received corporate allocations totaling $52.3 million , $57.0 million , and $50.9 million for the years ended December 31, 2015 , 2014 and 2013 , respectively. Retirement Plans & Other Postretirement Benefits At December 31, 2015 , Vectren maintains three closed qualified defined benefit pension plans (Vectren Corporation Non-Bargaining Retirement Plan, The Indiana Gas Company, Inc. Bargaining Unit Retirement Plan, Pension Plan for Hourly Employees of Southern Indiana Gas and Electric Company), a nonqualified supplemental executive retirement plan, and a postretirement benefit plan. The defined benefit pension plans and postretirement benefit plan, which cover the Company’s eligible full-time regular employees, are primarily noncontributory. The postretirement health care and life insurance plans are a combination of self-insured and fully insured plans. Utility Holdings and its subsidiaries comprise the vast majority of the participants and retirees covered by these plans. Vectren satisfies the future funding requirements and the payment of benefits from general corporate assets and, as necessary, relies on Utility Holdings to support the funding of these obligations. Although Utility Holdings has no contractual funding obligation, the company contributed $20.0 million to Vectren's defined benefit pension plans during 2015 and did not contribute in 2014. The combined funded status of Vectren’s plans was approximately 90 percent at December 31, 2015 and 87 percent at December 31, 2014 . Vectren allocates the periodic cost of its retirement plans calculated pursuant to US GAAP to its subsidiaries. Periodic cost, comprised of service cost and interest on that service cost, is directly charged to Utility Holdings based on labor at each measurement date and that cost is charged to operating expense and capital projects, using labor charges as the allocation method. For the years ended December 31, 2015 , 2014 and 2013 , costs totaling $7.0 million , $6.7 million and $8.0 million , respectively, were directly charged to Utility Holdings. Other components of periodic costs (such as interest cost, asset returns, and amortizations) and the service cost related to Vectren Corporate operations are charged to subsidiaries through the allocation process discussed above. Any difference between funding requirements and allocated periodic costs is recognized as an asset or liability until reflected in periodic costs. Neither plan assets nor the ending liability is allocated to individual subsidiaries since these assets and obligations are derived from corporate level decisions. The allocation methodology is consistent with FASB guidance related to “multiemployer” benefit accounting. As of December 31, 2015 and 2014 , $12.0 million and $11.6 million , respectively, is included in Deferred credits & other liabilities and represents costs related to other postretirement benefits directly charged to the Company that is yet to be funded to Vectren. As impacted by increased funding of pension plans, at December 31, 2015 and 2014 , the Company has $30.3 million , and $17.3 million , respectively, included in Other Assets representing defined benefit funding by the Company that is yet to be reflected in costs. Share-Based Incentive Plans & Deferred Compensation Plans Utility Holdings does not have share-based compensation plans separate from Vectren. The Company recognizes its allocated portion of expenses related to share-based incentive plans and deferred compensation plans in accordance with FASB guidance and to the extent these awards are expected to be settled in cash that liability is pushed down to Utility Holdings. As of December 31, 2015 and 2014 , $35.7 million and $36.1 million , respectively, is included in Deferred credits & other liabilities and represents obligations that are yet to be funded to Vectren. Income Taxes Utility Holdings does not file federal or state income tax returns separate from those filed by its parent, Vectren Corporation. Vectren files a consolidated U.S. federal income tax return, and Vectren and/or certain of its subsidiaries file income tax returns in various states. Pursuant to a tax sharing agreement and for financial reporting purposes, Vectren subsidiaries record income taxes on a separate company basis. The Company's allocated share of tax effects resulting from it being a part of Vectren's consolidated tax group are recorded at the Utility Holdings parent company level. Current taxes payable/receivable are settled with Vectren in cash quarterly and after filing the consolidated federal and state income tax returns. 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 in accordance with the regulatory treatment. 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. The components of income tax expense and amortization of investment tax credits follow: Year Ended December 31, (In millions) 2015 2014 2013 Current: Federal $ (1.9 ) $ 16.6 $ 48.0 State 4.2 10.9 11.0 Total current taxes 2.3 27.5 59.0 Deferred: Federal 81.7 57.8 26.8 State 4.6 (1.6 ) 0.1 Total deferred taxes 86.3 56.2 26.9 Amortization of investment tax credits (0.5 ) (0.5 ) (0.6 ) Total income tax expense $ 88.1 $ 83.2 $ 85.3 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 and local taxes-net of federal benefit 2.8 3.3 3.5 Amortization of investment tax credit (0.2 ) (0.2 ) (0.3 ) Domestic production deduction (0.9 ) (0.9 ) — Research and development credit (2.0 ) (0.3 ) (0.6 ) All other - net 0.7 (1.0 ) — Effective tax rate 35.4 % 35.9 % 37.6 % 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 $ 752.6 $ 685.0 Regulatory assets recoverable through future rates 31.6 29.2 Alternative minimum tax carryforward (34.5 ) (51.4 ) Employee benefit obligations 7.2 1.0 Regulatory liabilities to be settled through future rates (29.9 ) (27.5 ) Deferred fuel costs - net 14.2 22.0 Other – net 17.2 15.5 Net noncurrent deferred tax liability $ 758.4 $ 673.8 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 $13.2 million and $11.2 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 $2.1 million and $2.6 million , respectively, are included in Deferred credits & other liabilities . At December 31, 2015 , the Company has alternative minimum tax carryforwards of $34.5 million , which do not expire. 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 $0.8 million and $0.1 million , respectively, at December 31, 2015 and 2014 . Vectren 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 Vectren's U.S. federal income tax returns for tax years through December 31, 2012. The State of Indiana, Vectren's primary state tax jurisdiction, has conducted examinations of state income tax returns for tax years through December 31, 2010. The statutes of limitations for assessment of federal income tax and Indiana income tax have expired with respect to tax years through 2011 except to the extent of refunds claimed on amended tax returns. The statutes of limitations for assessments 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.

Borrowing Arrangements

Borrowing Arrangements	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
Borrowing Arrangements	Borrowing Arrangements Short-Term Borrowings At December 31, 2015 , the Company had $350 million of short-term borrowing capacity. As reduced by borrowings outstanding at December 31, 2015 , approximately $335 million was available. This short-term credit facility was extended in October 2014 and is available through October 2019 . The maximum limit of the facility remained unchanged. This facility is used to supplement working capital needs and also to fund capital investments and debt redemptions until financed on a long-term basis. The facility has a letter of credit limit of $100 million . As of December 31, 2015 , there was no letters of credit outstanding under the facility. The Company has historically funded the short-term borrowing needs through the commercial paper market and expects to use the short-term borrowing facility in instances where the commercial paper market is not efficient. Following is certain information regarding these short-term borrowing arrangements: (In millions) 2015 2014 2013 Year End Balance Outstanding $ 14.5 $ 156.4 $ 28.6 Weighted Average Interest Rate 0.55 % 0.50 % 0.29 % Annual Average Balance Outstanding $ 53.8 $ 35.6 $ 119.6 Weighted Average Interest Rate 0.38 % 0.34 % 0.34 % Maximum Month End Balance Outstanding $ 121.5 $ 156.4 $ 176.1 Throughout the years presented, the Company has successfully placed commercial paper as needed. 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 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 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 Total long-term debt outstanding 1,401.7 1,258.5 Current maturities of long-term debt (13.0 ) (95.0 ) Unamortized debt premium & discount - net (0.9 ) (1.2 ) Total long-term debt-net $ 1,387.8 $ 1,162.3 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 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. A portion of the proceeds received from this issuance was 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, and (ii) $5 and $10 million of 6.69 percent Indiana Gas senior unsecured notes that matured on December 21, 2015 and December 29, 2015, respectively. 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. 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 in 2038 , and $39.6 million at 4.05 percent per annum due in 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 $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 SIGECO, Indiana Gas, 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 SIGECO, Indiana Gas, 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 years following 2015 (in millions) are $13.0 million in 2016 , $100.0 in 2018 , $100.0 in 2020 , and $1,187.8 thereafter. There are no maturities of long-term debt in 2017 or 2019. Debt Guarantees Utility Holdings’ currently outstanding long-term and short-term debt is jointly and severally guaranteed by SIGECO, Indiana Gas, 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.

Common Shareholder's Equity

Common Shareholder's Equity	12 Months Ended
	Dec. 31, 2015
Stockholders' Equity Note [Abstract]
Common Shareholder's Equity	Common Shareholder’s Equity During the years ended December 31, 2015 , 2014 , and 2013 , the Company has cumulatively received additional capital of $18.3 million from Vectren which was funded by new share issues from Vectren’s dividend reinvestment plan.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	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 $0.8 in 2016 , $0.8 in 2017 , $0.8 in 2018 , $0.6 in 2019 , $0.5 in 2020 , and $2.3 thereafter. Total lease expense (in millions) was $0.8 in 2015 , $1.5 in 2014 , and $1.1 in 2013 . Firm purchase commitments for utility plant total $2.3 million in 2016 and $1.1 million in 2017 . The Company’s regulated utilities have both firm and non-firm commitments to purchase natural gas, coal, and electricity 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. Legal Proceedings The Company is party to various legal proceedings, audits, and reviews by taxing authorities and other government agencies arising in the normal course of business. In the opinion of management, there are no legal proceedings or other regulatory reviews or audits pending against the Company that are likely to have a material adverse effect on its financial position, results of operations or cash flows.

Gas Rate & Regulatory Matters

Gas Rate & Regulatory Matters	12 Months Ended
	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
	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
	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 SO2 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
	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 $ 1,400.8 $ 1,503.6 $ 1,257.3 $ 1,408.0 Short-term borrowings 14.5 14.5 156.4 156.4 Cash & cash equivalents 6.2 6.2 19.3 19.3 For the balance sheet dates presented in these financial statements, the Company had no material assets or liabilities recorded at fair value outstanding, and no material assets or liabilities valued using Level 3 inputs. Certain methods and assumptions must be used to estimate the fair value of financial instruments. The fair value of the Company's long-term debt was estimated based on the quoted market prices for the same or similar issues or on the current rates offered to the Company for instruments with similar characteristics. Because of the maturity dates and variable interest rates of short-term borrowings and cash & cash equivalents, those carrying amounts approximate fair value. Because of the inherent difficulty of estimating interest rate and other market risks, the methods used to estimate fair value may not always be indicative of actual realizable value, and different methodologies could produce different fair value estimates at the reporting date. Under current regulatory treatment, call premiums on reacquisition of long-term debt are generally recovered in customer rates over the life of the refunding issue 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.

Segment Reporting

Segment Reporting	12 Months Ended
	Dec. 31, 2015
Segment Reporting [Abstract]
Segment Reporting	Segment Reporting The Company’s operations consist of 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 Company is comprised of three operating segments: Gas Utility Services, Electric Utility Services, and Other Shared Service operations. Net income is the measure of profitability used by management for all operations. Information related to the Company’s business segments is summarized below: Year Ended December 31, (In millions) 2015 2014 2013 Revenues 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 revenues $ 1,394.5 $ 1,569.7 $ 1,429.6 Profitability Measure - 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 net income $ 160.9 $ 148.4 $ 141.8 Amounts Included in Profitability Measures Depreciation & Amortization 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 depreciation & amortization $ 208.8 $ 203.1 $ 196.4 Interest Expense 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 interest expense $ 66.3 $ 66.6 $ 65.0 Income Taxes 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 income taxes $ 88.1 $ 83.2 $ 85.3 Capital Expenditures Gas Utility Services $ 291.2 $ 245.9 $ 150.5 Electric Utility Services 87.6 92.4 100.0 Other Operations 25.7 22.8 25.8 Non-cash costs & changes in accruals (5.3 ) (10.1 ) (13.8 ) Total capital expenditures $ 399.2 $ 351.0 $ 262.5 At December 31, (In millions) 2015 2014 2013 Assets 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 assets $ 4,601.3 $ 4,416.8 $ 4,135.3

Additional Balance Sheet & Oper

Additional Balance Sheet & Operational Information	12 Months Ended
	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 Materials & supplies 38.4 37.2 Coal & oil for electric generation - at average cost 45.0 33.8 Other 1.4 1.7 Total inventories $ 125.3 $ 113.2 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 approximately $3 million . Prepayments & other current assets in the Consolidated Balance Sheets consist of the following: At December 31, (In millions) 2015 2014 Prepaid gas delivery service $ 30.0 $ 40.7 Prepaid taxes 3.9 29.5 Other prepayments & current assets 15.1 2.0 Total prepayments & other current assets $ 49.0 $ 72.2 Other investments in the Consolidated Balance Sheets consist of the following: At December 31, (In millions) 2015 2014 Cash surrender value of life insurance policies $ 19.2 $ 20.8 Municipal bond — 3.2 Restricted cash & other investments 0.9 1.6 Total other investments $ 20.1 $ 25.6 Accrued liabilities in the Consolidated Balance Sheets consist of the following: At December 31, (In millions) 2015 2014 Refunds to customers & customer deposits $ 51.4 $ 51.3 Accrued taxes 36.7 33.9 Accrued interest 16.3 16.1 Accrued salaries & other 24.0 21.0 Total accrued liabilities $ 128.4 $ 122.3 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 $ 54.6 $ 29.1 Accretion 3.3 1.7 Liabilities incurred in current period 24.2 — — Changes in estimates, net of cash payments (0.2 ) 23.8 Asset retirement obligation, December 31 $ 81.9 $ 54.6 Other – net in the Consolidated Statements of Income consists of the following: Year Ended December 31, (In millions) 2015 2014 2013 AFUDC - borrowed funds $ 16.3 $ 10.8 $ 5.9 AFUDC - equity funds 2.6 3.2 0.8 Nonutility plant capitalized interest 0.4 0.6 0.4 Interest income 0.6 0.7 0.6 Cash surrender value of life insurance policies (1.5 ) 0.6 1.7 Other income 0.3 0.9 1.1 Total other – net $ 18.7 $ 16.8 $ 10.5 Supplemental Cash Flow Information: Year Ended December 31, (In millions) 2015 2014 2013 Cash paid (received) for: Interest $ 66.2 $ 66.7 $ 68.2 Income taxes (23.1 ) 63.2 30.9 As of December 31, 2015 and 2014 , the Company has accruals related to utility and nonutility plant purchases totaling approximately $18.1 million and $19.0 million , respectively.

Subsidiary Guarantor and Consol

Subsidiary Guarantor and Consolidating Information	12 Months Ended
	Dec. 31, 2015
Subsidiary Guarantor and Consolidating Information [Abstract]
Subsidiary Guarantor and Consolidating Information [Text Block]	Subsidiary Guarantor & Consolidating Information The Company’s three operating utility companies, SIGECO, Indiana Gas, and VEDO, are guarantors of Utility Holdings’ $350 million in short-term credit facilities, of which $15 million is outstanding at December 31, 2015 , and Utility Holdings’ $1 billion unsecured senior notes outstanding at December 31, 2015 . The guarantees are full and unconditional and joint and several, and Utility Holdings has no subsidiaries other than the subsidiary guarantors. However, Utility Holdings does have operations other than those of the subsidiary guarantors. Pursuant to Item 3-10 of Regulation S-X, disclosure of the results of operations and balance sheets of the subsidiary guarantors, which are 100 percent owned, separate from the parent company’s operations is required. Following are consolidating financial statements including information on the combined operations of the subsidiary guarantors separate from the other operations of the parent company. Pursuant to a tax sharing agreement, consolidating tax effects, which are calculated on a separate return basis, are reflected at the parent level. Consolidating Statement of Income for the year ended December 31, 2015 (in millions): Subsidiary Guarantors Parent Company Reclassifications and Eliminations Consolidated OPERATING REVENUES Gas utility $ 792.6 $ — $ — $ 792.6 Electric utility 601.6 — — 601.6 Other — 40.7 (40.4 ) 0.3 Total operating revenues 1,394.2 40.7 (40.4 ) 1,394.5 OPERATING EXPENSES Cost of gas sold 305.4 — — 305.4 Cost of fuel & purchased power 187.5 — — 187.5 Other operating 376.9 — (37.8 ) 339.1 Depreciation & amortization 184.2 24.3 0.3 208.8 Taxes other than income taxes 55.2 1.8 0.1 57.1 Total operating expenses 1,109.2 26.1 (37.4 ) 1,097.9 OPERATING INCOME 285.0 14.6 (3.0 ) 296.6 OTHER INCOME (EXPENSE) Equity in earnings of consolidated companies — 147.0 (147.0 ) — Other – net 15.7 42.7 (39.7 ) 18.7 Total other income (expense) 15.7 189.7 (186.7 ) 18.7 Interest expense 63.7 45.3 (42.7 ) 66.3 INCOME BEFORE INCOME TAXES 237.0 159.0 (147.0 ) 249.0 Income taxes 90.0 (1.9 ) — 88.1 NET INCOME $ 147.0 $ 160.9 $ (147.0 ) $ 160.9 Consolidating Statement of Income for the year ended December 31, 2014 (in millions): Subsidiary Guarantors Parent Company Reclassifications and Eliminations Consolidated OPERATING REVENUES Gas utility $ 944.6 $ — $ — $ 944.6 Electric utility 624.8 — — 624.8 Other — 38.3 (38.0 ) 0.3 Total operating revenues 1,569.4 38.3 (38.0 ) 1,569.7 OPERATING EXPENSES Cost of gas sold 468.7 — — 468.7 Cost of fuel & purchased power 201.8 — — 201.8 Other operating 390.3 — (35.8 ) 354.5 Depreciation & amortization 179.1 23.5 0.5 203.1 Taxes other than income taxes 58.4 1.7 0.1 60.2 Total operating expenses 1,298.3 25.2 (35.2 ) 1,288.3 OPERATING INCOME 271.1 13.1 (2.8 ) 281.4 OTHER INCOME (EXPENSE) Equity in earnings of consolidated companies — 136.7 (136.7 ) — Other – net 13.3 43.2 (39.7 ) 16.8 Total other income (expense) 13.3 179.9 (176.4 ) 16.8 Interest expense 63.9 45.2 (42.5 ) 66.6 INCOME BEFORE INCOME TAXES 220.5 147.8 (136.7 ) 231.6 Income taxes 83.8 (0.6 ) — 83.2 NET INCOME $ 136.7 $ 148.4 $ (136.7 ) $ 148.4 Consolidating Statement of Income for the year ended December 31, 2013 (in millions): Subsidiary Guarantors Parent Company Reclassifications and Eliminations Consolidated OPERATING REVENUES Gas utility $ 810.0 $ — $ — $ 810.0 Electric utility 619.3 — — 619.3 Other — 37.9 (37.6 ) 0.3 Total operating revenues 1,429.3 37.9 (37.6 ) 1,429.6 OPERATING EXPENSES Cost of gas sold 358.1 — — 358.1 Cost of fuel & purchased power 202.9 — — 202.9 Other operating 369.2 — (35.8 ) 333.4 Depreciation & amortization 174.6 21.3 0.5 196.4 Taxes other than income taxes 55.6 1.5 0.1 57.2 Total operating expenses 1,160.4 22.8 (35.2 ) 1,148.0 OPERATING INCOME 268.9 15.1 (2.4 ) 281.6 OTHER INCOME (EXPENSE) Equity in earnings of consolidated companies — 131.3 (131.3 ) — Other – net 7.1 38.5 (35.1 ) 10.5 Total other income (expense) 7.1 169.8 (166.4 ) 10.5 Interest expense 59.8 42.7 (37.5 ) 65.0 INCOME BEFORE INCOME TAXES 216.2 142.2 (131.3 ) 227.1 Income taxes 84.9 0.4 — 85.3 NET INCOME $ 131.3 $ 141.8 $ (131.3 ) $ 141.8 Consolidating Balance Sheet as of December 31, 2015 (in millions): ASSETS Subsidiary Parent Guarantors Company Eliminations Consolidated Current Assets Cash & cash equivalents $ 5.5 $ 0.7 $ — $ 6.2 Accounts receivable - less reserves 92.3 — — 92.3 Intercompany receivables 51.2 142.9 (194.1 ) — Accrued unbilled revenues 85.7 — — 85.7 Inventories 125.3 — — 125.3 Prepayments & other current assets 49.3 4.1 (4.4 ) 49.0 Total current assets 409.3 147.7 (198.5 ) 358.5 Utility Plant Original cost 6,090.4 — — 6,090.4 Less: accumulated depreciation & amortization 2,415.5 — — 2,415.5 Net utility plant 3,674.9 — — 3,674.9 Investments in consolidated subsidiaries — 1,467.0 (1,467.0 ) — Notes receivable from consolidated subsidiaries — 836.0 (836.0 ) — Investments in unconsolidated affiliates 0.2 — — 0.2 Other investments 19.7 0.4 — 20.1 Nonutility plant - net 1.7 148.0 — 149.7 Goodwill - net 205.0 — — 205.0 Regulatory assets 139.3 21.4 — 160.7 Other assets 39.6 1.3 (8.7 ) 32.2 TOTAL ASSETS $ 4,489.7 $ 2,621.8 $ (2,510.2 ) $ 4,601.3 LIABILITIES & SHAREHOLDER'S EQUITY Subsidiary Parent Guarantors Company Eliminations Consolidated Current Liabilities Accounts payable $ 161.1 $ 7.4 $ — $ 168.5 Intercompany payables 12.4 — (12.4 ) — Payables to other Vectren companies 25.7 — — 25.7 Accrued liabilities 120.2 12.6 (4.4 ) 128.4 Short-term borrowings — 14.5 — 14.5 Intercompany short-term borrowings 130.5 51.2 (181.7 ) — Current maturities of long-term debt 13.0 — — 13.0 Total current liabilities 462.9 85.7 (198.5 ) 350.1 Long-Term Debt Long-term debt - net of current maturities & debt subject to tender 388.0 999.8 — 1,387.8 Long-term debt due to VUHI 836.0 — (836.0 ) — Total long-term debt - net 1,224.0 999.8 (836.0 ) 1,387.8 Deferred Income Taxes & Other Liabilities Deferred income taxes 763.7 (5.3 ) — 758.4 Regulatory liabilities 432.5 1.4 — 433.9 Deferred credits & other liabilities 139.6 5.0 (8.7 ) 135.9 Total deferred credits & other liabilities 1,335.8 1.1 (8.7 ) 1,328.2 Common Shareholder's Equity Common stock (no par value) 813.1 799.9 (813.1 ) 799.9 Retained earnings 653.9 735.3 (653.9 ) 735.3 Total common shareholder's equity 1,467.0 1,535.2 (1,467.0 ) 1,535.2 TOTAL LIABILITIES & SHAREHOLDER'S EQUITY $ 4,489.7 $ 2,621.8 $ (2,510.2 ) $ 4,601.3 Consolidating Balance Sheet as of December 31, 2014 (in millions): ASSETS Subsidiary Parent Guarantors Company Eliminations Consolidated Current Assets Cash & cash equivalents $ 6.9 $ 12.4 $ — $ 19.3 Accounts receivable - less reserves 113.0 — — 113.0 Intercompany receivables 0.8 186.7 (187.5 ) — Accrued unbilled revenues 122.4 — — 122.4 Inventories 113.2 — — 113.2 Recoverable fuel & natural gas costs 9.8 — — 9.8 Prepayments & other current assets 94.8 0.5 (23.1 ) 72.2 Total current assets 460.9 199.6 (210.6 ) 449.9 Utility Plant Original cost 5,718.7 — — 5,718.7 Less: accumulated depreciation & amortization 2,279.7 — — 2,279.7 Net utility plant 3,439.0 — — 3,439.0 Investments in consolidated subsidiaries — 1,416.9 (1,416.9 ) — Notes receivable from consolidated subsidiaries — 746.5 (746.5 ) — Investments in unconsolidated affiliates 0.2 — — 0.2 Other investments 21.3 4.3 — 25.6 Nonutility plant - net 1.8 147.4 — 149.2 Goodwill - net 205.0 — — 205.0 Regulatory assets 106.7 21.6 — 128.3 Other assets 29.4 1.7 (11.5 ) 19.6 TOTAL ASSETS $ 4,264.3 $ 2,538.0 $ (2,385.5 ) $ 4,416.8 LIABILITIES & SHAREHOLDER'S EQUITY Subsidiary Parent Guarantors Company Eliminations Consolidated Current Liabilities Accounts payable $ 176.2 $ 4.2 $ — $ 180.4 Intercompany payables 15.6 0.8 (16.4 ) — Payables to other Vectren companies 28.6 — — 28.6 Accrued liabilities 110.4 35.0 (23.1 ) 122.3 Short-term borrowings — 156.4 — 156.4 Intercompany short-term borrowings 97.0 — (97.0 ) — Current maturities of long-term debt 20.0 75.0 — 95.0 Current maturities of long-term debt due to VUHI 74.1 — (74.1 ) — Total current liabilities 521.9 271.4 (210.6 ) 582.7 Long-Term Debt Long-term debt - net of current maturities & debt subject to tender 362.6 799.7 — 1,162.3 Long-term debt due to VUHI 746.5 — (746.5 ) — Total long-term debt - net 1,109.1 799.7 (746.5 ) 1,162.3 Deferred Income Taxes & Other Liabilities Deferred income taxes 692.1 (18.3 ) — 673.8 Regulatory liabilities 408.8 1.5 — 410.3 Deferred credits & other liabilities 115.5 5.2 (11.5 ) 109.2 Total deferred credits & other liabilities 1,216.4 (11.6 ) (11.5 ) 1,193.3 Common Shareholder's Equity Common stock (no par value) 806.9 793.7 (806.9 ) 793.7 Retained earnings 610.0 684.8 (610.0 ) 684.8 Total common shareholder's equity 1,416.9 1,478.5 (1,416.9 ) 1,478.5 TOTAL LIABILITIES & SHAREHOLDER'S EQUITY $ 4,264.3 $ 2,538.0 $ (2,385.5 ) $ 4,416.8 Consolidating Statement of Cash Flows for the year ended December 31, 2015 (in millions): Subsidiary Guarantors Parent Company Eliminations Consolidated NET CASH PROVIDED BY OPERATING ACTIVITIES $ 460.3 $ 32.6 $ — $ 492.9 CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from: Additional capital contribution from Parent 6.2 6.2 (6.2 ) 6.2 Long-term debt, net of issuance costs 126.8 199.0 (89.5 ) 236.3 Requirements for: Dividends to parent (103.2 ) (110.4 ) 103.2 (110.4 ) Retirement of long-term debt (20.0 ) (75.0 ) — (95.0 ) Net change in intercompany short-term borrowings (40.7 ) 51.2 (10.5 ) — Net change in short-term borrowings — (141.9 ) — (141.9 ) Net cash used in financing activities (30.9 ) (70.9 ) (3.0 ) (104.8 ) CASH FLOWS FROM INVESTING ACTIVITIES Proceeds from: Consolidated subsidiary distributions — 103.2 (103.2 ) — Other investing activities — 3.9 — 3.9 Requirements for: Capital expenditures, excluding AFUDC equity (373.7 ) (25.5 ) — (399.2 ) Consolidated subsidiary investments — (6.2 ) 6.2 — Changes in restricted cash (5.9 ) — — (5.9 ) Net change in long-term intercompany notes receivable — (89.5 ) 89.5 — Net change in short-term intercompany notes receivable (51.2 ) 40.7 10.5 — Net cash used in investing activities (430.8 ) 26.6 3.0 (401.2 ) Net change in cash & cash equivalents (1.4 ) (11.7 ) — (13.1 ) Cash & cash equivalents at beginning of period 6.9 12.4 — 19.3 Cash & cash equivalents at end of period $ 5.5 $ 0.7 $ — $ 6.2 Consolidating Statement of Cash Flows for the year ended December 31, 2014 (in millions): Subsidiary Guarantors Parent Company Eliminations Consolidated NET CASH PROVIDED BY OPERATING ACTIVITIES $ 274.4 $ 63.1 $ — $ 337.5 CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from: Additional capital contribution from Parent 6.0 6.0 (6.0 ) 6.0 Long-term debt, net of issuance costs 186.6 — (124.2 ) 62.4 Requirements for: Dividends to parent (101.6 ) (108.7 ) 101.6 (108.7 ) Retirement of long-term debt (63.6 ) — — (63.6 ) Net change in intercompany short-term borrowings 23.9 (0.3 ) (23.6 ) — Net change in short-term borrowings — 127.8 — 127.8 Net cash used in financing activities 51.3 24.8 (52.2 ) 23.9 CASH FLOWS FROM INVESTING ACTIVITIES Proceeds from: Consolidated subsidiary distributions — 101.6 (101.6 ) — Other investing activities — 0.3 — 0.3 Requirements for: Capital expenditures, excluding AFUDC equity (327.3 ) (23.7 ) — (351.0 ) Consolidated subsidiary investments — (6.0 ) 6.0 — Net change in long-term intercompany notes receivable — (50.1 ) 50.1 — Net change in short-term intercompany notes receivable 0.3 (98.0 ) 97.7 — Net cash used in investing activities (327.0 ) (75.9 ) 52.2 (350.7 ) Net change in cash & cash equivalents (1.3 ) 12.0 — 10.7 Cash & cash equivalents at beginning of period 8.2 0.4 — 8.6 Cash & cash equivalents at end of period $ 6.9 $ 12.4 $ — $ 19.3 Consolidating Statement of Cash Flows for the year ended December 31, 2013 (in millions): Subsidiary Guarantors Parent Company Eliminations Consolidated NET CASH PROVIDED BY OPERATING ACTIVITIES $ 371.0 $ 28.9 $ — $ 399.9 CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from: Additional capital contribution from Parent 13.1 6.1 (13.1 ) 6.1 Long-term debt, net of issuance costs 232.6 273.5 (124.4 ) 381.7 Requirements for: Dividends to parent (97.9 ) (105.1 ) 97.9 (105.1 ) Retirement of long-term debt, including premiums paid (223.6 ) (221.6 ) 107.7 (337.5 ) Net change in intercompany short-term borrowings (61.5 ) 0.3 61.2 — Net change in short-term borrowings — (88.1 ) — (88.1 ) Net cash used in financing activities (137.3 ) (134.9 ) 129.3 (142.9 ) CASH FLOWS FROM INVESTING ACTIVITIES Proceeds from: Consolidated subsidiary distributions — 97.9 (97.9 ) — Other investing activities 0.6 0.2 — 0.8 Requirements for: Capital expenditures, excluding AFUDC equity (238.3 ) (24.2 ) — (262.5 ) Consolidated subsidiary investments — (13.1 ) 13.1 — Net change in long-term intercompany notes receivable — (16.7 ) 16.7 — Net change in short-term intercompany notes receivable (0.3 ) 61.5 (61.2 ) — Net cash used in investing activities (238.0 ) 105.6 (129.3 ) (261.7 ) Net change in cash & cash equivalents (4.3 ) (0.4 ) — (4.7 ) Cash & cash equivalents at beginning of period 12.5 0.8 — 13.3 Cash & cash equivalents at end of period $ 8.2 $ 0.4 $ — $ 8.6

Impact of Recently Issued Accou

Impact of Recently Issued Accounting Guidance	12 Months Ended
	Dec. 31, 2015
Impact of Recently Issued 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 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 early adopted for the year ended December 31, 2015, and has been applied retrospectively to all periods presented. The effect of this change on the December 31, 2015 and 2014 balance sheets is the reclassification of $13.2 million and $11.2 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. Leases In February 2016, the FASB issued new accounting guidance for the recognition, measurement, presentation and disclosure of leasing arrangements. This ASU requires the recognition of lease assets and liabilities for those leases currently classified as operating leases while also refining the definition of a lease. In addition, lessees will be required to disclose key information about the amount, timing, and uncertainty of cash flows arising from leasing arrangements. This ASU is effective for the interim and annual reporting periods beginning January 1, 2019, although it can be early adopted, with a modified retrospective approach for leases that commenced prior to the date of adoption. The Company is currently evaluating the standard to determine the impact it will have on the financial statements. Management believes that other recently issued standards, which are not yet effective, will not have a material impact on the Company's financial position, results of operations, or cash flows upon adoption.

Quarterly Financial Data (Unaud

Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 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. Summarized quarterly financial data for 2015 and 2014 follows: (In millions) Q1 Q2 Q3 Q4 2015 Results of Operations: Operating revenues $ 506.9 $ 276.5 $ 273.0 $ 338.1 Operating income 110.8 50.5 54.1 81.3 Net income 63.0 24.4 26.9 46.6 2014 Results of Operations: Operating revenues $ 606.6 $ 284.5 $ 271.1 $ 407.5 Operating income 110.4 48.1 49.4 73.4 Net income 61.3 22.9 24.3 39.8

SCHEDULE II VALUATION AND QUALI

SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES	12 Months Ended
	Dec. 31, 2015
Valuation and Qualifying Accounts [Abstract]
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES	Supplemental Schedules For the years ended December 31, 2015 , 2014 , and 2013 , the Company’s Schedule II -- Valuation and Qualifying Accounts Consolidated Financial Statement Schedules is presented herein. The report of Deloitte & Touche LLP on the schedule may be found in Item 8. All other schedules are omitted as the required information is inapplicable or the information is presented in the Consolidated Financial Statements or related notes in Item 8. SCHEDULE II Vectren Utility Holdings, Inc. 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 $ 3.9 $ 6.9 $ — $ 7.8 $ 3.0 Year 2014 – Accumulated provision for uncollectible accounts $ 5.0 $ 6.1 $ — $ 7.2 $ 3.9 Year 2013 – Accumulated provision for uncollectible accounts $ 5.0 $ 6.5 $ — $ 6.5 $ 5.0

Summary of Significant Accoun25

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	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.
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.
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.
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.
Revenues	Revenues Revenues are recorded as products and services are delivered to customers. To more closely match revenues and expenses, the Company records revenues for all gas and electricity delivered to customers 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	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.
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 .
Segment Reporting, Policy [Policy Text Block]	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’s operations consist of 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.
Fair Value Measurements	Fair Value Measurements Certain assets and liabilities are valued and disclosed at fair value. Nonfinancial assets and liabilities include the initial measurement of an asset retirement obligation or the use of fair value in 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. 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.
Earnings Per Share	Earnings Per Share Earnings per share are not presented as Utility Holdings’ common stock is wholly owned by Vectren.
Other Significant Policies	Other Significant Policies Included elsewhere in these notes are significant accounting policies related to retirement plans and other postretirement benefits, intercompany allocations and income taxes (Note 5).

Utility & Nonutility Plant (Tab

Utility & Nonutility Plant (Tables)	12 Months Ended
	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 and For the Year Ended 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 $ 107.6 $ 105.0 Land & buildings 35.0 35.8 All other 7.1 8.4 Nonutility plant - net $ 149.7 $ 149.2

Regulatory Assets & Liabiliti27

Regulatory Assets & Liabilities (Tables)	12 Months Ended
	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: Net deferred income taxes (See Note 5) $ (16.9 ) $ (14.8 ) (16.9 ) (14.8 ) 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 $ 160.7 $ 128.3

Transactions with Other Vectr28

Transactions with Other Vectren Companies and Affiliates Transactions with other Vectren Companies and Affiliates (Tables)	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Components of income tax expense and utilization of investment tax credits	The components of income tax expense and amortization of investment tax credits follow: Year Ended December 31, (In millions) 2015 2014 2013 Current: Federal $ (1.9 ) $ 16.6 $ 48.0 State 4.2 10.9 11.0 Total current taxes 2.3 27.5 59.0 Deferred: Federal 81.7 57.8 26.8 State 4.6 (1.6 ) 0.1 Total deferred taxes 86.3 56.2 26.9 Amortization of investment tax credits (0.5 ) (0.5 ) (0.6 ) Total income tax expense $ 88.1 $ 83.2 $ 85.3
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 and local taxes-net of federal benefit 2.8 3.3 3.5 Amortization of investment tax credit (0.2 ) (0.2 ) (0.3 ) Domestic production deduction (0.9 ) (0.9 ) — Research and development credit (2.0 ) (0.3 ) (0.6 ) All other - net 0.7 (1.0 ) — Effective tax rate 35.4 % 35.9 % 37.6 %
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 $ 752.6 $ 685.0 Regulatory assets recoverable through future rates 31.6 29.2 Alternative minimum tax carryforward (34.5 ) (51.4 ) Employee benefit obligations 7.2 1.0 Regulatory liabilities to be settled through future rates (29.9 ) (27.5 ) Deferred fuel costs - net 14.2 22.0 Other – net 17.2 15.5 Net noncurrent deferred tax liability $ 758.4 $ 673.8
Roll forward of unrecognized tax benefits

Borrowing Arrangements (Tables)

Borrowing Arrangements (Tables)	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
Short term borrowing arrangements	Following is certain information regarding these short-term borrowing arrangements: (In millions) 2015 2014 2013 Year End Balance Outstanding $ 14.5 $ 156.4 $ 28.6 Weighted Average Interest Rate 0.55 % 0.50 % 0.29 % Annual Average Balance Outstanding $ 53.8 $ 35.6 $ 119.6 Weighted Average Interest Rate 0.38 % 0.34 % 0.34 % Maximum Month End Balance Outstanding $ 121.5 $ 156.4 $ 176.1
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 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 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 Total long-term debt outstanding 1,401.7 1,258.5 Current maturities of long-term debt (13.0 ) (95.0 ) Unamortized debt premium & discount - net (0.9 ) (1.2 ) Total long-term debt-net $ 1,387.8 $ 1,162.3

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	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 $ 1,400.8 $ 1,503.6 $ 1,257.3 $ 1,408.0 Short-term borrowings 14.5 14.5 156.4 156.4 Cash & cash equivalents 6.2 6.2 19.3 19.3

Segment Reporting (Tables)

Segment Reporting (Tables)	12 Months Ended
	Dec. 31, 2015
Segment Reporting [Abstract]
Schedule of Segment Reporting Information, by Segment [Table Text Block]	Information related to the Company’s business segments is summarized below: Year Ended December 31, (In millions) 2015 2014 2013 Revenues 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 revenues $ 1,394.5 $ 1,569.7 $ 1,429.6 Profitability Measure - 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 net income $ 160.9 $ 148.4 $ 141.8 Amounts Included in Profitability Measures Depreciation & Amortization 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 depreciation & amortization $ 208.8 $ 203.1 $ 196.4 Interest Expense 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 interest expense $ 66.3 $ 66.6 $ 65.0 Income Taxes 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 income taxes $ 88.1 $ 83.2 $ 85.3 Capital Expenditures Gas Utility Services $ 291.2 $ 245.9 $ 150.5 Electric Utility Services 87.6 92.4 100.0 Other Operations 25.7 22.8 25.8 Non-cash costs & changes in accruals (5.3 ) (10.1 ) (13.8 ) Total capital expenditures $ 399.2 $ 351.0 $ 262.5 At December 31, (In millions) 2015 2014 2013 Assets 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 assets $ 4,601.3 $ 4,416.8 $ 4,135.3

Additional Balance Sheet & Op32

Additional Balance Sheet & Operational Information (Tables)	12 Months Ended
	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 Materials & supplies 38.4 37.2 Coal & oil for electric generation - at average cost 45.0 33.8 Other 1.4 1.7 Total inventories $ 125.3 $ 113.2
Summary of prepayments and other current assets	Prepayments & other current assets in the Consolidated Balance Sheets consist of the following: At December 31, (In millions) 2015 2014 Prepaid gas delivery service $ 30.0 $ 40.7 Prepaid taxes 3.9 29.5 Other prepayments & current assets 15.1 2.0 Total prepayments & other current assets $ 49.0 $ 72.2
Other utility and corporate investments in the consolidated balance sheets	Other investments in the Consolidated Balance Sheets consist of the following: At December 31, (In millions) 2015 2014 Cash surrender value of life insurance policies $ 19.2 $ 20.8 Municipal bond — 3.2 Restricted cash & other investments 0.9 1.6 Total other investments $ 20.1 $ 25.6
Accrued Liabilities	Accrued liabilities in the Consolidated Balance Sheets consist of the following: At December 31, (In millions) 2015 2014 Refunds to customers & customer deposits $ 51.4 $ 51.3 Accrued taxes 36.7 33.9 Accrued interest 16.3 16.1 Accrued salaries & other 24.0 21.0 Total accrued liabilities $ 128.4 $ 122.3
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 $ 54.6 $ 29.1 Accretion 3.3 1.7 Liabilities incurred in current period 24.2 — — Changes in estimates, net of cash payments (0.2 ) 23.8 Asset retirement obligation, December 31 $ 81.9 $ 54.6
Other, net in the consolidated statements of income	Other – net in the Consolidated Statements of Income consists of the following: Year Ended December 31, (In millions) 2015 2014 2013 AFUDC - borrowed funds $ 16.3 $ 10.8 $ 5.9 AFUDC - equity funds 2.6 3.2 0.8 Nonutility plant capitalized interest 0.4 0.6 0.4 Interest income 0.6 0.7 0.6 Cash surrender value of life insurance policies (1.5 ) 0.6 1.7 Other income 0.3 0.9 1.1 Total other – net $ 18.7 $ 16.8 $ 10.5
Supplemental cash flow information	Supplemental Cash Flow Information: Year Ended December 31, (In millions) 2015 2014 2013 Cash paid (received) for: Interest $ 66.2 $ 66.7 $ 68.2 Income taxes (23.1 ) 63.2 30.9

Subsidiary Guarantor and Cons33

Subsidiary Guarantor and Consolidating Information Subsidiary Guarantor and Consolidating Information(Tables)	12 Months Ended
	Dec. 31, 2015
Condensed Financial Information of Parent Company and Subsidiaries [Abstract]
Condensed consolidating statements fo income [Table Text Block]	Consolidating Statement of Income for the year ended December 31, 2015 (in millions): Subsidiary Guarantors Parent Company Reclassifications and Eliminations Consolidated OPERATING REVENUES Gas utility $ 792.6 $ — $ — $ 792.6 Electric utility 601.6 — — 601.6 Other — 40.7 (40.4 ) 0.3 Total operating revenues 1,394.2 40.7 (40.4 ) 1,394.5 OPERATING EXPENSES Cost of gas sold 305.4 — — 305.4 Cost of fuel & purchased power 187.5 — — 187.5 Other operating 376.9 — (37.8 ) 339.1 Depreciation & amortization 184.2 24.3 0.3 208.8 Taxes other than income taxes 55.2 1.8 0.1 57.1 Total operating expenses 1,109.2 26.1 (37.4 ) 1,097.9 OPERATING INCOME 285.0 14.6 (3.0 ) 296.6 OTHER INCOME (EXPENSE) Equity in earnings of consolidated companies — 147.0 (147.0 ) — Other – net 15.7 42.7 (39.7 ) 18.7 Total other income (expense) 15.7 189.7 (186.7 ) 18.7 Interest expense 63.7 45.3 (42.7 ) 66.3 INCOME BEFORE INCOME TAXES 237.0 159.0 (147.0 ) 249.0 Income taxes 90.0 (1.9 ) — 88.1 NET INCOME $ 147.0 $ 160.9 $ (147.0 ) $ 160.9 Consolidating Statement of Income for the year ended December 31, 2014 (in millions): Subsidiary Guarantors Parent Company Reclassifications and Eliminations Consolidated OPERATING REVENUES Gas utility $ 944.6 $ — $ — $ 944.6 Electric utility 624.8 — — 624.8 Other — 38.3 (38.0 ) 0.3 Total operating revenues 1,569.4 38.3 (38.0 ) 1,569.7 OPERATING EXPENSES Cost of gas sold 468.7 — — 468.7 Cost of fuel & purchased power 201.8 — — 201.8 Other operating 390.3 — (35.8 ) 354.5 Depreciation & amortization 179.1 23.5 0.5 203.1 Taxes other than income taxes 58.4 1.7 0.1 60.2 Total operating expenses 1,298.3 25.2 (35.2 ) 1,288.3 OPERATING INCOME 271.1 13.1 (2.8 ) 281.4 OTHER INCOME (EXPENSE) Equity in earnings of consolidated companies — 136.7 (136.7 ) — Other – net 13.3 43.2 (39.7 ) 16.8 Total other income (expense) 13.3 179.9 (176.4 ) 16.8 Interest expense 63.9 45.2 (42.5 ) 66.6 INCOME BEFORE INCOME TAXES 220.5 147.8 (136.7 ) 231.6 Income taxes 83.8 (0.6 ) — 83.2 NET INCOME $ 136.7 $ 148.4 $ (136.7 ) $ 148.4 Consolidating Statement of Income for the year ended December 31, 2013 (in millions): Subsidiary Guarantors Parent Company Reclassifications and Eliminations Consolidated OPERATING REVENUES Gas utility $ 810.0 $ — $ — $ 810.0 Electric utility 619.3 — — 619.3 Other — 37.9 (37.6 ) 0.3 Total operating revenues 1,429.3 37.9 (37.6 ) 1,429.6 OPERATING EXPENSES Cost of gas sold 358.1 — — 358.1 Cost of fuel & purchased power 202.9 — — 202.9 Other operating 369.2 — (35.8 ) 333.4 Depreciation & amortization 174.6 21.3 0.5 196.4 Taxes other than income taxes 55.6 1.5 0.1 57.2 Total operating expenses 1,160.4 22.8 (35.2 ) 1,148.0 OPERATING INCOME 268.9 15.1 (2.4 ) 281.6 OTHER INCOME (EXPENSE) Equity in earnings of consolidated companies — 131.3 (131.3 ) — Other – net 7.1 38.5 (35.1 ) 10.5 Total other income (expense) 7.1 169.8 (166.4 ) 10.5 Interest expense 59.8 42.7 (37.5 ) 65.0 INCOME BEFORE INCOME TAXES 216.2 142.2 (131.3 ) 227.1 Income taxes 84.9 0.4 — 85.3 NET INCOME $ 131.3 $ 141.8 $ (131.3 ) $ 141.8
Condensed consolidating balance sheets [Table Text Block]	Consolidating Balance Sheet as of December 31, 2015 (in millions): ASSETS Subsidiary Parent Guarantors Company Eliminations Consolidated Current Assets Cash & cash equivalents $ 5.5 $ 0.7 $ — $ 6.2 Accounts receivable - less reserves 92.3 — — 92.3 Intercompany receivables 51.2 142.9 (194.1 ) — Accrued unbilled revenues 85.7 — — 85.7 Inventories 125.3 — — 125.3 Prepayments & other current assets 49.3 4.1 (4.4 ) 49.0 Total current assets 409.3 147.7 (198.5 ) 358.5 Utility Plant Original cost 6,090.4 — — 6,090.4 Less: accumulated depreciation & amortization 2,415.5 — — 2,415.5 Net utility plant 3,674.9 — — 3,674.9 Investments in consolidated subsidiaries — 1,467.0 (1,467.0 ) — Notes receivable from consolidated subsidiaries — 836.0 (836.0 ) — Investments in unconsolidated affiliates 0.2 — — 0.2 Other investments 19.7 0.4 — 20.1 Nonutility plant - net 1.7 148.0 — 149.7 Goodwill - net 205.0 — — 205.0 Regulatory assets 139.3 21.4 — 160.7 Other assets 39.6 1.3 (8.7 ) 32.2 TOTAL ASSETS $ 4,489.7 $ 2,621.8 $ (2,510.2 ) $ 4,601.3 LIABILITIES & SHAREHOLDER'S EQUITY Subsidiary Parent Guarantors Company Eliminations Consolidated Current Liabilities Accounts payable $ 161.1 $ 7.4 $ — $ 168.5 Intercompany payables 12.4 — (12.4 ) — Payables to other Vectren companies 25.7 — — 25.7 Accrued liabilities 120.2 12.6 (4.4 ) 128.4 Short-term borrowings — 14.5 — 14.5 Intercompany short-term borrowings 130.5 51.2 (181.7 ) — Current maturities of long-term debt 13.0 — — 13.0 Total current liabilities 462.9 85.7 (198.5 ) 350.1 Long-Term Debt Long-term debt - net of current maturities & debt subject to tender 388.0 999.8 — 1,387.8 Long-term debt due to VUHI 836.0 — (836.0 ) — Total long-term debt - net 1,224.0 999.8 (836.0 ) 1,387.8 Deferred Income Taxes & Other Liabilities Deferred income taxes 763.7 (5.3 ) — 758.4 Regulatory liabilities 432.5 1.4 — 433.9 Deferred credits & other liabilities 139.6 5.0 (8.7 ) 135.9 Total deferred credits & other liabilities 1,335.8 1.1 (8.7 ) 1,328.2 Common Shareholder's Equity Common stock (no par value) 813.1 799.9 (813.1 ) 799.9 Retained earnings 653.9 735.3 (653.9 ) 735.3 Total common shareholder's equity 1,467.0 1,535.2 (1,467.0 ) 1,535.2 TOTAL LIABILITIES & SHAREHOLDER'S EQUITY $ 4,489.7 $ 2,621.8 $ (2,510.2 ) $ 4,601.3 Consolidating Balance Sheet as of December 31, 2014 (in millions): ASSETS Subsidiary Parent Guarantors Company Eliminations Consolidated Current Assets Cash & cash equivalents $ 6.9 $ 12.4 $ — $ 19.3 Accounts receivable - less reserves 113.0 — — 113.0 Intercompany receivables 0.8 186.7 (187.5 ) — Accrued unbilled revenues 122.4 — — 122.4 Inventories 113.2 — — 113.2 Recoverable fuel & natural gas costs 9.8 — — 9.8 Prepayments & other current assets 94.8 0.5 (23.1 ) 72.2 Total current assets 460.9 199.6 (210.6 ) 449.9 Utility Plant Original cost 5,718.7 — — 5,718.7 Less: accumulated depreciation & amortization 2,279.7 — — 2,279.7 Net utility plant 3,439.0 — — 3,439.0 Investments in consolidated subsidiaries — 1,416.9 (1,416.9 ) — Notes receivable from consolidated subsidiaries — 746.5 (746.5 ) — Investments in unconsolidated affiliates 0.2 — — 0.2 Other investments 21.3 4.3 — 25.6 Nonutility plant - net 1.8 147.4 — 149.2 Goodwill - net 205.0 — — 205.0 Regulatory assets 106.7 21.6 — 128.3 Other assets 29.4 1.7 (11.5 ) 19.6 TOTAL ASSETS $ 4,264.3 $ 2,538.0 $ (2,385.5 ) $ 4,416.8 LIABILITIES & SHAREHOLDER'S EQUITY Subsidiary Parent Guarantors Company Eliminations Consolidated Current Liabilities Accounts payable $ 176.2 $ 4.2 $ — $ 180.4 Intercompany payables 15.6 0.8 (16.4 ) — Payables to other Vectren companies 28.6 — — 28.6 Accrued liabilities 110.4 35.0 (23.1 ) 122.3 Short-term borrowings — 156.4 — 156.4 Intercompany short-term borrowings 97.0 — (97.0 ) — Current maturities of long-term debt 20.0 75.0 — 95.0 Current maturities of long-term debt due to VUHI 74.1 — (74.1 ) — Total current liabilities 521.9 271.4 (210.6 ) 582.7 Long-Term Debt Long-term debt - net of current maturities & debt subject to tender 362.6 799.7 — 1,162.3 Long-term debt due to VUHI 746.5 — (746.5 ) — Total long-term debt - net 1,109.1 799.7 (746.5 ) 1,162.3 Deferred Income Taxes & Other Liabilities Deferred income taxes 692.1 (18.3 ) — 673.8 Regulatory liabilities 408.8 1.5 — 410.3 Deferred credits & other liabilities 115.5 5.2 (11.5 ) 109.2 Total deferred credits & other liabilities 1,216.4 (11.6 ) (11.5 ) 1,193.3 Common Shareholder's Equity Common stock (no par value) 806.9 793.7 (806.9 ) 793.7 Retained earnings 610.0 684.8 (610.0 ) 684.8 Total common shareholder's equity 1,416.9 1,478.5 (1,416.9 ) 1,478.5 TOTAL LIABILITIES & SHAREHOLDER'S EQUITY $ 4,264.3 $ 2,538.0 $ (2,385.5 ) $ 4,416.8
Condensed consolidating statements of cash flows [Table Text Block]	Consolidating Statement of Cash Flows for the year ended December 31, 2015 (in millions): Subsidiary Guarantors Parent Company Eliminations Consolidated NET CASH PROVIDED BY OPERATING ACTIVITIES $ 460.3 $ 32.6 $ — $ 492.9 CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from: Additional capital contribution from Parent 6.2 6.2 (6.2 ) 6.2 Long-term debt, net of issuance costs 126.8 199.0 (89.5 ) 236.3 Requirements for: Dividends to parent (103.2 ) (110.4 ) 103.2 (110.4 ) Retirement of long-term debt (20.0 ) (75.0 ) — (95.0 ) Net change in intercompany short-term borrowings (40.7 ) 51.2 (10.5 ) — Net change in short-term borrowings — (141.9 ) — (141.9 ) Net cash used in financing activities (30.9 ) (70.9 ) (3.0 ) (104.8 ) CASH FLOWS FROM INVESTING ACTIVITIES Proceeds from: Consolidated subsidiary distributions — 103.2 (103.2 ) — Other investing activities — 3.9 — 3.9 Requirements for: Capital expenditures, excluding AFUDC equity (373.7 ) (25.5 ) — (399.2 ) Consolidated subsidiary investments — (6.2 ) 6.2 — Changes in restricted cash (5.9 ) — — (5.9 ) Net change in long-term intercompany notes receivable — (89.5 ) 89.5 — Net change in short-term intercompany notes receivable (51.2 ) 40.7 10.5 — Net cash used in investing activities (430.8 ) 26.6 3.0 (401.2 ) Net change in cash & cash equivalents (1.4 ) (11.7 ) — (13.1 ) Cash & cash equivalents at beginning of period 6.9 12.4 — 19.3 Cash & cash equivalents at end of period $ 5.5 $ 0.7 $ — $ 6.2 Consolidating Statement of Cash Flows for the year ended December 31, 2014 (in millions): Subsidiary Guarantors Parent Company Eliminations Consolidated NET CASH PROVIDED BY OPERATING ACTIVITIES $ 274.4 $ 63.1 $ — $ 337.5 CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from: Additional capital contribution from Parent 6.0 6.0 (6.0 ) 6.0 Long-term debt, net of issuance costs 186.6 — (124.2 ) 62.4 Requirements for: Dividends to parent (101.6 ) (108.7 ) 101.6 (108.7 ) Retirement of long-term debt (63.6 ) — — (63.6 ) Net change in intercompany short-term borrowings 23.9 (0.3 ) (23.6 ) — Net change in short-term borrowings — 127.8 — 127.8 Net cash used in financing activities 51.3 24.8 (52.2 ) 23.9 CASH FLOWS FROM INVESTING ACTIVITIES Proceeds from: Consolidated subsidiary distributions — 101.6 (101.6 ) — Other investing activities — 0.3 — 0.3 Requirements for: Capital expenditures, excluding AFUDC equity (327.3 ) (23.7 ) — (351.0 ) Consolidated subsidiary investments — (6.0 ) 6.0 — Net change in long-term intercompany notes receivable — (50.1 ) 50.1 — Net change in short-term intercompany notes receivable 0.3 (98.0 ) 97.7 — Net cash used in investing activities (327.0 ) (75.9 ) 52.2 (350.7 ) Net change in cash & cash equivalents (1.3 ) 12.0 — 10.7 Cash & cash equivalents at beginning of period 8.2 0.4 — 8.6 Cash & cash equivalents at end of period $ 6.9 $ 12.4 $ — $ 19.3 Consolidating Statement of Cash Flows for the year ended December 31, 2013 (in millions): Subsidiary Guarantors Parent Company Eliminations Consolidated NET CASH PROVIDED BY OPERATING ACTIVITIES $ 371.0 $ 28.9 $ — $ 399.9 CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from: Additional capital contribution from Parent 13.1 6.1 (13.1 ) 6.1 Long-term debt, net of issuance costs 232.6 273.5 (124.4 ) 381.7 Requirements for: Dividends to parent (97.9 ) (105.1 ) 97.9 (105.1 ) Retirement of long-term debt, including premiums paid (223.6 ) (221.6 ) 107.7 (337.5 ) Net change in intercompany short-term borrowings (61.5 ) 0.3 61.2 — Net change in short-term borrowings — (88.1 ) — (88.1 ) Net cash used in financing activities (137.3 ) (134.9 ) 129.3 (142.9 ) CASH FLOWS FROM INVESTING ACTIVITIES Proceeds from: Consolidated subsidiary distributions — 97.9 (97.9 ) — Other investing activities 0.6 0.2 — 0.8 Requirements for: Capital expenditures, excluding AFUDC equity (238.3 ) (24.2 ) — (262.5 ) Consolidated subsidiary investments — (13.1 ) 13.1 — Net change in long-term intercompany notes receivable — (16.7 ) 16.7 — Net change in short-term intercompany notes receivable (0.3 ) 61.5 (61.2 ) — Net cash used in investing activities (238.0 ) 105.6 (129.3 ) (261.7 ) Net change in cash & cash equivalents (4.3 ) (0.4 ) — (4.7 ) Cash & cash equivalents at beginning of period 12.5 0.8 — 13.3 Cash & cash equivalents at end of period $ 8.2 $ 0.4 $ — $ 8.6

Quarterly Financial Data (Una34

Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
	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. Summarized quarterly financial data for 2015 and 2014 follows: (In millions) Q1 Q2 Q3 Q4 2015 Results of Operations: Operating revenues $ 506.9 $ 276.5 $ 273.0 $ 338.1 Operating income 110.8 50.5 54.1 81.3 Net income 63.0 24.4 26.9 46.6 2014 Results of Operations: Operating revenues $ 606.6 $ 284.5 $ 271.1 $ 407.5 Operating income 110.4 48.1 49.4 73.4 Net income 61.3 22.9 24.3 39.8

Organization and Nature of Op35

Organization and Nature of Operations (Details)	12 Months Ended
	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 Accoun36

Summary of Significant Accounting Policies (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Accounting Policies [Abstract]
Excise taxes and a portion of utility receipts taxes	$ 29.4	$ 32.3	$ 29.6

Utility & Nonutility Plant (Det

Utility & Nonutility Plant (Details) $ in Millions	12 Months Ended
	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	149.7	149.2
Utility Group [Member]
Utility & Nonutility Plant
Original Cost	6,090.4	5,718.7
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] | Warrick Power Plant [Member]
Utility & Nonutility Plant
Size of Unit 4 Warrick Power Plant (in megawatts) | MW	300
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	149.7	$ 149.2
Nonutility plant accumulated depreciation and amortization	248	226.7
Capitalized interest on nonutility plant construction projects	0.4	0.6	$ 0.4
Nonutility Group [Member] | Computer Hardware and Software [Member]
Utility & Nonutility Plant
Cost of Non-Utility plant, net of depreciation and amortization	107.6	105
Nonutility Group [Member] | Land and Buildings [Member]
Utility & Nonutility Plant
Cost of Non-Utility plant, net of depreciation and amortization	35	35.8
Nonutility Group [Member] | All Other [Member]
Utility & Nonutility Plant
Cost of Non-Utility plant, net of depreciation and amortization	$ 7.1	$ 8.4

Regulatory Assets & Liabiliti38

Regulatory Assets & Liabilities (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Regulatory Assets [Line Items]
Regulatory Assets, Noncurrent	$ 160.7	$ 128.3
Regulatory Assets Currently Being Recovered in Base Rates	$ 35
Weighted average recovery period of regulatory assets currently being recovered (in years)	24
Regulatory Liabilities [Abstract]
Regulatory Liability, Noncurrent	$ 433.9	410.3
Asset Retirement Obligations and Other [Member]
Regulatory Liabilities [Abstract]
Regulatory Liability, Noncurrent	399.1	373.5
Future Amounts Recoverable From Ratepayers [Member]
Regulatory Assets [Line Items]
Regulatory Assets, Noncurrent	(16.9)	(14.8)
Future Amounts Recoverable From Ratepayers [Member] | Deferred Income Taxes [Member]
Regulatory Assets [Line Items]
Regulatory Assets, Noncurrent	(16.9)	(14.8)
Amounts Deferred for Future Recovery [Member]
Regulatory Assets [Line Items]
Regulatory Assets, Noncurrent	54.6	33.3
Amounts Deferred for Future Recovery [Member] | Cost Recovery Riders Other [Member]
Regulatory Assets [Line Items]
Regulatory Assets, Noncurrent	54.6	33.3
Amounts Currently Recovered in Customer Rates [Member]
Regulatory Assets [Line Items]
Regulatory Assets, Noncurrent	123	109.8
Amounts Currently Recovered in Customer Rates [Member] | Deferred Coal Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets, Noncurrent	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, Noncurrent	34.4	35.2
Amounts Currently Recovered in Customer Rates [Member] | Demand Side Management Programs [Member]
Regulatory Assets [Line Items]
Remaining Amounts of Regulatory Assets for which No Return on Investment During Recovery Period is Provided	0
Regulatory Assets, Noncurrent	0	0.6
Amounts Currently Recovered in Customer Rates [Member] | Indiana Authorized Trackers [Member]
Regulatory Assets [Line Items]
Regulatory Assets, Noncurrent	42.6	25.6
Amounts Currently Recovered in Customer Rates [Member] | Ohio Authorized Trackers [Member]
Regulatory Assets [Line Items]
Regulatory Assets, Noncurrent	17.6	12.7
Amounts Currently Recovered in Customer Rates [Member] | Other Base Rate Recoveries [Member]
Regulatory Assets [Line Items]
Regulatory Assets, Noncurrent	$ 0.1	$ 0.4

Transactions with Other Vectr39

Transactions with Other Vectren Companies and Affiliates Transactions with Other Vectren Companies and Afffiliates (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Transactions with Other Vectren Companies and Affiliates [Line Items]
Net liability for recognized tax benefits inclusive of interest, penalties and net of secondary impacts which are a component of the Deferred income taxes	$ 0.8	$ 0.1
Deferred Tax Assets, Net of Valuation Allowance, Current	13.2	11.2
Deferred Credits and Other Liabilities	135.9	109.2
Amount of Share Based Compensation and Deferred Compensation Liability included in Deferred Credits and Other Liabilities	35.7	36.1
Current: [Abstract]
Federal	(1.9)	16.6	$ 48
State	4.2	10.9	11
Total current taxes	2.3	27.5	59
Deferred: [Abstract]
Federal	81.7	57.8	26.8
State	4.6	(1.6)	0.1
Total deferred taxes	86.3	56.2	26.9
Amortization of investment tax credits	(0.5)	(0.5)	(0.6)
Total income tax expense	$ 88.1	$ 83.2	$ 85.3
Reconciliation of the federal statutory rate to the effective income tax rate [Abstract]
Statutory rate: (in hundredths)	35.00%	35.00%	35.00%
State and local taxes-net of federal benefit (in hundredths)	2.80%	3.30%	3.50%
Amortization of investment tax credit (in hundredths)	(0.20%)	(0.20%)	(0.30%)
Domestic Production Deduction (in hundredths)	(0.90%)	(0.90%)	(0.00%)
Research and Development Credit	(2.00%)	(0.30%)	(0.60%)
All other - net (in hundredths)	0.70%	(1.00%)	(0.00%)
Effective tax rate (in hundredths)	35.40%	35.90%	37.60%
Noncurrent deferred tax liabilities (assets) [Abstract]
Depreciation and cost recovery timing differences	$ 752.6	$ 685
Regulatory assets recoverable through future rates	31.6	29.2
Alternative minimum tax carryforward	(34.5)	(51.4)
Deferred Tax Liability, Employer Benefit Plan Funding	7.2	1
Regulatory liabilities to be settled through future rates	(29.9)	(27.5)
Deferred fuel costs-net	14.2	22
Deferred Tax Liabilities, Other	17.2	15.5
Net noncurrent deferred tax liability	758.4	673.8
Investment tax credits	$ 2.1	$ 2.6
Pension Plans, Defined Benefit [Member]
Transactions with Other Vectren Companies and Affiliates [Line Items]
Number of qualified defined benefit pension plans	3
Pension and Other Postretirement Benefit Contributions	$ 20
Defined Benefit Plan, Funded Percentage	90.00%	87.00%
Defined Benefit Plan, Net Periodic Benefit Cost	$ 7	$ 6.7	$ 8
Deferred Credits and Other Liabilities	12	11.6
Other Assets	30.3	17.3
Vectren Fuels Inc. [Member]
Transactions with Other Vectren Companies and Affiliates [Line Items]
Expenses from transactions with related party		98.6	103.7
ProLiance [Member]
Transactions with Other Vectren Companies and Affiliates [Line Items]
Expenses from transactions with related party	$ 0	0	200.5
Percentage of purchases from single third party	78.00%
Support Services & Purchases [Member]
Transactions with Other Vectren Companies and Affiliates [Line Items]
Cost of corporate and general and administrative services	$ 52.3	57	50.9
Vectren Infrastructure Services Corporation [Member]
Transactions with Other Vectren Companies and Affiliates [Line Items]
Expenses from transactions with related party	$ 109.5	$ 94	$ 54.2

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	$ 350
Short term borrowings available	$ 335
Short term credit facilities expiration date	Oct. 31, 2019
Year end [Abstract]
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%
Annual Average [Abstract]
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
Vectren Utility Holdings Inc [Member] | Utility Group [Member]
Short-term borrowings [Abstract]
Letter of credit, within debt facility, maximum borrowing capacity	$ 100

Borrowing Arrangements (Details

Borrowing Arrangements (Details) - USD ($) $ in Millions

Dec. 29, 2015

Dec. 21, 2015

Dec. 01, 2015

Mar. 15, 2015

Dec. 05, 2013

Aug. 28, 2013

Aug. 01, 2013

Apr. 26, 2013

Sep. 30, 2014

Jun. 30, 2013

Dec. 31, 2015

Dec. 15, 2015

Sep. 09, 2015

Dec. 31, 2014

Sep. 24, 2014

Aug. 22, 2013

Aug. 13, 2013

Apr. 01, 2013

Long term debt [Abstract]

Total long term debt outstanding

$ 1,401.7

$ 1,258.5

Current maturities of long-term debt

(13)

(95)

Unamortized debt premium and discount - net

(0.9)

(1.2)

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

1,387.8

1,162.3

Maturities of long term debt [Abstract]

Debt maturing within 12 months following date of latest balance sheet

13

Debt maturing within two years following date of latest balance sheet

0

Debt maturing within three years following date of latest balance sheet

100

Debt maturing within four years following date of latest balance sheet

0

Debt maturing within five years following date of latest balance sheet

100

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

1,187.8

Debt guarantees [Abstract]

Long-term guarantees

1,000

Short-term debt guarantees

$ 15

Covenants [Abstract]

Debt to consolidated total capitalization - maximum ratio

65.00%

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

Long term debt [Abstract]

Total long term debt outstanding

$ 1,000

875

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

Debt Instrument [Line Items]

Extinguishment of Debt, Amount

$ 75

Long term debt [Abstract]

Fixed rate stated percentage (in hundredths)

5.45%

Total long term debt outstanding

0

75

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

Long term debt [Abstract]

Total long term debt outstanding

100

100

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

Long term debt [Abstract]

Total long term debt outstanding

100

100

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

Long term debt [Abstract]

Total long term debt outstanding

55

55

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

150

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

Long term debt [Abstract]

Total long term debt outstanding

60

60

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

45

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

Long term debt [Abstract]

Total long term debt outstanding

75

75

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

Long term debt [Abstract]

Debt Issuance

$ 25

Fixed rate stated percentage (in hundredths)

3.90%

Total long term debt outstanding

25

0

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

Long term debt [Abstract]

Total long term debt outstanding

35

35

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

Long term debt [Abstract]

Total long term debt outstanding

100

100

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

Long term debt [Abstract]

Total long term debt outstanding

80

80

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

Long term debt [Abstract]

Debt Issuance

$ 135

Fixed rate stated percentage (in hundredths)

4.36%

Total long term debt outstanding

135

0

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

Long term debt [Abstract]

Debt Issuance

$ 40

Fixed rate stated percentage (in hundredths)

4.51%

Total long term debt outstanding

40

0

Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member] | FixedRateSeniorGuaranteedNotes2043425 [Member]

Long term debt [Abstract]

Fixed rate stated percentage (in hundredths)

4.25%

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

Long term debt [Abstract]

Total long term debt outstanding

96

116

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

Debt Instrument [Line Items]

Extinguishment of Debt, Amount

$ 5

Long term debt [Abstract]

Fixed rate stated percentage (in hundredths)

7.15%

Total long term debt outstanding

0

5

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

Debt Instrument [Line Items]

Extinguishment of Debt, Amount

$ 5

Long term debt [Abstract]

Fixed rate stated percentage (in hundredths)

6.69%

Total long term debt outstanding

0

5

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

Debt Instrument [Line Items]

Extinguishment of Debt, Amount

$ 10

Long term debt [Abstract]

Fixed rate stated percentage (in hundredths)

6.69%

Total long term debt outstanding

0

10

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

10

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

5

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

1

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

20

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

10

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

20

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

30

SIGECO [Member] | First Mortgage Bonds [Member]

Long term debt [Abstract]

Debt Issuance

62

Proceeds from debt issuance

$ 60

SIGECO [Member] | First Mortgage Bonds [Member] | Tax Exempt Debt, 4.00 percent, due 2038 [Member]

Long term debt [Abstract]

Debt Issuance

$ 22.2

Fixed rate stated percentage (in hundredths)

4.00%

SIGECO [Member] | First Mortgage Bonds [Member] | Tax Exempt Debt, 4.05 percent, due 2043 [Member]

Long term debt [Abstract]

Debt Issuance

$ 39.6

Fixed rate stated percentage (in hundredths)

4.05%

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

Long term debt [Abstract]

Proceeds from debt issuance

$ 48.3

Fixed rate stated percentage (in hundredths)

1.95%

Amount of debt to be re-marketed

$ 49

SIGECO [Member] | Mortgages [Member]

Debt Instrument [Line Items]

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

87.3

Extinguishment of Debt, Amount

$ 63.6

$ 111

Long term debt [Abstract]

Debt Issuance

$ 63.6

Total long term debt outstanding

$ 305.7

$ 267.5

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

Gross utility plant balance subject to the mortgage indenture

3,100

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

Long term debt [Abstract]

Total long term debt outstanding

13

13

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

Long term debt [Abstract]

Total long term debt outstanding

4.6

4.6

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

Long term debt [Abstract]

Total long term debt outstanding

22.5

22.5

SIGECO [Member] | Mortgages [Member] | 2025, 2014 Series B, .722% Tax Exempt [Member]

Long term debt [Abstract]

Total long term debt outstanding

41.3

41.3

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

Long term debt [Abstract]

Total long term debt outstanding

80

80

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

Long term debt [Abstract]

Total long term debt outstanding

22

22

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

Long term debt [Abstract]

Total long term debt outstanding

22.2

22.2

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

Long term debt [Abstract]

Total long term debt outstanding

39.6

39.6

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

Long term debt [Abstract]

Debt Issuance

22.3

Fixed rate stated percentage (in hundredths)

4.00%

Total long term debt outstanding

22.3

22.3

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

0

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

15.2

$ 0

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

Debt Instrument [Line Items]

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

49.1

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

Debt Instrument [Line Items]

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

38.2

SIGECO [Member] | Mortgages [Member] | FirstMortgageBonds20252014CurrentAdjustbaleRate0784TaxExempt [Member]

Debt Instrument [Line Items]

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

$ 41.3

Long term debt [Abstract]

Debt Issuance

$ 41.3

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

Long term debt [Abstract]

Debt Issuance

$ 15.2

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

Fixed rate stated percentage (in hundredths)

2.375%

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

Long term debt [Abstract]

Debt Issuance

$ 150

Proceeds from debt issuance

$ 149.1

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

Long term debt [Abstract]

Debt Issuance

$ 45

Proceeds from debt issuance

44.8

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

Long term debt [Abstract]

Debt Issuance

$ 121.6

Fixed rate stated percentage (in hundredths)

6.25%

Vectren Utility Holdings Inc [Member] | Fixed Rate Senior Unsecured Notes [Member] | FixedRateSeniorGuaranteedNotes2043425 [Member]

Long term debt [Abstract]

Debt Issuance

80

Proceeds from debt issuance

$ 79.6

Vectren Utility Holdings Inc [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2013, 5.25% [Member]

Debt Instrument [Line Items]

Extinguishment of Debt, Amount

$ 100

Long term debt [Abstract]

Fixed rate stated percentage (in hundredths)

5.25%

Common Shareholder's Equity (De

Common Shareholder's Equity (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Common Shareholders Equity [Line Items]
Additional capital contribution	$ 6.2	$ 6	$ 6.1
Common Shareholders Equity [Member]
Common Shareholders Equity [Line Items]
Additional capital contribution	$ 18.3	$ 19.1	$ 13.1

Commitments and Contingencies (

Commitments and Contingencies (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Commitments [Abstract]
Future minimum operating lease payments due within one year of the balance sheet date	$ 0.8
Future minimum operating lease payments due within the second year of the balance sheet date	0.8
Future minimum operating lease payments due within the third year of the balance sheet date	0.8
Future minimum operating lease payments due within the fourth year of the balance sheet date	0.6
Future minimum operating lease payments due within the fifth year	0.5
Future minimum operating lease payments due after the fifth year of the balance sheet date	2.3
Total lease expense	0.8	$ 1.5	$ 1.1
Unrecorded Unconditional Purchase Obligation, Due within One Year	2.3
Unrecorded Unconditional Purchase Obligation, Due within Two Years	$ 1.1

Gas Rate & Regulatory Matters (

Gas Rate & Regulatory Matters (Details)	3 Months Ended	12 Months Ended
	Sep. 30, 2014USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)	Aug. 27, 2014
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items]
Regulatory Assets, Noncurrent		$ 160,700,000	$ 128,300,000
Length of project plan required for recovery under new legislation		7 years
Other income - net		$ 18,700,000	16,800,000	$ 10,500,000
Indiana [Member] | 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
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%
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 income - net		6,400,000	3,900,000
Amount of deferral related to depreciation and property tax expense		5,400,000	3,100,000
INDIANA | Senate Bill 251 and 560 [Member]
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items]
Expected Seven Year Period Modernization Investment		1,000,000,000
Capital Expenditure Increases		100,000,000
Project spend life to date		272,000,000
Amount approved by the Commission for planned infrastructure investments		800,000,000
Regulatory assets related to return on investment, depreciation deferral, and other operating expenses		28,600,000	11,400,000
SIGECO [Member] | Indiana [Member] | 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 [Member] | 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 45

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
	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	81.9	$ 29.1	$ 25	$ 54.6
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	80,000,000
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	1,967,000,000
Vectren's emission rate (as measured in lbs CO2/MWh) after installation of new technology	1,922,000,000
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
	Dec. 31, 2015	Dec. 31, 2014
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
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	$ 1,400.8	$ 1,257.3
Short-term Debt, Fair Value	14.5	156.4
Cash and cash equivalents	6.2	19.3
Estimated Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	1,503.6	1,408
Short-term Debt, Fair Value	14.5	156.4
Cash and cash equivalents	$ 6.2	$ 19.3

Segment Reporting (Details)

Segment Reporting (Details) $ in Millions	3 Months Ended								12 Months Ended
	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 [Abstract]
Portion of Indiana that is provided natural gas distribution and transportation services by the Gas Utility Services segment (in hundredths)	66.66667%								66.66667%
Segment Reporting Information [Line Items]
Number of operating segments in Utility group	3								3
Revenues	$ 338.1	$ 273	$ 276.5	$ 506.9	$ 407.5	$ 271.1	$ 284.5	$ 606.6	$ 1,394.5	$ 1,569.7	$ 1,429.6
Net income (loss)	46.6	$ 26.9	$ 24.4	$ 63	39.8	$ 24.3	$ 22.9	$ 61.3	160.9	148.4	141.8
Assets	4,601.3				4,416.8				4,601.3	4,416.8	4,135.3
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
Capital Expenditures									399.2	351	262.5
Gas Utility Services [Member]
Segment Reporting Information [Line Items]
Revenues									792.6	944.6	810
Net income (loss)									64.4	57	55.7
Assets	2,707.5				2,605.1				2,707.5	2,605.1	2,286.6
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
Capital Expenditures									291.2	245.9	150.5
Electric Utility Services [Member]
Segment Reporting Information [Line Items]
Revenues									601.6	624.8	619.3
Net income (loss)									82.6	79.7	75.8
Assets	1,782.2				1,659.3				1,782.2	1,659.3	1,679
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
Capital Expenditures									87.6	92.4	100
Other Operations [Member]
Segment Reporting Information [Line Items]
Revenues									40.7	38.3	38.1
Net income (loss)									13.9	11.7	10.3
Assets	$ 111.6				$ 152.4				111.6	152.4	169.7
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
Capital Expenditures									25.7	22.8	25.8
Intersegment Elimination [Member]
Segment Reporting Information [Line Items]
Revenues									(40.4)	(38)	(37.8)
Non-Cash Cost and Change in Accruals [Member]
Amounts Included in Profitability Measures [Abstract]
Increase (Decrease) in Other Accrued Liabilities									$ (5.3)	$ (10.1)	$ (13.8)

Additional Balance Sheet & Op49

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
Materials and supplies	38.4	37.2
Coal and Oil for electric generation - at average cost	45	33.8
Other	1.4	1.7
Total inventories	125.3	113.2
Amount by which cost of replacing inventories carried at LIFO cost exceeded carrying value	0	3
Prepayments and other current assets [Abstract]
Prepaid gas delivery service	30	40.7
Prepaid taxes	3.9	29.5
Other prepayments and current assets	15.1	2
Total prepayments and other current assets	49	72.2
Other utility and corporate investments [Abstract]
Cash surrender value of life insurance policies	19.2	20.8
Municipal bond	0	3.2
Restricted cash & other investments	0.9	1.6
Total other investments	20.1	25.6
Accrued liabilities [Abstract]
Refunds to customers and customer deposits	51.4	51.3
Accrued taxes	36.7	33.9
Accrued interest	16.3	16.1
Accrued salaries and other	24	21
Total accrued liabilities	128.4	122.3
Asset Retirement Obligation [Roll Forward]
Asset retirement obligation, beginning balance	54.6	29.1
Accretion	3.3	1.7
Asset Retirement Obligation, Liabilities Incurred	24.2	0
Changes in estimates, net of cash payments	(0.2)	23.8
Asset retirement obligation, ending balance	81.9	54.6	$ 29.1
Other - net in the consolidated statement of income [Abstract]
AFUDC - borrowed funds	16.3	10.8	5.9
AFUDC - equity funds	2.6	3.2	0.8
Interest Costs Capitalized Adjustment	0.4	0.6	0.4
Interest income, net	0.6	0.7	0.6
Cash surrender value of life insurance policies	(1.5)	0.6	1.7
All other income	0.3	0.9	1.1
Total other income (expense) – net	18.7	16.8	10.5
Cash paid (received) for [Abstract]
Interest	66.2	66.7	68.2
Income taxes	(23.1)	63.2	$ 30.9
Accruals related to utility and nonutility plant purchases [Abstract]
Accruals related to utility and nonutility plant purchases	$ 18.1	$ 19

Subsidiary Guarantor and Cons50

Subsidiary Guarantor and Consolidating Information Subsidiary Guarantor and Consolidating Information Balance Sheet (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
ASSETS
Cash & cash equivalents	$ 6.2	$ 19.3	$ 8.6	$ 13.3
Accounts receivable - less reserves	92.3	113
Accrued unbilled revenues	85.7	122.4
Inventories	125.3	113.2
Recoverable fuel & natural gas costs	0	9.8
Prepayments & other curent assets	49	72.2
Total current assets	358.5	449.9
Original Cost	6,090.4	5,718.7
Less: accumulated depreciation & amortization	2,415.5	2,279.7
Net utility plant	3,674.9	3,439
Investments in unconsolidated affiliates	0.2	0.2
Other Investments	20.1	25.6
Nonutility plant - net	149.7	149.2
Goodwill - net	205	205
Regulatory assets	160.7	128.3
Other assets	32.2	19.6
TOTAL ASSETS	4,601.3	4,416.8	4,135.3
LIABILITIES & SHAREHOLDERS' EQUITY
Accounts payable	168.5	180.4
Payables to other Vectren companies	25.7	28.6
Accrued liabilities	128.4	122.3
Short-term borrowings	14.5	156.4	28.6
Current maturities of long-term debt	13	95
Total current liabilities	350.1	582.7
Long-term Debt - Net of Current Maturities	1,387.8	1,162.3
Deferred income taxes	758.4	673.8
Regulatory liabilities	433.9	410.3
Deferred Credits and Other Liabilities	135.9	109.2
Total deferred credits and other liabilities	1,328.2	1,193.3
Common stock (no par value)	799.9	793.7
Retained earnings	735.3	684.8
Total common shareholders' equity	1,535.2	1,478.5
TOTAL LIABILITIES and SHAREHOLDERS' EQUITY	4,601.3	4,416.8
Line of Credit Facility, Maximum Borrowing Capacity	350
Line of Credit Facility, Amount Outstanding	15
Unsecured Debt	$ 1,000
Subsidiary Ownership Percentage	100.00%
Subsidiary Guarantors [Member]
ASSETS
Cash & cash equivalents	$ 5.5	6.9	8.2	12.5
Accounts receivable - less reserves	92.3	113
Intercompany Receivables	51.2	0.8
Accrued unbilled revenues	85.7	122.4
Inventories	125.3	113.2
Recoverable fuel & natural gas costs		9.8
Prepayments & other curent assets	49.3	94.8
Total current assets	409.3	460.9
Original Cost	6,090.4	5,718.7
Less: accumulated depreciation & amortization	2,415.5	2,279.7
Net utility plant	3,674.9	3,439
Investments in consolidated subsidiaries	0	0
Notes receivable from consolidated subsidiaries	0	0
Investments in unconsolidated affiliates	0.2	0.2
Other Investments	19.7	21.3
Nonutility plant - net	1.7	1.8
Goodwill - net	205	205
Regulatory assets	139.3	106.7
Other assets	39.6	29.4
TOTAL ASSETS	4,489.7	4,264.3
LIABILITIES & SHAREHOLDERS' EQUITY
Accounts payable	161.1	176.2
Intercompany Payables	12.4	15.6
Payables to other Vectren companies	25.7	28.6
Accrued liabilities	120.2	110.4
Short-term borrowings	0	0
Intercompany short-term borrowings	130.5	97
Current maturities of long-term debt	13	20
Current maturities of long-term debt due to VUHI		74.1
Total current liabilities	462.9	521.9
Long-term Debt - Net of Current Maturities	388	362.6
Long-term debt due to VUHI	836	746.5
Total long-term debt - net	1,224	1,109.1
Deferred income taxes	763.7	692.1
Regulatory liabilities	432.5	408.8
Deferred Credits and Other Liabilities	139.6	115.5
Total deferred credits and other liabilities	1,335.8	1,216.4
Common stock (no par value)	813.1	806.9
Retained earnings	653.9	610
Total common shareholders' equity	1,467	1,416.9
TOTAL LIABILITIES and SHAREHOLDERS' EQUITY	4,489.7	4,264.3
Parent Company [Member]
ASSETS
Cash & cash equivalents	0.7	12.4	0.4	0.8
Accounts receivable - less reserves	0	0
Intercompany Receivables	142.9	186.7
Accrued unbilled revenues	0	0
Inventories	0	0
Recoverable fuel & natural gas costs		0
Prepayments & other curent assets	4.1	0.5
Total current assets	147.7	199.6
Original Cost	0	0
Less: accumulated depreciation & amortization	0	0
Net utility plant	0	0
Investments in consolidated subsidiaries	1,467	1,416.9
Notes receivable from consolidated subsidiaries	836	746.5
Investments in unconsolidated affiliates	0	0
Other Investments	0.4	4.3
Nonutility plant - net	148	147.4
Goodwill - net	0	0
Regulatory assets	21.4	21.6
Other assets	1.3	1.7
TOTAL ASSETS	2,621.8	2,538
LIABILITIES & SHAREHOLDERS' EQUITY
Accounts payable	7.4	4.2
Intercompany Payables	0	0.8
Payables to other Vectren companies	0	0
Accrued liabilities	12.6	35
Short-term borrowings	14.5	156.4
Intercompany short-term borrowings	51.2	0
Current maturities of long-term debt	0	75
Current maturities of long-term debt due to VUHI		0
Total current liabilities	85.7	271.4
Long-term Debt - Net of Current Maturities	999.8	799.7
Long-term debt due to VUHI	0	0
Total long-term debt - net	999.8	799.7
Deferred income taxes	(5.3)	(18.3)
Regulatory liabilities	1.4	1.5
Deferred Credits and Other Liabilities	5	5.2
Total deferred credits and other liabilities	1.1	(11.6)
Common stock (no par value)	799.9	793.7
Retained earnings	735.3	684.8
Total common shareholders' equity	1,535.2	1,478.5
TOTAL LIABILITIES and SHAREHOLDERS' EQUITY	2,621.8	2,538
Consolidation, Eliminations [Member]
ASSETS
Cash & cash equivalents	0	0	0	0
Accounts receivable - less reserves	0	0
Intercompany Receivables	(194.1)	(187.5)
Accrued unbilled revenues	0	0
Inventories	0	0
Recoverable fuel & natural gas costs		0
Prepayments & other curent assets	(4.4)	(23.1)
Total current assets	(198.5)	(210.6)
Original Cost	0	0
Less: accumulated depreciation & amortization	0	0
Net utility plant	0	0
Investments in consolidated subsidiaries	(1,467)	(1,416.9)
Notes receivable from consolidated subsidiaries	(836)	(746.5)
Investments in unconsolidated affiliates	0	0
Other Investments	0	0
Nonutility plant - net	0	0
Goodwill - net	0	0
Regulatory assets	0	0
Other assets	(8.7)	(11.5)
TOTAL ASSETS	(2,510.2)	(2,385.5)
LIABILITIES & SHAREHOLDERS' EQUITY
Accounts payable	0	0
Intercompany Payables	(12.4)	(16.4)
Payables to other Vectren companies	0	0
Accrued liabilities	(4.4)	(23.1)
Short-term borrowings	0	0
Intercompany short-term borrowings	(181.7)	(97)
Current maturities of long-term debt	0	0
Current maturities of long-term debt due to VUHI		(74.1)
Total current liabilities	(198.5)	(210.6)
Long-term Debt - Net of Current Maturities	0	0
Long-term debt due to VUHI	(836)	(746.5)
Total long-term debt - net	(836)	(746.5)
Deferred income taxes	0	0
Regulatory liabilities	0	0
Deferred Credits and Other Liabilities	(8.7)	(11.5)
Total deferred credits and other liabilities	(8.7)	(11.5)
Common stock (no par value)	(813.1)	(806.9)
Retained earnings	(653.9)	(610)
Total common shareholders' equity	(1,467)	(1,416.9)
TOTAL LIABILITIES and SHAREHOLDERS' EQUITY	(2,510.2)	(2,385.5)
Consolidated Entities [Member]
ASSETS
Cash & cash equivalents	6.2	19.3	$ 8.6	$ 13.3
Accounts receivable - less reserves	92.3	113
Intercompany Receivables	0	0
Accrued unbilled revenues	85.7	122.4
Inventories	125.3	113.2
Recoverable fuel & natural gas costs		9.8
Prepayments & other curent assets	49	72.2
Total current assets	358.5	449.9
Original Cost	6,090.4	5,718.7
Less: accumulated depreciation & amortization	2,415.5	2,279.7
Net utility plant	3,674.9	3,439
Investments in consolidated subsidiaries	0	0
Notes receivable from consolidated subsidiaries	0	0
Investments in unconsolidated affiliates	0.2	0.2
Other Investments	20.1	25.6
Nonutility plant - net	149.7	149.2
Goodwill - net	205	205
Regulatory assets	160.7	128.3
Other assets	32.2	19.6
TOTAL ASSETS	4,601.3	4,416.8
LIABILITIES & SHAREHOLDERS' EQUITY
Accounts payable	168.5	180.4
Intercompany Payables	0	0
Payables to other Vectren companies	25.7	28.6
Accrued liabilities	128.4	122.3
Short-term borrowings	14.5	156.4
Intercompany short-term borrowings	0	0
Current maturities of long-term debt	13	95
Current maturities of long-term debt due to VUHI		0
Total current liabilities	350.1	582.7
Long-term Debt - Net of Current Maturities	1,387.8	1,162.3
Long-term debt due to VUHI	0	0
Total long-term debt - net	1,387.8	1,162.3
Deferred income taxes	758.4	673.8
Regulatory liabilities	433.9	410.3
Deferred Credits and Other Liabilities	135.9	109.2
Total deferred credits and other liabilities	1,328.2	1,193.3
Common stock (no par value)	799.9	793.7
Retained earnings	735.3	684.8
Total common shareholders' equity	1,535.2	1,478.5
TOTAL LIABILITIES and SHAREHOLDERS' EQUITY	$ 4,601.3	$ 4,416.8

Subsidiary Guarantor and Cons51

Subsidiary Guarantor and Consolidating Information Subsidiary Guarantor and Consolidating Information Income Statement (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
OPERATING REVENUES [Abstract]
Gas utility									$ 792.6	$ 944.6	$ 810
Electric utility									601.6	624.8	619.3
Other									0.3	0.3	0.3
Total operating revenues	$ 338.1	$ 273	$ 276.5	$ 506.9	$ 407.5	$ 271.1	$ 284.5	$ 606.6	1,394.5	1,569.7	1,429.6
OPERATING EXPENSES [Abstract]
Cost of Gas Sold									305.4	468.7	358.1
Cost of fuel & purchased power									187.5	201.8	202.9
Other operating									339.1	354.5	333.4
Depreciation & Amortization									208.8	203.1	196.4
Taxes other than income taxes									57.1	60.2	57.2
Total operating expenses									1,097.9	1,288.3	1,148
OPERATING INCOME	81.3	54.1	50.5	110.8	73.4	49.4	48.1	110.4	296.6	281.4	281.6
Other - net									18.7	16.8	10.5
Interest Expense									66.3	66.6	65
INCOME BEFORE INCOME TAXES									249	231.6	227.1
Income taxes									88.1	83.2	85.3
Net Income	$ 46.6	$ 26.9	$ 24.4	$ 63	$ 39.8	$ 24.3	$ 22.9	$ 61.3	160.9	148.4	141.8
Subsidiary Guarantors [Member]
OPERATING REVENUES [Abstract]
Gas utility									792.6	944.6	810
Electric utility									601.6	624.8	619.3
Other									0	0	0
Total operating revenues									1,394.2	1,569.4	1,429.3
OPERATING EXPENSES [Abstract]
Cost of Gas Sold									305.4	468.7	358.1
Cost of fuel & purchased power									187.5	201.8	202.9
Other operating									376.9	390.3	369.2
Depreciation & Amortization									184.2	179.1	174.6
Taxes other than income taxes									55.2	58.4	55.6
Total operating expenses									1,109.2	1,298.3	1,160.4
OPERATING INCOME									285	271.1	268.9
Equity in earnings of consolidated companies									0	0	0
Other - net									15.7	13.3	7.1
Total other income (expense)									15.7	13.3	7.1
Interest Expense									63.7	63.9	59.8
INCOME BEFORE INCOME TAXES									237	220.5	216.2
Income taxes									90	83.8	84.9
Net Income									147	136.7	131.3
Parent Company [Member]
OPERATING REVENUES [Abstract]
Gas utility									0	0	0
Electric utility									0	0	0
Other									40.7	38.3	37.9
Total operating revenues									40.7	38.3	37.9
OPERATING EXPENSES [Abstract]
Cost of Gas Sold									0	0	0
Cost of fuel & purchased power									0	0	0
Other operating									0	0	0
Depreciation & Amortization									24.3	23.5	21.3
Taxes other than income taxes									1.8	1.7	1.5
Total operating expenses									26.1	25.2	22.8
OPERATING INCOME									14.6	13.1	15.1
Equity in earnings of consolidated companies									147	136.7	131.3
Other - net									42.7	43.2	38.5
Total other income (expense)									189.7	179.9	169.8
Interest Expense									45.3	45.2	42.7
INCOME BEFORE INCOME TAXES									159	147.8	142.2
Income taxes									(1.9)	(0.6)	0.4
Net Income									160.9	148.4	141.8
Consolidation, Eliminations [Member]
OPERATING REVENUES [Abstract]
Gas utility									0	0	0
Electric utility									0	0	0
Other									(40.4)	(38)	(37.6)
Total operating revenues									(40.4)	(38)	(37.6)
OPERATING EXPENSES [Abstract]
Cost of Gas Sold									0	0	0
Cost of fuel & purchased power									0	0	0
Other operating									(37.8)	(35.8)	(35.8)
Depreciation & Amortization									0.3	0.5	0.5
Taxes other than income taxes									0.1	0.1	0.1
Total operating expenses									(37.4)	(35.2)	(35.2)
OPERATING INCOME									(3)	(2.8)	(2.4)
Equity in earnings of consolidated companies									(147)	(136.7)	(131.3)
Other - net									(39.7)	(39.7)	(35.1)
Total other income (expense)									(186.7)	(176.4)	(166.4)
Interest Expense									(42.7)	(42.5)	(37.5)
INCOME BEFORE INCOME TAXES									(147)	(136.7)	(131.3)
Income taxes									0	0	0
Net Income									(147)	(136.7)	(131.3)
Consolidated Entities [Member]
OPERATING REVENUES [Abstract]
Gas utility									792.6	944.6	810
Electric utility									601.6	624.8	619.3
Other									0.3	0.3	0.3
Total operating revenues									1,394.5	1,569.7	1,429.6
OPERATING EXPENSES [Abstract]
Cost of Gas Sold									305.4	468.7	358.1
Cost of fuel & purchased power									187.5	201.8	202.9
Other operating									339.1	354.5	333.4
Depreciation & Amortization									208.8	203.1	196.4
Taxes other than income taxes									57.1	60.2	57.2
Total operating expenses									1,097.9	1,288.3	1,148
OPERATING INCOME									296.6	281.4	281.6
Equity in earnings of consolidated companies									0	0	0
Other - net									18.7	16.8	10.5
Total other income (expense)									18.7	16.8	10.5
Interest Expense									66.3	66.6	65
INCOME BEFORE INCOME TAXES									249	231.6	227.1
Income taxes									88.1	83.2	85.3
Net Income									$ 160.9	$ 148.4	$ 141.8

Subsidiary Guarantor and Cons52

Subsidiary Guarantor and Consolidating Information Subsidiary Guarantor and Consolidating Information Cash Flows (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Net cash flows from operating activities	$ 492.9	$ 337.5	$ 399.9
Additional capital contribution	6.2	6	6.1
Long-term debt - net of issuance costs	236.3	62.4	381.7
Payments of Dividends	(110.4)	(108.7)	(105.1)
Retirement of long-term debt, including premiums paid	(95)	(63.6)	(337.5)
Net change in short-term borrowings	(141.9)	127.8	(88.1)
Net cash flows from financing activities	(104.8)	23.9	(142.9)
Proceeds from other investing activities	3.9	0.3	0.8
Capital expenditures, excluding AFUDC equity	(399.2)	(351)	(262.5)
Changes in Restricted Cash	5.9	0	0
Net cash flows from investing activities	(401.2)	(350.7)	(261.7)
Net change in cash and cash equivalents	(13.1)	10.7	(4.7)
Cash & cash equivalents	6.2	19.3	8.6	$ 13.3
Subsidiary Guarantors [Member]
Net cash flows from operating activities	460.3	274.4	371
Additional capital contribution	6.2	6	13.1
Long-term debt - net of issuance costs	126.8	186.6	232.6
Payments of Dividends	(103.2)	(101.6)	(97.9)
Retirement of long-term debt, including premiums paid	(20)	(63.6)	(223.6)
Net change in intercompany short-term borrowings	(40.7)	23.9	(61.5)
Net change in short-term borrowings	0	0	0
Net cash flows from financing activities	(30.9)	51.3	(137.3)
Consolidated subsidiary distributions	0	0	0
Proceeds from other investing activities	0	0	0.6
Capital expenditures, excluding AFUDC equity	(373.7)	(327.3)	(238.3)
Requirements for consolidated subsidiary investments	0		0
Changes in Restricted Cash	(5.9)
Other investing activities		0
Net change in long term intercompany notes receivable	0	0	0
Net change in short term intercompany notes receivable	(51.2)	0.3	(0.3)
Net cash flows from investing activities	(430.8)	(327)	(238)
Net change in cash and cash equivalents	(1.4)	(1.3)	(4.3)
Cash & cash equivalents	5.5	6.9	8.2	12.5
Parent Company [Member]
Net cash flows from operating activities	32.6	63.1	28.9
Additional capital contribution	6.2	6	6.1
Long-term debt - net of issuance costs	199	0	273.5
Payments of Dividends	(110.4)	(108.7)	(105.1)
Retirement of long-term debt, including premiums paid	(75)	0	(221.6)
Net change in intercompany short-term borrowings	51.2	(0.3)	0.3
Net change in short-term borrowings	(141.9)	127.8	(88.1)
Net cash flows from financing activities	(70.9)	24.8	(134.9)
Consolidated subsidiary distributions	103.2	101.6	97.9
Proceeds from other investing activities	3.9	0.3	0.2
Capital expenditures, excluding AFUDC equity	(25.5)	(23.7)	(24.2)
Requirements for consolidated subsidiary investments	(6.2)		(13.1)
Changes in Restricted Cash	0
Other investing activities		(6)
Net change in long term intercompany notes receivable	(89.5)	(50.1)	(16.7)
Net change in short term intercompany notes receivable	40.7	(98)	61.5
Net cash flows from investing activities	26.6	(75.9)	105.6
Net change in cash and cash equivalents	(11.7)	12	(0.4)
Cash & cash equivalents	0.7	12.4	0.4	0.8
Consolidation, Eliminations [Member]
Net cash flows from operating activities	0	0	0
Additional capital contribution	(6.2)	(6)	(13.1)
Long-term debt - net of issuance costs	(89.5)	(124.2)	(124.4)
Payments of Dividends	103.2	101.6	97.9
Retirement of long-term debt, including premiums paid	0	0	107.7
Net change in intercompany short-term borrowings	(10.5)	(23.6)	61.2
Net change in short-term borrowings	0	0	0
Net cash flows from financing activities	(3)	(52.2)	129.3
Consolidated subsidiary distributions	(103.2)	(101.6)	(97.9)
Proceeds from other investing activities	0	0	0
Capital expenditures, excluding AFUDC equity	0	0	0
Requirements for consolidated subsidiary investments	6.2		13.1
Changes in Restricted Cash	0
Other investing activities		6
Net change in long term intercompany notes receivable	89.5	50.1	16.7
Net change in short term intercompany notes receivable	10.5	97.7	(61.2)
Net cash flows from investing activities	3	52.2	(129.3)
Net change in cash and cash equivalents	0	0	0
Cash & cash equivalents	0	0	0	0
Consolidated Entities [Member]
Net cash flows from operating activities	492.9	337.5	399.9
Additional capital contribution	6.2	6	6.1
Long-term debt - net of issuance costs	236.3	62.4	381.7
Payments of Dividends	(110.4)	(108.7)	(105.1)
Retirement of long-term debt, including premiums paid	(95)	(63.6)	(337.5)
Net change in intercompany short-term borrowings	0	0	0
Net change in short-term borrowings	(141.9)	127.8	(88.1)
Net cash flows from financing activities	(104.8)	23.9	(142.9)
Consolidated subsidiary distributions	0	0	0
Proceeds from other investing activities	3.9	0.3	0.8
Capital expenditures, excluding AFUDC equity	(399.2)	(351)	(262.5)
Requirements for consolidated subsidiary investments	0		0
Changes in Restricted Cash	(5.9)
Other investing activities		0
Net change in long term intercompany notes receivable	0	0	0
Net change in short term intercompany notes receivable	0	0	0
Net cash flows from investing activities	(401.2)	(350.7)	(261.7)
Net change in cash and cash equivalents	(13.1)	10.7	(4.7)
Cash & cash equivalents	$ 6.2	$ 19.3	$ 8.6	$ 13.3

Quarterly Financial Data (Una53

Quarterly Financial Data (Unaudited) (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
Quarterly Financial Information Disclosure [Abstract]
Total operating revenues	$ 338.1	$ 273	$ 276.5	$ 506.9	$ 407.5	$ 271.1	$ 284.5	$ 606.6	$ 1,394.5	$ 1,569.7	$ 1,429.6
Operating Income	81.3	54.1	50.5	110.8	73.4	49.4	48.1	110.4	296.6	281.4	281.6
Net Income	$ 46.6	$ 26.9	$ 24.4	$ 63	$ 39.8	$ 24.3	$ 22.9	$ 61.3	$ 160.9	$ 148.4	$ 141.8

SCHEDULE II VALUATION AND QUA54

SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES (Details) - Accumulated Provision for Uncollectible Accounts [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Valuation and Qualifying Accounts Disclosure [Line Items]
Balance, at beginning of year	$ 3.9	$ 5	$ 5
Additions charged to expenses	6.9	6.1	6.5
Additions charged to other accounts	0	0	0
Deductions from Reserves, Net	7.8	7.2	6.5
Balance, at end of period	$ 3	$ 3.9	$ 5