Vectren Utility 10-K 5 Mar 15 2014 FY Annual report Financial data

Document_And_Entity_Informatio

Document And Entity Information (USD $)	12 Months Ended
	Dec. 31, 2014	Feb. 27, 2015	Jun. 30, 2014
Entity Information [Line Items]
Entity Registrant Name	VECTREN UTILITY HOLDINGS INC
Entity Central Index Key	1129542
Current Fiscal Year End Date	-19
Entity Filer Category	Non-accelerated Filer
Document Type	10-K
Document Period End Date	31-Dec-14
Document Fiscal Year Focus	2014
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 $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Assets, Current [Abstract]
Cash & cash equivalents	$19.30	$8.60
Accounts receivable - less reserves of $3.9 & $5.0, respectively	113	112.1
Accrued unbilled revenues	122.4	113.5
Inventories	113.2	89.9
Recoverable fuel & natural gas costs	9.8	5.5
Prepayments & other current assets	83.5	42.4
Total current assets	461.2	372
Utility Plant [Abstract]
Original Cost	5,718.70	5,389.60
Less: accumulated depreciation & amortization	2,279.70	2,165.30
Net utility plant	3,439	3,224.30
Investments in unconsolidated affiliates	0.2	0.2
Other investments	25.6	27.3
Nonutility plant - net	149.2	150.5
Goodwill - net	205	205
Regulatory assets	128.3	136.2
Other assets	19.6	25.3
TOTAL ASSETS	4,428.10	4,140.80
Current Liabilities [Abstract]
Accounts payable	180.4	172.1
Payables to other Vectren companies	28.6	24.6
Accrued liabilities	122.3	127.4
Short-term borrowings	156.4	28.6
Current maturities of long-term debt	95	0
Total current liabilities	582.7	352.7
Long-Term Debt - Net of Current Maturities	1,162.30	1,257.10
Deferred Income Taxes & Other Liabilities [Abstract]
Deferred income taxes	685.1	627.4
Regulatory liabilities	410.3	387.3
Deferred credits & other liabilities	109.2	83.5
Total deferred credits and other liabilities	1,204.60	1,098.20
Commitments & Contingencies (Notes 8-11)
Common Shareholder's Equity [Abstract]
Common stock (no par value)	793.7	787.7
Retained earnings	684.8	645.1
Total common shareholders' equity	1,478.50	1,432.80
TOTAL LIABILITIES and SHAREHOLDERS' EQUITY	$4,428.10	$4,140.80

CONSOLIDATED_CONDENSED_BALANCE1

CONSOLIDATED CONDENSED BALANCE SHEETS (Unaudited) (Parenthetical) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Assets, Current [Abstract]
Allowance for Doubtful Accounts Receivable, Current	$3.90	$5

CONSOLIDATED_CONDENSED_STATEME

CONSOLIDATED CONDENSED STATEMENTS OF INCOME (Unaudited) (USD $)	3 Months Ended								12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
OPERATING REVENUES [Abstract]
Gas utility									$944.60	$810	$738.10
Electric utility									624.8	619.3	594.9
Other									0.3	0.3	0.6
Total operating revenues	407.5	271.1	284.5	606.6	403.6	267.7	292.8	465.5	1,569.70	1,429.60	1,333.60
OPERATING EXPENSES [Abstract]
Cost of gas sold									468.7	358.1	301.3
Cost of fuel & purchased power									201.8	202.9	192
Other operating									354.5	333.4	310.1
Depreciation & Amortization									203.1	196.4	190
Taxes other than income taxes									60.2	57.2	53.4
Total operating expenses									1,288.30	1,148	1,046.80
OPERATING INCOME	73.4	49.4	48.1	110.4	70.5	54.5	51.2	105.4	281.4	281.6	286.8
Nonoperating Income (Expense) [Abstract]
Other income - net									16.8	10.5	8
Interest Expense									66.6	65	71.5
INCOME BEFORE INCOME TAXES									231.6	227.1	223.3
Income taxes									83.2	85.3	85.3
Net Income	$39.80	$24.30	$22.90	$61.30	$37.20	$25.30	$24.20	$55.10	$148.40	$141.80	$138

CONSOLIDATED_CONDENSED_STATEME1

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS (Unaudited) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
CASH FLOWS FROM OPERATING ACTIVITIES [Abstract]
Net Income	$148.40	$141.80	$138
Adjustments to Reconcile Net Income to Cash from Operating Activities [Abstract]
Depreciation & Amortization	203.1	196.4	190
Deferred income taxes & investment tax credits	55.7	26.4	72.3
Expense portion of pension & postretirement periodic benefit cost	4.7	5.6	5
Provision for uncollectible accounts	6.1	6.5	7.4
Other non-cash expense - net	3.2	2.5	5.6
Changes in working capital accounts [Abstract]
Accounts receivable, including to Vectren companies and accrued unbilled revenues	-15.8	-56.8	3.7
Inventories	-23.3	24.1	18.5
Recoverable/refundable fuel & natural gas costs	-4.4	22.4	-12.9
Prepayments & other current assets	-34.4	15.5	2.6
Accounts payable, including to Vectren companies & affiliated companies	7.5	10.1	-7.4
Accrued liabilities	-2.2	4.9	-1.6
Changes in noncurrent ssets	6.4	11.4	-33.2
Changes in noncurrent liabilities	-17.5	-10.9	-14.6
Net cash flows from operating activities	337.5	399.9	373.4
Proceeds from:
Long-term debt - net of issuance costs	62.4	381.7	99.5
Additional capital contribution	6	6.1	7
Requirements for:
Dividends to parent	-108.7	-105.1	-101.5
Retirement of long-term debt	-63.6	-337.5	0
Net change in short-term borrowings	127.8	-88.1	-126.1
Net cash flows from financing activities	23.9	-142.9	-121.1
CASH FLOWS FROM INVESTING ACTIVITIES [Abstract]
Proceeds from other investing activities	0.3	0.8	2.6
Requirements for:
Capital expenditures, excluding AFUDC equity	-351	-262.5	-247.6
Net cash flows from investing activities	-350.7	-261.7	-245
Net change in cash and cash equivalents	10.7	-4.7	7.3
Cash and cash equivalents at beginning of period	8.6	13.3	6
Cash and cash equivalents at end of period	$19.30	$8.60	$13.30

Statement_of_Shareholders_Equi

Statement of Shareholders' Equity (USD $)	3 Months Ended		12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Balance at end of period	$1,478.50	$1,432.80	$1,478.50	$1,432.80	$1,390	$1,346.60
Net Income	39.8	37.2	148.4	141.8	138
Other comprehensive income					0
Common stock:
Other			-0.1
Additional Capital Contribution			6	6.1	7
Dividends			-108.7	-105.1	-101.5
Common Stock [Member]
Balance at end of period	793.7	787.7	793.7	787.7	781.6	774.6
Common stock:
Additional Capital Contribution			6	6.1	7
Retained Earnings [Member]
Balance at end of period	684.8	645.1	684.8	645.1	608.4	572
Net Income			148.4	141.8	138
Common stock:
Other					-0.1
Dividends			-108.7	-105.1	-101.5
Accumulated Other Comprehensive Income (Loss) [Member]
Balance at end of period	0	0	0	0	0	0
Other comprehensive income

Organization_and_Nature_of_Ope

Organization and Nature of Operations	12 Months Ended
	Dec. 31, 2014
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), Southern Indiana Gas and Electric Company (SIGECO), 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 575,000 natural gas customers located in central and southern Indiana. SIGECO provides energy delivery services to approximately 143,000 electric customers and over 110,000 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 313,000 natural gas customers located near Dayton in west central Ohio.

Summary_of_Significant_Account

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Summary of Significant Accounting Policies
	In applying its accounting policies, the Company makes judgments, assumptions, and estimates that affect the amounts reported in these consolidated financial statements and related footnotes.  Examples of transactions for which estimation techniques are used include valuing pension and postretirement benefit obligations, deferred tax obligations, unbilled revenue, uncollectible accounts, regulatory assets and liabilities, reclamation liabilities, 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 significant 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 is recorded using the Last In – First Out (LIFO) method.  Inventory is valued at historical cost consistent with ratemaking treatment.  Materials and supplies are recorded as inventory when purchased and subsequently charged to expense or capitalized to plant when installed.
	Property, Plant & Equipment
	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.  There were no impairments related to property, plant and equipment during the periods presented.
	Goodwill
	Goodwill recorded on the Consolidated Balance Sheets results from business acquisitions in the Gas Utility Services operating segment 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 that test 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 probable future revenues associated with certain incurred costs, which will be recovered 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 other 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 exempted 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 the accounting period in Accrued Unbilled Revenues.
	MISO Transactions
	With the IURC’s approval, the Company is a member of the MISO, a FERC approved regional transmission organization.  The MISO serves the electrical transmission needs of much of the Midcontinent region and maintains operational control over the Company’s electric transmission facilities as well as that of other utilities in the region.  The Company is an active participant in the MISO energy markets, bidding its owned generation into the Day Ahead and Real Time markets and procuring power for its retail customers at Locational Marginal Pricing (LMP) as determined by the MISO market.
	MISO-related purchase and sale transactions are recorded using settlement information provided by 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 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 $32.3 million in 2014, $29.6 million in 2013, and $26.9 million in 2012.  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/or 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’s 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, 2014
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)	2014				2013
		Original Cost		Depreciation		Original Cost		Depreciation
				Rates as a				Rates as a
				Percent of				Percent of
				Original Cost				Original Cost
	Gas utility plant	$	3,011.00	3.4	%	$	2,762.20	3.5	%
	Electric utility plant	2,602.50		3.3	%	2,519.80		3.3	%
	Common utility plant	54.3		3.2	%	53.4		3	%
	Construction work in progress	50.9		—		54.2		—
	Total original cost	$	5,718.70			$	5,389.60
	SIGECO and Alcoa Generating Corporation (AGC), a subsidiary of ALCOA, own the 300 MW Unit 4 at the Warrick Power Plant as tenants in common.  SIGECO's share of the cost of this unit at December 31, 2014, is $188.0 million with accumulated depreciation totaling $93.5 million.  AGC and SIGECO also 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.
	Nonutility Plant, net of accumulated depreciation and amortization follows:
		At December 31,
	(In millions)	2014		2013
	Computer hardware & software	$	105	$	102.3
	Land & buildings	35.8		38.3
	All other	8.4		9.9
	Nonutility plant - net	$	149.2	$	150.5
	Nonutility plant is presented net of accumulated depreciation and amortization totaling $226.7 million and $209.2 million as of December 31, 2014 and 2013, respectively.  For the years ended December 31, 2014, 2013, and 2012, the Company capitalized interest totaling $0.6 million, $0.4 million, and $0.2 million, respectively, on nonutility plant construction projects.

Regulatory_Assets_Liabilities

Regulatory Assets & Liabilities	12 Months Ended
	Dec. 31, 2014
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)	2014			2013
	Future amounts recoverable from ratepayers related to:
	Net deferred income taxes (See Note 5)	$	(14.8	)	$	(5.8	)
	Asset retirement obligations & other	—			2.3
		(14.8		)	(3.5		)
	Amounts deferred for future recovery related to:
	Deferred coal costs (See Note 10)	—			42.4
	Cost recovery riders & other	33.3			18.6
		33.3			61
	Amounts currently recovered in customer rates related to:
	Unamortized debt issue costs & hedging proceeds	33.5			34.6
	Demand side management programs	0.6			2.5
	Deferred coal costs (See Note 10)	35.3			—
	Indiana authorized trackers	25.6			30.8
	Ohio authorized trackers	12.7			7.9
	Premiums paid to reacquire debt	1.7			2.2
	Other base rate recoveries	0.4			0.7
		109.8			78.7
	Total regulatory assets	$	128.3		$	136.2
	Of the $109.8 million currently being recovered in customer rates, $0.6 million that is associated with demand side management programs is earning a return.  The weighted average recovery period of regulatory assets currently being recovered in base rates, which totals $36 million, is 23 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, 2014 and 2013, the Company has approximately $410.3 million and $387.3 million, respectively, in Regulatory liabilities.  Of these amounts, $373.5 million and $373.0 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_Vectre

Transactions with Other Vectren Companies and Affiliates	12 Months Ended
	Dec. 31, 2014
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 $94.0 million in 2014, $54.2 million in 2013, and $46.6 million in 2012.  Amounts owed to VISCO at December 31, 2014 and 2013 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, 2013 and 2012, totaled $98.6 million, $103.7 million, and $115.6 million, respectively. No amounts were owed to Vectren Fuels at December 31, 2014 and amounts owed as of December 31, 2013 were included in Payables to other Vectren companies. 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 provided services to a broad range of municipalities, utilities, industrial operations, schools, and healthcare institutions located throughout the Midwest and Southeast United States.  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, 2014, as a result of ProLiance exiting the natural gas marketing business. For the years ended December 31, 2013 and 2012 the Company had purchases totaling $200.5 million, $274.5 million, respectively.  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 84 percent is from a single third party for the year ended December 31, 2014.
	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 $57.0 million, $50.9 million, and $44.8 million for the years ended December 31, 2014, 2013 and 2012, respectively.
	Retirement Plans & Other Postretirement Benefits
	At December 31, 2014, Vectren maintains three qualified defined benefit pension plans (Vectren Corporation Non-Bargaining Retirement Plan, The Indiana Gas Company, Inc. Bargaining Unit Retirement Plan, Pension Plan for Hourly Employees of Southern Indiana Gas and Electric Company), a nonqualified supplemental executive retirement plan, 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.   However, Utility Holdings has no contractual funding commitment and did not contribute to Vectren's defined benefit pension plans during 2014 or 2013.  The combined funded status of Vectren’s plans was approximately 87 percent at December 31, 2014 and 101 percent at December 31, 2013.
	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, 2014, 2013 and 2012, costs totaling $6.7 million, $8.0 million and $7.2 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, 2014 and 2013, $11.6 million and $11.2 million, respectively, is included in Deferred credits & other liabilities and represents costs directly charged to the Company that is yet to be funded to Vectren.  As impacted by increased funding of pension plans, at December 31, 2014 and 2013, the Company has $17.3 million, and $23.6 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, 2014 and 2013, $36.1 million and $29.6 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)	2014				2013				2012
	Current:
	Federal	$	16.6			$	48			$	6.1
	State	10.9				11				6.9
	Total current taxes	27.5				59				13
	Deferred:
	Federal	57.8				26.8				68.7
	State	(1.6		)		0.1				4.2
	Total deferred taxes	56.2				26.9				72.9
	Amortization of investment tax credits	(0.5		)		(0.6		)		(0.6		)
	Total income tax expense	$	83.2			$	85.3			$	85.3
	A reconciliation of the federal statutory rate to the effective income tax rate follows:
		Year Ended December 31,
		2014			2013			2012
	Statutory rate	35	%		35	%		35	%
	State and local taxes-net of federal benefit	3.3			3.5			3.7
	Amortization of investment tax credit	(0.2	)		(0.3	)		(0.3	)
	Domestic Production Deduction	(0.9	)		—			—
	Adjustment of income tax accruals	(0.9	)		—			—
	All other - net	(0.4	)		(0.6	)		(0.2	)
	Effective tax rate	35.9	%		37.6	%		38.2	%
	Significant components of the net deferred tax liability follow:
		At December 31,
	(In millions)	2014				2013
	Noncurrent deferred tax liabilities (assets):
	Depreciation & cost recovery timing differences	$	685			$	627.9
	Regulatory assets recoverable through future rates	29.2				22.8
	Alternative minimum tax carryforward	(13.3		)		(18.5		)
	Employee benefit obligations	1				5.2
	Regulatory liabilities to be settled through future rates	(27.5		)		(18.7		)
	Other – net	10.7				8.7
	Net noncurrent deferred tax liability	685.1				627.4
	Current deferred tax liabilities (assets):
	Deferred fuel costs - net	22				22.9
	Alternative minimum tax carryforward	(38.1		)		(36.4		)
	General business credit carryforwards	—				(1.2		)
	Other – net	4.8				9.2
	Net current deferred tax liability (asset)	(11.3		)		(5.5		)
	Net deferred tax liability	$	673.8			$	621.9
	At December 31, 2014 and 2013, investment tax credits totaling $2.6 million and $3.2 million, respectively, are included in Deferred credits & other liabilities.  At December 31, 2014, the Company has alternative minimum tax carryforwards of $51.4 million, which do not expire.
Uncertain Tax Positions
The following is a roll forward of the total amount of unrecognized tax benefits for the three years ended December 31, 2014:
(In millions)	2014				2013				2012
Unrecognized tax benefits at January 1	$	4.7			$	3.7			$	11
Gross increases - tax positions in prior periods	—				—				0.1
Gross decreases - tax positions in prior periods	(4.7		)		(0.2		)		(9.3		)
Gross increases - current period tax positions	—				1.2				1.9
Settlements	—				—				—
Unrecognized tax benefits at December 31	$	—			$	4.7			$	3.7
Of the change in unrecognized tax benefits during 2014, 2013, and 2012, none impacted the effective rate.  The amount of unrecognized tax benefits, which if recognized, that would impact the effective tax rate was zero at December 31, 2014 , 2013, and 2012.
In 2014, the Company recognized income related to a reversal of interest expense previously accrued and net of penalties totaling approximately $0.2 million. In 2013, the Company recognized no expense related to interest and penalties. In 2012, the Company recognized income related to a reversal of interest expense previously accrued and net of penalties totaling approximately $0.7 million.  The Company had no accrual for payment of interest and penalties as of December 31, 2014, and $0.2 million for the payment of interest and penalties accrued as of 2013.
The Company and/or certain of its subsidiaries file income tax returns in the U.S. federal jurisdiction and various states. The Internal Revenue Service (IRS) has concluded examinations of the Company's U.S. federal income tax returns for tax years through December 31, 2008. The IRS is currently examining the 2009-2012 federal income tax returns as part of a routine review by the Joint Committee on Taxation. The State of Indiana, the Company's primary state tax jurisdiction, has conducted examinations of state income tax returns for tax years through December 31, 2008. The statutes of limitations for assessment of federal income tax and Indiana income tax have expired with respect to tax years through 2008.
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 will be 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 2015. The Company continues to evaluate the impact adoption of the regulations and industry guidance will have on its consolidated financial statements. As of this date, the Company does not expect the adoption of the regulations 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, 2014
Debt Disclosure [Abstract]
Borrowing Arrangements	Borrowing Arrangements
	Short-Term Borrowings
	At December 31, 2014, the Company has $350 million of short-term borrowing capacity.  As reduced by borrowings outstanding at December 31, 2014, approximately $194 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 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)		2014				2013			2012
	Year End
	Balance Outstanding		$	156.4			$	28.6		$	116.7
	Weighted Average Interest Rate		0.5		%		0.29		%	0.4		%
	Annual Average
	Balance Outstanding		$	35.6			$	119.6		$	77.6
	Weighted Average Interest Rate		0.34		%		0.34		%	0.47		%
	Maximum Month End Balance Outstanding		$	156.4			$	176.1		$	214.2
	Throughout 2014, 2013, and 2012, the Company placed commercial paper without any significant issues and did not borrow from its backup credit facility in any of these periods.
	Long-Term Debt
	Long-term senior unsecured obligations and first mortgage bonds outstanding by subsidiary follow:
		At December 31,
	(In millions)	2014				2013
	Utility Holdings
	Fixed Rate Senior Unsecured Notes
	2015, 5.45%	75				75
	2018, 5.75%	100				100
	2020, 6.28%	100				100
	2021, 4.67%	55				55
	2023, 3.72%	150				150
	2026, 5.02%	60				60
	2028, 3.20%	45				45
	2035, 6.10%	75				75
	2041, 5.99%	35				35
	2042, 5.00%	100				100
	2043, 4.25%	80				80
	Total Utility Holdings	875				875
	SIGECO
	First Mortgage Bonds
	2015, 1985 Pollution Control Series A, current adjustable rate 0.05%, tax exempt,
	2013 weighted average: 0.10%	—				9.8
	2016, 1986 Series, 8.875%	13				13
	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, 1998 Pollution Control Series A, current adjustable rate 0.05%, tax exempt,
	2013 weighted average: 0.10%	—				31.5
	2025, 2014 Series B, current adjustable rate 0.722%, tax-exempt	41.3				—
	2029, 1999 Series, 6.72%	80				80
	2037, 2013 Series E, 1.95%, tax exempt	22				22
	2038, 2013 Series A, 4.0%, tax exempt	22.2				22.2
	2040, 2009 Environmental Improvement Series, 5.40%, tax exempt	—				22.3
	2043, 2013 Series B, 4.05%, tax exempt	39.6				39.6
	2044, 2014 Series A, 4.00%, tax exempt	22.3				—
	Total SIGECO	267.5				267.5
	Indiana Gas
	Senior Unsecured Notes
	2015, Series E, 7.15%	5				5
	2015, Series E, 6.69%	5				5
	2015, Series E, 6.69%	10				10
	2025, Series E, 6.53%	10				10
	2027, Series E, 6.42%	5				5
	2027, Series E, 6.68%	1				1
	2027, Series F, 6.34%	20				20
	2028, Series F, 6.36%	10				10
	2028, Series F, 6.55%	20				20
	2029, Series G, 7.08%	30				30
	Total Indiana Gas	116				116
	Total long-term debt outstanding	1,258.50				1,258.50
	Current maturities of long-term debt	(95.0		)		—
	Unamortized debt premium & discount - net	(1.2		)		(1.4		)
Total long-term debt-net	$	1,162.30			$	1,257.10
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.
Utility Holdings 2012 Debt Transactions
On February 1, 2012, Utility Holdings issued $100 million of senior unsecured notes at an interest rate of 5.00 percent per annum and with a maturity date of February 3, 2042.  The notes were sold to various institutional investors pursuant to a private placement note purchase agreement executed in November 2011 with a delayed draw feature.  These senior notes are unsecured and jointly and severally guaranteed by Utility Holdings’ regulated utility subsidiaries, SIGECO, Indiana Gas, and VEDO.  The proceeds from the sale of the notes, net of issuance costs, totaled approximately $99.5 million.  These notes have no sinking fund requirements and interest payments are due semi-annually.  These notes contain customary representations, warranties and covenants, including a leverage covenant consistent with leverage covenants contained in other Utility Holdings’ borrowing arrangements.
Mandatory Tenders
At December 31, 2014, certain series of SIGECO bonds, aggregating $49.1 million, currently bear interest at fixed rates and are subject to mandatory tender in September 2017.  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 intends to meet the 2014 sinking fund requirement by this means and, accordingly, the sinking fund requirement for 2014 is excluded from Current liabilities in the Consolidated Balance Sheets.  At December 31, 2014, $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 $3.0 billion at December 31, 2014.
Consolidated maturities of long-term debt during the years following 2014 (in millions) are $95.0 million in 2015, $13.0 in 2016, $0.0 in 2017, $100.0 in 2018, $0.0 in 2019, and $1,049.3 thereafter.
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, 2014, totaled $875 million and $156 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, 2014, the Company was in compliance with all financial covenants.

Common_Shareholders_Equity

Common Shareholder's Equity	12 Months Ended
	Dec. 31, 2014
Stockholders' Equity Note [Abstract]
Common Shareholder's Equity	Common Shareholder’s Equity
	During the years ended December 31, 2014, 2013, and 2012, the Company has cumulatively received additional capital of $19.1 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, 2014
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 2014 and thereafter (in millions) are $0.9 in 2015, $0.8 in 2016, $0.8 in 2017, $0.7 in 2018, $0.5 in 2019, and $2.4 thereafter.  Total lease expense (in millions) was $1.5 in 2014, $1.1 in 2013, and $1.2 in 2012.  Firm purchase commitments for utility plant total $0.2 million in 2015, $0.2 million in 2016 and $0.2 million in 2017, and zero thereafter.
	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.  Because of the pass through nature of these costs, they have not been included in the listing of contractual obligations.
	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, 2014
Public Utilities, General Disclosures [Abstract]
Gas Rate and Regulatory Matters	Gas Rate & Regulatory Matters
	Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement
	The Company monitors and maintains its natural gas distribution system to ensure that 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 in both Indiana and Ohio were passed that 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, 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 and of the investment, as well as property taxes and operating expenses.  The remaining 20 percent of project costs is 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. By allowing for the deferral of costs, such as depreciation, property taxes, and debt-related post in service carrying costs until recovery is approved by the Ohio Commission.
	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 project to three years after being placed into service at SIGECO and four years after being placed into service at Indiana Gas. At December 31, 2014 and 2013, the Company has regulatory assets totaling $16.4 million and $12.1 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, discussed further below.
	Requests for Recovery Under Indiana Regulatory Mechanisms
	On August 27, 2014, the Commission issued an Order approving the Company’s seven-year capital infrastructure replacement and improvement plan, beginning in 2014, and the proposed accounting authority and recovery, pursuant to Senate Bill 251 and 560. 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 associated with pipeline safety rules, with 80 percent of the costs 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 update the seven-year capital investment plan annually, with detailed estimates provided for the upcoming calendar year. 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 Indiana Office of Utility Consumer Counselor (OUCC) filed a Notice of Appeal with the Indiana Court of Appeals in response to the IURC's Order. On January 28, 2015, the OUCC filed its appellate brief raising an issue regarding the treatment of retired assets within the recovery mechanism. An appeal was also filed in response to the IURC's Order in Northern Indiana Public Service Company's (NIPSCO) Senate Bill 560 electric infrastructure proceeding, pertaining to certain issues regarding the Commission's authority to approve NIPSCO's infrastructure plan. The outcome of neither appeal and the implications to the Company’s Order, if any, cannot be determined.
	On January 14, 2015, the Commission issued an Order approving the Company’s initial request for recovery of the revenue requirement associated with capital investment and applicable operating costs through June 30, 2014 as part of its approved seven-year plan. As the next step of the recovery process, as outlined in the legislation, this Order initiates the rates and charges necessary to begin cash recovery of 80 percent of the revenue requirement, with the remaining 20 percent deferred for recovery in the Company's next rate cases. Also, consistent with the guidelines set forth in the original August 2014 Order, the Commission 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 cost increases. The updated plan reflects capital expenditures of approximately $900 million, an increase of $35 million from the previous plan and is inclusive of an estimated $30 million of economic development related expenditures, over the seven-year period beginning in 2014. The plan also includes approximately $15 million of annual operating costs associated with pipeline safety rules.
	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 to be earned 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 $150.5 million. Regulatory assets associated with post-in-service carrying costs and depreciation deferrals were $13.1 million and $9.3 million at December 31, 2014 and December 31, 2013, 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, subject to the graduated caps on the fixed DRR monthly charge applicable to residential and small general service customers approved in the Order. 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 May 1, 2014, the Company filed its annual request to adjust the DRR for recovery of costs incurred through December 31, 2013. On August 27, 2014 the PUCO issued an Order approving the Company’s revised DRR rates and charges, effective September 1, 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 three-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, 2014, 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, 2014, which covers the Company’s capital expenditure program through calendar year 2014. During 2014 and 2013, these approved capital expenditure programs under House Bill 95 generated Other income associated with the debt-related post-in-service carrying costs totaling $3.9 million and $2.2 million, respectively. Deferral of depreciation and property tax expenses related to these programs in 2014 and 2013 totaled $3.1 million and $1.7 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 has modified its position in testimony filed on November 5, 2014, and now suggests a reduced disallowance of $3 million. The Commission has moved this specific issue to a sub-docket proceeding, and based on the procedural schedule, an order is expected later in 2015. The Company believes that the costs are either recoverable in its GCA, or that if the incentive mechanism calculation is found to create a credit due to customers, any such outcome would be funded by its supply administrator. The administrator has intervened and filed testimony in the proceeding.
	Indiana Gas & SIGECO Gas Decoupling Extension Filing
	On August 18, 2011, the IURC issued an Order granting the extension of the current decoupling mechanism in place at both Indiana gas companies and recovery of new conservation program costs through December 2015.  On March 2, 2015, the Company and the OUCC filed a joint settlement agreement for approval by the Commission to extend the decoupling mechanism through 2020.

Electric_Rate_and_Regulatory_M

Electric Rate and Regulatory Matters Electric Rate and Regulatory Matters	12 Months Ended
	Dec. 31, 2014
Public Utilities, General Disclosures [Abstract]
Electric Rate and Regulatory Matters	Electric Rate & Regulatory Matters
	SIGECO Electric Environmental Compliance Filing
	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 mercury and air toxin standards effective in 2015 and to address an outstanding Notice of Violation (NOV) from the EPA.  The total investment is estimated to be between $80 and $90 million, roughly half of which will be made to control mercury in both air and water emissions, and the remaining investment will be made to address the issues raised in the NOV proceeding on the increase in sulfur trioxide emissions.  Although the Company and the Commission acknowledge that these investments are recoverable as clean coal technology under Senate Bill 29 and federal mandated investment under Senate Bill 251, the Order approves the Company’s request for deferred accounting treatment in lieu of timely recovery to avoid immediate customer bill impacts.  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 expected to occur in 2015 and 2016.
	Coal Procurement Procedures
	Entering 2014, SIGECO had in place staggered term coal contracts with Vectren Fuels and one other supplier to provide supply for its generating units.  During 2014, SIGECO entered into separate negotiations with Vectren Fuels and Sunrise Coal to modify its existing contracts as well as enter into new long-term contracts in order to secure its supply of coal with specifications that support its compliance with the Mercury and Air Toxins Rule. Subsequent to the sale of Vectren Fuels to Sunrise Coal in August 2014, all such contracts have been assigned to Sunrise Coal. Those contracts were submitted to the IURC for review as part of the 2014 annual sub docket proceeding.  In December 2014, the Commission determined that the terms of the coal contracts were reasonable. The annual sub docket proceeding is no longer required.
	On December 5, 2011 within the quarterly FAC filing, SIGECO submitted a joint proposal with the OUCC to reduce its fuel costs billed to customers by accelerating into 2012 the impact of lower cost coal under new term contracts effective after 2012. The cost difference was deferred to a regulatory asset and is being recovered over a 6 year period without interest beginning in 2014.  The IURC approved this proposal on January 25, 2012, with the reduction to customer’s rates effective February 1, 2012.  The total balance deferred for recovery through the Company’s FAC, which began February 2014, was $42.4 million, of which $35.3 million remains as of December 31, 2014.
	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; and 4) deferral of lost margin up to $3 million in 2012 and $1 million in 2011 associated with small customer DSM programs for subsequent recovery under a tracking mechanism to be proposed by the Company.  On June 20, 2012, the IURC issued an Order approving a small customer lost margin recovery mechanism, inclusive of all previous deferrals. This mechanism is an alternative to the electric decoupling proposal that was denied by the IURC in the Company's last base rate proceeding.  For the twelve months ended December 31, 2014 and December 31, 2013, the Company recognized Electric utility revenue of $8.7 million and $5.0 million, respectively, associated with this approved lost margin recovery mechanism.
	On March 28, 2014, Senate Bill 340 was signed into law. This legislation ended electric DSM programs on December 31, 2014 that have been conducted to meet the energy savings requirements established in the Commission's December 2009 Order. 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. Indiana's governor has requested that the Commission make new recommendations for energy efficiency programs to be proposed for 2015 and beyond, and has also asked the legislature to consider further legislation requiring some level of utility sponsored energy efficiency programs. The Company filed a request for Commission approval of a new portfolio of DSM programs on May 29, 2014 to be offered in 2015. On October 15, 2014, the Commission issued an Order approving a Settlement between the OUCC and the Company regarding the new portfolio of DSM programs effective January 2015.
	FERC Return on Equity (ROE) Complaint
	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 MISO and various MISO transmission owners, including SIGECO. The joint parties seek to reduce the 12.38 percent return on equity 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. The MISO transmission owners filed their response to the complaint on January 6, 2014, opposing any change to the return. As of December 31, 2014, the Company had invested approximately $157.7 million in qualifying projects. The net plant balance for these projects totaled $143.6 million at December 31, 2014.
	This joint complaint is 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 methodology set out in its June 19, 2014 decision.
	In addition to the NETO ruling, the FERC acknowledged that the pending complaint raised against the MISO transmission owners is reasonable, and ordered the initiation of a formal settlement discussion, mediated by a FERC appointed judge, in November 2014. As of January 2015, a settlement was not reached, and the case will move to a formal evidentiary hearing before the FERC. A procedural schedule was set on January 22, 2015, which will define a targeted date of final resolution from the FERC. An initial decision is expected later in 2015, but the timing of the final order from the FERC is unknown at this time. The Company has established a reserve pending the outcome of this complaint.
	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 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.

Environmental_Matters

Environmental Matters	12 Months Ended
	Dec. 31, 2014
Environmental Matters Disclosure [Abstract]
Environmental Matters	Environmental Matters
	Indiana Senate Bill 251
	Indiana Senate Bill 251 is also applicable to federal environmental mandates impacting SIGECO electric operations. The Company continues with its ongoing evaluation of the impact Senate Bill 251 may have on its operations, including applicability of the stricter regulations the EPA is currently considering involving air quality, fly ash disposal, cooling tower intake facilities, waste water discharges, and greenhouse gases. These issues are further discussed below.
	Air Quality
	Cross-State Air Pollution Rule
	In July 2011, the EPA finalized the Cross-State Air Pollution Rule (CSAPR).  CSAPR was the EPA’s response to the US Court of Appeals for the District of Columbia’s (the Court) remand of the Clean Air Interstate Rule (CAIR). CAIR was originally established in 2005 as an allowance cap and trade program that required reductions from coal-burning power plants for NOX emissions beginning January 1, 2009 and SO2 emissions beginning January 1, 2010, with a second phase of reductions in 2015. In an effort to address the Court’s finding that CAIR did not adequately ensure attainment of pollutants in certain downwind states due to unlimited trading of SO2 and NOX allowances, CSAPR reduced the ability of facilities to meet emission reduction targets through allowance trading.  CSAPR reductions were to be achieved with initial step reductions beginning January 1, 2012, and final compliance to be achieved in 2014.  After a series of legal challenges, the United States Supreme Court upheld CSAPR in April 2014, and the EPA finalized a new deadline schedule for entities that must comply, with CSAPR’s first phase caps starting in 2015 and 2016, and the second phase in 2017. The Company is in full compliance with all requirements of CSAPR.
	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. Reductions are to be achieved within three years of publication of the final rule in the Federal Register (April 2015). The EPA did not grant blanket compliance extensions but asserted that states have broad authority to grant one year extensions for individual electric generating units where potential reliability impacts have been demonstrated. Legal challenges to the MATS Rule continue. In July, a coalition of twenty-one states, including Indiana, filed a petition for certiorari with the U.S. Supreme Court seeking review of the decision of the appellate court. On November 25, 2014, the U.S. Supreme Court agreed to hear the case, with a decision expected later in 2015.
	Notice of Violation for A.B. Brown Power Plant
	The Company received a notice of violation (NOV) from the EPA in November 2011 pertaining to its A.B. Brown generating station.  The NOV asserts that 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. The Company reached a settlement in principle with the EPA to resolve the NOV. That settlement was contemplated in the plan filed and approved by the IURC on January 28, 2015 in the SIGECO Electric Environmental Compliance Filing.
	Information Request
	SIGECO and Alcoa Generating Corporation (AGC), a subsidiary of ALCOA, own a 300 MW Unit 4 at the Warrick Power Plant as tenants in common.  AGC and SIGECO also share equally in the cost of operation and output of the unit.  In January 2013, AGC received an information request from the EPA under Section 114 of the Clean Air Act for historical operational information on the Warrick Power Plant. In April 2013, ALCOA filed a timely response to the information request.
	Ozone NAAQS
	On November 26, 2014, the U.S. 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. The EPA has stated that it intends to finalize the rule by October 2015. Upon finalization, the EPA will then determine whether a particular region is in attainment with the new standard. While it is possible that counties in southwest Indiana could be declared in non-attainment with the new standard, and thus may 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.
	Water
	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.  Costs for compliance with these final regulations should qualify as federally mandated regulatory requirements and be recoverable under Indiana Senate Bill 251 referenced above.
	Under the Clean Water Act, the EPA sets technology-based guidelines for water discharges from new and existing facilities. The EPA is currently in the process of revising the existing steam electric effluent limitation guidelines that set the technology-based water discharge limits for the electric power industry. The EPA is focusing its rulemaking on wastewater generated primarily by pollution control equipment necessitated by the comprehensive air regulations. The EPA released proposed rules on April 19, 2013 however the rule is not yet finalized. At this time, it is not possible to estimate what potential costs may be required to meet these new water discharge limits, however costs for compliance with these regulations should qualify as federally mandated regulatory requirements and be recoverable under Senate Bill 251 referenced above.
	Conclusions Regarding Air and Water Regulations
	To comply with Indiana’s implementation plan of the Clean Air Act, the Company obtained authority from the IURC to invest in clean coal technology.  Using this authorization, the Company invested approximately $411 million starting in 2001 with the last equipment being placed into service on January 1, 2010.  The pollution control equipment included SCR systems, fabric filters, and an SO2 scrubber at its generating facility that is jointly owned with AGC.  SCR technology is the most effective method of reducing NOX emissions where high removal efficiencies are required and fabric filters control particulate matter emissions.  The unamortized portion of the $411 million clean coal technology investment was included in rate base for purposes of determining SIGECO’s electric base rates approved in the latest base rate order obtained April 27, 2011.  SIGECO’s coal-fired generating fleet is 100 percent scrubbed for SO2 and 90 percent controlled for NOX.
	Utilization of the Company’s NOX and SO2 allowances can be impacted as regulations are revised and implemented.  Most of these allowances were granted to the Company at zero cost; therefore, any reduction in carrying value that could result from future changes in regulations would be immaterial.
	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 mercury and air toxin standards effective in 2015 and to address an outstanding Notice of Violation from the EPA.  The total investment is estimated to be between $80 and $90 million, roughly half of which will be made to control mercury in both air and water emissions, and the remaining investment will be made to address the issues raised in the NOV proceeding on the increase in sulfur trioxide emissions.
	Coal Ash Waste Disposal & Ash Ponds
	In June 2010, the EPA issued proposed regulations affecting the management and disposal of coal combustion products, such as ash generated by the Company’s coal-fired power plants.  The proposed rules more stringently regulate these byproducts and would likely increase the cost of operating or expanding existing ash ponds and the development of new ash ponds.  The alternatives include regulating coal combustion by-products that are not being beneficially reused as hazardous waste.  The EPA did not offer a preferred alternative, but took public comment on multiple alternative regulations.
	In December 2014 the U.S. EPA released its final coal ash rule which regulates ash as non-hazardous material under Subtitle D of the Resource Conservation and Recovery Act (RCRA). At this time the final rule has not been published in the Federal Register and as such is not yet effective. Under the final rule the Company will be required to commence an enhanced groundwater monitoring program to determine whether its existing ash ponds must be closed or retrofitted with liners. The final rule allows beneficial reuse of ash and the Company will continue to beneficially reuse a majority of its ash. Legislation is currently being considered by Congress that would provide for enforcement of the federal program by states in lieu of citizen suits.
	The Company originally estimated capital expenditures to comply with the alternatives in the proposal could be as much as $30 million, and such expenditures could exceed $100 million if the most stringent of the alternatives was selected. As the less stringent Subtitle D program was selected by U.S. EPA in the final rule, the Company expects capital expenditures to comply in the lower end of this range.  Annual compliance costs could increase only slightly or be impacted by as much as $5 million.  Costs for compliance with these regulations should qualify as federally mandated regulatory requirements and be recoverable under Senate Bill 251 referenced above.
	Climate Change
	In April 2007, the US Supreme Court determined that greenhouse gases (GHG's) meet the definition of "air pollutant" under the Clean Air Act and ordered the EPA to determine whether GHG emissions cause or contribute to air pollution that may reasonably be anticipated to endanger public health or welfare. The endangerment finding was finalized in December 2009, concluding that carbon emissions pose an endangerment to public health and the environment.
	The EPA has finalized two sets of GHG regulations that apply to the Company’s generating facilities.  In 2009, the EPA finalized a mandatory GHG emissions registry which requires the reporting of emissions.  The EPA has also finalized a revision to the Prevention of Significant Deterioration (PSD) and Title V permitting rules which would require facilities that emit 75,000 tons or more of GHG's a year to obtain a PSD permit for new construction or a significant modification of an existing facility.  The EPA's PSD and Title V permitting rules for GHG's were upheld by the US Court of Appeals for the District of Columbia, and in June 2014 the US Supreme Court upheld the regulations with respect to applicability to major sources such as coal-fired power plants that are required to hold PSD construction and Title V air operating permits for other criteria pollutants.
	While the Company has no plans to invest in new coal-fired generation, there is also a rule making and related legal challenge involving new source performance standards for new construction. This rulemaking must be finalized and withstand legal scrutiny in order for the EPA to implement its proposed new source performance standards for existing units discussed below.
	In July 2013, the President announced a Climate Action Plan, which calls on the EPA to finalize the rule for new construction expeditiously and by June 2015 finalize, New Source Performance Standards (NSPS) for GHG's for existing electric generating units which would apply to the Company's power plants. States must have their implementation plans to the EPA no later than June 2016. On June 2, 2014, the EPA proposed its rule for states to regulate CO2 emissions from existing electric generating units. The rule, when final, will require states to adopt plans that reduce CO2 emissions by 30 percent from 2005 levels by 2030. The EPA provided an extended time frame for public commentary to December 1, 2014. The proposal sets state-specific CO2 emission rate-based CO2 goals (measured in lb CO2/MWh) and guidelines for the development, submission and implementation of state plans to achieve the state goals. These state-specific goals are calculated based upon 2012 average emission rates aggregated for all fossil fuel-based units in the state. For Indiana, the proposal uses a 2012 emission rate of 1,923 lb CO2/MWh, and sets an interim goal of 1,607 lb CO2/MWh and a final emission goal of 1,531 lb CO2/MWh that must be met by 2030. Under this proposal, these CO2 emission rate goals do not apply directly to individual units, or generating systems. They instead are state goals. As such, the state must establish a framework that will guide how compliance will be met on a statewide basis. The state’s interim or “phase in” goal of 1,607 lb CO2/MWh must be met as averaged over a ten-year period (2020 - 2029) with progress toward this goal to be demonstrated for every two rolling calendar years starting in 2020, with the first report due in 2022.
	Under the proposal, all states have unique goals based upon each state’s mix of electric generating assets. The EPA is proposing a 20 percent reduction in Indiana’s total CO2 emission rate compared to 2012. At 20 percent, Indiana’s CO2 emission rate reduction requirement is tied with West Virginia as the 9th lowest reduction requirement. This is due in part to the EPA’s attempt to recognize the existing generating resource mix in the state and take into account each state’s ability to cost effectively lower its CO2 emission rate through a portfolio approach including energy efficiency and renewables, improving power plant heat rates, and dispatching lower emitting fuel sources. Each state’s goals were set by taking 2012 emissions data and applying four “building blocks” of emission rate improvements that the EPA asserts can be achieved by that state. These four building blocks constitute the EPA’s determination of “Best System of Emission Reductions that has been adequately demonstrated,” which defines the EPA’s authority under § 111(d) for existing sources. When applied to each state, the portfolio approach leads to significant differences in requirements across state lines. With the exception of building block number 1 (heat rate improvement of 6 percent), other building blocks are tailored to individual states based upon each state’s existing generating mix and what the EPA concluded a state could reasonably accomplish to reduce its CO2 emission rate. The Company timely filed comments to the Clean Power Plan proposal on December 1, 2014. The state of Indiana also filed public comments, asking that the proposal be withdrawn. Despite having just been recently proposed and not expected to be finalized until summer of 2015, legal challenges to the EPA's proposal have begun. On July 31, 2014, litigation was filed by the state of Indiana and other parties challenging the rules which may delay the timing of approval of the various state plans. That litigation has been set for argument before the U.S. Court of Appeals for the D.C. circuit in April of 2015, with a decision expected later in the summer.
	With respect to the state of Indiana, the four building blocks that support Indiana’s goal are as follows:
	(1) Heat rate (HR) improvements of 6 percent (this is consistently applied to all states).
	(2) Increasing the dispatch of existing natural gas baseload generation sources to 70 percent.
	(3) Renewable energy portfolio requirements of 5 percent (interim) and 7 percent (final).
	(4) Energy efficiency / DSM that results in reductions of 1.5 percent annually starting in 2020, ending at a sustained 11 percent by 2030.
	Under the proposal, Indiana may choose to implement a program based upon an annual average emission rate target or convert that target rate to a comparable CO2 emission cap. 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. Since 2005, the Company’s emissions of CO2 have declined 23 percent (on a tonnage basis). These reductions have come from the retirement of FB Culley Unit 1, expiration of municipal contracts, electric conservation and 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. With respect to CO2 emission rate, since 2005 the Company has lowered its CO2 emission rate (as measured in lbs CO2/MWh) from 1967 lbs CO2/MWh to 1922 lbs CO2/MWh, for a reduction of 3 percent. The Company’s CO2 emission rate of 1922 lbs/MWh is basically the same as the State’s average CO2 emission rate of 1923 lb CO2/MWh.
	Impact of Legislative Actions & Other Initiatives is Unknown
	If the regulations referenced above are finalized by the EPA, or if legislation requiring reductions in CO2 and other GHG's or legislation mandating a renewable energy portfolio standard is adopted, such regulation could substantially affect both the costs and operating characteristics of the Company’s fossil fuel generating plants and natural gas distribution businesses.  At this time and in the absence of final legislation or rulemaking, 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.  As the EPA moves toward finalization of the NSPS for existing sources and the State of Indiana begins formulation of its state implementation plan, the Company will continue to remain engaged with the state to develop a plan for compliance and have more information to enable it to better assess potential compliance costs with a final regulation. Costs to purchase allowances that cap GHG emissions or expenditures made to control emissions or lower carbon emission rates should be considered a federally mandated cost of providing electricity, and as such, the Company believes such costs and expenditures should be recoverable from customers through Senate Bill 251 as referenced above or Senate Bill 29, which was used by the Company to recover its initial pollution control investments.
	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 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 $14.3 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, 2014 and 2013, approximately $3.6 million and $5.7 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, 2014
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,
		2014				2013
	(In millions)	Carrying		Est. Fair		Carrying		Est. Fair
		Amount		Value		Amount		Value
	Long-term debt	$	1,257.30	$	1,408.00	$	1,257.10	$	1,317.40
	Short-term borrowings	156.4		156.4		28.6		28.6
	Cash & cash equivalents	19.3		19.3		8.6		8.6
	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, 2014
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 transmission and 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)	2014			2013			2012
	Revenues
	Gas Utility Services	$	944.6		$	810		$	738.1
	Electric Utility Services	624.8			619.3			594.9
	Other Operations	38.3			38.1			40.1
	Eliminations	(38.0		)	(37.8		)	(39.5		)
	Total revenues	$	1,569.70		$	1,429.60		$	1,333.60
	Profitability Measure - Net Income
	Gas Utility Services	$	57		$	55.7		$	60
	Electric Utility Services	79.7			75.8			68
	Other Operations	11.7			10.3			10
	Total net income	$	148.4		$	141.8		$	138
	Amounts Included in Profitability Measures
	Depreciation & Amortization
	Gas Utility Services	$	93.3		$	90.5		$	85.4
	Electric Utility Services	85.7			84			81.3
	Other Operations	24.1			21.9			23.3
	Total depreciation & amortization	$	203.1		$	196.4		$	190
	Interest Expense
	Gas Utility Services	$	34.9		$	30.6		$	31.8
	Electric Utility Services	29			29.2			33.8
	Other Operations	2.7			5.2			5.9
	Total interest expense	$	66.6		$	65		$	71.5
	Income Taxes
	Gas Utility Services	$	35.7		$	36.6		$	39.1
	Electric Utility Services	48.1			48.3			46.4
	Other Operations	(0.6		)	0.4			(0.2		)
	Total income taxes	$	83.2		$	85.3		$	85.3
	Capital Expenditures
	Gas Utility Services	$	245.9		$	150.5		$	128.8
	Electric Utility Services	92.4			100			108.8
	Other Operations	22.8			25.8			16.2
	Non-cash costs & changes in accruals	(10.1		)	(13.8		)	(6.2		)
	Total capital expenditures	$	351		$	262.5		$	247.6
			At December 31,
	(In millions)		2014			2013			2012
	Assets
	Gas Utility Services		$	2,605.10		$	2,287.90		$	2,173.50
	Electric Utility Services		1,659.30			1,679.00			1,705.10
	Other Operations, net of eliminations		163.7			173.9			168.2
	Total assets		$	4,428.10		$	4,140.80		$	4,046.80

Additional_Balance_Sheet_Opera

Additional Balance Sheet & Operational Information	12 Months Ended
	Dec. 31, 2014
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)	2014		2013
	Gas in storage – at LIFO cost	$	40.5	$	33.2
	Materials & supplies	37.2		39
	Coal & oil for electric generation - at average cost	33.8		16.5
	Other	1.7		1.2
	Total inventories	$	113.2	$	89.9
	Based on the average cost of gas purchased during December, the cost of replacing gas in storage carried at LIFO cost exceeded that carrying value at December 31, 2014 and 2013 by approximately $3 million and $9 million, respectively.
	Prepayments & other current assets in the Consolidated Balance Sheets consist of the following:
		At December 31,
	(In millions)	2014		2013
	Prepaid gas delivery service	$	40.7	$	32.9
	Prepaid taxes	29.5		0.2
	Deferred income taxes	11.3		5.5
	Other prepayments & current assets	2		3.8
	Total prepayments & other current assets	$	83.5	$	42.4
	Other investments in the Consolidated Balance Sheets consist of the following:
		At December 31,
	(In millions)	2014		2013
	Cash surrender value of life insurance policies	$	20.8	$	22.3
	Municipal bond	3.2		3.4
	Restricted cash & other investments	1.6		1.6
	Total other investments	$	25.6	$	27.3
	Accrued liabilities in the Consolidated Balance Sheets consist of the following:
		At December 31,
	(In millions)	2014		2013
	Refunds to customers & customer deposits	$	51.3	$	50.2
	Accrued taxes	33.9		32.3
	Accrued interest	16.1		16.2
	Accrued salaries & other	21		28.7
	Total accrued liabilities	$	122.3	$	127.4
	Asset retirement obligations included in Deferred credits and other liabilities in the Consolidated Balance Sheets roll forward as follows:
	(In millions)	2014		2013
	Asset retirement obligation, January 1	$	29.1	$	27.3
	Accretion	1.7		1.6
	Changes in estimates, net of cash payments	23.8		0.2
	Asset retirement obligation, December 31	$	54.6	$	29.1
	Other – net in the Consolidated Statements of Income consists of the following:
		Year Ended December 31,
	(In millions)	2014		2013		2012
	AFUDC - borrowed funds	$	10.8	$	5.9	$	4.6
	AFUDC - equity funds	3.2		0.8		0.4
	Nonutility plant capitalized interest	0.6		0.4		0.2
	Interest income	0.7		0.6		0.6
	Cash surrender value of life insurance policies	0.6		1.7		1.4
	Other income	0.9		1.1		0.8
	Total other – net	$	16.8	$	10.5	$	8
	Supplemental Cash Flow Information:
		Year Ended December 31,
	(In millions)	2014		2013		2012
	Cash paid (received) for:
	Interest	$	66.7	$	68.2	$	69.6
	Income taxes	63.2		30.9		30.1
	As of December 31, 2014 and 2013, the Company has accruals related to utility and nonutility plant purchases totaling approximately $19.0 million and $13.1 million, respectively.

Subsidiary_Guarantor_and_Conso

Subsidiary Guarantor and Consolidating Information	12 Months Ended
	Dec. 31, 2014
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 $156 million is outstanding at December 31, 2014, and Utility Holdings’ $875 million unsecured senior notes outstanding at December 31, 2014.  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, 2014 (in millions):
		Subsidiary			Parent			Reclassifications and Eliminations			Consolidated
		Guarantors			Company
	OPERATING REVENUES
	Gas utility	$	944.6		$	—		$	—		$	944.6
	Electric utility	624.8			—			—			624.8
	Other	—			38.3			(38.0		)	0.3
	Total operating revenues	1,569.40			38.3			(38.0		)	1,569.70
	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	1,298.30			25.2			(35.2		)	1,288.30
	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			Parent			Reclassifications and Eliminations			Consolidated
		Guarantors			Company
	OPERATING REVENUES
	Gas utility	$	810		$	—		$	—		$	810
	Electric utility	619.3			—			—			619.3
	Other	—			37.9			(37.6		)	0.3
	Total operating revenues	1,429.30			37.9			(37.6		)	1,429.60
	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	1,160.40			22.8			(35.2		)	1,148.00
	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
	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 Statement of Income for the year ended December 31, 2012 (in millions):
		Subsidiary			Parent			Reclassifications and Eliminations			Consolidated
		Guarantors			Company
	OPERATING REVENUES
	Gas utility	$	738.1		$	—		$	—		$	738.1
	Electric utility	594.9			—			—			594.9
	Other	—			40.1			(39.5		)	0.6
	Total operating revenues	1,333.00			40.1			(39.5		)	1,333.60
	OPERATING EXPENSES
	Cost of gas sold	301.3			—			—			301.3
	Cost of fuel & purchased power	192			—			—			192
	Other operating	348.5			0.4			(38.8		)	310.1
	Depreciation & amortization	166.8			22.7			0.5			190
	Taxes other than income taxes	51.7			1.6			0.1			53.4
Total operating expenses	1,060.30			24.7			(38.2		)	1,046.80
OPERATING INCOME	272.7			15.4			(1.3		)	286.8
OTHER INCOME (EXPENSE)
Equity in earnings of consolidated companies	—			127.9			(127.9		)	—
Other – net	6.2			41.4			(39.6		)	8
Total other income (expense)	6.2			169.3			(167.5		)	8
Interest expense	65.6			46.8			(40.9		)	71.5
INCOME BEFORE INCOME TAXES	213.3			137.9			(127.9		)	223.3
Income taxes	85.4			(0.1		)	—			85.3
NET INCOME	$	127.9		$	138		$	(127.9	)	$	138
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			—			—			113
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			38.1			(49.4		)	83.5
Total current assets	460.9			237.2			(236.9		)	461.2
Utility Plant
Original cost	5,718.70			—			—			5,718.70
Less:  accumulated depreciation & amortization	2,279.70			—			—			2,279.70
Net utility plant	3,439.00			—			—			3,439.00
Investments in consolidated subsidiaries	—			1,416.90			(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			—			—			205
Regulatory assets	106.7			21.6			—			128.3
Other assets	29.4			1.7			(11.5		)	19.6
TOTAL ASSETS	$	4,264.30		$	2,575.60		$	(2,411.8	)	$	4,428.10
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	136.7			35			(49.4		)	122.3
Short-term borrowings	—			156.4			—			156.4
Intercompany short-term borrowings	97			—			(97.0		)	—
Current maturities of long-term debt	20			75			—			95
Current maturities of long-term debt due to VUHI	74.1			—			(74.1		)	—
Total current liabilities	548.2			271.4			(236.9		)	582.7
Long-Term Debt
Long-term debt - net of current maturities &
debt subject to tender	362.6			799.7			—			1,162.30
Long-term debt due to VUHI	746.5			—			(746.5		)	—
Total long-term debt - net	1,109.10			799.7			(746.5		)	1,162.30
Deferred Income Taxes & Other Liabilities
Deferred income taxes	665.8			19.3			—			685.1
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	1,190.10			26			(11.5		)	1,204.60
Common Shareholder's Equity
Common stock (no par value)	806.9			793.7			(806.9		)	793.7
Retained earnings	610			684.8			(610.0		)	684.8
Total common shareholder's equity	1,416.90			1,478.50			(1,416.9		)	1,478.50
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	$	4,264.30		$	2,575.60		$	(2,411.8	)	$	4,428.10
Consolidating Balance Sheet as of December 31, 2013 (in millions):
ASSETS	Subsidiary			Parent
	Guarantors			Company			Eliminations			Consolidated
Current Assets
Cash & cash equivalents	$	8.2		$	0.4		$	—		$	8.6
Accounts receivable - less reserves	112.1			—			—			112.1
Intercompany receivables	0.3			84.8			(85.1		)	—
Accrued unbilled revenues	113.5			—			—			113.5
Inventories	89.9			—			—			89.9
Recoverable fuel & natural gas costs	5.5			—			—			5.5
Prepayments & other current assets	37.3			40.1			(35.0		)	42.4
Total current assets	366.8			125.3			(120.1		)	372
Utility Plant
Original cost	5,389.60			—			—			5,389.60
Less:  accumulated depreciation & amortization	2,165.30			—			—			2,165.30
Net utility plant	3,224.30			—			—			3,224.30
Investments in consolidated subsidiaries	—			1,375.80			(1,375.8		)	—
Notes receivable from consolidated subsidiaries	—			696.4			(696.4		)	—
Investments in unconsolidated affiliates	0.2			—			—			0.2
Other investments	22.8			4.5			—			27.3
Nonutility plant - net	2.2			148.3			—			150.5
Goodwill - net	205			—			—			205
Regulatory assets	113.4			22.8			—			136.2
Other assets	32.2			1			(7.9		)	25.3
TOTAL ASSETS	$	3,966.90		$	2,374.10		$	(2,200.2	)	$	4,140.80
LIABILITIES & SHAREHOLDER'S EQUITY	Subsidiary			Parent
	Guarantors			Company			Eliminations			Consolidated
Current Liabilities
Accounts payable	$	161.6		$	10.5		$	—		$	172.1
Intercompany payables	11.7			—			(11.7		)	—
Payables to other Vectren companies	24.6			—			—			24.6
Accrued liabilities	150.3			12.1			(35.0		)	127.4
Short-term borrowings	—			28.6			—			28.6
Intercompany short-term borrowings	73.1			0.3			(73.4		)	—
Total current liabilities	421.3			51.5			(120.1		)	352.7
Long-Term Debt
Long-term debt - net of current maturities &
debt subject to tender	382.5			874.6			—			1,257.10
Long-term debt due to VUHI	696.4			—			(696.4		)	—
Total long-term debt - net	1,078.90			874.6			(696.4		)	1,257.10
Deferred Income Taxes & Other Liabilities
Deferred income taxes	616.9			10.5			—			627.4
Regulatory liabilities	385.7			1.6			—			387.3
Deferred credits & other liabilities	88.3			3.1			(7.9		)	83.5
Total deferred credits & other liabilities	1,090.90			15.2			(7.9		)	1,098.20
Common Shareholder's Equity
Common stock (no par value)	800.9			787.7			(800.9		)	787.7
Retained earnings	574.9			645.1			(574.9		)	645.1
Total common shareholder's equity	1,375.80			1,432.80			(1,375.8		)	1,432.80
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	$	3,966.90		$	2,374.10		$	(2,200.2	)	$	4,140.80
Consolidating Statement of Cash Flows for the year ended December 31, 2014 (in millions):
	Subsidiary			Parent			Eliminations			Consolidated
	Guarantors			Company
NET CASH FLOWS FROM OPERATING ACTIVITIES	$	274.4		$	63.1		$	—		$	337.5
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from:
Additional capital contribution from Parent	6			6			(6.0		)	6
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, including premiums paid	(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 flows from 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			—
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 flows from investing activities	(327.0		)	(75.9		)	52.2			(350.7		)
Net change in cash & cash equivalents	(1.3		)	12			—			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			Parent			Eliminations			Consolidated
	Guarantors			Company
NET CASH FLOWS FROM OPERATING ACTIVITIES	$	371		$	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 flows from 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 flows from 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
Consolidating Statement of Cash Flows for the year ended December 31, 2012 (in millions):
	Subsidiary			Parent			Eliminations			Consolidated
	Guarantors			Company
NET CASH FLOWS FROM OPERATING ACTIVITIES	$	335.6		$	37.8		$	—		$	373.4
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from:
Additional capital contribution from Parent	—			7			—			7
Long-term debt - net of issuance costs	—			99.5			—			99.5
Requirements for dividends to parent	(70.9		)	(101.5		)	70.9			(101.5		)
Net change in intercompany short-term borrowings	(24.0		)	—			24			—
Net change in short-term borrowings	—			(126.1		)	—			(126.1		)
Net cash flows from financing activities	(94.9		)	(121.1		)	94.9			(121.1		)
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from:
Consolidated subsidiary distributions	—			70.9			(70.9		)	—
Other investing activities	0.3			2.3			—			2.6
Requirements for capital expenditures, excluding AFUDC equity	(233.8		)	(13.8		)	—			(247.6		)
Net change in short-term intercompany notes receivable	—			24			(24.0		)	—
Net cash flows from investing activities	(233.5		)	83.4			(94.9		)	(245.0		)
Net change in cash & cash equivalents	7.2			0.1			—			7.3
Cash & cash equivalents at beginning of period	5.3			0.7			—			6
Cash & cash equivalents at end of period	$	12.5		$	0.8		$	—		$	13.3

Impact_of_Recently_Issued_Acco

Impact of Recently Issued Accounting Guidance	12 Months Ended
	Dec. 31, 2014
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. For a public entity, the guidance is effective for annual reporting periods beginning after December 15, 2016, with early adoption not permitted. An entity should apply the amendments in this update retrospectively to each prior reporting period presented or retrospectively with the cumulative effect of initially applying this update recognized at the date of initial application. The Company is currently evaluating the standard to understand the overall impact it 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 about discontinued operations 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 did not early adopt this guidance in accounting for the sale of its Coal Mining assets. The Company is currently evaluating the impact of this guidance, if any.
	Financial Reporting of Going Concern
	In August 2014, the FASB issued new accounting guidance with respect to reporting on an entity's ability to continue as a going concern. This new guidance requires management to assess an entity's ability to continue as a going concern by incorporating and expanding upon certain principles that are currently in U.S. auditing standards, which requires disclosure surrounding what constitutes substantial doubt for the entity, including disclosure of management's plans to mitigate and alleviate substantial doubt. This guidance is effective for annual periods beginning after December 15, 2016, and for annual and interim periods thereafter, with early application permitted. Adoption of this guidance will not have a material impact on the Company’s financial statements.

Quarterly_Financial_Data_Unaud

Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2014
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 2014 and 2013 follows:
	(In millions)		Q1		Q2		Q3		Q4
	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
	2013
		Results of Operations:
		Operating revenues	$	465.5	$	292.8	$	267.7	$	403.6
		Operating income	105.4		51.2		54.5		70.5
		Net income	55.1		24.2		25.3		37.2

SCHEDULE_II_VALUATION_AND_QUAL

SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES	12 Months Ended
	Dec. 31, 2014
Valuation and Qualifying Accounts [Abstract]
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES	Supplemental Schedules
	For the years ended December 31, 2014, 2013, and 2012, 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 2014 – Accumulated provision for
	uncollectible accounts	$	5	$	6.1	$	—	$	7.2	$	3.9
	Year 2013 – Accumulated provision for
	uncollectible accounts	$	5	$	6.5	$	—	$	6.5	$	5
	Year 2012 – Accumulated provision for
	uncollectible accounts	$	5.9	$	7.4	$	—	$	8.3	$	5
	OTHER RESERVES:
	Year 2014 – Restructuring costs	$	0.2	$	—	$	—	$	0.2	$	—
	Year 2013 – Restructuring costs	$	0.3	$	—	$	—	$	0.1	$	0.2
	Year 2012 – Restructuring costs	$	0.4	$	—	$	—	$	0.1	$	0.3

Summary_of_Significant_Account1

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2014
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 significant 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 is recorded using the Last In – First Out (LIFO) method.  Inventory is valued at historical cost consistent with ratemaking treatment.  Materials and supplies are recorded as inventory when purchased and subsequently charged to expense or capitalized to plant when installed.
Property, Plant 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.  There were no impairments related to property, plant and equipment during the periods presented.
Goodwill	Goodwill
	Goodwill recorded on the Consolidated Balance Sheets results from business acquisitions in the Gas Utility Services operating segment 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 that test 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 probable future revenues associated with certain incurred costs, which will be recovered 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 other 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 exempted 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 the accounting period in Accrued Unbilled Revenues.
MISO Transactions	MISO Transactions
	With the IURC’s approval, the Company is a member of the MISO, a FERC approved regional transmission organization.  The MISO serves the electrical transmission needs of much of the Midcontinent region and maintains operational control over the Company’s electric transmission facilities as well as that of other utilities in the region.  The Company is an active participant in the MISO energy markets, bidding its owned generation into the Day Ahead and Real Time markets and procuring power for its retail customers at Locational Marginal Pricing (LMP) as determined by the MISO market.
	MISO-related purchase and sale transactions are recorded using settlement information provided by 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 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 $32.3 million in 2014, $29.6 million in 2013, and $26.9 million in 2012.  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/or 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’s 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_Table

Utility & Nonutility Plant (Tables)	12 Months Ended
	Dec. 31, 2014
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)	2014				2013
		Original Cost		Depreciation		Original Cost		Depreciation
				Rates as a				Rates as a
				Percent of				Percent of
				Original Cost				Original Cost
	Gas utility plant	$	3,011.00	3.4	%	$	2,762.20	3.5	%
	Electric utility plant	2,602.50		3.3	%	2,519.80		3.3	%
	Common utility plant	54.3		3.2	%	53.4		3	%
	Construction work in progress	50.9		—		54.2		—
	Total original cost	$	5,718.70			$	5,389.60
Nonutility Plant, Net of Depreciation and Amortization	Nonutility Plant, net of accumulated depreciation and amortization follows:
		At December 31,
	(In millions)	2014		2013
	Computer hardware & software	$	105	$	102.3
	Land & buildings	35.8		38.3
	All other	8.4		9.9
	Nonutility plant - net	$	149.2	$	150.5

Regulatory_Assets_Liabilities_

Regulatory Assets & Liabilities (Tables)	12 Months Ended
	Dec. 31, 2014
Regulatory Assets and Liabilities Disclosure [Abstract]
Schedule of Regulatory Assets	Regulatory assets consist of the following:
		At December 31,
	(In millions)	2014			2013
	Future amounts recoverable from ratepayers related to:
	Net deferred income taxes (See Note 5)	$	(14.8	)	$	(5.8	)
	Asset retirement obligations & other	—			2.3
		(14.8		)	(3.5		)
	Amounts deferred for future recovery related to:
	Deferred coal costs (See Note 10)	—			42.4
	Cost recovery riders & other	33.3			18.6
		33.3			61
	Amounts currently recovered in customer rates related to:
	Unamortized debt issue costs & hedging proceeds	33.5			34.6
	Demand side management programs	0.6			2.5
	Deferred coal costs (See Note 10)	35.3			—
	Indiana authorized trackers	25.6			30.8
	Ohio authorized trackers	12.7			7.9
	Premiums paid to reacquire debt	1.7			2.2
	Other base rate recoveries	0.4			0.7
		109.8			78.7
	Total regulatory assets	$	128.3		$	136.2

Transactions_with_Other_Vectre1

Transactions with Other Vectren Companies and Affiliates Transactions with other Vectren Companies and Affiliates (Tables)	12 Months Ended
	Dec. 31, 2014
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)	2014				2013				2012
	Current:
	Federal	$	16.6			$	48			$	6.1
	State	10.9				11				6.9
	Total current taxes	27.5				59				13
	Deferred:
	Federal	57.8				26.8				68.7
	State	(1.6		)		0.1				4.2
	Total deferred taxes	56.2				26.9				72.9
	Amortization of investment tax credits	(0.5		)		(0.6		)		(0.6		)
	Total income tax expense	$	83.2			$	85.3			$	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,
		2014			2013			2012
	Statutory rate	35	%		35	%		35	%
	State and local taxes-net of federal benefit	3.3			3.5			3.7
	Amortization of investment tax credit	(0.2	)		(0.3	)		(0.3	)
	Domestic Production Deduction	(0.9	)		—			—
	Adjustment of income tax accruals	(0.9	)		—			—
	All other - net	(0.4	)		(0.6	)		(0.2	)
	Effective tax rate	35.9	%		37.6	%		38.2	%
Significant components of the net deferred tax liability (assets)	Significant components of the net deferred tax liability follow:
		At December 31,
	(In millions)	2014				2013
	Noncurrent deferred tax liabilities (assets):
	Depreciation & cost recovery timing differences	$	685			$	627.9
	Regulatory assets recoverable through future rates	29.2				22.8
	Alternative minimum tax carryforward	(13.3		)		(18.5		)
	Employee benefit obligations	1				5.2
	Regulatory liabilities to be settled through future rates	(27.5		)		(18.7		)
	Other – net	10.7				8.7
	Net noncurrent deferred tax liability	685.1				627.4
	Current deferred tax liabilities (assets):
	Deferred fuel costs - net	22				22.9
	Alternative minimum tax carryforward	(38.1		)		(36.4		)
	General business credit carryforwards	—				(1.2		)
	Other – net	4.8				9.2
	Net current deferred tax liability (asset)	(11.3		)		(5.5		)
	Net deferred tax liability	$	673.8			$	621.9
Roll forward of unrecognized tax benefits	ollowing is a roll forward of the total amount of unrecognized tax benefits for the three years ended December 31, 2014:
	(In millions)	2014				2013				2012
	Unrecognized tax benefits at January 1	$	4.7			$	3.7			$	11
	Gross increases - tax positions in prior periods	—				—				0.1
	Gross decreases - tax positions in prior periods	(4.7		)		(0.2		)		(9.3		)
	Gross increases - current period tax positions	—				1.2				1.9
	Settlements	—				—				—
	Unrecognized tax benefits at December 31	$	—			$	4.7			$	3.7

Borrowing_Arrangements_Tables

Borrowing Arrangements (Tables)	12 Months Ended
	Dec. 31, 2014
Debt Disclosure [Abstract]
Short term borrowing arrangements	Following is certain information regarding these short-term borrowing arrangements:
	(In millions)		2014				2013			2012
	Year End
	Balance Outstanding		$	156.4			$	28.6		$	116.7
	Weighted Average Interest Rate		0.5		%		0.29		%	0.4		%
	Annual Average
	Balance Outstanding		$	35.6			$	119.6		$	77.6
	Weighted Average Interest Rate		0.34		%		0.34		%	0.47		%
	Maximum Month End Balance Outstanding		$	156.4			$	176.1		$	214.2
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)	2014				2013
	Utility Holdings
	Fixed Rate Senior Unsecured Notes
	2015, 5.45%	75				75
	2018, 5.75%	100				100
	2020, 6.28%	100				100
	2021, 4.67%	55				55
	2023, 3.72%	150				150
	2026, 5.02%	60				60
	2028, 3.20%	45				45
	2035, 6.10%	75				75
	2041, 5.99%	35				35
	2042, 5.00%	100				100
	2043, 4.25%	80				80
	Total Utility Holdings	875				875
	SIGECO
	First Mortgage Bonds
	2015, 1985 Pollution Control Series A, current adjustable rate 0.05%, tax exempt,
	2013 weighted average: 0.10%	—				9.8
	2016, 1986 Series, 8.875%	13				13
	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, 1998 Pollution Control Series A, current adjustable rate 0.05%, tax exempt,
	2013 weighted average: 0.10%	—				31.5
	2025, 2014 Series B, current adjustable rate 0.722%, tax-exempt	41.3				—
	2029, 1999 Series, 6.72%	80				80
	2037, 2013 Series E, 1.95%, tax exempt	22				22
	2038, 2013 Series A, 4.0%, tax exempt	22.2				22.2
	2040, 2009 Environmental Improvement Series, 5.40%, tax exempt	—				22.3
	2043, 2013 Series B, 4.05%, tax exempt	39.6				39.6
	2044, 2014 Series A, 4.00%, tax exempt	22.3				—
	Total SIGECO	267.5				267.5
	Indiana Gas
	Senior Unsecured Notes
	2015, Series E, 7.15%	5				5
	2015, Series E, 6.69%	5				5
	2015, Series E, 6.69%	10				10
	2025, Series E, 6.53%	10				10
	2027, Series E, 6.42%	5				5
	2027, Series E, 6.68%	1				1
	2027, Series F, 6.34%	20				20
	2028, Series F, 6.36%	10				10
	2028, Series F, 6.55%	20				20
	2029, Series G, 7.08%	30				30
	Total Indiana Gas	116				116
	Total long-term debt outstanding	1,258.50				1,258.50
	Current maturities of long-term debt	(95.0		)		—
	Unamortized debt premium & discount - net	(1.2		)		(1.4		)
	Total long-term debt-net	$	1,162.30			$	1,257.10

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2014
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,
		2014				2013
	(In millions)	Carrying		Est. Fair		Carrying		Est. Fair
		Amount		Value		Amount		Value
	Long-term debt	$	1,257.30	$	1,408.00	$	1,257.10	$	1,317.40
	Short-term borrowings	156.4		156.4		28.6		28.6
	Cash & cash equivalents	19.3		19.3		8.6		8.6

Segment_Reporting_Tables

Segment Reporting (Tables)	12 Months Ended
	Dec. 31, 2014
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)	2014			2013			2012
	Revenues
	Gas Utility Services	$	944.6		$	810		$	738.1
	Electric Utility Services	624.8			619.3			594.9
	Other Operations	38.3			38.1			40.1
	Eliminations	(38.0		)	(37.8		)	(39.5		)
	Total revenues	$	1,569.70		$	1,429.60		$	1,333.60
	Profitability Measure - Net Income
	Gas Utility Services	$	57		$	55.7		$	60
	Electric Utility Services	79.7			75.8			68
	Other Operations	11.7			10.3			10
	Total net income	$	148.4		$	141.8		$	138
	Amounts Included in Profitability Measures
	Depreciation & Amortization
	Gas Utility Services	$	93.3		$	90.5		$	85.4
	Electric Utility Services	85.7			84			81.3
	Other Operations	24.1			21.9			23.3
	Total depreciation & amortization	$	203.1		$	196.4		$	190
	Interest Expense
	Gas Utility Services	$	34.9		$	30.6		$	31.8
	Electric Utility Services	29			29.2			33.8
	Other Operations	2.7			5.2			5.9
	Total interest expense	$	66.6		$	65		$	71.5
	Income Taxes
	Gas Utility Services	$	35.7		$	36.6		$	39.1
	Electric Utility Services	48.1			48.3			46.4
	Other Operations	(0.6		)	0.4			(0.2		)
	Total income taxes	$	83.2		$	85.3		$	85.3
	Capital Expenditures
	Gas Utility Services	$	245.9		$	150.5		$	128.8
	Electric Utility Services	92.4			100			108.8
	Other Operations	22.8			25.8			16.2
	Non-cash costs & changes in accruals	(10.1		)	(13.8		)	(6.2		)
	Total capital expenditures	$	351		$	262.5		$	247.6
			At December 31,
	(In millions)		2014			2013			2012
	Assets
	Gas Utility Services		$	2,605.10		$	2,287.90		$	2,173.50
	Electric Utility Services		1,659.30			1,679.00			1,705.10
	Other Operations, net of eliminations		163.7			173.9			168.2
	Total assets		$	4,428.10		$	4,140.80		$	4,046.80

Additional_Balance_Sheet_Opera1

Additional Balance Sheet & Operational Information (Tables)	12 Months Ended
	Dec. 31, 2014
Additional Balance Sheet and Operational Information [Abstract]
Summary of inventories	Inventories consist of the following:
		At December 31,
	(In millions)	2014		2013
	Gas in storage – at LIFO cost	$	40.5	$	33.2
	Materials & supplies	37.2		39
	Coal & oil for electric generation - at average cost	33.8		16.5
	Other	1.7		1.2
	Total inventories	$	113.2	$	89.9
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)	2014		2013
	Prepaid gas delivery service	$	40.7	$	32.9
	Prepaid taxes	29.5		0.2
	Deferred income taxes	11.3		5.5
	Other prepayments & current assets	2		3.8
	Total prepayments & other current assets	$	83.5	$	42.4
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)	2014		2013
	Cash surrender value of life insurance policies	$	20.8	$	22.3
	Municipal bond	3.2		3.4
	Restricted cash & other investments	1.6		1.6
	Total other investments	$	25.6	$	27.3
Accrued Liabilities	Accrued liabilities in the Consolidated Balance Sheets consist of the following:
		At December 31,
	(In millions)	2014		2013
	Refunds to customers & customer deposits	$	51.3	$	50.2
	Accrued taxes	33.9		32.3
	Accrued interest	16.1		16.2
	Accrued salaries & other	21		28.7
	Total accrued liabilities	$	122.3	$	127.4
Asset retirement obligation	Asset retirement obligations included in Deferred credits and other liabilities in the Consolidated Balance Sheets roll forward as follows:
	(In millions)	2014		2013
	Asset retirement obligation, January 1	$	29.1	$	27.3
	Accretion	1.7		1.6
	Changes in estimates, net of cash payments	23.8		0.2
	Asset retirement obligation, December 31	$	54.6	$	29.1
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)	2014		2013		2012
	AFUDC - borrowed funds	$	10.8	$	5.9	$	4.6
	AFUDC - equity funds	3.2		0.8		0.4
	Nonutility plant capitalized interest	0.6		0.4		0.2
	Interest income	0.7		0.6		0.6
	Cash surrender value of life insurance policies	0.6		1.7		1.4
	Other income	0.9		1.1		0.8
	Total other – net	$	16.8	$	10.5	$	8
Supplemental cash flow information	Supplemental Cash Flow Information:
		Year Ended December 31,
	(In millions)	2014		2013		2012
	Cash paid (received) for:
	Interest	$	66.7	$	68.2	$	69.6
	Income taxes	63.2		30.9		30.1

Subsidiary_Guarantor_and_Conso1

Subsidiary Guarantor and Consolidating Information Subsidiary Guarantor and Consolidating Information(Tables)	12 Months Ended
	Dec. 31, 2014
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, 2014 (in millions):
		Subsidiary			Parent			Reclassifications and Eliminations			Consolidated
		Guarantors			Company
	OPERATING REVENUES
	Gas utility	$	944.6		$	—		$	—		$	944.6
	Electric utility	624.8			—			—			624.8
	Other	—			38.3			(38.0		)	0.3
	Total operating revenues	1,569.40			38.3			(38.0		)	1,569.70
	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	1,298.30			25.2			(35.2		)	1,288.30
	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			Parent			Reclassifications and Eliminations			Consolidated
		Guarantors			Company
	OPERATING REVENUES
	Gas utility	$	810		$	—		$	—		$	810
	Electric utility	619.3			—			—			619.3
	Other	—			37.9			(37.6		)	0.3
	Total operating revenues	1,429.30			37.9			(37.6		)	1,429.60
	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	1,160.40			22.8			(35.2		)	1,148.00
	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
	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 Statement of Income for the year ended December 31, 2012 (in millions):
		Subsidiary			Parent			Reclassifications and Eliminations			Consolidated
		Guarantors			Company
	OPERATING REVENUES
	Gas utility	$	738.1		$	—		$	—		$	738.1
	Electric utility	594.9			—			—			594.9
	Other	—			40.1			(39.5		)	0.6
	Total operating revenues	1,333.00			40.1			(39.5		)	1,333.60
	OPERATING EXPENSES
	Cost of gas sold	301.3			—			—			301.3
	Cost of fuel & purchased power	192			—			—			192
	Other operating	348.5			0.4			(38.8		)	310.1
	Depreciation & amortization	166.8			22.7			0.5			190
	Taxes other than income taxes	51.7			1.6			0.1			53.4
	Total operating expenses	1,060.30			24.7			(38.2		)	1,046.80
	OPERATING INCOME	272.7			15.4			(1.3		)	286.8
OTHER INCOME (EXPENSE)
Equity in earnings of consolidated companies	—			127.9			(127.9		)	—
Other – net	6.2			41.4			(39.6		)	8
Total other income (expense)	6.2			169.3			(167.5		)	8
Interest expense	65.6			46.8			(40.9		)	71.5
INCOME BEFORE INCOME TAXES	213.3			137.9			(127.9		)	223.3
Income taxes	85.4			(0.1		)	—			85.3
NET INCOME	$	127.9		$	138		$	(127.9	)	$	138
Condensed consolidating balance sheets [Table Text Block]	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			—			—			113
	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			38.1			(49.4		)	83.5
	Total current assets	460.9			237.2			(236.9		)	461.2
	Utility Plant
	Original cost	5,718.70			—			—			5,718.70
	Less:  accumulated depreciation & amortization	2,279.70			—			—			2,279.70
	Net utility plant	3,439.00			—			—			3,439.00
	Investments in consolidated subsidiaries	—			1,416.90			(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			—			—			205
	Regulatory assets	106.7			21.6			—			128.3
	Other assets	29.4			1.7			(11.5		)	19.6
	TOTAL ASSETS	$	4,264.30		$	2,575.60		$	(2,411.8	)	$	4,428.10
	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	136.7			35			(49.4		)	122.3
	Short-term borrowings	—			156.4			—			156.4
	Intercompany short-term borrowings	97			—			(97.0		)	—
	Current maturities of long-term debt	20			75			—			95
	Current maturities of long-term debt due to VUHI	74.1			—			(74.1		)	—
	Total current liabilities	548.2			271.4			(236.9		)	582.7
	Long-Term Debt
	Long-term debt - net of current maturities &
	debt subject to tender	362.6			799.7			—			1,162.30
	Long-term debt due to VUHI	746.5			—			(746.5		)	—
	Total long-term debt - net	1,109.10			799.7			(746.5		)	1,162.30
	Deferred Income Taxes & Other Liabilities
	Deferred income taxes	665.8			19.3			—			685.1
	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	1,190.10			26			(11.5		)	1,204.60
	Common Shareholder's Equity
	Common stock (no par value)	806.9			793.7			(806.9		)	793.7
	Retained earnings	610			684.8			(610.0		)	684.8
	Total common shareholder's equity	1,416.90			1,478.50			(1,416.9		)	1,478.50
	TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	$	4,264.30		$	2,575.60		$	(2,411.8	)	$	4,428.10
	Consolidating Balance Sheet as of December 31, 2013 (in millions):
	ASSETS	Subsidiary			Parent
		Guarantors			Company			Eliminations			Consolidated
	Current Assets
	Cash & cash equivalents	$	8.2		$	0.4		$	—		$	8.6
	Accounts receivable - less reserves	112.1			—			—			112.1
	Intercompany receivables	0.3			84.8			(85.1		)	—
	Accrued unbilled revenues	113.5			—			—			113.5
	Inventories	89.9			—			—			89.9
	Recoverable fuel & natural gas costs	5.5			—			—			5.5
	Prepayments & other current assets	37.3			40.1			(35.0		)	42.4
	Total current assets	366.8			125.3			(120.1		)	372
Utility Plant
Original cost	5,389.60			—			—			5,389.60
Less:  accumulated depreciation & amortization	2,165.30			—			—			2,165.30
Net utility plant	3,224.30			—			—			3,224.30
Investments in consolidated subsidiaries	—			1,375.80			(1,375.8		)	—
Notes receivable from consolidated subsidiaries	—			696.4			(696.4		)	—
Investments in unconsolidated affiliates	0.2			—			—			0.2
Other investments	22.8			4.5			—			27.3
Nonutility plant - net	2.2			148.3			—			150.5
Goodwill - net	205			—			—			205
Regulatory assets	113.4			22.8			—			136.2
Other assets	32.2			1			(7.9		)	25.3
TOTAL ASSETS	$	3,966.90		$	2,374.10		$	(2,200.2	)	$	4,140.80
LIABILITIES & SHAREHOLDER'S EQUITY	Subsidiary			Parent
	Guarantors			Company			Eliminations			Consolidated
Current Liabilities
Accounts payable	$	161.6		$	10.5		$	—		$	172.1
Intercompany payables	11.7			—			(11.7		)	—
Payables to other Vectren companies	24.6			—			—			24.6
Accrued liabilities	150.3			12.1			(35.0		)	127.4
Short-term borrowings	—			28.6			—			28.6
Intercompany short-term borrowings	73.1			0.3			(73.4		)	—
Total current liabilities	421.3			51.5			(120.1		)	352.7
Long-Term Debt
Long-term debt - net of current maturities &
debt subject to tender	382.5			874.6			—			1,257.10
Long-term debt due to VUHI	696.4			—			(696.4		)	—
Total long-term debt - net	1,078.90			874.6			(696.4		)	1,257.10
Deferred Income Taxes & Other Liabilities
Deferred income taxes	616.9			10.5			—			627.4
Regulatory liabilities	385.7			1.6			—			387.3
Deferred credits & other liabilities	88.3			3.1			(7.9		)	83.5
Total deferred credits & other liabilities	1,090.90			15.2			(7.9		)	1,098.20
Common Shareholder's Equity
Common stock (no par value)	800.9			787.7			(800.9		)	787.7
Retained earnings	574.9			645.1			(574.9		)	645.1
Total common shareholder's equity	1,375.80			1,432.80			(1,375.8		)	1,432.80
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	$	3,966.90		$	2,374.10		$	(2,200.2	)	$	4,140.80
Condensed consolidating statements of cash flows [Table Text Block]	Consolidating Statement of Cash Flows for the year ended December 31, 2014 (in millions):
		Subsidiary			Parent			Eliminations			Consolidated
		Guarantors			Company
	NET CASH FLOWS FROM OPERATING ACTIVITIES	$	274.4		$	63.1		$	—		$	337.5
	CASH FLOWS FROM FINANCING ACTIVITIES
	Proceeds from:
	Additional capital contribution from Parent	6			6			(6.0		)	6
	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, including premiums paid	(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 flows from 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			—
	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 flows from investing activities	(327.0		)	(75.9		)	52.2			(350.7		)
	Net change in cash & cash equivalents	(1.3		)	12			—			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			Parent			Eliminations			Consolidated
		Guarantors			Company
	NET CASH FLOWS FROM OPERATING ACTIVITIES	$	371		$	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 flows from 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 flows from 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
	Consolidating Statement of Cash Flows for the year ended December 31, 2012 (in millions):
		Subsidiary			Parent			Eliminations			Consolidated
		Guarantors			Company
	NET CASH FLOWS FROM OPERATING ACTIVITIES	$	335.6		$	37.8		$	—		$	373.4
	CASH FLOWS FROM FINANCING ACTIVITIES
	Proceeds from:
	Additional capital contribution from Parent	—			7			—			7
	Long-term debt - net of issuance costs	—			99.5			—			99.5
	Requirements for dividends to parent	(70.9		)	(101.5		)	70.9			(101.5		)
	Net change in intercompany short-term borrowings	(24.0		)	—			24			—
Net change in short-term borrowings	—			(126.1		)	—			(126.1		)
Net cash flows from financing activities	(94.9		)	(121.1		)	94.9			(121.1		)
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from:
Consolidated subsidiary distributions	—			70.9			(70.9		)	—
Other investing activities	0.3			2.3			—			2.6
Requirements for capital expenditures, excluding AFUDC equity	(233.8		)	(13.8		)	—			(247.6		)
Net change in short-term intercompany notes receivable	—			24			(24.0		)	—
Net cash flows from investing activities	(233.5		)	83.4			(94.9		)	(245.0		)
Net change in cash & cash equivalents	7.2			0.1			—			7.3
Cash & cash equivalents at beginning of period	5.3			0.7			—			6
Cash & cash equivalents at end of period	$	12.5		$	0.8		$	—		$	13.3

Quarterly_Financial_Data_Unaud1

Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2014
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 2014 and 2013 follows:
	(In millions)		Q1		Q2		Q3		Q4
	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
	2013
		Results of Operations:
		Operating revenues	$	465.5	$	292.8	$	267.7	$	403.6
		Operating income	105.4		51.2		54.5		70.5
		Net income	55.1		24.2		25.3		37.2

Organization_and_Nature_of_Ope1

Organization and Nature of Operations (Details)	12 Months Ended
	Dec. 31, 2014
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)	575,000
Estimated number of electric customers located near Evansville in southwestern Indiana serviced by Southern Indiana Gas and Electric Company (in number of customers)	143,000
Estimated number of natural gas customers located near Evansville in southwestern Indiana serviced by Southern Indiana Gas and Electric Company (in number of customers)	110,000
Estimated number of natural gas customers located near Dayton in west central Ohio serviced by the Ohio operations (in number of customers)	313,000

Summary_of_Significant_Account2

Summary of Significant Accounting Policies (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Accounting Policies [Abstract]
Excise taxes and a portion of utility receipts taxes	$32.30	$29.60	$26.90

Utility_Nonutility_Plant_Detai

Utility & Nonutility Plant (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Utility & Nonutility Plant
Original Cost	$5,718.70	$5,389.60
Cost of Non-Utility plant, net of depreciation and amortization	149.2	150.5
Utility Group [Member]
Utility & Nonutility Plant
Original Cost	5,718.70	5,389.60
Utility Group [Member] | Gas Utility Plant [Member]
Utility & Nonutility Plant
Original Cost	3,011	2,762.20
Depreciation Rates as a Percent of Original Cost (in hundredths)	3.40%	3.50%
Utility Group [Member] | Electric Utility Plant [Member]
Utility & Nonutility Plant
Original Cost	2,602.50	2,519.80
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	54.3	53.4
Depreciation Rates as a Percent of Original Cost (in hundredths)	3.20%	3.00%
Utility Group [Member] | Construction Work in Progress [Member]
Utility & Nonutility Plant
Original Cost	50.9	54.2
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)	300
Utility Group [Member] | SIGECO [Member]
Utility & Nonutility Plant
Southern Indiana Gas And Electric Company's Share Of Cost Of Unit 4	188
Southern Indiana Gas And Electric Company's Share Of Accumulated Depreciation Of Unit 4	93.5
Nonutility Group [Member]
Utility & Nonutility Plant
Cost of Non-Utility plant, net of depreciation and amortization	149.2	150.5
Nonutility plant accumulated depreciation and amortization	226.7	209.2
Capitalized interest on nonutility plant construction projects	0.6	0.4	0.2
Nonutility Group [Member] | Computer Hardware and Software [Member]
Utility & Nonutility Plant
Cost of Non-Utility plant, net of depreciation and amortization	105	102.3
Nonutility Group [Member] | Land and Buildings [Member]
Utility & Nonutility Plant
Cost of Non-Utility plant, net of depreciation and amortization	35.8	38.3
Nonutility Group [Member] | All Other [Member]
Utility & Nonutility Plant
Cost of Non-Utility plant, net of depreciation and amortization	$8.40	$9.90

Regulatory_Assets_Liabilities_1

Regulatory Assets & Liabilities (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Regulatory Assets [Line Items]
Regulatory Assets Currently Being Recovered in Base Rates	$36
Regulatory assets	128.3	136.2
Weighted average recovery period of regulatory assets currently being recovered (in years)	23
Regulatory Liabilities [Abstract]
Regulatory liabilities	410.3	387.3
Asset Retirement Obligations and Other [Member]
Regulatory Liabilities [Abstract]
Regulatory liabilities	373.5	373
Future Amounts Recoverable From Ratepayers [Member]
Regulatory Assets [Line Items]
Regulatory assets	-14.8	-3.5
Future Amounts Recoverable From Ratepayers [Member] | Deferred Income Taxes [Member]
Regulatory Assets [Line Items]
Regulatory assets	-14.8	-5.8
Future Amounts Recoverable From Ratepayers [Member] | Asset Retirement Obligations and Other [Member]
Regulatory Assets [Line Items]
Regulatory assets	0	2.3
Amounts Deferred for Future Recovery [Member]
Regulatory Assets [Line Items]
Regulatory assets	33.3	61
Amounts Deferred for Future Recovery [Member] | Deferred Coal Costs [Member]
Regulatory Assets [Line Items]
Regulatory assets	0	42.4
Amounts Deferred for Future Recovery [Member] | Cost Recovery Riders Other [Member]
Regulatory Assets [Line Items]
Regulatory assets	33.3	18.6
Amounts Currently Recovered in Customer Rates [Member]
Regulatory Assets [Line Items]
Regulatory assets	109.8	78.7
Amounts Currently Recovered in Customer Rates [Member] | Deferred Coal Costs [Member]
Regulatory Assets [Line Items]
Regulatory assets	35.3	0
Amounts Currently Recovered in Customer Rates [Member] | Unamortized Debt Issue Costs and Hedging Proceeds [Member]
Regulatory Assets [Line Items]
Regulatory assets	33.5	34.6
Amounts Currently Recovered in Customer Rates [Member] | Demand Side Management Programs [Member]
Regulatory Assets [Line Items]
Regulatory assets	0.6	2.5
Amounts Currently Recovered in Customer Rates [Member] | Indiana Authorized Trackers [Member]
Regulatory Assets [Line Items]
Regulatory assets	25.6	30.8
Amounts Currently Recovered in Customer Rates [Member] | Ohio Authorized Trackers [Member]
Regulatory Assets [Line Items]
Regulatory assets	12.7	7.9
Amounts Currently Recovered in Customer Rates [Member] | Premiums Paid to Reaquire Debt [Member]
Regulatory Assets [Line Items]
Regulatory assets	1.7	2.2
Amounts Currently Recovered in Customer Rates [Member] | Other Base Rate Recoveries [Member]
Regulatory Assets [Line Items]
Regulatory assets	$0.40	$0.70

Transactions_with_Other_Vectre2

Transactions with Other Vectren Companies and Affiliates Transactions with Other Vectren Companies and Afffiliates (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Transactions with Other Vectren Companies and Affiliates [Line Items]
Defined Benefit Plan, Funded Percentage	87.00%	101.00%
Defined Benefit Plan, Net Periodic Benefit Cost	$6.70	$8	$7.20
Deferred Credits and Other Liabilities	109.2	83.5
Amount of Share Based Compensation and Deferred Compensation Liability included in Deferred Credits and Other Liabilities	36.1	29.6
Current: [Abstract]
Federal	16.6	48	6.1
State	10.9	11	6.9
Total current taxes	27.5	59	13
Deferred: [Abstract]
Federal	57.8	26.8	68.7
State	-1.6	0.1	4.2
Total deferred taxes	56.2	26.9	72.9
Amortization of investment tax credits	-0.5	-0.6	-0.6
Total income tax expense	83.2	85.3	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)	3.30%	3.50%	3.70%
Amortization of investment tax credit (in hundredths)	-0.20%	-0.30%	-0.30%
Domestic Production Deduction (in hundredths)	-0.90%	0.00%	0.00%
Adjustment of Income Tax Accruals (in hundredths)	-0.90%	0.00%	0.00%
All other - net (in hundredths)	-0.40%	-0.60%	-0.20%
Effective tax rate (in hundredths)	35.90%	37.60%	38.20%
Noncurrent deferred tax liabilities (assets) [Abstract]
Depreciation and cost recovery timing differences	685	627.9
Regulatory assets recoverable through future rates	29.2	22.8
Alternative minimum tax carryforward	-13.3	-18.5
Employee benefit obligations	1	5.2
Regulatory liabilities to be settled through future rates	-27.5	-18.7
Other - net	10.7	8.7
Net noncurrent deferred tax liability	685.1	627.4
Deferred Tax (Assets) Liabilities Current [Abstract]
Deferred fuel costs-net	22	22.9
Alternative minimum tax carryforward	-38.1	-36.4
General business credit carryforwards	0	-1.2
Other - net	4.8	9.2
Net current deferred tax liability (asset)	-11.3	-5.5
Net deferred tax liability	673.8	621.9
Investment tax credits	2.6	3.2
Uncertain tax positions [Roll Forward]
Unrecognized tax benefits at beginning of period	4.7	3.7	11
Gross increases - tax positions in prior periods	0	0	0.1
Gross decreases - tax positions in prior periods	-4.7	-0.2	-9.3
Gross increases - current period tax positions	0	1.2	1.9
Settlements	0	0	0
Unrecognized tax benefits at end of period	0	4.7	3.7
Uncertain tax positions [Abstract]
Interest and penalties	-0.2	0	-0.7
Payment of interest and penalties accrued	0	0.2
Deferred Tax Assets, Tax Credit Carryforwards, Alternative Minimum Tax	-51.4
Pension Plans, Defined Benefit [Member]
Transactions with Other Vectren Companies and Affiliates [Line Items]
Number of qualified defined benefit pension plans	3
Deferred Credits and Other Liabilities	11.6	11.2
Other Assets	17.3	23.6
Vectren Fuels Inc. [Member]
Transactions with Other Vectren Companies and Affiliates [Line Items]
Expenses from transactions with related party	98.6	103.7	115.6
ProLiance [Member]
Transactions with Other Vectren Companies and Affiliates [Line Items]
Expenses from transactions with related party	0	200.5	274.5
Percentage of purchases from single third party	84.00%
Support Services & Purchases [Member]
Transactions with Other Vectren Companies and Affiliates [Line Items]
Cost of corporate and general and administrative services	57	50.9	44.8
Vectren Infrastructure Services Corporation [Member]
Transactions with Other Vectren Companies and Affiliates [Line Items]
Expenses from transactions with related party	$94	$54.20	$46.60

Borrowing_Arrangements_ShortTe

Borrowing Arrangements Short-Term Borrowings (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Short-term borrowings [Abstract]
Short-term borrowing capacity	$350
Short term borrowings available	194
Short term credit facilities expiration date	31-Oct-19
Year end [Abstract]
Balance Outstanding, end of period	156.4	28.6	116.7
Weighted Average Interest Rate, end of period (in hundredths)	0.50%	0.29%	0.40%
Annual Average [Abstract]
Balance Outstanding, annual average	35.6	119.6	77.6
Weighted Average Interest Rate, annual average (in hundredths)	0.34%	0.34%	0.47%
Maximum Month End Balance Outstanding	$156.40	$176.10	$214.20

Borrowing_Arrangements_Details

Borrowing Arrangements (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Long term debt [Abstract]
Total long term debt outstanding	$1,258,500,000	$1,258,500,000
Current maturities of long-term debt	-95,000,000	0
Unamortized debt premium and discount - net	-1,200,000	-1,400,000
Long-term debt - net of current maturities and debt subject to tender	1,162,300,000	1,257,100,000
Maturities of long term debt [Abstract]
Debt maturing within 12 months following date of latest balance sheet	95,000,000
Debt maturing within two years following date of latest balance sheet	13,000,000
Debt maturing within three years following date of latest balance sheet	0
Debt maturing within four years following date of latest balance sheet	100,000,000
Debt maturing within five years following date of latest balance sheet	0
Debt maturing thereafter 5 years following date of the latest balance sheet	1,049,300,000
Debt guarantees [Abstract]
Long-term guarantees	875,000,000
Short-term debt guarantees	156,000,000
Covenants [Abstract]
Ratio of consolidated total debt to consolidated total capitalization, maximum ( in hundredths)	not exceed 65 percent
Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member]
Long term debt [Abstract]
Total long term debt outstanding	875,000,000	875,000,000
Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2015, 5.45% [Member]
Long term debt [Abstract]
Total long term debt outstanding	75,000,000	75,000,000
Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2018, 5.75% [Member]
Long term debt [Abstract]
Total long term debt outstanding	100,000,000	100,000,000
Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2020, 6.28% [Member]
Long term debt [Abstract]
Total long term debt outstanding	100,000,000	100,000,000
Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2021, 4.67 [Member]
Long term debt [Abstract]
Total long term debt outstanding	55,000,000	55,000,000
Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2023, 3.72% [Member]
Long term debt [Abstract]
Total long term debt outstanding	150,000,000	150,000,000
Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2026, 5.02% [Member]
Long term debt [Abstract]
Total long term debt outstanding	60,000,000	60,000,000
Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2028, 3.20% [Member]
Long term debt [Abstract]
Total long term debt outstanding	45,000,000	45,000,000
Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2035, 6.10% [Member]
Long term debt [Abstract]
Total long term debt outstanding	75,000,000	75,000,000
Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2041, 5.99% [Member]
Long term debt [Abstract]
Total long term debt outstanding	35,000,000	35,000,000
Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2042, 5.00% [Member]
Long term debt [Abstract]
Debt Issuance		100,000,000
Proceeds from debt issuance		99,500,000
Fixed rate stated percentage (in hundredths)		5.00%
Maturity date		3-Feb-42
Debt Instrument Issuance Date		1-Feb-12
Total long term debt outstanding	100,000,000	100,000,000
Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2043, 4.25% [Member]
Long term debt [Abstract]
Total long term debt outstanding	80,000,000	80,000,000
Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2013, 5.25% [Member]
Long term debt [Abstract]
Debt Issuance			100,000,000
Fixed rate stated percentage (in hundredths)			5.25%
Indiana Gas [Member] | Fixed Rate Senior Unsecured Notes [Member]
Long term debt [Abstract]
Total long term debt outstanding	116,000,000	116,000,000
Indiana Gas [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2015, Series E, 7.15% [Member]
Long term debt [Abstract]
Total long term debt outstanding	5,000,000	5,000,000
Indiana Gas [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2015, Series E, 6.69% [Member]
Long term debt [Abstract]
Total long term debt outstanding	5,000,000	5,000,000
Indiana Gas [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2015, Series E1, 6.69% [Member]
Long term debt [Abstract]
Total long term debt outstanding	10,000,000	10,000,000
Indiana Gas [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2025, Series E, 6.53% [Member]
Long term debt [Abstract]
Total long term debt outstanding	10,000,000	10,000,000
Indiana Gas [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2027, Series E, 6.42% [Member]
Long term debt [Abstract]
Total long term debt outstanding	5,000,000	5,000,000
Indiana Gas [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2027, Series E, 6.68% [Member]
Long term debt [Abstract]
Total long term debt outstanding	1,000,000	1,000,000
Indiana Gas [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2027, Series F, 6.34% [Member]
Long term debt [Abstract]
Total long term debt outstanding	20,000,000	20,000,000
Indiana Gas [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2028, Series F, 6.36% [Member]
Long term debt [Abstract]
Total long term debt outstanding	10,000,000	10,000,000
Indiana Gas [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2028, Series F, 6.55% [Member]
Long term debt [Abstract]
Total long term debt outstanding	20,000,000	20,000,000
Indiana Gas [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2029, Series G, 7.08% [Member]
Long term debt [Abstract]
Total long term debt outstanding	30,000,000	30,000,000
SIGECO [Member] | First Mortgage Bonds [Member]
Long term debt [Abstract]
Debt Issuance	62,000,000
Proceeds from debt issuance	60,000,000
SIGECO [Member] | First Mortgage Bonds [Member] | Tax Exempt Debt, 4.05 percent, due 2043 [Member]
Long term debt [Abstract]
Debt Issuance	39,600,000
Fixed rate stated percentage (in hundredths)	4.05%
Maturity date	1-May-43
Debt Instrument Issuance Date	26-Apr-13
SIGECO [Member] | First Mortgage Bonds [Member] | Tax Exempt Debt, 4.00 percent, due 2038 [Member]
Long term debt [Abstract]
Debt Issuance	22,200,000
Fixed rate stated percentage (in hundredths)	4.00%
Maturity date	1-Mar-38
Debt Instrument Issuance Date	26-Apr-13
SIGECO [Member] | First Mortgage Bonds [Member] | Tax Exempt Debt, 1.95 Percent [Member]
Long term debt [Abstract]
Proceeds from debt issuance	48,300,000
Fixed rate stated percentage (in hundredths)	1.95%
Amount of debt to be re-marketed	49,000,000
Debt re-market date	13-Aug-13
SIGECO [Member] | Mortgages [Member]
Long term debt [Abstract]
Total long term debt outstanding	267,500,000	267,500,000
Future long term debt sinking fund fund requirements and maturities [Abstract]
Annual sinking fund requirement fixed percentage (in hundredths)	1.00%
Utility plant remaining unfunded under mortgage indenture	1,300,000,000
Gross utility plant balance subject to the mortgage indenture	3,000,000,000
SIGECO [Member] | Mortgages [Member] | 2015, 1985 Pollution Control Series A, current adjustable rate 0.05%, tax exempt, 2013 weighted average: 0.10%
Long term debt [Abstract]
Total long term debt outstanding	0	9,800,000
SIGECO [Member] | Mortgages [Member] | 2016, 1986 Series, 8.875% [Member]
Long term debt [Abstract]
Total long term debt outstanding	13,000,000	13,000,000
SIGECO [Member] | Mortgages [Member] | 2022, 2013 Series C, 1.95% tax exempt [Member]
Long term debt [Abstract]
Total long term debt outstanding	4,600,000	4,600,000
SIGECO [Member] | Mortgages [Member] | 2024, 2013 Series D, 1.95% tax exempt [Member]
Long term debt [Abstract]
Total long term debt outstanding	22,500,000	22,500,000
SIGECO [Member] | Mortgages [Member] | 2025, 1998 Pollution Control Series A, current adjustable rate 0.05%, tax exempt, 2013 weighted average: 0.10%
Long term debt [Abstract]
Total long term debt outstanding	0	31,500,000
SIGECO [Member] | Mortgages [Member] | 2025, 2014 Series B, .722% Tax Exempt [Member]
Long term debt [Abstract]
Total long term debt outstanding	41,300,000	0
SIGECO [Member] | Mortgages [Member] | 2029, 1999 Senior Notes, 6.72% [Member]
Long term debt [Abstract]
Total long term debt outstanding	80,000,000	80,000,000
SIGECO [Member] | Mortgages [Member] | 2037, 2013 Series E 1.95% Tax Exempt [Member]
Long term debt [Abstract]
Total long term debt outstanding	22,000,000	22,000,000
SIGECO [Member] | Mortgages [Member] | 2038, 2013 Series A, 4.00% Tax Exempt [Member]
Long term debt [Abstract]
Total long term debt outstanding	22,200,000	22,200,000
SIGECO [Member] | Mortgages [Member] | 2040, 2009 Environmental Improvement Series, 5.40%, tax exempt [Member]
Long term debt [Abstract]
Total long term debt outstanding	0	22,300,000
SIGECO [Member] | Mortgages [Member] | 2043, 2013 Series B 4.05% Tax Exempt [Member]
Long term debt [Abstract]
Total long term debt outstanding	39,600,000	39,600,000
SIGECO [Member] | Mortgages [Member] | 2044, 2014 Series A 4.00% Tax Exempt [Member]
Long term debt [Abstract]
Fixed rate stated percentage (in hundredths)	4.00%
Total long term debt outstanding	22,300,000	0
Vectren Utility Holdings Inc [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2023, 3.72% [Member]
Long term debt [Abstract]
Proceeds from debt issuance	149,100,000
Fixed rate stated percentage (in hundredths)	3.72%
Debt Instrument, Offering Date	22-Aug-13
Debt Instrument Issuance Date	5-Dec-13
Vectren Utility Holdings Inc [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2028, 3.20% [Member]
Long term debt [Abstract]
Debt Issuance	45,000,000
Proceeds from debt issuance	44,800,000
Fixed rate stated percentage (in hundredths)	3.20%
Maturity date	5-Jun-28
Debt Instrument Issuance Date	5-Jun-13
Vectren Utility Holdings Inc [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2043, 4.25% [Member]
Long term debt [Abstract]
Debt Issuance	80,000,000
Proceeds from debt issuance	79,600,000
Fixed rate stated percentage (in hundredths)	4.25%
Maturity date	5-Jun-43
Debt Instrument Issuance Date	5-Jun-13
Vectren Utility Holdings Inc [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2039, 6.25% [Member]
Long term debt [Abstract]
Debt Issuance	$121,600,000
Fixed rate stated percentage (in hundredths)	6.25%
Maturity date	31-Dec-39

Common_Shareholders_Equity_Det

Common Shareholder's Equity (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Common Shareholders Equity [Line Items]
Additional capital contribution	$6	$6.10	$7
Common Shareholders Equity [Member]
Common Shareholders Equity [Line Items]
Additional capital contribution	$19.10	$13.10	$11.70

Commitments_and_Contingencies_

Commitments and Contingencies (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Commitments [Abstract]
Future minimum operating lease payments due within one year of the balance sheet date	$0.90
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	0.7
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	2.4
Total lease expense	1.5	1.1	1.2
Unrecorded Unconditional Purchase Obligation, Due within One Year	0.2
Unrecorded Unconditional Purchase Obligation, Due within Two Years	0.2
Unrecorded Unconditional Purchase Obligation, Due within Three Years	0.2
Unrecorded Unconditional Purchase Obligation, Due within Four Years	$0

Gas_Rate_Regulatory_Matters_De

Gas Rate & Regulatory Matters (Details) (USD $)	12 Months Ended			3 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Sep. 30, 2014
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items]
Other income - net	$16,800,000	$10,500,000	$8,000,000
Ohio [Member] | 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	150,500,000
Regulatory Asset associated with DRR deferrals of depreciation and post in-service carrying costs	13,100,000	9,300,000
Initial DRR term	5
Extension period requested to recover capital investments	5
Amount of Capital Investment Expected Over Next Five Years Recoverable Under DRR	200,000,000
Ohio [Member] | House Bill 95 [Member]
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items]
Bill impact per customer per month	1.5
Other income - net	3,900,000	2,200,000
Amount of deferral related to depreciation and property tax expense	3,100,000	1,700,000
Indiana [Member] | Senate Bill 251 and 560 [Member]
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items]
Length of project plan required for recovery under new legislation	7
Expected Seven Year Period Modernization Investment	900,000,000
Capital Expenditure Increases	35,000,000
Economic Development Expenditures	30,000,000
Expected annual operating costs associated with new pipeline safety regulations	15,000,000
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	16,400,000	12,100,000
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%
SIGECO [Member] | Indiana [Member] | Indiana Recovery and Deferral Mechanisms [Member]
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items]
Allowable 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

Electric_Rate_and_Regulatory_M1

Electric Rate and Regulatory Matters Electric Rate and Regulatory Matters (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Feb. 01, 2014
Vectren South Electric Environmental Compliance Filing [Abstract]
Lower range of request for approval of capital investments on coal-fired generation units	$80
Upper range of request for approval of capital investments on coal-fired generation units	90
Coal Procurement Procedures [Abstract]
Number of years for recovery of coal costs	6 years
Cumulative total deferrals related to coal purchases	35.3				42.4
Vectren South Electric Demand Side Management Program Filing [Abstract]
Number Of Years In Initial Demand Side Management Program	3
Maximum Deferral Of Lost Margin Associated With Small Customer DSM Programs			3	1
Electric revenue recognized associated with lost margin recovery	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	$143.60
Incentive return granted on qualifying investments in NETO	11.14%
Percentage return approved by FERC on ROE complaint against NETO	10.57%
Number of incentive basis point above and beyond approved FERC approved ROE	50

Environmental_Matters_Details

Environmental Matters (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
	MW	T
Air Quality [Abstract]
Lower range of request for approval of capital investments on coal-fired generation units	$80
Upper range of request for approval of capital investments on coal-fired generation units	90
SIGECO investment in Property, Plant and Equipment, Pollution control equipment	411
Property, Plant and Equipment, amount of investment in pollution control equipment included in rate base	411
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%
Cost of most of the allowances granted to company for NOx and SO2 inventory usage	0
Clean Water Act [Abstract]
Estimated capital expenditures related to Clean Water Act (Lower Range)	4
Estimated capital expenditures to comply with Clean Water Act (Upper Range)	8
Coal Ash Waste Disposal and Ash Ponds [Abstract]
Estimated capital expenditures to comply with ash pond and coal ash disposal regulations	30
Potential estimated capital expenditures to comply with ash pond and coal ash disposal regulations with stringent alternative	100
Estimated annual compliance costs maximum with ash pond and coal ash disposal regulation	5
Climate Changes [Abstract]
Maximum level of greenhouse gas emissions that prompts requirement to obtain permit for facilities to construct new facility of significant modification to existing facility (in tons)	75,000
Vectren's share of Indiana's total CO2 emmisions in 2013 (in tons)		6,300,000
Vectren's share of Indiana's total CO2 emissions in 2013 (as a percent)		6.00%
Percent reduction of Vectren's CO2 emissions since 2005	23.00%
Long term contract for purchase of electric power generated by wind energy (in megawatts)	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
Environmental cost recognized, recover from insurance carriers credited to expense	20.8
Accrual for Environmental Loss Contingencies	3.6	5.7
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
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	14.3
Expected Site Contingency Recovery from Insurance Carriers of Environmental Remediation Costs	$15.80

Fair_Value_Measurements_Detail

Fair Value Measurements (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
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	1,257.30	$1,257.10
Short-term Debt, Fair Value	156.4	28.6
Cash and cash equivalents	19.3	8.6
Estimated Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	1,408	1,317.40
Short-term Debt, Fair Value	156.4	28.6
Cash and cash equivalents	19.3	$8.60

Segment_Reporting_Details

Segment Reporting (Details) (USD $)	3 Months Ended								12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Segment Reporting [Abstract]
Portion of Indiana that is provided natural gas distribution and transportation services by the Gas Utility Services segment (in hundredths)	66.67%								66.67%
Segment Reporting Information [Line Items]
Number of operating segments in Utility group	3								3
Revenues	$407.50	$271.10	$284.50	$606.60	$403.60	$267.70	$292.80	$465.50	$1,569.70	$1,429.60	$1,333.60
Net income (loss)	39.8	24.3	22.9	61.3	37.2	25.3	24.2	55.1	148.4	141.8	138
Assets	4,428.10				4,140.80				4,428.10	4,140.80	4,046.80
Amounts Included in Profitability Measures [Abstract]
Depreciation and Amortization									203.1	196.4	190
Interest Expense									66.6	65	71.5
Income Taxes									83.2	85.3	85.3
Capital Expenditures									351	262.5	247.6
Gas Utility Services [Member]
Segment Reporting Information [Line Items]
Revenues									944.6	810	738.1
Net income (loss)									57	55.7	60
Assets	2,605.10				2,287.90				2,605.10	2,287.90	2,173.50
Amounts Included in Profitability Measures [Abstract]
Depreciation and Amortization									93.3	90.5	85.4
Interest Expense									34.9	30.6	31.8
Income Taxes									35.7	36.6	39.1
Capital Expenditures									245.9	150.5	128.8
Electric Utility Services [Member]
Segment Reporting Information [Line Items]
Revenues									624.8	619.3	594.9
Net income (loss)									79.7	75.8	68
Assets	1,659.30				1,679				1,659.30	1,679	1,705.10
Amounts Included in Profitability Measures [Abstract]
Depreciation and Amortization									85.7	84	81.3
Interest Expense									29	29.2	33.8
Income Taxes									48.1	48.3	46.4
Capital Expenditures									92.4	100	108.8
Other Operations [Member]
Segment Reporting Information [Line Items]
Revenues									38.3	38.1	40.1
Net income (loss)									11.7	10.3	10
Assets	163.7				173.9				163.7	173.9	168.2
Amounts Included in Profitability Measures [Abstract]
Depreciation and Amortization									24.1	21.9	23.3
Interest Expense									2.7	5.2	5.9
Income Taxes									-0.6	0.4	-0.2
Capital Expenditures									22.8	25.8	16.2
Intersegment Elimination [Member]
Segment Reporting Information [Line Items]
Revenues									-38	-37.8	-39.5
Non-Cash Cost and Change in Accruals [Member]
Amounts Included in Profitability Measures [Abstract]
Capital Expenditures									($10.10)	($13.80)	($6.20)

Additional_Balance_Sheet_Opera2

Additional Balance Sheet & Operational Information (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Inventory, Net [Abstract]
Gas in storage - at LIFO cost	$40.50	$33.20
Materials and supplies	37.2	39
Coal and Oil for electric generation - at average cost	33.8	16.5
Other	1.7	1.2
Total inventories	113.2	89.9
Amount by which cost of replacing inventories carried at LIFO cost exceeded carrying value	3	9
Prepayments and other current assets [Abstract]
Prepaid gas delivery service	40.7	32.9
Prepaid taxes	29.5	0.2
Deferred income taxes	11.3	5.5
Other prepayments and current assets	2	3.8
Total prepayments and other current assets	83.5	42.4
Other utility and corporate investments [Abstract]
Cash surrender value of life insurance policies	20.8	22.3
Municipal bond	3.2	3.4
Restricted cash & other investments	1.6	1.6
Total other investments	25.6	27.3
Accrued liabilities [Abstract]
Refunds to customers and customer deposits	51.3	50.2
Accrued taxes	33.9	32.3
Accrued interest	16.1	16.2
Accrued salaries and other	21	28.7
Total accrued liabilities	122.3	127.4
Asset Retirement Obligation [Roll Forward]
Asset retirement obligation, beginning balance	29.1	27.3
Accretion	1.7	1.6
Changes in estimates, net of cash payments	23.8	0.2
Asset retirement obligation, ending balance	54.6	29.1	27.3
Other - net in the consolidated statement of income [Abstract]
AFUDC - borrowed funds	10.8	5.9	4.6
AFUDC - equity funds	3.2	0.8	0.4
Nonutility plant capitalized interest	0.6	0.4	0.2
Interest income, net	0.7	0.6	0.6
Cash surrender value of life insurance policies	0.6	1.7	1.4
All other income	0.9	1.1	0.8
Total other income (expense) b net	16.8	10.5	8
Cash paid (received) for [Abstract]
Interest	66.7	68.2	69.6
Income taxes	63.2	30.9	30.1
Accruals related to utility and nonutility plant purchases [Abstract]
Accruals related to utility and nonutility plant purchases	$19	$13.10

Subsidiary_Guarantor_and_Conso2

Subsidiary Guarantor and Consolidating Information Subsidiary Guarantor and Consolidating Information Balance Sheet (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
ASSETS
Cash & cash equivalents	$19.30	$8.60	$13.30	$6
Accounts receivable - less reserves	113	112.1
Accrued unbilled revenues	122.4	113.5
Inventories	113.2	89.9
Recoverable fuel & natural gas costs	9.8	5.5
Prepayments & other curent assets	83.5	42.4
Total current assets	461.2	372
Original Cost	5,718.70	5,389.60
Less: accumulated depreciation & amortization	2,279.70	2,165.30
Net utility plant	3,439	3,224.30
Investments in unconsolidated affiliates	0.2	0.2
Other Investments	25.6	27.3
Nonutility plant - net	149.2	150.5
Goodwill - net	205	205
Regulatory assets	128.3	136.2
Other assets	19.6	25.3
TOTAL ASSETS	4,428.10	4,140.80	4,046.80
LIABILITIES & SHAREHOLDERS' EQUITY
Accounts payable	180.4	172.1
Payables to other Vectren companies	28.6	24.6
Accrued liabilities	122.3	127.4
Short-term borrowings	156.4	28.6	116.7
Current maturities of long-term debt	95	0
Total current liabilities	582.7	352.7
Long-term Debt - Net of Current Maturities	1,162.30	1,257.10
Deferred income taxes	685.1	627.4
Regulatory liabilities	410.3	387.3
Deferred Credits and Other Liabilities	109.2	83.5
Total deferred credits and other liabilities	1,204.60	1,098.20
Common stock (no par value)	793.7	787.7
Retained earnings	684.8	645.1
Total common shareholders' equity	1,478.50	1,432.80
TOTAL LIABILITIES and SHAREHOLDERS' EQUITY	4,428.10	4,140.80
Line of Credit Facility, Maximum Borrowing Capacity	350
Line of Credit Facility, Amount Outstanding	156
Unsecured Debt	875
Subsidiary Ownership Percentage	100.00%
Subsidiary Guarantors [Member]
ASSETS
Cash & cash equivalents	6.9	8.2	12.5	5.3
Accounts receivable - less reserves	113	112.1
Intercompany Receivables	0.8	0.3
Accrued unbilled revenues	122.4	113.5
Inventories	113.2	89.9
Recoverable fuel & natural gas costs	9.8	5.5
Prepayments & other curent assets	94.8	37.3
Total current assets	460.9	366.8
Original Cost	5,718.70	5,389.60
Less: accumulated depreciation & amortization	2,279.70	2,165.30
Net utility plant	3,439	3,224.30
Investments in consolidated subsidiaries	0	0
Notes receivable from consolidated subsidiaries	0	0
Investments in unconsolidated affiliates	0.2	0.2
Other Investments	21.3	22.8
Nonutility plant - net	1.8	2.2
Goodwill - net	205	205
Regulatory assets	106.7	113.4
Other assets	29.4	32.2
TOTAL ASSETS	4,264.30	3,966.90
LIABILITIES & SHAREHOLDERS' EQUITY
Accounts payable	176.2	161.6
Intercompany Payables	15.6	11.7
Payables to other Vectren companies	28.6	24.6
Accrued liabilities	136.7	150.3
Short-term borrowings	0	0
Intercompany short-term borrowings	97	73.1
Current maturities of long-term debt	20
Current maturities of long-term debt due to VUHI	74.1
Total current liabilities	548.2	421.3
Long-term Debt - Net of Current Maturities	362.6	382.5
Long-term debt due to VUHI	746.5	696.4
Total long-term debt - net	1,109.10	1,078.90
Deferred income taxes	665.8	616.9
Regulatory liabilities	408.8	385.7
Deferred Credits and Other Liabilities	115.5	88.3
Total deferred credits and other liabilities	1,190.10	1,090.90
Common stock (no par value)	806.9	800.9
Retained earnings	610	574.9
Total common shareholders' equity	1,416.90	1,375.80
TOTAL LIABILITIES and SHAREHOLDERS' EQUITY	4,264.30	3,966.90
Parent Company [Member]
ASSETS
Cash & cash equivalents	12.4	0.4	0.8	0.7
Accounts receivable - less reserves	0	0
Intercompany Receivables	186.7	84.8
Accrued unbilled revenues	0	0
Inventories	0	0
Recoverable fuel & natural gas costs	0	0
Prepayments & other curent assets	38.1	40.1
Total current assets	237.2	125.3
Original Cost	0	0
Less: accumulated depreciation & amortization	0	0
Net utility plant	0	0
Investments in consolidated subsidiaries	1,416.90	1,375.80
Notes receivable from consolidated subsidiaries	746.5	696.4
Investments in unconsolidated affiliates	0	0
Other Investments	4.3	4.5
Nonutility plant - net	147.4	148.3
Goodwill - net	0	0
Regulatory assets	21.6	22.8
Other assets	1.7	1
TOTAL ASSETS	2,575.60	2,374.10
LIABILITIES & SHAREHOLDERS' EQUITY
Accounts payable	4.2	10.5
Intercompany Payables	0.8	0
Payables to other Vectren companies	0	0
Accrued liabilities	35	12.1
Short-term borrowings	156.4	28.6
Intercompany short-term borrowings	0	0.3
Current maturities of long-term debt	75
Current maturities of long-term debt due to VUHI	0
Total current liabilities	271.4	51.5
Long-term Debt - Net of Current Maturities	799.7	874.6
Long-term debt due to VUHI	0	0
Total long-term debt - net	799.7	874.6
Deferred income taxes	19.3	10.5
Regulatory liabilities	1.5	1.6
Deferred Credits and Other Liabilities	5.2	3.1
Total deferred credits and other liabilities	26	15.2
Common stock (no par value)	793.7	787.7
Retained earnings	684.8	645.1
Total common shareholders' equity	1,478.50	1,432.80
TOTAL LIABILITIES and SHAREHOLDERS' EQUITY	2,575.60	2,374.10
Consolidation, Eliminations [Member]
ASSETS
Cash & cash equivalents	0	0	0	0
Accounts receivable - less reserves	0	0
Intercompany Receivables	-187.5	-85.1
Accrued unbilled revenues	0	0
Inventories	0	0
Recoverable fuel & natural gas costs	0	0
Prepayments & other curent assets	-49.4	-35
Total current assets	-236.9	-120.1
Original Cost	0	0
Less: accumulated depreciation & amortization	0	0
Net utility plant	0	0
Investments in consolidated subsidiaries	-1,416.90	-1,375.80
Notes receivable from consolidated subsidiaries	-746.5	-696.4
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	-11.5	-7.9
TOTAL ASSETS	-2,411.80	-2,200.20
LIABILITIES & SHAREHOLDERS' EQUITY
Accounts payable	0	0
Intercompany Payables	-16.4	-11.7
Payables to other Vectren companies	0	0
Accrued liabilities	-49.4	-35
Short-term borrowings	0	0
Intercompany short-term borrowings	-97	-73.4
Current maturities of long-term debt	0
Current maturities of long-term debt due to VUHI	-74.1
Total current liabilities	-236.9	-120.1
Long-term Debt - Net of Current Maturities	0	0
Long-term debt due to VUHI	-746.5	-696.4
Total long-term debt - net	-746.5	-696.4
Deferred income taxes	0	0
Regulatory liabilities	0	0
Deferred Credits and Other Liabilities	-11.5	-7.9
Total deferred credits and other liabilities	-11.5	-7.9
Common stock (no par value)	-806.9	-800.9
Retained earnings	-610	-574.9
Total common shareholders' equity	-1,416.90	-1,375.80
TOTAL LIABILITIES and SHAREHOLDERS' EQUITY	-2,411.80	-2,200.20
Consolidated Entities [Member]
ASSETS
Cash & cash equivalents	19.3	8.6	13.3	6
Accounts receivable - less reserves	113	112.1
Intercompany Receivables	0	0
Accrued unbilled revenues	122.4	113.5
Inventories	113.2	89.9
Recoverable fuel & natural gas costs	9.8	5.5
Prepayments & other curent assets	83.5	42.4
Total current assets	461.2	372
Original Cost	5,718.70	5,389.60
Less: accumulated depreciation & amortization	2,279.70	2,165.30
Net utility plant	3,439	3,224.30
Investments in consolidated subsidiaries	0	0
Notes receivable from consolidated subsidiaries	0	0
Investments in unconsolidated affiliates	0.2	0.2
Other Investments	25.6	27.3
Nonutility plant - net	149.2	150.5
Goodwill - net	205	205
Regulatory assets	128.3	136.2
Other assets	19.6	25.3
TOTAL ASSETS	4,428.10	4,140.80
LIABILITIES & SHAREHOLDERS' EQUITY
Accounts payable	180.4	172.1
Intercompany Payables	0	0
Payables to other Vectren companies	28.6	24.6
Accrued liabilities	122.3	127.4
Short-term borrowings	156.4	28.6
Intercompany short-term borrowings	0	0
Current maturities of long-term debt	95
Current maturities of long-term debt due to VUHI	0
Total current liabilities	582.7	352.7
Long-term Debt - Net of Current Maturities	1,162.30	1,257.10
Long-term debt due to VUHI	0	0
Total long-term debt - net	1,162.30	1,257.10
Deferred income taxes	685.1	627.4
Regulatory liabilities	410.3	387.3
Deferred Credits and Other Liabilities	109.2	83.5
Total deferred credits and other liabilities	1,204.60	1,098.20
Common stock (no par value)	793.7	787.7
Retained earnings	684.8	645.1
Total common shareholders' equity	1,478.50	1,432.80
TOTAL LIABILITIES and SHAREHOLDERS' EQUITY	$4,428.10	$4,140.80

Subsidiary_Guarantor_and_Conso3

Subsidiary Guarantor and Consolidating Information Subsidiary Guarantor and Consolidating Information Income Statement (Details) (USD $)	3 Months Ended								12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
OPERATING REVENUES [Abstract]
Gas utility									$944.60	$810	$738.10
Electric utility									624.8	619.3	594.9
Other									0.3	0.3	0.6
Total operating revenues	407.5	271.1	284.5	606.6	403.6	267.7	292.8	465.5	1,569.70	1,429.60	1,333.60
OPERATING EXPENSES [Abstract]
Cost of Gas Sold									468.7	358.1	301.3
Cost of fuel & purchased power									201.8	202.9	192
Other operating									354.5	333.4	310.1
Depreciation & Amortization									203.1	196.4	190
Taxes other than income taxes									60.2	57.2	53.4
Total operating expenses									1,288.30	1,148	1,046.80
OPERATING INCOME	73.4	49.4	48.1	110.4	70.5	54.5	51.2	105.4	281.4	281.6	286.8
Other - net									16.8	10.5	8
Interest Expense									66.6	65	71.5
INCOME BEFORE INCOME TAXES									231.6	227.1	223.3
Income taxes									83.2	85.3	85.3
NET INCOME	39.8	24.3	22.9	61.3	37.2	25.3	24.2	55.1	148.4	141.8	138
Subsidiary Guarantors [Member]
OPERATING REVENUES [Abstract]
Gas utility									944.6	810	738.1
Electric utility									624.8	619.3	594.9
Other									0	0	0
Total operating revenues									1,569.40	1,429.30	1,333
OPERATING EXPENSES [Abstract]
Cost of Gas Sold									468.7	358.1	301.3
Cost of fuel & purchased power									201.8	202.9	192
Other operating									390.3	369.2	348.5
Depreciation & Amortization									179.1	174.6	166.8
Taxes other than income taxes									58.4	55.6	51.7
Total operating expenses									1,298.30	1,160.40	1,060.30
OPERATING INCOME									271.1	268.9	272.7
Equity in earnings of consolidated companies									0	0	0
Other - net									13.3	7.1	6.2
Total other income (expense)									13.3	7.1	6.2
Interest Expense									63.9	59.8	65.6
INCOME BEFORE INCOME TAXES									220.5	216.2	213.3
Income taxes									83.8	84.9	85.4
NET INCOME									136.7	131.3	127.9
Parent Company [Member]
OPERATING REVENUES [Abstract]
Gas utility									0	0	0
Electric utility									0	0	0
Other									38.3	37.9	40.1
Total operating revenues									38.3	37.9	40.1
OPERATING EXPENSES [Abstract]
Cost of Gas Sold									0	0	0
Cost of fuel & purchased power									0	0	0
Other operating									0	0	0.4
Depreciation & Amortization									23.5	21.3	22.7
Taxes other than income taxes									1.7	1.5	1.6
Total operating expenses									25.2	22.8	24.7
OPERATING INCOME									13.1	15.1	15.4
Equity in earnings of consolidated companies									136.7	131.3	127.9
Other - net									43.2	38.5	41.4
Total other income (expense)									179.9	169.8	169.3
Interest Expense									45.2	42.7	46.8
INCOME BEFORE INCOME TAXES									147.8	142.2	137.9
Income taxes									-0.6	0.4	-0.1
NET INCOME									148.4	141.8	138
Consolidation, Eliminations [Member]
OPERATING REVENUES [Abstract]
Gas utility									0	0	0
Electric utility									0	0	0
Other									-38	-37.6	-39.5
Total operating revenues									-38	-37.6	-39.5
OPERATING EXPENSES [Abstract]
Cost of Gas Sold									0	0	0
Cost of fuel & purchased power									0	0	0
Other operating									-35.8	-35.8	-38.8
Depreciation & Amortization									0.5	0.5	0.5
Taxes other than income taxes									0.1	0.1	0.1
Total operating expenses									-35.2	-35.2	-38.2
OPERATING INCOME									-2.8	-2.4	-1.3
Equity in earnings of consolidated companies									-136.7	-131.3	-127.9
Other - net									-39.7	-35.1	-39.6
Total other income (expense)									-176.4	-166.4	-167.5
Interest Expense									-42.5	-37.5	-40.9
INCOME BEFORE INCOME TAXES									-136.7	-131.3	-127.9
Income taxes									0	0	0
NET INCOME									-136.7	-131.3	-127.9
Consolidated Entities [Member]
OPERATING REVENUES [Abstract]
Gas utility									944.6	810	738.1
Electric utility									624.8	619.3	594.9
Other									0.3	0.3	0.6
Total operating revenues									1,569.70	1,429.60	1,333.60
OPERATING EXPENSES [Abstract]
Cost of Gas Sold									468.7	358.1	301.3
Cost of fuel & purchased power									201.8	202.9	192
Other operating									354.5	333.4	310.1
Depreciation & Amortization									203.1	196.4	190
Taxes other than income taxes									60.2	57.2	53.4
Total operating expenses									1,288.30	1,148	1,046.80
OPERATING INCOME									281.4	281.6	286.8
Equity in earnings of consolidated companies									0	0	0
Other - net									16.8	10.5	8
Total other income (expense)									16.8	10.5	8
Interest Expense									66.6	65	71.5
INCOME BEFORE INCOME TAXES									231.6	227.1	223.3
Income taxes									83.2	85.3	85.3
NET INCOME									$148.40	$141.80	$138

Subsidiary_Guarantor_and_Conso4

Subsidiary Guarantor and Consolidating Information Subsidiary Guarantor and Consolidating Information Cash Flows (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Net cash flows from operating activities	$337.50	$399.90	$373.40
Additional capital contribution	6	6.1	7
Long-term debt - net of issuance costs	62.4	381.7	99.5
Dividends to parent	-108.7	-105.1	-101.5
Retirement of long-term debt, including premiums paid	-63.6	-337.5	0
Net change in short-term borrowings	127.8	-88.1	-126.1
Net cash flows from financing activities	23.9	-142.9	-121.1
Proceeds from other investing activities	0.3	0.8	2.6
Capital expenditures, excluding AFUDC equity	-351	-262.5	-247.6
Net cash flows from investing activities	-350.7	-261.7	-245
Net change in cash and cash equivalents	10.7	-4.7	7.3
Cash & cash equivalents	19.3	8.6	13.3	6
Subsidiary Guarantors [Member]
Net cash flows from operating activities	274.4	371	335.6
Additional capital contribution	6	13.1	0
Long-term debt - net of issuance costs	186.6	232.6	0
Dividends to parent	-101.6	-97.9	-70.9
Retirement of long-term debt, including premiums paid	-63.6	-223.6
Net change in intercompany short-term borrowings	23.9	-61.5	-24
Net change in short-term borrowings	0	0	0
Net cash flows from financing activities	51.3	-137.3	-94.9
Consolidated subsidiary distributions	0	0	0
Proceeds from other investing activities	0	0.6	0.3
Capital expenditures, excluding AFUDC equity	-327.3	-238.3	-233.8
Requirements for consolidated subsidiary investments	0
Other investing activities		0
Net change in long term intercompany notes receivable	0	0
Net change in short term intercompany notes receivable	0.3	-0.3	0
Net cash flows from investing activities	-327	-238	-233.5
Net change in cash and cash equivalents	-1.3	-4.3	7.2
Cash & cash equivalents	6.9	8.2	12.5	5.3
Parent Company [Member]
Net cash flows from operating activities	63.1	28.9	37.8
Additional capital contribution	6	6.1	7
Long-term debt - net of issuance costs	0	273.5	99.5
Dividends to parent	-108.7	-105.1	-101.5
Retirement of long-term debt, including premiums paid	0	-221.6
Net change in intercompany short-term borrowings	-0.3	0.3	0
Net change in short-term borrowings	127.8	-88.1	-126.1
Net cash flows from financing activities	24.8	-134.9	-121.1
Consolidated subsidiary distributions	101.6	97.9	70.9
Proceeds from other investing activities	0.3	0.2	2.3
Capital expenditures, excluding AFUDC equity	-23.7	-24.2	-13.8
Requirements for consolidated subsidiary investments	-6
Other investing activities		-13.1
Net change in long term intercompany notes receivable	-50.1	-16.7
Net change in short term intercompany notes receivable	-98	61.5	24
Net cash flows from investing activities	-75.9	105.6	83.4
Net change in cash and cash equivalents	12	-0.4	0.1
Cash & cash equivalents	12.4	0.4	0.8	0.7
Consolidation, Eliminations [Member]
Net cash flows from operating activities	0	0	0
Additional capital contribution	-6	-13.1	0
Long-term debt - net of issuance costs	-124.2	-124.4	0
Dividends to parent	101.6	97.9	70.9
Retirement of long-term debt, including premiums paid	0	107.7
Net change in intercompany short-term borrowings	-23.6	61.2	24
Net change in short-term borrowings	0	0	0
Net cash flows from financing activities	-52.2	129.3	94.9
Consolidated subsidiary distributions	-101.6	-97.9	-70.9
Proceeds from other investing activities	0	0	0
Capital expenditures, excluding AFUDC equity	0	0	0
Requirements for consolidated subsidiary investments	6
Other investing activities		13.1
Net change in long term intercompany notes receivable	50.1	16.7
Net change in short term intercompany notes receivable	97.7	-61.2	-24
Net cash flows from investing activities	52.2	-129.3	-94.9
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	337.5	399.9	373.4
Additional capital contribution	6	6.1	7
Long-term debt - net of issuance costs	62.4	381.7	99.5
Dividends to parent	-108.7	-105.1	-101.5
Retirement of long-term debt, including premiums paid	-63.6	-337.5
Net change in intercompany short-term borrowings	0	0	0
Net change in short-term borrowings	127.8	-88.1	-126.1
Net cash flows from financing activities	23.9	-142.9	-121.1
Consolidated subsidiary distributions	0	0	0
Proceeds from other investing activities	0.3	0.8	2.6
Capital expenditures, excluding AFUDC equity	-351	-262.5	-247.6
Requirements for consolidated subsidiary investments	0
Other investing activities		0
Net change in long term intercompany notes receivable	0	0
Net change in short term intercompany notes receivable	0	0	0
Net cash flows from investing activities	-350.7	-261.7	-245
Net change in cash and cash equivalents	10.7	-4.7	7.3
Cash & cash equivalents	$19.30	$8.60	$13.30	$6

Quarterly_Financial_Data_Unaud2

Quarterly Financial Data (Unaudited) (Details) (USD $)	3 Months Ended								12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Quarterly Financial Information Disclosure [Abstract]
Total operating revenues	$407.50	$271.10	$284.50	$606.60	$403.60	$267.70	$292.80	$465.50	$1,569.70	$1,429.60	$1,333.60
Operating Income	73.4	49.4	48.1	110.4	70.5	54.5	51.2	105.4	281.4	281.6	286.8
Net Income	$39.80	$24.30	$22.90	$61.30	$37.20	$25.30	$24.20	$55.10	$148.40	$141.80	$138

SCHEDULE_II_VALUATION_AND_QUAL1

SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Accumulated Provision for Uncollectible Accounts [Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
Balance, at beginning of year	$5	$5	$5.90
Additions charged to expenses	6.1	6.5	7.4
Additions charged to other accounts	0	0	0
Deductions from Reserves, Net	7.2	6.5	8.3
Balance, at end of period	3.9	5	5
Restructuring Costs [Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
Balance, at beginning of year	0.2	0.3	0.4
Additions charged to expenses	0	0	0
Additions charged to other accounts	0	0	0
Deductions from Reserves, Net	0.2	0.1	0.1
Balance, at end of period	$0	$0.20	$0.30