Vectren Utility 10-K 5 Mar 14 2013 FY Annual report Financial data

Document_And_Entity_Informatio

Document And Entity Information (USD $)	12 Months Ended
	Dec. 31, 2013	Feb. 28, 2014	Jun. 30, 2013
Entity Information [Line Items]	'	'	'
Entity Registrant Name	'VECTREN UTILITY HOLDINGS INC	'	'
Entity Central Index Key	'0001129542	'	'
Current Fiscal Year End Date	'--12-31	'	'
Entity Filer Category	'Non-accelerated Filer	'	'
Document Type	'10-K	'	'
Document Period End Date	31-Dec-13	'	'
Document Fiscal Year Focus	'2013	'	'
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, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Assets, Current [Abstract]	'	'
Cash & cash equivalents	$8.60	$13.30
Accounts receivable - less reserves of $5.0 & $5.0, respectively	112.1	81.8
Accrued unbilled revenues	113.5	93.6
Inventories	89.9	114
Recoverable fuel & natural gas costs	5.5	25.3
Prepayments & other current assets	42.4	52.3
Total current assets	372	380.3
Utility Plant [Abstract]	'	'
Original Cost	5,389.60	5,176.80
Less: accumulated depreciation & amortization	2,165.30	2,057.20
Net utility plant	3,224.30	3,119.60
Investments in unconsolidated affiliates	0.2	0.2
Other investments	27.3	32.6
Nonutility plant - net	150.5	146.9
Goodwill - net	205	205
Regulatory assets	136.2	126.5
Other assets	25.3	35.7
TOTAL ASSETS	4,140.80	4,046.80
Current Liabilities [Abstract]	'	'
Accounts payable	172.1	121
Accounts payable to affiliated companies	0	29.7
Payables to other Vectren companies	24.6	25.1
Accrued liabilities	127.4	139.3
Short-term borrowings	28.6	116.7
Current maturities of long-term debt	0	105
Total current liabilities	352.7	536.8
Long-Term Debt - Net of Current Maturities	1,257.10	1,103.40
Deferred Income Taxes & Other Liabilities [Abstract]	'	'
Deferred income taxes	627.4	578.5
Regulatory liabilities	387.3	364.2
Deferred credits & other liabilities	83.5	73.9
Total deferred credits and other liabilities	1,098.20	1,016.60
Commitments & Contingencies (Notes 8-10)	'	'
Common Shareholder's Equity [Abstract]	'	'
Common stock (no par value)	787.7	781.6
Retained earnings	645.1	608.4
Total common shareholders' equity	1,432.80	1,390
TOTAL LIABILITIES and SHAREHOLDERS' EQUITY	$4,140.80	$4,046.80

CONSOLIDATED_CONDENSED_BALANCE1

CONSOLIDATED CONDENSED BALANCE SHEETS (Unaudited) (Parenthetical) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Assets, Current [Abstract]	'	'
Allowance for Doubtful Accounts Receivable, Current	$5	$5

CONSOLIDATED_CONDENSED_STATEME

CONSOLIDATED CONDENSED STATEMENTS OF INCOME (Unaudited) (USD $)	3 Months Ended								12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
OPERATING REVENUES [Abstract]	'	'	'	'	'	'	'	'	'	'	'
Gas utility	'	'	'	'	'	'	'	'	$810	$738.10	$819.10
Electric utility	'	'	'	'	'	'	'	'	619.3	594.9	635.9
Other	'	'	'	'	'	'	'	'	0.3	0.6	2
Total operating revenues	403.6	267.7	292.8	465.5	368	267.7	265.8	432.1	1,429.60	1,333.60	1,457
OPERATING EXPENSES [Abstract]	'	'	'	'	'	'	'	'	'	'	'
Cost of gas sold	'	'	'	'	'	'	'	'	358.1	301.3	375.4
Cost of fuel & purchased power	'	'	'	'	'	'	'	'	202.9	192	240.4
Other operating	'	'	'	'	'	'	'	'	333.4	310.1	313.1
Depreciation & Amortization	'	'	'	'	'	'	'	'	196.4	190	192.3
Taxes other than income taxes	'	'	'	'	'	'	'	'	57.2	53.4	54
Total operating expenses	'	'	'	'	'	'	'	'	1,148	1,046.80	1,175.20
OPERATING INCOME	70.5	54.5	51.2	105.4	74	57.1	49.8	105.9	281.6	286.8	281.8
Nonoperating Income (Expense) [Abstract]	'	'	'	'	'	'	'	'	'	'	'
Other income - net	'	'	'	'	'	'	'	'	10.5	8	4.3
Interest Expense	'	'	'	'	'	'	'	'	65	71.5	80.3
INCOME BEFORE INCOME TAXES	'	'	'	'	'	'	'	'	227.1	223.3	205.8
Income taxes	'	'	'	'	'	'	'	'	85.3	85.3	82.9
NET INCOME	$37.20	$25.30	$24.20	$55.10	$35.50	$26.40	$20.10	$56	$141.80	$138	$122.90

CONSOLIDATED_CONDENSED_STATEME1

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS (Unaudited) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
CASH FLOWS FROM OPERATING ACTIVITIES [Abstract]	'	'	'
Net Income	$141.80	$138	$122.90
Adjustments to Reconcile Net Income to Cash from Operating Activities [Abstract]	'	'	'
Depreciation & Amortization	196.4	190	192.3
Deferred income taxes & investment tax credits	26.4	72.3	64.6
Expense portion of pension & postretirement periodic benefit cost	5.6	5	4.6
Provision for uncollectible accounts	6.5	7.4	11.4
Other non-cash expense - net	2.5	5.6	11
Changes in working capital accounts [Abstract]	'	'	'
Accounts receivable, including to Vectren companies and accrued unbilled revenues	-56.8	3.7	36.7
Inventories	24.1	18.5	-15
Recoverable/refundable fuel & natural gas costs	22.4	-12.9	-4.5
Prepayments & other current assets	15.5	2.6	28.2
Accounts payable, including to Vectren companies & affiliated companies	10.1	-7.4	-50.3
Accrued liabilities	4.9	-1.6	-14.8
Changes in noncurrent ssets	11.4	-33.2	-46.5
Changes in noncurrent liabilities	-10.9	-14.6	-6.3
Net cash flows from operating activities	399.9	373.4	334.3
Proceeds from:	'	'	'
Long-term debt - net of issuance costs	381.7	99.5	148.9
Additional capital contribution	6.1	7	0
Requirements for:	'	'	'
Dividends to parent	-105.1	-101.5	-91.6
Retirement of long-term debt	-337.5	0	-347
Other Financing Activities	0	0	-1.1
Net change in short-term borrowings	-88.1	-126.1	195.8
Net cash flows from financing activities	-142.9	-121.1	-95
CASH FLOWS FROM INVESTING ACTIVITIES [Abstract]	'	'	'
Proceeds from other investing activities	0.8	2.6	0.4
Requirements for:	'	'	'
Capital expenditures, excluding AFUDC equity	-262.5	-247.6	-235.3
Other investments	0	0	-0.8
Net cash flows from investing activities	-261.7	-245	-235.7
Net change in cash and cash equivalents	-4.7	7.3	3.6
Cash and cash equivalents at beginning of period	13.3	6	2.4
Cash and cash equivalents at end of period	$8.60	$13.30	$6

Statement_of_Shareholders_Equi

Statement of Shareholders' Equity (USD $)	3 Months Ended		12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Balance at end of period	$1,432.80	$1,390	$1,432.80	$1,390	$1,346.60	$1,315.40
Net Income	37.2	35.5	141.8	138	122.9	'
Other comprehensive income	'	'	'	'	-0.1	'
Common stock:	'	'	'	'	'	'
Other	'	'	'	-0.1	'	'
Adjustments to Additional Paid in Capital, Other	'	'	6.1	7	'	'
Cash Dividends Paid to Parent Company	'	'	-105.1	-101.5	-91.6	'
Common Stock [Member]	'	'	'	'	'	'
Balance at end of period	787.7	781.6	787.7	781.6	774.6	774.6
Common stock:	'	'	'	'	'	'
Adjustments to Additional Paid in Capital, Other	'	'	6.1	7	'	'
Retained Earnings [Member]	'	'	'	'	'	'
Balance at end of period	645.1	608.4	645.1	608.4	572	540.7
Net Income	'	'	141.8	138	122.9	'
Common stock:	'	'	'	'	'	'
Other	'	'	'	-0.1	'	'
Cash Dividends Paid to Parent Company	'	'	-105.1	-101.5	-91.6	'
Accumulated Other Comprehensive Income (Loss) [Member]	'	'	'	'	'	'
Balance at end of period	0	0	0	0	0	0.1
Other comprehensive income	'	'	'	'	($0.10)	'

Organization_and_Nature_of_Ope

Organization and Nature of Operations	12 Months Ended
	Dec. 31, 2013
Organization, Consolidation and Presentation of Financial Statements [Abstract]	'
Organization and Nature of Operations	'
	Organization & Nature of Operations
	Vectren Utility Holdings, Inc. (the Company, Utility Holdings or VUHI), an Indiana corporation, was formed on March 31, 2000, to serve as the intermediate holding company for Vectren Corporation’s (Vectren) three operating public utilities:  Indiana Gas Company, Inc. (Indiana Gas or Vectren North), Southern Indiana Gas and Electric Company (SIGECO or Vectren South), and Vectren Energy Delivery of Ohio, Inc. (VEDO).  Utility Holdings also has other assets that provide information technology and other services to the three utilities.  Vectren, an Indiana corporation, is an energy holding company headquartered in Evansville, Indiana, and was organized on June 10, 1999.  Both Vectren and Utility Holdings are holding companies as defined by the Energy Policy Act of 2005 (Energy Act).
	Indiana Gas provides energy delivery services to approximately 570,000 natural gas customers located in central and southern Indiana. SIGECO provides energy delivery services to approximately 142,000 electric customers and approximately 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 312,000 natural gas customers located near Dayton in west central Ohio.

Summary_of_Significant_Account

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2013
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 related to the Company’s regulated operations is valued at historical cost consistent with ratemaking treatment.  Materials and supplies are recorded as inventory when purchased and subsequently charged to expense or capitalized to plant when installed.
	Property, Plant & Equipment
	Both the Company’s Utility Plant and Nonutility Plant is stated at historical cost, inclusive of financing costs and direct and indirect construction costs, less accumulated depreciation and when necessary, impairment charges.  The cost of renewals and betterments that extend the useful life are capitalized.  Maintenance and repairs, including the cost of removal of minor items of property and planned major maintenance projects, are charged to expense as incurred.
	Utility Plant & Related Depreciation
	Both the IURC and PUCO allow the Company’s utilities to capitalize financing costs associated with Utility Plant based on a computed interest cost and a designated cost of equity funds.  These financing costs are commonly referred to as AFUDC and are capitalized for ratemaking purposes and for financial reporting purposes instead of amounts that would otherwise be capitalized when acquiring nonutility plant.  The Company reports both the debt and equity components of AFUDC in Other – net in the Consolidated Statements of Income.
	When property that represents a retirement unit is replaced or removed, the remaining historical value of such property is charged to Utility plant, with an offsetting charge to Accumulated depreciation, resulting in no gain or loss.  Costs to dismantle and remove retired property are recovered through the depreciation rates as determined by the IURC and PUCO.
	The Company’s portion of jointly-owned Utility Plant, along with that plant’s related operating expenses, is presented in these financial statements in proportion to the ownership percentage.
	Nonutility Plant & Related Depreciation
	The depreciation of Nonutility Plant is charged against income over its estimated useful life, using the straight-line method of depreciation.  When nonutility property is retired, or otherwise disposed of, the asset and accumulated depreciation are removed, and the resulting gain or loss is reflected in income, typically impacting operating expenses.
	Impairment Reviews
	Property, plant and equipment along with other long-lived assets are reviewed as facts and circumstances indicate that the carrying amount may be impaired.  This impairment review involves the comparison of an asset’s (or group of assets’) carrying value to the estimated future cash flows the asset (or asset group) is expected to generate over a remaining life.  If this evaluation were to conclude that the carrying value is impaired, an impairment charge would be recorded based on the difference between the carrying amount and its fair value (less costs to sell for assets to be disposed of by sale) as a charge to operations or discontinued operations.  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 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 and certain asbestos-related issues 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 $29.6 million in 2013, $26.9 million in 2012, and $29.0 million in 2011.  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, 2013
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)	2013				2012
		Original Cost		Depreciation		Original Cost		Depreciation
				Rates as a				Rates as a
				Percent of				Percent of
				Original Cost				Original Cost
	Gas utility plant	$	2,762.20	3.5	%	$	2,614.30	3.5	%
	Electric utility plant	2,519.80		3.3	%	2,463.60		3.3	%
	Common utility plant	53.4		3	%	52		3	%
	Construction work in progress	54.2		—		46.9		—
	Total original cost	$	5,389.60			$	5,176.80
	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, 2013, is $186.3 million with accumulated depreciation totaling $84.4 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)	2013		2012
	Computer hardware & software	$	102.3	$	96.6
	Land & buildings	38.3		38.6
	All other	9.9		11.7
	Nonutility plant - net	$	150.5	$	146.9
	Nonutility plant is presented net of accumulated depreciation and amortization totaling $209.2 million and $201.5 million as of December 31, 2013 and 2012, respectively.  For the years ended December 31, 2013, 2012, and 2011, the Company capitalized interest totaling $0.4 million, $0.2 million, and $0.3 million, respectively, on nonutility plant construction projects.

Regulatory_Assets_Liabilities

Regulatory Assets & Liabilities	12 Months Ended
	Dec. 31, 2013
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)	2013			2012
	Future amounts recoverable from ratepayers related to:
	Deferred income taxes (See Note 5) - net	$	(5.8	)	$	(3.9	)
	Asset retirement obligations & other	2.3			2.6
		(3.5		)	(1.3		)
	Amounts deferred for future recovery related to:
	Deferred coal costs (See Note 9)	42.4			42.4
	Cost recovery riders & other	18.6			10.2
		61			52.6
	Amounts currently recovered in customer rates related to:
	Unamortized debt issue costs & hedging proceeds	34.6			32.6
	Demand side management programs	2.5			4.4
	Indiana authorized trackers	30.8			32.1
	Ohio authorized trackers	7.9			1.5
	Premiums paid to reacquire debt	2.2			2.7
	Other base rate recoveries	0.7			1.9
		78.7			75.2
	Total regulatory assets	$	136.2		$	126.5
	Of the $78.7 million currently being recovered in customer rates, $2.5 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 $40 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, 2013 and 2012, the Company has approximately $387.3 million and $364.2 million, respectively, in Regulatory liabilities.  Of these amounts, $373.0 million and $349.5 million relate to cost of removal obligations.  The remaining amounts primarily relate to timing differences associated with asset retirement obligations and deferred financing costs.

Transactions_with_Other_Vectre

Transactions with Other Vectren Companies and Affiliates	12 Months Ended
	Dec. 31, 2013
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 Fuels, Inc.
	Vectren Fuels, Inc., a wholly owned subsidiary of Vectren, owns coal mines from which SIGECO purchases coal used for electric generation.  The price of coal that is charged by Vectren Fuels to SIGECO is priced consistent with contracts reviewed by the OUCC and on file with IURC.  Amounts purchased for the years ended December 31, 2013, 2012 and 2011, totaled $103.7 million, $115.6 million, and $144.1 million, respectively.  Amounts owed to Vectren Fuels at December 31, 2013 and 2012 are included in Payables to other Vectren companies.
	Vectren Infrastructure Services Corporation (VISCO)
	VISCO, a wholly owned subsidiary of Vectren, performs natural gas and water distribution, transmission, and construction repair and rehabilitation primarily in the Midwest and the repair and rehabilitation of gas, water, and wastewater facilities nationwide. In addition, VISCO also provides transmission pipeline construction and maintenance; pump station, compressor station, terminal and refinery construction; and hydrostatic testing to customers generally in the northern Midwest region. VISCO’s customers include Utility Holdings’ utilities.  Fees incurred by Utility Holdings and its subsidiaries totaled $54.2 million in 2013, $46.6 million in 2012, and $43.1 million in 2011.  Amounts owed to VISCO at December 31, 2013 and 2012 are included in Payables to other Vectren companies.
	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.
	Purchases from ProLiance for resale and for injections into storage for the years ended December 31, 2013, 2012 and 2011 totaled $200.5 million, $274.5 million, and $375.7 million, respectively.  The Company did not have any amounts owed to ProLiance for purchases at December 31, 2013, and amounts owed to ProLiance at December 31, 2012 were $29.7 million and are included in Accounts payable to affiliated companies in the Consolidated Balance Sheets.  The Company purchased approximately 52 percent of its gas through ProLiance in 2013, and 97 percent in 2012 and 2011.  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 91 percent is from a single third party.
	Vectren Source
	Vectren Source, a former wholly owned and nonutility subsidiary of Vectren that was sold on December 31, 2011, provided natural gas and other related products and services in the Midwest and Northeast United States to approximately 283,000 residential and commercial customers as of the date of sale.  This customer base reflected approximately 143,000 customers in VEDO’s service territory that had either voluntarily opted to choose their natural gas supplier or were supplied natural gas by Vectren Source but remained customers of the regulated utility as part of VEDO’s exit the merchant function process.  From January 2010 through the date of sale, Vectren Source sold gas commodity directly to customers in VEDO’s service territory and VEDO purchased receivables from Vectren Source to include those sales in one customer bill similar to the receivables purchased from Vectren Source related to customers that voluntarily chose Vectren Source as their supplier.  Total receivables purchased from Vectren Source in the year ended December 31, 2011 totaled $66.5 million.
	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 $50.9 million, $44.8 million, and $46.1 million for the years ended December 31, 2013, 2012 and 2011, respectively.
	Retirement Plans & Other Postretirement Benefits
	At December 31, 2013, 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 2013 or 2012.  For the year ended December 31, 2011, Utility Holdings contributed $33.4 million, to Vectren’s defined benefit pension plans. Such contributions were made to Vectren in total and are not plan specific.  The combined funded status of Vectren’s plans was approximately 101 percent at December 31, 2013 and 82 percent at December 31, 2012. Vectren’s management currently anticipates making no contributions to qualified pension plans in 2014, due to the plans being at or above 100 percent funded levels.
	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, 2013, 2012 and 2011, costs totaling $8.0 million, $7.2 million and $6.6 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, 2013 and 2012, $11.2 million and $10.7 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 in 2011, at December 31, 2013 and 2012, the Company has $23.6 million, and $31.1 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, 2013 and 2012, $29.6 million and $23.6 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 subsidiary tax sharing agreement and for financial reporting purposes, Vectren subsidiaries record income taxes on a separate company basis. The Company's allocated share of tax effects resulting from it being a part of Vectren's consolidated tax group are recorded at the parent company level. Current taxes payable/receivable are settled with Vectren in cash quarterly and after filing the consolidated federal and state income tax returns.
	Deferred income taxes are provided for temporary differences between the tax basis (adjusted for related unrecognized tax benefits, if any) of an asset or liability and its reported amount in the 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)	2013				2012				2011
	Current:
	Federal	$	48			$	6.1			$	10.4
	State	11				6.9				7.9
	Total current taxes	59				13				18.3
	Deferred:
	Federal	26.8				68.7				58.6
	State	0.1				4.2				6.6
	Total deferred taxes	26.9				72.9				65.2
	Amortization of investment tax credits	(0.6		)		(0.6		)		(0.6		)
	Total income tax expense	$	85.3			$	85.3			$	82.9
	A reconciliation of the federal statutory rate to the effective income tax rate follows:
		Year Ended December 31,
		2013			2012			2011
	Statutory rate	35	%		35	%		35	%
	State and local taxes-net of federal benefit	3.5			3.7			3.9
	Amortization of investment tax credit	(0.3	)		(0.3	)		(0.3	)
	State apportionment impacts	—			—			0.9
	All other - net	(0.6	)		(0.2	)		0.8
	Effective tax rate	37.6	%		38.2	%		40.3	%
	Significant components of the net deferred tax liability follow:
		At December 31,
	(In millions)	2013				2012
	Noncurrent deferred tax liabilities (assets):
	Depreciation & cost recovery timing differences	$	627.9			$	597.1
	Regulatory assets recoverable through future rates	22.8				23.5
	Alternative minimum tax carryforward	(18.5		)		(44.0		)
	Employee benefit obligations	5.2				13.4
	Regulatory liabilities to be settled through future rates	(18.7		)		(18.3		)
	Other – net	8.7				6.8
	Net noncurrent deferred tax liability	627.4				578.5
	Current deferred tax liabilities (assets):
	Deferred fuel costs - net	22.9				25.7
	Alternative minimum tax carryforward	(36.4		)		(2.7		)
	Demand side management programs	0.1				2.7
	General business credit carryforwards	(1.2		)		—
	Other – net	9.1				(5.9		)
Net current deferred tax liability (asset)	(5.5		)		19.8
Net deferred tax liability	$	621.9			$	598.3
At December 31, 2013 and 2012, investment tax credits totaling $3.2 million and $3.8 million, respectively, are included in Deferred credits & other liabilities.  At December 31, 2013, the Company has alternative minimum tax carryforwards of $54.9 million, which do not expire. In addition, the Company has $1.2 million in general business credit carryfowards, which will expire in 5 years.
Indiana House Bill 1004
In May 2011, House Bill 1004 was signed into law. This legislation phases in over four years a 2 percent rate reduction to the Indiana Adjusted Gross Income Tax for corporations. Pursuant to House Bill 1004, the tax rate will be lowered by 0.5 percent each year beginning on July 1, 2012, to the final rate of 6.5 percent effective July 1, 2015. Pursuant to FASB guidance, the Company accounted for the effect of the change in tax law on its deferred taxes in the second quarter of 2011, the period of enactment.  The remeasurement of these temporary differences at the lower tax rate was recorded as a reduction of a regulatory asset.
Uncertain Tax Positions
Following is a roll forward of the total amount of unrecognized tax benefits for the three years ended December 31, 2013:
(In millions)	2013				2012				2011
Unrecognized tax benefits at January 1	$	3.7			$	11			$	11.8
Gross increases - tax positions in prior periods	—				0.1				3.3
Gross decreases - tax positions in prior periods	(0.2		)		(9.3		)		(4.4		)
Gross increases - current period tax positions	1.2				1.9				0.6
Settlements	—				—				(0.3		)
Unrecognized tax benefits at December 31	$	4.7			$	3.7			$	11
Of the change in unrecognized tax benefits during 2013, 2012, and 2011, almost none impacted the effective rate.  The amount of unrecognized tax benefits, which if recognized, that would impact the effective tax rate was almost none at December 31, 2013 , 2012, and 2011.  As of December 31, 2013, the unrecognized tax benefit relates to tax positions for which the ultimate deductibility is more likely than not but for which there is uncertainty about the timing of such deductibility.  Because of the impact of deferred tax accounting, other than interest and penalties, the disallowance of the shorter deductibility period would not affect the annual effective tax rate but would accelerate the payment of cash to the taxing authority. Thus, it is not expected that any changes to these tax positions would have a significant impact on earnings.
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 $0.7 million, and recognized expense related to interest and penalties totaling approximately $0.4 million in 2011.  The Company had approximately $0.2 million for the payment of interest and penalties accrued as of December 31, 2013 and 2012.
The net liability on the Consolidated Balance Sheet for unrecognized tax benefits inclusive of interest, penalties and net of secondary impacts which are a component of the Deferred income taxes and are benefits, totaled $4.5 million and $3.6 million, respectively, at December 31, 2013 and 2012.
The Internal Revenue Service (IRS) has concluded examinations of Vectren's U.S. federal income tax returns for tax years through December 31, 2008. The primary focus of the 2008 IRS examination was certain repairs and maintenance deductions, an area of particular focus by the IRS throughout the utility industry. In 2012, the IRS suspended all examinations related to this issue generally, resulting in the elimination of the audit risk in this area for Vectren through 2012. The Company does not expect any changes to this liability for unrecognized income tax benefits within the next 12 months that would significantly impact the Company's results of operations or financial condition. The State of Indiana, Vectren'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 Internal Revenue Service (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, but may be adopted for 2013 tax years. The Company intends to adopt the guidance for its 2014 tax year. 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 guidance with respect to natural gas transmission and distribution assets during 2014. 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.

Borrowing_Arrangements

Borrowing Arrangements	12 Months Ended
	Dec. 31, 2013
Debt Disclosure [Abstract]	'
Borrowing Arrangements	'
	Borrowing Arrangements
	Short-Term Borrowings
	At December 31, 2013, the Company has $350 million of short-term borrowing capacity.  As reduced by borrowings outstanding at December 31, 2013, approximately $321 million was available.  This short-term credit facility was renewed in November 2011 and is available through September 2016. 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)		2013				2012			2011
	Year End
	Balance Outstanding		$	28.6			$	116.7		$	242.8
	Weighted Average Interest Rate		0.29		%		0.4		%	0.57		%
	Annual Average
	Balance Outstanding		$	119.6			$	77.6		$	39.6
	Weighted Average Interest Rate		0.34		%		0.47		%	0.48		%
	Maximum Month End Balance Outstanding		$	176.1			$	214.2		$	242.8
	Throughout 2013, 2012, and most of 2011, 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)	2013				2012
	Utility Holdings
	Fixed Rate Senior Unsecured Notes
	2013, 5.25%	$	—			$	100
	2015, 5.45%	75				75
	2018, 5.75%	100				100
	2020, 6.28%	100				100
	2021, 4.67%	55				55
	2023, 3.72%	150				—
	2026, 5.02%	60				60
	2028, 3.20%	45				—
	2035, 6.10%	75				75
	2039, 6.25%	—				121.6
	2041, 5.99%	35				35
	2042, 5.00%	100				100
	2043, 4.25%	80				—
	Total Utility Holdings	875				821.6
	SIGECO
	First Mortgage Bonds
	2015, 1985 Pollution Control Series A, current adjustable rate 0.05%, tax exempt,
	2013 weighted average: 0.10%	9.8				9.8
	2016, 1986 Series, 8.875%	13				13
	2020, 1998 Pollution Control Series B, 4.50%, tax exempt	—				4.6
	2022, 2013 Series C, 1.95%, tax exempt	4.6				—
	2023, 1993 Environmental Improvement Series B, 5.15%, tax exempt	—				22.6
	2024, 2000 Environmental Improvement Series A, 4.65%, tax exempt	—				22.5
	2024, 2013 Series D, 1.95%, tax exempt	22.5				—
	2025, 1998 Pollution Control Series A, current adjustable rate 0.05%, tax exempt,
	2013 weighted average: 0.10%	31.5				31.5
	2029, 1999 Series, 6.72%	80				80
	2030, 1998 Pollution Control Series B, 5.00%, tax exempt	—				22
	2030, 1998 Pollution Control Series C, 5.35%, tax exempt	—				22.2
	2037, 2013 Series E, 1.95%, tax exempt	22				—
	2038, 2013 Series A, 4.0%, tax exempt	22.2				—
	2040, 2009 Environmental Improvement Series, 5.40%, tax exempt	22.3				22.3
	2041, 2007 Pollution Control Series, 5.45%, tax exempt	—				17
	2043, 2013 Series B, 4.05%, tax exempt	39.6				—
	Total SIGECO	267.5				267.5
	Indiana Gas
	Senior Unsecured Notes
	2013, Series E, 6.69%	—				5
	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				121
Total long-term debt outstanding	1,258.50				1,210.10
Current maturities of long-term debt	—				(105.0		)
Unamortized debt premium & discount - net	(1.4		)		(1.7		)
Total long-term debt-net	$	1,257.10			$	1,103.40
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 Indiana Gas, SIGECO and VEDO.
On August 22, 2013, VUHI entered into a private placement note purchase agreement with a delayed draw feature, pursuant to which institutional investors agreed to purchase $150 million of senior guaranteed notes with a fixed interest rate of 3.72 percent per annum, due December 5, 2023. The notes were unconditionally guaranteed by Indiana Gas, SIGECO, and VEDO. On December 5, 2013, the Company received net proceeds of $149.1 million from the issuance of the senior guaranteed notes, which were used to refinance $100 million of 5.25 percent senior notes that matured August 1, 2013, for capital expenditures, and for general corporate purposes.
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.
Utility Holdings 2011 Debt Issuance
On November 21, 2011, the Company exercised a call option on $96.2 million 5.95 percent senior notes due in 2036. This debt was refinanced on November 30, 2011. On that date, Utility Holdings closed a financing under a private placement note purchase agreement pursuant to which various institutional investors purchased the following tranches of notes:  (i) $55 million of 4.67 percent Senior Guaranteed Notes, due November 30, 2021, (ii) $60 million of 5.02 percent Senior Guaranteed Notes, due November 30, 2026, and (iii) $35 million of 5.99 percent Senior Guaranteed Notes, due December 2, 2041.  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 $149 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.
Long-Term Debt Puts, Calls, and Mandatory Tenders
Certain long-term debt issues contain optional put and call provisions that can be exercised on various dates before maturity.  During 2013, the Company had no repayments related to investor put provisions and at December 31, 2013, the only debt with investor puts were two series of SIGECO variable rate demand bonds, aggregating $41.3 million, with a variable interest rate that is reset weekly.  This SIGECO debt is fully supported by letters of credit that are available should any of the debt holders decide to put the debt to SIGECO and the remarketing agent is unable to remarket it to other investors.
Certain other series of SIGECO bonds, aggregating $49.1 million, currently bear interest at fixed rates and are subject to mandatory tender in September 2017.
In March and April, 2013, the Company notified holders of six issues of SIGECO's tax exempt long-term debt totaling $110.9 million with interest rates ranging from 4.50 percent to 5.45 percent, and with maturity dates from 2020 to 2041 of its intent to call this debt. The call options were exercised at par in April and May, 2013.
Letters of Credit Supporting Long-Term Debt
As of December 31, 2013, the Company has letters of credit outstanding in support of two SIGECO tax exempt adjustable rate first mortgage bonds totaling $41.7 million.  In the unlikely event the letters of credit were called, the Company could settle with the financial institutions supporting these letters of credit with general assets or by drawing from the credit facility that expires in September 2016.  Due to the long-term nature of the credit agreement, such debt is classified as long-term at December 31, 2013.
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 2013 sinking fund requirement by this means and, accordingly, the sinking fund requirement for 2013 is excluded from Current liabilities in the Consolidated Balance Sheets.  At December 31, 2013, $1.2 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 $2.9 billion at December 31, 2013.
Consolidated maturities of long-term debt during the years following 2013 (in millions) are zero in 2014, $104.8 in 2015, $13.0 in 2016, zero in 2017, $100.0 in 2018, and $1,039.3 thereafter.
Debt Guarantees
Utility Holdings’ currently outstanding long-term and short-term debt is jointly and severally guaranteed by Indiana Gas, SIGECO, and VEDO.  Utility Holdings’ long-term debt and short-term debt outstanding at December 31, 2013, totaled $875 million and $29 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, 2013, the Company was in compliance with all financial covenants.

Common_Shareholders_Equity

Common Shareholder's Equity	12 Months Ended
	Dec. 31, 2013
Stockholders' Equity Note [Abstract]	'
Common Shareholder's Equity	'
	Common Shareholder’s Equity
	During the years ended December 31, 2013, 2012, and 2011, the Company has cumulatively received additional capital of $13.1 million from Vectren which was funded by new share issues from Vectren’s dividend reinvestment plan and other stock plans.

Commitments_and_Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2013
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 2013 and thereafter (in millions) are $0.8 in 2014, $0.4 in 2015, $0.3 in 2016, $0.3 in 2017, $0.2 in 2018, and zero thereafter.  Total lease expense (in millions) was $1.1 in 2013, $1.2 in 2012, and $0.6 in 2011.  Firm purchase commitments for utility plant total $0.5 million in 2014 and zero in 2015 and 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.

Rate_Regulatory_Matters

Rate & Regulatory Matters	12 Months Ended
	Dec. 31, 2013
Public Utilities, General Disclosures [Abstract]	'
Rate and Regulatory Matters	'
	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 replacement programs in both Indiana and Ohio, the primary purpose of which is preventive maintenance and continual renewal and operational improvement. Laws in both Indiana and Ohio were passed that expand the ability of utilities to recover certain costs of federally mandated projects and other infrastructure improvement projects, outside of a base rate proceeding.  Utilization of these recovery mechanisms is discussed below.
	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 recovered through the DRR. The order also established a prospective bill impact evaluation on the annual deferrals, limiting the deferrals at a level which would equal a change over the prior year rate of $1.00 per residential and small general service customer per month. To date, the Company has made capital investments under this rider totaling $109.0 million. During 2013, 2012, and 2011 gas operating revenues associated with the DRR were $9.8 million, $6.5 million, and $3.6 million, respectively. Other income associated with the debt-related post in service carrying costs totaled $2.0 million, $1.8 million, and $2.0 million for 2013, 2012, and 2011, respectively. Regulatory assets associated with post in service carrying costs and depreciation deferrals were $9.3 million, $6.5 million, and $3.0 million at December 31, 2013, 2012, and 2011 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 approved a Stipulation entered into by the PUCO Staff and the Company which provided for the extension of the DRR through 2017 and expanded the types of investment covered by the DRR to include recovery of other infrastructure investments.  The Order approved the Company's five-year capital expenditure plan for calendar years 2013 through 2017 totaling $187 million related to these infrastructure investments, along with savings credits associated with reduced operations and maintenance expenses for each mile of aging infrastructure replaced. In addition, the Order approved the Company's commitment that the DRR can only be further extended as part of a base rate case.
	In June 2011, Ohio House Bill 95 was signed into law. Outside of a base rate proceeding, this legislation permits a natural gas company to apply for recovery of much of its capital expenditure program. The legislation also allows for the deferral of costs, such as depreciation, property taxes, and debt-related post in service carrying costs. On December 12, 2012, the PUCO issued an order approving the Company's initial application using this law, reflecting its $23.5 million capital expenditure program covering the fifteen month period ending December 31, 2012. Such capital expenditures include infrastructure expansion and improvements not covered by the DRR as well as expenditures necessary to comply with PUCO rules, regulations, orders, and system expansion to some new customers. The order also established a prospective bill impact evaluation on the cumulative deferrals, limiting the total deferrals at a level which would equal $1.50 per residential and small general service customer per month. On December 4, 2013, the Company received an order granting the accounting authority described above on its capital expenditure program for the 2013 calendar year totaling $61.5 million. In addition, the order approved the Company's proposal that subsequent requests for accounting authority will be filed annually in April. During 2013 and 2012, these approved capital expenditure programs under House Bill 95 generated Other income associated with the debt-related post in service carrying costs totaling $2.2 million and $0.9 million, respectively. Deferral of depreciation and property tax expenses related to these programs in 2013 and 2012 totaled $1.7 million and $0.6 million, respectively.
	Based on the deferral of costs and continuing recognition of debt-related post in service carrying costs using the 2009 capital structure, regulatory assets associated with these Ohio infrastructure programs increased $6.7 million in 2013. Regulatory assets are expected to continue to increase in future periods as post in service carrying costs are recognized in the statement of income and operating costs are deferred. Historical relationships between rate base growth and depreciation expense and property taxes will also be impacted.
	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 $20.0 million annually at Vectren North and $3.0 million annually at Vectren South. 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 Vectren South and four years after being placed into service at Vectren North. At December 31, 2013 and 2012, the Company has regulatory assets totaling $12.1 million and $8.5 million, respectively, associated with the deferral of depreciation and debt-related post in service carrying cost activities.
	In April 2011, 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 are to be deferred for future recovery in the utility's next general rate case.
	In April 2013, Senate Bill 560 was signed into law.  This legislation supplements Senate Bill 251 described above, which addressed federally-mandated investment, 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 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 are to be deferred for future recovery in the Company's next general rate case.  The adjustment mechanism is capped at an annual increase in retail revenues of no more than two percent.
	Pipeline Safety Law
	On January 3, 2012, the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 (Pipeline Safety Law) was signed into law. The Pipeline Safety Law, which reauthorizes federal pipeline safety programs through fiscal year 2015, provides for enhanced safety, reliability, and environmental protection in the transportation of energy products by pipeline. The law increases federal enforcement authority; grants the federal government expanded authority over pipeline safety; provides for new safety regulations and standards; and authorizes or requires the completion of several pipeline safety-related studies. The DOT is required to promulgate a number of new regulatory requirements over the next two years. Those regulations may eventually lead to further regulatory or statutory requirements.
	While the Company continues to study the impact of the Pipeline Safety Law and potential new regulations associated with its implementation, it is expected that the law will result in further investment in pipeline inspections, and where necessary, additional investments in pipeline infrastructure and, therefore, result in both increased levels of operating expenses and capital expenditures associated with the Company's natural gas distribution businesses.
	Requests for Recovery Under Regulatory Mechanisms
	The Company filed in November 2013 for authority to recover appropriate costs related to its gas infrastructure replacement and improvement programs in Indiana, including costs associated with existing pipeline safety regulations, using the mechanisms allowed under Senate Bill 251 and Senate Bill 560. The combined Vectren South and Vectren North Indiana filing requests recovery of the capital expenditures associated with the infrastructure replacement and improvement plan pursuant to the legislation, estimated to be approximately $865 million combined over the seven year period beginning in 2014, along with approximately $13 million combined annual operating costs associated with pipeline safety rules. A hearing in this proceeding is scheduled for the second quarter of 2014, and an order is expected later in 2014.
	Vectren South Electric Environmental Compliance Filing
	On January 17, 2014, Vectren South filed a request with the IURC for approval of capital investments estimated to be between $70 million and $90 million on its coal-fired generation units to comply with new EPA mandates related to mercury and air toxin standards effective in 2016. Roughly half of the investment will be made to control mercury in both air and water emissions. The remaining investment will be made to address EPA concerns on alleged increases in sulfur trioxide emissions. Although the Company believes these investments are recoverable as a federally mandated investment under Senate Bill 251, the Company has requested deferred accounting treatment in lieu of timely recovery to avoid immediate customer impacts. The accounting treatment request seeks 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 company will file its case-in-chief testimony on March 14, 2014 and a hearing is scheduled for July 9, 2014.
	Vectren South Electric Base Rate Filing
	The IURC issued an order on April 27, 2011, providing for a revenue increase to recover costs associated with approximately $325.0 million in system upgrades that were completed in the three years leading up to the December 2009 filing and modest increases in maintenance and operating expenses.  The approved revenue increase is based on rate base of $1,295.6 million, return on equity of 10.4 percent, and an overall rate of return of 7.29 percent.  The new rates were effective May 3, 2011.  The IURC, in its order, provided for deferred accounting treatment related to the Company's investment in dense pack technology, of which approximately $28.7 million was spent as of December 31, 2013. Addressing issues raised in the case concerning coal supply contracts and related costs, the IURC found that current coal contracts remain effective and that a prospective review process of future procurement decisions would be initiated and is discussed below.
	Coal Procurement Procedures
	Vectren South submitted a request for proposal (RFP) in April 2011 regarding coal purchases for a four year period beginning in 2012. After negotiations with bidders, Vectren South reached an agreement in principle for multi-year purchases with two suppliers, one of which is Vectren Fuels, Inc. Consistent with the IURC direction in the electric rate case, a sub docket proceeding was established to review the Company’s prospective coal procurement procedures, and the Company submitted evidence related to its 2011 RFP.  In March 2012, the IURC issued its order in the sub docket which concluded that Vectren South’s 2011 RFP process resulted in the lowest fuel cost reasonably possible.  In late 2012, Vectren South terminated its contract with one of the suppliers due to coal quality issues that were identified during test burns of the coal. In addition to coal purchased under these contracts, Vectren South also contracted with Vectren Fuels, Inc. in 2012 to purchase lower priced spot coal. This spot purchase, which was completed in 2012, was found to be reasonable in a recent fuel adjustment clause (FAC) order issued in July 2012. The IURC will continue to regularly monitor Vectren South’s procurement process in future fuel adjustment proceedings.
	Delivery to Vectren's power plants of lower priced contract coal from the April 2011 RFP process began during 2012. On December 5, 2011 within the quarterly FAC filing, Vectren South 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 these new term contracts effective after 2012. The cost difference was deferred to a regulatory asset and will be recovered over a six-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 deferred balance as of December 31, 2013 was $42.4 million Recovery of this deferred balance began in February 2014.
	Vectren South Electric Demand Side Management Program Filing
	On August 16, 2010, Vectren South filed a petition with the IURC, seeking approval of its proposed electric Demand Side Management (DSM) Programs, recovery of the costs associated with these programs, recovery of lost margins as a result of implementing these programs for large customers, and recovery of performance incentives linked with specific measurement criteria on all programs.  The DSM Programs proposed were consistent with a December 9, 2009 order issued by the IURC, which, among other actions, defined long-term conservation objectives and goals of DSM programs for all Indiana electric utilities under a consistent statewide approach.  In order to meet these objectives, the IURC order divided the DSM programs into Core and Core Plus programs.  Core programs are joint programs required to be offered by all Indiana electric utilities to all customers, and include some for large industrial customers.  Core Plus programs are those programs not required specifically by the IURC, but defined by each utility to meet the overall energy savings targets defined by the IURC.
	On August 31, 2011 the IURC issued an order approving an initial three year DSM plan in the Vectren South 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 discussed earlier.  For the twelve months ended December 31, 2013, the Company recognized Electric revenue of $5 million associated with this approved lost margin recovery mechanism.
	Vectren North Pipeline Safety Investigation
	On April 11, 2012, the IURC's pipeline safety division filed a complaint against Vectren North alleging several violations of safety regulations pertaining to damage that occurred at a residence in Vectren North's service territory during a pipeline replacement project. The Company negotiated a settlement with the IURC's pipeline safety division, agreeing to a fine and several modifications to the Company's operating policies. The amount of the fine was not material to the Company's financial results. The IURC approved the settlement but modified certain terms of the settlement and added a requirement that Company employees conduct inspections of pipeline excavations. The Company sought and was granted a request for rehearing on the sole issue related to the requirement to use Company employees to inspect excavations. A settlement in the case was reached between the IURC's pipeline safety division and Vectren North that allowed Vectren North to continue to use its risk based approach to inspecting excavations and to allow the Company to continue using a mix of highly trained and qualified contractors and employees to perform inspections. On January 15, 2014, the IURC issued a Final Order in the case approving the settlement agreement, without modification.
	Vectren North & Vectren South 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 gas companies and recovery of new conservation program costs through December 2015.
	FERC Return on Equity 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. In the event a refund is required upon resolution of the complaint, the parties are seeking a refund calculated as of the filing date of the complaint. The MISO transmission owners filed their response to the complaint on January 6, 2014, opposing any change to the return. In addition to the group response, the Company filed a supplemental response, stating that if FERC allows the complaint to go forward, the complaint should not be applied to the Company’s recently completed Gibson-Brown-Reid 345 Kv transmission line investment.
	FERC has no deadline for action. 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. In August 2013, a FERC administrative law judge recommended in that proceeding that the return be lowered to 9.7 percent, retroactive to the date of the complaint filing. The FERC has yet to rule on that case.
	The Company is unable to predict the outcome of the proceeding.  A 100 basis point change in the incentive rate of return would equate to approximately $0.8 million of net income on an annual basis.

Environmental_Matters

Environmental Matters	12 Months Ended
	Dec. 31, 2013
Environmental Matters Disclosure [Abstract]	'
Environmental Matters	'
	Environmental Matters
	Indiana Senate Bill 251 is also applicable to federal environmental mandates impacting Vectren South's electric operations. The Company continues to evaluate 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
	Clean Air Interstate Rule / 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.  Like CAIR, CSAPR set individual state caps for SO2 and NOx emissions.
	However, unlike CAIR in which states allocated allowances to generating units through state implementation plans, CSAPR allowances were allocated to individual units directly through the federal rule.  CSAPR reductions were to be achieved with initial step reductions beginning January 1, 2012, and final compliance to be achieved in 2014.  Multiple administrative and judicial challenges were filed. On December 30, 2011, the Court granted a stay of CSAPR and left CAIR in place pending its review. On August 21, 2012, the Court vacated CSAPR and directed the EPA to continue to administer CAIR. In October 2012, the EPA filed its request for a hearing before the full federal appeals court that struck down the CSAPR.  EPA's request for rehearing was denied by the Court on January 24, 2013. In March 2013, the EPA filed a petition for review with the US Supreme Court, and in June 2013 the Supreme Court agreed to review the lower court decision. A decision by the Supreme Court is expected in 2014. The Company remains in full compliance with CAIR (see additional information below "Conclusions Regarding Environmental Regulations").
	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. 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.  Reductions are to be achieved within three years of publication of the final rule in the Federal register (April 2015).  Initiatives to suspend CSAPR’s implementation by Congress also apply to the implementation of the MATS rule.  Multiple judicial challenges were filed and briefing is proceeding. The EPA agreed to reconsider MATS requirements for new construction. Such requirements are more stringent than those for existing plants. Utilities planning new coal-fired generation had argued standards outlined in the MATS could not be attained even using the best available control technology. The EPA issued its revised emission limits for new construction in March 2013.
	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 power plant.  The NOV asserts that when the power plant 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 is currently in discussions with the EPA to resolve this NOV.
	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.
	Water
	Section 316(b) of the Clean Water Act requires that generating facilities use the “best technology available” to minimize adverse environmental impacts in 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.  In April 2009, the U.S. Supreme Court affirmed that the EPA could, but was not required to, consider costs and benefits in making the evaluation as to the best technology available for existing generating facilities.  The regulation was remanded back to the EPA for further consideration.  In March 2011, the EPA released its proposed Section 316(b) regulations.  The EPA did not mandate the retrofitting of cooling towers in the proposed regulation, but if finalized, the regulation will leave it to each state to determine whether cooling towers should be required on a case by case basis.  A final rule is expected in 2014.  Depending on the final rule and on the Company’s facts and circumstances, capital investments could approximate $40 million if new infrastructure, such as new cooling water towers, is required.  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, EPA sets technology-based guidelines for water discharges from new and existing facilities. 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. 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 and the Company is reviewing the proposal. 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 Environmental Regulations
	To comply with Indiana’s implementation plan of the Clean Air Act, and other federal air quality standards, 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 (the Company’s portion is 150 MW).  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 new 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.
	The Company continues to review the sufficiency of its existing pollution control equipment in relation to the requirements described in the MATS Rule, the recent renewal of water discharge permits, and the NOV discussed above.  Some operational modifications to the control equipment are likely. The Company is continuing to evaluate potential technologies to address compliance and what the additional costs may be associated with these efforts. Currently, it is expected that the capital costs could be between $70 million and $90 million. Compliance is required by government regulation, and the Company believes that such additional costs, if incurred, should be recoverable under Senate Bill 251 referenced above. On January 17, 2014, the Company filed its request with the IURC seeking approval to upgrade its existing emissions control equipment to comply with the MATS Rule, take steps to address EPA's allegations in the NOV and comply with new mercury limits to the waste water discharge permits at the Culley and Brown generating stations. In that filing, the Company has proposed to defer recovery of the costs until 2020 in order to mitigate the impact on customer rates in the near term.
	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.  Rules have not been finalized given oversight hearings, congressional interest, and other factors. Recently the EPA entered into a consent decree in which it agreed to finalize by December 2014 its determination whether to regulate ash as hazardous waste, or the less stringent solid waste designation.
	At this time, the majority of the Company’s ash is being beneficially reused.  However, the alternatives proposed would require modification to, or closure of, existing ash ponds.  The Company estimates capital expenditures to comply could be as much as $30 million, and such expenditures could exceed $100 million if the most stringent of the alternatives is selected.  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 from motor vehicles cause or contribute to air pollution that may reasonably be anticipated to endanger public health or welfare.  In April 2009, the EPA published its proposed endangerment finding for public comment.  The proposed endangerment finding concludes that carbon emissions from mobile sources pose an endangerment to public health and the environment.  The endangerment finding was finalized in December 2009, and is the first step toward the EPA regulating carbon emissions through the existing Clean Air Act in the absence of specific carbon legislation from Congress.
	The EPA has promulgated two 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. In 2012, the EPA proposed New Source Performance Standards (NSPS) for GHG's for new electric generating facilities under the Clean Air Act Section 111(b). On October 15, 2013, the US Supreme Court agreed to review a focused appeal on the issue of whether the GHG rule applicable to mobile sources triggered PSD permitting for all stationary sources such as Vectren's power plants. A decision is expected in 2014.
	In July 2013, the President announced a Climate Action Plan, which calls on the EPA to re-propose and finalize the new source rule expeditiously, and by June 2014 propose, and by June 2015 finalize, NSPS standards for GHG's for existing electric generating units which would apply to Vectren's power plants. States must have their implementation plans to the EPA no later than June 2016. The President's Climate Action Plan did not provide any detail as to actual emission targets or compliance requirements. The Company anticipates that these initial standards will focus on power plant efficiency and other coal fleet carbon intensity reduction measures. The Company believes that such additional costs, if necessary, should be recoverable under Indiana Senate Bill 251 referenced above.
	Numerous competing federal legislative proposals have also been introduced in recent years that involve carbon, energy efficiency, and renewable energy.  Comprehensive energy legislation at the federal level continues to be debated, but there has been little progress to date.  The progression of regional initiatives throughout the United States has also slowed.
	Impact of Legislative Actions & Other Initiatives is Unknown
	If regulations are enacted by the EPA or other agencies 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 are based on highly uncertain assumptions, including allowance prices if a cap and trade approach were employed, and energy efficiency targets.  Costs to purchase allowances that cap GHG emissions or expenditures made to control emissions 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 referenced above.
	Senate Bill 251 also established a voluntary clean energy portfolio standard that provides incentives to Indiana electricity suppliers participating in the program. The goal of the program is that by 2025, at least 10 percent of the total electricity obtained by the supplier to meet the energy needs of Indiana retail customers will be provided by clean energy sources, as defined. In advance of a federal portfolio standard and Senate Bill 251, SIGECO received regulatory approval to purchase a 3 MW landfill gas generation facility from a related entity. The facility was purchased in 2009 and is directly connected to the Company's distribution system. 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 5 percent of its electricity being provided by clean energy sources due to the long-term wind contracts and landfill gas investment.
	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, 2013 and 2012, approximately $5.7 million and $4.6 million, respectively, of accrued, but not yet spent, costs are included in Other Liabilities related to the Indiana Gas and SIGECO sites.

Fair_Value_Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2013
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,
		2013				2012
	(In millions)	Carrying		Est. Fair		Carrying		Est. Fair
		Amount		Value		Amount		Value
	Long-term debt	$	1,257.10	$	1,317.40	$	1,208.40	$	1,372.60
	Short-term borrowings	28.6		28.6		116.7		116.7
	Cash & cash equivalents	8.6		8.6		13.3		13.3
	For the balance sheet dates presented in these financial statements, the Company had no material assets or liabilities recorded at fair value outstanding, and no material assets or liabilities valued using Level 3 inputs.
	Certain methods and assumptions must be used to estimate the fair value of financial instruments.  The fair value of the Company's long-term debt was estimated based on the quoted market prices for the same or similar issues or on the current rates offered to the Company for instruments with similar characteristics.  Because of the maturity dates and variable interest rates of short-term borrowings and cash & cash equivalents, those carrying amounts approximate fair value.  Because of the inherent difficulty of estimating interest rate and other market risks, the methods used to estimate fair value may not always be indicative of actual realizable value, and different methodologies could produce different fair value estimates at the reporting date.
	Under current regulatory treatment, call premiums on reacquisition of long-term debt are generally recovered in customer rates over the life of the refunding issue or over a 15-year period.  Accordingly, any reacquisition would not be expected to have a material effect on the Company's results of operations.

Segment_Reporting

Segment Reporting	12 Months Ended
	Dec. 31, 2013
Segment Reporting [Abstract]	'
Segment Reporting	'
	Segment Reporting
	The Company’s operations consist of regulated operations and other operations that provide information technology and other support services to those regulated operations.  The Company segregates its regulated operations between a Gas Utility Services operating segment and an Electric Utility Services operating segment.  The Gas Utility Services segment provides natural gas distribution and transportation services to nearly two-thirds of Indiana and to west central Ohio.  The Electric Utility Services segment provides electric distribution services primarily to southwestern Indiana, and includes the Company’s power generating and wholesale power operations.  Regulated operations supply natural gas and/or electricity to over one million customers.  In total, the Company is comprised of three operating segments:  Gas Utility Services, Electric Utility Services, and Other Shared Service operations.  Net income is the measure of profitability used by management for all operations.
	Information related to the Company’s business segments is summarized below:
		Year Ended December 31,
	(In millions)	2013			2012			2011
	Revenues
	Gas Utility Services	$	810		$	738.1		$	819.1
	Electric Utility Services	619.3			594.9			635.9
	Other Operations	38.1			40.1			43.9
	Eliminations	(37.8		)	(39.5		)	(41.9		)
	Total revenues	$	1,429.60		$	1,333.60		$	1,457.00
	Profitability Measure - Net Income
	Gas Utility Services	$	55.7		$	60		$	52.5
	Electric Utility Services	75.8			68			65
	Other Operations	10.3			10			5.4
	Total net income	$	141.8		$	138		$	122.9
	Amounts Included in Profitability Measures
	Depreciation & Amortization
	Gas Utility Services	$	90.5		$	85.4		$	84.3
	Electric Utility Services	84			81.3			80.2
	Other Operations	21.9			23.3			27.8
	Total depreciation & amortization	$	196.4		$	190		$	192.3
	Interest Expense
	Gas Utility Services	$	30.6		$	31.8		$	37.1
	Electric Utility Services	29.2			33.8			36.4
	Other Operations	5.2			5.9			6.8
	Total interest expense	$	65		$	71.5		$	80.3
	Income Taxes
	Gas Utility Services	$	36.6		$	39.1		$	34.5
	Electric Utility Services	48.3			46.4			45.3
	Other Operations	0.4			(0.2		)	3.1
	Total income taxes	$	85.3		$	85.3		$	82.9
	Capital Expenditures
	Gas Utility Services	$	150.5		$	128.8		$	113.5
	Electric Utility Services	100			108.8			102.2
	Other Operations	25.8			16.2			17.8
	Non-cash costs & changes in accruals	(13.8		)	(6.2		)	1.8
	Total capital expenditures	$	262.5		$	247.6		$	235.3
			At December 31,
	(In millions)		2013			2012			2011
	Assets
	Gas Utility Services		$	2,287.90		$	2,173.50		$	2,125.20
	Electric Utility Services		1,679.00			1,705.10			1,656.50
	Other Operations, net of eliminations		173.9			168.2			192.8
	Total assets		$	4,140.80		$	4,046.80		$	3,974.50

Additional_Balance_Sheet_Opera

Additional Balance Sheet & Operational Information	12 Months Ended
	Dec. 31, 2013
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)	2013		2012
	Gas in storage – at LIFO cost	$	33.2	$	22.4
	Materials & supplies	39		38.4
	Coal & oil for electric generation - at average cost	16.5		52
	Other	1.2		1.2
	Total inventories	$	89.9	$	114
	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, 2013 and 2012 by approximately $9 million and $12 million, respectively.
	Prepayments & other current assets in the Consolidated Balance Sheets consist of the following:
		At December 31,
	(In millions)	2013		2012
	Prepaid gas delivery service	$	32.9	$	28.5
	Prepaid taxes	0.2		21.1
	Deferred income taxes	5.5		—
	Other prepayments & current assets	3.8		2.7
	Total prepayments & other current assets	$	42.4	$	52.3
	Other investments in the Consolidated Balance Sheets consist of the following:
		At December 31,
	(In millions)	2013		2012
	Cash surrender value of life insurance policies	$	22.3	$	27.4
	Municipal bond	3.4		3.6
	Restricted cash & other investments	1.6		1.6
	Total other investments	$	27.3	$	32.6
	Accrued liabilities in the Consolidated Balance Sheets consist of the following:
		At December 31,
	(In millions)	2013		2012
	Refunds to customers & customer deposits	$	50.2	$	53.1
	Accrued taxes	32.3		30.7
	Accrued interest	16.2		19.4
	Deferred income taxes	—		19.8
	Accrued salaries & other	28.7		16.3
	Total accrued liabilities	$	127.4	$	139.3
	Asset retirement obligations included in Deferred Credits and Other Liabilities in the Consolidated Balance Sheets roll forward as follows:
	(In millions)	2013		2012
	Asset retirement obligation, January 1	$	27.3	$	34
	Accretion	1.6		2.2
	Changes in estimates, net of cash payments	0.2		(8.9		)
	Asset retirement obligation, December 31	$	29.1	$	27.3
	Other – net in the Consolidated Statements of Income consists of the following:
		Year Ended December 31,
	(In millions)	2013		2012			2011
	AFUDC - borrowed funds	$	5.9	$	4.6		$	2.5
	AFUDC - equity funds	0.8		0.4			0.2
	Nonutility plant capitalized interest	0.4		0.2			0.3
	Interest income	0.6		0.6			0.6
	Cash surrender value of life insurance policies	1.7		1.4			0.1
	Other income	1.1		0.8			0.6
	Total other – net	$	10.5	$	8		$	4.3
	Supplemental Cash Flow Information:
		Year Ended December 31,
	(In millions)	2013		2012			2011
	Cash paid (received) for:
	Interest	$	68.2	$	69.6		$	82.5
	Income taxes	30.9		30.1			(3.4		)
	As of December 31, 2013 and 2012, the Company has accruals related to utility and nonutility plant purchases totaling approximately $13.1 million and $7.1 million, respectively.

Subsidiary_Guarantor_and_Conso

Subsidiary Guarantor and Consolidating Information	12 Months Ended
	Dec. 31, 2013
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 $29 million is outstanding at December 31, 2013, and Utility Holdings’ $875 million unsecured senior notes outstanding at December 31, 2013.  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, 2013 (in millions):
		Subsidiary			Parent			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			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 Statement of Income for the year ended December 31, 2011 (in millions):
		Subsidiary			Parent			Eliminations			Consolidated
		Guarantors			Company
	OPERATING REVENUES
	Gas utility	$	819.1		$	—		$	—		$	819.1
	Electric utility	635.9			—			—			635.9
	Other	—			43.9			(41.9		)	2
	Total operating revenues	1,455.00			43.9			(41.9		)	1,457.00
	OPERATING EXPENSES
	Cost of gas sold	375.4			—			—			375.4
	Cost of fuel & purchased power	240.4			—			—			240.4
	Other operating	354.6			—			(41.5		)	313.1
	Depreciation & amortization	164.6			27.1			0.6			192.3
Taxes other than income taxes	52.3			1.5			0.2			54
Total operating expenses	1,187.30			28.6			(40.7		)	1,175.20
OPERATING INCOME	267.7			15.3			(1.2		)	281.8
OTHER INCOME (EXPENSE)
Equity in earnings of consolidated companies	—			117.5			(117.5		)	—
Other – net	3.1			48.9			(47.7		)	4.3
Total other income (expense)	3.1			166.4			(165.2		)	4.3
Interest expense	73.5			55.7			(48.9		)	80.3
INCOME BEFORE INCOME TAXES	197.3			126			(117.5		)	205.8
Income taxes	79.8			3.1			—			82.9
NET INCOME	$	117.5		$	122.9		$	(117.5	)	$	122.9
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 Balance Sheet as of December 31, 2012 (in millions):
ASSETS	Subsidiary			Parent
	Guarantors			Company			Eliminations			Consolidated
Current Assets
Cash & cash equivalents	$	12.5		$	0.8		$	—		$	13.3
Accounts receivable - less reserves	81.8			—			—			81.8
Intercompany receivables	—			145.1			(145.1		)	—
Accrued unbilled revenues	93.6			—			—			93.6
Inventories	114			—			—			114
Recoverable fuel & natural gas costs	25.3			—			—			25.3
Prepayments & other current assets	52			5.8			(5.5		)	52.3
Total current assets	379.2			151.7			(150.6		)	380.3
Utility Plant
Original cost	5,176.60			0.2			—			5,176.80
Less:  accumulated depreciation & amortization	2,057.20			—			—			2,057.20
Net utility plant	3,119.40			0.2			—			3,119.60
Investments in consolidated subsidiaries	—			1,329.20			(1,329.2		)	—
Notes receivable from consolidated subsidiaries	—			679.7			(679.7		)	—
Investments in unconsolidated affiliates	0.2			—			—			0.2
Other investments	27.8			4.8			—			32.6
Nonutility plant - net	2.6			144.3			—			146.9
Goodwill - net	205			—			—			205
Regulatory assets	104.1			22.4			—			126.5
Other assets	40.4			1.7			(6.4		)	35.7
TOTAL ASSETS	$	3,878.70		$	2,334.00		$	(2,165.9	)	$	4,046.80
LIABILITIES & SHAREHOLDER'S EQUITY	Subsidiary			Parent
	Guarantors			Company			Eliminations			Consolidated
Current Liabilities
Accounts payable	$	114.8		$	6.2		$	—		$	121
Accounts payable to affiliated companies	29.7			—			—			29.7
Intercompany payables	10.6			—			(10.6		)	—
Payables to other Vectren companies	25.1			—			—			25.1
Accrued liabilities	131.3			13.5			(5.5		)	139.3
Short-term borrowings	—			116.7			—			116.7
Intercompany short-term borrowings	134.5			—			(134.5		)	—
Current maturities of long-term debt	5			100			—			105
Total current liabilities	451			236.4			(150.6		)	536.8
Long-Term Debt
Long-term debt - net of current maturities &
debt subject to tender	382.3			721.1			—			1,103.40
Long-term debt due to VUHI	679.7			—			(679.7		)	—
Total long-term debt - net	1,062.00			721.1			(679.7		)	1,103.40
Deferred Income Taxes & Other Liabilities
Deferred income taxes	595.4			(16.9		)	—			578.5
Regulatory liabilities	362.2			2			—			364.2
Deferred credits & other liabilities	78.9			1.4			(6.4		)	73.9
Total deferred credits & other liabilities	1,036.50			(13.5		)	(6.4		)	1,016.60
Common Shareholder's Equity
Common stock (no par value)	787.8			781.6			(787.8		)	781.6
Retained earnings	541.4			608.4			(541.4		)	608.4
Total common shareholder's equity	1,329.20			1,390.00			(1,329.2		)	1,390.00
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	$	3,878.70		$	2,334.00		$	(2,165.9	)	$	4,046.80
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
Consolidating Statement of Cash Flows for the year ended December 31, 2011 (in millions):
	Subsidiary			Parent			Eliminations			Consolidated
	Guarantors			Company
NET CASH FLOWS FROM OPERATING ACTIVITIES	$	316.2		$	18.1		$	—		$	334.3
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt - net of issuance costs	248.4			148.9			(248.4		)	148.9
Requirements for:
Dividends to parent	(84.4		)	(91.6		)	84.4			(91.6		)
Retirement of long-term debt, including premiums paid	(337.4		)	(347.0		)	337.4			(347.0		)
Other financing activities	—			(1.1		)	—			(1.1		)
Net change in intercompany short-term borrowings	13.4			(277.6		)	264.2			—
Net change in short-term borrowings	—			195.8			—			195.8
Net cash flows from financing activities	(160.0		)	(372.6		)	437.6			(95.0		)
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from:
Consolidated subsidiary distributions	—			84.4			(84.4		)	—
Other investing activities	0.2			0.2			—			0.4
Requirements for:
Capital expenditures, excluding AFUDC equity	(218.2		)	(17.1		)	—			(235.3		)
Other investing activities	(0.8		)	—			—			(0.8		)
Net change in long-term intercompany notes receivable	—			89			(89.0		)	—
Net change in short-term intercompany notes receivable	65.9			198.3			(264.2		)	—
Net cash flows from investing activities	(152.9		)	354.8			(437.6		)	(235.7		)
Net change in cash & cash equivalents	3.3			0.3			—			3.6
Cash & cash equivalents at beginning of period	2			0.4			—			2.4
Cash & cash equivalents at end of period	$	5.3		$	0.7		$	—		$	6

Impact_of_Recently_Issued_Acco

Impact of Recently Issued Accounting Guidance	12 Months Ended
	Dec. 31, 2013
Impact of Recently Issued Accounting Principles [Abstract]	'
Recently Issued Accounting Standards	'
	Impact of Recently Issued Accounting Guidance
	Offsetting Assets and Liabilities
	In January 2013, the FASB issued new accounting guidance on disclosures of offsetting assets and liabilities. This guidance amends prior requirements to add clarification to the scope of the offsetting disclosures. The amendment clarifies that the scope applies to derivative instruments accounted for in accordance with reporting topics on derivatives and hedging, including bifurcated embedded derivatives, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions that are either offset in accordance with US GAAP or subject to an enforceable master netting arrangement or similar agreement. This guidance is effective for fiscal years beginning on or after January 1, 2013 and interim periods within annual periods. The Company adopted this guidance as of January 1, 2013. The adoption of this guidance did not have a material impact on the Company's financial statements.
	Accumulated Other Comprehensive Income (AOCI)
	In February 2013, the FASB issued new accounting guidance on the reporting of reclassifications from AOCI. The guidance requires an entity to report the effect of significant reclassification from AOCI on the respective line items in net income if the amount being reclassified is required under US GAAP to be reclassified in its entirety to net income. For other amounts that are not required under US GAAP to be reclassified in their entirety to net income in the same reporting period, an entity is required to cross-reference to other disclosures required that provide additional details about these amounts.  The new guidance is effective for fiscal years, and interim periods within annual periods, beginning after December 15, 2012.  As this guidance provides only disclosure requirements, the adoption of this standard did not impact the company's results of operations, cash flows or financial position.
	Unrecognized Tax Benefit Presentation
	In July 2013, the FASB issued new accounting guidance on presenting an unrecognized tax benefit when net operating loss carryforwards exist. The new standard was issued in an effort to eliminate diversity in practice resulting from a lack of guidance on this topic in the current US GAAP. The update provides that an unrecognized tax benefit, or a portion of an unrecognized tax benefit, should be presented in the financial statements as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward, except under certain circumstances outlined in the update. The amendments in the update are effective for fiscal years, and interim periods within those years, beginning after December 15, 2013, with early adoption permitted. This update is consistent with how the Company currently presents unrecognized tax benefits, therefore, adoption of this guidance resulted in no material impact on the Company's financial statements.

Quarterly_Financial_Data_Unaud

Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2013
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 2013 and 2012 follows:
	(In millions)		Q1		Q2		Q3		Q4
	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
	2012
		Results of Operations:
		Operating revenues	$	432.1	$	265.8	$	267.7	$	368
		Operating income	105.9		49.8		57.1		74
		Net income	56		20.1		26.4		35.5

SCHEDULE_II_VALUATION_AND_QUAL

SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES	12 Months Ended
	Dec. 31, 2013
Valuation and Qualifying Accounts [Abstract]	'
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES	'
	Supplemental Schedules
	For the years ended December 31, 2013, 2012, and 2011, 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 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
	Year 2011 – Accumulated provision for
	uncollectible accounts	$	4.5	$	11.4	$	—	$	10	$	5.9
	OTHER RESERVES:
	Year 2013 – Restructuring costs	$	0.3	$	—	$	—	$	0.1	$	0.2
	Year 2012 – Restructuring costs	$	0.4	$	—	$	—	$	0.1	$	0.3
	Year 2011 – Restructuring costs	$	0.4	$	—	$	—	$	—	$	0.4

Summary_of_Significant_Account1

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2013
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.
	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.
	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.
	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.
	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 related to the Company’s regulated operations is valued at historical cost consistent with ratemaking treatment.  Materials and supplies are recorded as inventory when purchased and subsequently charged to expense or capitalized to plant when installed.
Property, Plant and Equipment	'
	Property, Plant & Equipment
	Both the Company’s Utility Plant and Nonutility Plant is stated at historical cost, inclusive of financing costs and direct and indirect construction costs, less accumulated depreciation and when necessary, impairment charges.  The cost of renewals and betterments that extend the useful life are capitalized.  Maintenance and repairs, including the cost of removal of minor items of property and planned major maintenance projects, are charged to expense as incurred.
	Utility Plant & Related Depreciation
	Both the IURC and PUCO allow the Company’s utilities to capitalize financing costs associated with Utility Plant based on a computed interest cost and a designated cost of equity funds.  These financing costs are commonly referred to as AFUDC and are capitalized for ratemaking purposes and for financial reporting purposes instead of amounts that would otherwise be capitalized when acquiring nonutility plant.  The Company reports both the debt and equity components of AFUDC in Other – net in the Consolidated Statements of Income.
	When property that represents a retirement unit is replaced or removed, the remaining historical value of such property is charged to Utility plant, with an offsetting charge to Accumulated depreciation, resulting in no gain or loss.  Costs to dismantle and remove retired property are recovered through the depreciation rates as determined by the IURC and PUCO.
	The Company’s portion of jointly-owned Utility Plant, along with that plant’s related operating expenses, is presented in these financial statements in proportion to the ownership percentage.
	Nonutility Plant & Related Depreciation
	The depreciation of Nonutility Plant is charged against income over its estimated useful life, using the straight-line method of depreciation.  When nonutility property is retired, or otherwise disposed of, the asset and accumulated depreciation are removed, and the resulting gain or loss is reflected in income, typically impacting operating expenses.
	Impairment Reviews
	Property, plant and equipment along with other long-lived assets are reviewed as facts and circumstances indicate that the carrying amount may be impaired.  This impairment review involves the comparison of an asset’s (or group of assets’) carrying value to the estimated future cash flows the asset (or asset group) is expected to generate over a remaining life.  If this evaluation were to conclude that the carrying value is impaired, an impairment charge would be recorded based on the difference between the carrying amount and its fair value (less costs to sell for assets to be disposed of by sale) as a charge to operations or discontinued operations.  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 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 and certain asbestos-related issues 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 $29.6 million in 2013, $26.9 million in 2012, and $29.0 million in 2011.  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, 2013
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)	2013				2012
		Original Cost		Depreciation		Original Cost		Depreciation
				Rates as a				Rates as a
				Percent of				Percent of
				Original Cost				Original Cost
	Gas utility plant	$	2,762.20	3.5	%	$	2,614.30	3.5	%
	Electric utility plant	2,519.80		3.3	%	2,463.60		3.3	%
	Common utility plant	53.4		3	%	52		3	%
	Construction work in progress	54.2		—		46.9		—
	Total original cost	$	5,389.60			$	5,176.80
Nonutility Plant, Net of Depreciation and Amortization	'
	Nonutility plant, net of accumulated depreciation and amortization follows:
		At December 31,
	(In millions)	2013		2012
	Computer hardware & software	$	102.3	$	96.6
	Land & buildings	38.3		38.6
	All other	9.9		11.7
	Nonutility plant - net	$	150.5	$	146.9

Regulatory_Assets_Liabilities_

Regulatory Assets & Liabilities (Tables)	12 Months Ended
	Dec. 31, 2013
Regulatory Assets and Liabilities Disclosure [Abstract]	'
Schedule of Regulatory Assets	'
	Regulatory assets consist of the following:
		At December 31,
	(In millions)	2013			2012
	Future amounts recoverable from ratepayers related to:
	Deferred income taxes (See Note 5) - net	$	(5.8	)	$	(3.9	)
	Asset retirement obligations & other	2.3			2.6
		(3.5		)	(1.3		)
	Amounts deferred for future recovery related to:
	Deferred coal costs (See Note 9)	42.4			42.4
	Cost recovery riders & other	18.6			10.2
		61			52.6
	Amounts currently recovered in customer rates related to:
	Unamortized debt issue costs & hedging proceeds	34.6			32.6
	Demand side management programs	2.5			4.4
	Indiana authorized trackers	30.8			32.1
	Ohio authorized trackers	7.9			1.5
	Premiums paid to reacquire debt	2.2			2.7
	Other base rate recoveries	0.7			1.9
		78.7			75.2
	Total regulatory assets	$	136.2		$	126.5

Transactions_with_Other_Vectre1

Transactions with Other Vectren Companies and Affiliates Transactions with other Vectren Companies and Affiliates (Tables)	12 Months Ended
	Dec. 31, 2013
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)	2013				2012				2011
	Current:
	Federal	$	48			$	6.1			$	10.4
	State	11				6.9				7.9
	Total current taxes	59				13				18.3
	Deferred:
	Federal	26.8				68.7				58.6
	State	0.1				4.2				6.6
	Total deferred taxes	26.9				72.9				65.2
	Amortization of investment tax credits	(0.6		)		(0.6		)		(0.6		)
	Total income tax expense	$	85.3			$	85.3			$	82.9
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,
		2013			2012			2011
	Statutory rate	35	%		35	%		35	%
	State and local taxes-net of federal benefit	3.5			3.7			3.9
	Amortization of investment tax credit	(0.3	)		(0.3	)		(0.3	)
	State apportionment impacts	—			—			0.9
	All other - net	(0.6	)		(0.2	)		0.8
	Effective tax rate	37.6	%		38.2	%		40.3	%
Significant components of the net deferred tax liability (assets)	'
	Significant components of the net deferred tax liability follow:
		At December 31,
	(In millions)	2013				2012
	Noncurrent deferred tax liabilities (assets):
	Depreciation & cost recovery timing differences	$	627.9			$	597.1
	Regulatory assets recoverable through future rates	22.8				23.5
	Alternative minimum tax carryforward	(18.5		)		(44.0		)
	Employee benefit obligations	5.2				13.4
	Regulatory liabilities to be settled through future rates	(18.7		)		(18.3		)
	Other – net	8.7				6.8
	Net noncurrent deferred tax liability	627.4				578.5
	Current deferred tax liabilities (assets):
	Deferred fuel costs - net	22.9				25.7
	Alternative minimum tax carryforward	(36.4		)		(2.7		)
	Demand side management programs	0.1				2.7
	General business credit carryforwards	(1.2		)		—
	Other – net	9.1				(5.9		)
	Net current deferred tax liability (asset)	(5.5		)		19.8
	Net deferred tax liability	$	621.9			$	598.3
Roll forward of unrecognized tax benefits	'
	Following is a roll forward of the total amount of unrecognized tax benefits for the three years ended December 31, 2013:
	(In millions)	2013				2012				2011
	Unrecognized tax benefits at January 1	$	3.7			$	11			$	11.8
	Gross increases - tax positions in prior periods	—				0.1				3.3
	Gross decreases - tax positions in prior periods	(0.2		)		(9.3		)		(4.4		)
	Gross increases - current period tax positions	1.2				1.9				0.6
	Settlements	—				—				(0.3		)
	Unrecognized tax benefits at December 31	$	4.7			$	3.7			$	11

Borrowing_Arrangements_Tables

Borrowing Arrangements (Tables)	12 Months Ended
	Dec. 31, 2013
Debt Disclosure [Abstract]	'
Short term borrowing arrangements	'
	Following is certain information regarding these short-term borrowing arrangements:
	(In millions)		2013				2012			2011
	Year End
	Balance Outstanding		$	28.6			$	116.7		$	242.8
	Weighted Average Interest Rate		0.29		%		0.4		%	0.57		%
	Annual Average
	Balance Outstanding		$	119.6			$	77.6		$	39.6
	Weighted Average Interest Rate		0.34		%		0.47		%	0.48		%
	Maximum Month End Balance Outstanding		$	176.1			$	214.2		$	242.8
Long term senior unsecured obligations and first mortgage bonds outstanding by subsidiary	'
	Long-term senior unsecured obligations and first mortgage bonds outstanding by subsidiary follow:
		At December 31,
	(In millions)	2013				2012
	Utility Holdings
	Fixed Rate Senior Unsecured Notes
	2013, 5.25%	$	—			$	100
	2015, 5.45%	75				75
	2018, 5.75%	100				100
	2020, 6.28%	100				100
	2021, 4.67%	55				55
	2023, 3.72%	150				—
	2026, 5.02%	60				60
	2028, 3.20%	45				—
	2035, 6.10%	75				75
	2039, 6.25%	—				121.6
	2041, 5.99%	35				35
	2042, 5.00%	100				100
	2043, 4.25%	80				—
	Total Utility Holdings	875				821.6
	SIGECO
	First Mortgage Bonds
	2015, 1985 Pollution Control Series A, current adjustable rate 0.05%, tax exempt,
	2013 weighted average: 0.10%	9.8				9.8
	2016, 1986 Series, 8.875%	13				13
	2020, 1998 Pollution Control Series B, 4.50%, tax exempt	—				4.6
	2022, 2013 Series C, 1.95%, tax exempt	4.6				—
	2023, 1993 Environmental Improvement Series B, 5.15%, tax exempt	—				22.6
	2024, 2000 Environmental Improvement Series A, 4.65%, tax exempt	—				22.5
	2024, 2013 Series D, 1.95%, tax exempt	22.5				—
	2025, 1998 Pollution Control Series A, current adjustable rate 0.05%, tax exempt,
	2013 weighted average: 0.10%	31.5				31.5
	2029, 1999 Series, 6.72%	80				80
	2030, 1998 Pollution Control Series B, 5.00%, tax exempt	—				22
	2030, 1998 Pollution Control Series C, 5.35%, tax exempt	—				22.2
	2037, 2013 Series E, 1.95%, tax exempt	22				—
	2038, 2013 Series A, 4.0%, tax exempt	22.2				—
	2040, 2009 Environmental Improvement Series, 5.40%, tax exempt	22.3				22.3
	2041, 2007 Pollution Control Series, 5.45%, tax exempt	—				17
	2043, 2013 Series B, 4.05%, tax exempt	39.6				—
	Total SIGECO	267.5				267.5
	Indiana Gas
	Senior Unsecured Notes
	2013, Series E, 6.69%	—				5
	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				121
	Total long-term debt outstanding	1,258.50				1,210.10
	Current maturities of long-term debt	—				(105.0		)
	Unamortized debt premium & discount - net	(1.4		)		(1.7		)
	Total long-term debt-net	$	1,257.10			$	1,103.40

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2013
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,
		2013				2012
	(In millions)	Carrying		Est. Fair		Carrying		Est. Fair
		Amount		Value		Amount		Value
	Long-term debt	$	1,257.10	$	1,317.40	$	1,208.40	$	1,372.60
	Short-term borrowings	28.6		28.6		116.7		116.7
	Cash & cash equivalents	8.6		8.6		13.3		13.3

Segment_Reporting_Tables

Segment Reporting (Tables)	12 Months Ended
	Dec. 31, 2013
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)	2013			2012			2011
	Revenues
	Gas Utility Services	$	810		$	738.1		$	819.1
	Electric Utility Services	619.3			594.9			635.9
	Other Operations	38.1			40.1			43.9
	Eliminations	(37.8		)	(39.5		)	(41.9		)
	Total revenues	$	1,429.60		$	1,333.60		$	1,457.00
	Profitability Measure - Net Income
	Gas Utility Services	$	55.7		$	60		$	52.5
	Electric Utility Services	75.8			68			65
	Other Operations	10.3			10			5.4
	Total net income	$	141.8		$	138		$	122.9
	Amounts Included in Profitability Measures
	Depreciation & Amortization
	Gas Utility Services	$	90.5		$	85.4		$	84.3
	Electric Utility Services	84			81.3			80.2
	Other Operations	21.9			23.3			27.8
	Total depreciation & amortization	$	196.4		$	190		$	192.3
	Interest Expense
	Gas Utility Services	$	30.6		$	31.8		$	37.1
	Electric Utility Services	29.2			33.8			36.4
	Other Operations	5.2			5.9			6.8
	Total interest expense	$	65		$	71.5		$	80.3
	Income Taxes
	Gas Utility Services	$	36.6		$	39.1		$	34.5
	Electric Utility Services	48.3			46.4			45.3
	Other Operations	0.4			(0.2		)	3.1
	Total income taxes	$	85.3		$	85.3		$	82.9
	Capital Expenditures
	Gas Utility Services	$	150.5		$	128.8		$	113.5
	Electric Utility Services	100			108.8			102.2
	Other Operations	25.8			16.2			17.8
	Non-cash costs & changes in accruals	(13.8		)	(6.2		)	1.8
	Total capital expenditures	$	262.5		$	247.6		$	235.3
			At December 31,
	(In millions)		2013			2012			2011
	Assets
	Gas Utility Services		$	2,287.90		$	2,173.50		$	2,125.20
	Electric Utility Services		1,679.00			1,705.10			1,656.50
	Other Operations, net of eliminations		173.9			168.2			192.8
	Total assets		$	4,140.80		$	4,046.80		$	3,974.50

Additional_Balance_Sheet_Opera1

Additional Balance Sheet & Operational Information (Tables)	12 Months Ended
	Dec. 31, 2013
Additional Balance Sheet and Operational Information [Abstract]	'
Summary of inventories	'
	Inventories consist of the following:
		At December 31,
	(In millions)	2013		2012
	Gas in storage – at LIFO cost	$	33.2	$	22.4
	Materials & supplies	39		38.4
	Coal & oil for electric generation - at average cost	16.5		52
	Other	1.2		1.2
	Total inventories	$	89.9	$	114
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)	2013		2012
	Prepaid gas delivery service	$	32.9	$	28.5
	Prepaid taxes	0.2		21.1
	Deferred income taxes	5.5		—
	Other prepayments & current assets	3.8		2.7
	Total prepayments & other current assets	$	42.4	$	52.3
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)	2013		2012
	Cash surrender value of life insurance policies	$	22.3	$	27.4
	Municipal bond	3.4		3.6
	Restricted cash & other investments	1.6		1.6
	Total other investments	$	27.3	$	32.6
Accrued Liabilities	'
	Accrued liabilities in the Consolidated Balance Sheets consist of the following:
		At December 31,
	(In millions)	2013		2012
	Refunds to customers & customer deposits	$	50.2	$	53.1
	Accrued taxes	32.3		30.7
	Accrued interest	16.2		19.4
	Deferred income taxes	—		19.8
	Accrued salaries & other	28.7		16.3
	Total accrued liabilities	$	127.4	$	139.3
Asset retirement obligation	'
	Asset retirement obligations included in Deferred Credits and Other Liabilities in the Consolidated Balance Sheets roll forward as follows:
	(In millions)	2013		2012
	Asset retirement obligation, January 1	$	27.3	$	34
	Accretion	1.6		2.2
	Changes in estimates, net of cash payments	0.2		(8.9		)
	Asset retirement obligation, December 31	$	29.1	$	27.3
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)	2013		2012			2011
	AFUDC - borrowed funds	$	5.9	$	4.6		$	2.5
	AFUDC - equity funds	0.8		0.4			0.2
	Nonutility plant capitalized interest	0.4		0.2			0.3
	Interest income	0.6		0.6			0.6
	Cash surrender value of life insurance policies	1.7		1.4			0.1
	Other income	1.1		0.8			0.6
	Total other – net	$	10.5	$	8		$	4.3
Supplemental cash flow information	'
	Supplemental Cash Flow Information:
		Year Ended December 31,
	(In millions)	2013		2012			2011
	Cash paid (received) for:
	Interest	$	68.2	$	69.6		$	82.5
	Income taxes	30.9		30.1			(3.4		)

Subsidiary_Guarantor_and_Conso1

Subsidiary Guarantor and Consolidating Information Subsidiary Guarantor and Consolidating Information(Tables)	12 Months Ended
	Dec. 31, 2013
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, 2013 (in millions):
		Subsidiary			Parent			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			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 Statement of Income for the year ended December 31, 2011 (in millions):
		Subsidiary			Parent			Eliminations			Consolidated
		Guarantors			Company
	OPERATING REVENUES
	Gas utility	$	819.1		$	—		$	—		$	819.1
	Electric utility	635.9			—			—			635.9
	Other	—			43.9			(41.9		)	2
	Total operating revenues	1,455.00			43.9			(41.9		)	1,457.00
	OPERATING EXPENSES
	Cost of gas sold	375.4			—			—			375.4
	Cost of fuel & purchased power	240.4			—			—			240.4
	Other operating	354.6			—			(41.5		)	313.1
	Depreciation & amortization	164.6			27.1			0.6			192.3
	Taxes other than income taxes	52.3			1.5			0.2			54
	Total operating expenses	1,187.30			28.6			(40.7		)	1,175.20
OPERATING INCOME	267.7			15.3			(1.2		)	281.8
OTHER INCOME (EXPENSE)
Equity in earnings of consolidated companies	—			117.5			(117.5		)	—
Other – net	3.1			48.9			(47.7		)	4.3
Total other income (expense)	3.1			166.4			(165.2		)	4.3
Interest expense	73.5			55.7			(48.9		)	80.3
INCOME BEFORE INCOME TAXES	197.3			126			(117.5		)	205.8
Income taxes	79.8			3.1			—			82.9
NET INCOME	$	117.5		$	122.9		$	(117.5	)	$	122.9
Condensed consolidating balance sheets [Table Text Block]	'
	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 Balance Sheet as of December 31, 2012 (in millions):
	ASSETS	Subsidiary			Parent
		Guarantors			Company			Eliminations			Consolidated
	Current Assets
	Cash & cash equivalents	$	12.5		$	0.8		$	—		$	13.3
	Accounts receivable - less reserves	81.8			—			—			81.8
	Intercompany receivables	—			145.1			(145.1		)	—
	Accrued unbilled revenues	93.6			—			—			93.6
	Inventories	114			—			—			114
	Recoverable fuel & natural gas costs	25.3			—			—			25.3
	Prepayments & other current assets	52			5.8			(5.5		)	52.3
	Total current assets	379.2			151.7			(150.6		)	380.3
	Utility Plant
Original cost	5,176.60			0.2			—			5,176.80
Less:  accumulated depreciation & amortization	2,057.20			—			—			2,057.20
Net utility plant	3,119.40			0.2			—			3,119.60
Investments in consolidated subsidiaries	—			1,329.20			(1,329.2		)	—
Notes receivable from consolidated subsidiaries	—			679.7			(679.7		)	—
Investments in unconsolidated affiliates	0.2			—			—			0.2
Other investments	27.8			4.8			—			32.6
Nonutility plant - net	2.6			144.3			—			146.9
Goodwill - net	205			—			—			205
Regulatory assets	104.1			22.4			—			126.5
Other assets	40.4			1.7			(6.4		)	35.7
TOTAL ASSETS	$	3,878.70		$	2,334.00		$	(2,165.9	)	$	4,046.80
LIABILITIES & SHAREHOLDER'S EQUITY	Subsidiary			Parent
	Guarantors			Company			Eliminations			Consolidated
Current Liabilities
Accounts payable	$	114.8		$	6.2		$	—		$	121
Accounts payable to affiliated companies	29.7			—			—			29.7
Intercompany payables	10.6			—			(10.6		)	—
Payables to other Vectren companies	25.1			—			—			25.1
Accrued liabilities	131.3			13.5			(5.5		)	139.3
Short-term borrowings	—			116.7			—			116.7
Intercompany short-term borrowings	134.5			—			(134.5		)	—
Current maturities of long-term debt	5			100			—			105
Total current liabilities	451			236.4			(150.6		)	536.8
Long-Term Debt
Long-term debt - net of current maturities &
debt subject to tender	382.3			721.1			—			1,103.40
Long-term debt due to VUHI	679.7			—			(679.7		)	—
Total long-term debt - net	1,062.00			721.1			(679.7		)	1,103.40
Deferred Income Taxes & Other Liabilities
Deferred income taxes	595.4			(16.9		)	—			578.5
Regulatory liabilities	362.2			2			—			364.2
Deferred credits & other liabilities	78.9			1.4			(6.4		)	73.9
Total deferred credits & other liabilities	1,036.50			(13.5		)	(6.4		)	1,016.60
Common Shareholder's Equity
Common stock (no par value)	787.8			781.6			(787.8		)	781.6
Retained earnings	541.4			608.4			(541.4		)	608.4
Total common shareholder's equity	1,329.20			1,390.00			(1,329.2		)	1,390.00
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	$	3,878.70		$	2,334.00		$	(2,165.9	)	$	4,046.80
Condensed consolidating statements of cash flows [Table Text Block]	'
	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
	Consolidating Statement of Cash Flows for the year ended December 31, 2011 (in millions):
		Subsidiary			Parent			Eliminations			Consolidated
		Guarantors			Company
	NET CASH FLOWS FROM OPERATING ACTIVITIES	$	316.2		$	18.1		$	—		$	334.3
	CASH FLOWS FROM FINANCING ACTIVITIES
	Proceeds from long-term debt - net of issuance costs	248.4			148.9			(248.4		)	148.9
	Requirements for:
	Dividends to parent	(84.4		)	(91.6		)	84.4			(91.6		)
	Retirement of long-term debt, including premiums paid	(337.4		)	(347.0		)	337.4			(347.0		)
	Other financing activities	—			(1.1		)	—			(1.1		)
	Net change in intercompany short-term borrowings	13.4			(277.6		)	264.2			—
	Net change in short-term borrowings	—			195.8			—			195.8
	Net cash flows from financing activities	(160.0		)	(372.6		)	437.6			(95.0		)
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from:
Consolidated subsidiary distributions	—			84.4			(84.4		)	—
Other investing activities	0.2			0.2			—			0.4
Requirements for:
Capital expenditures, excluding AFUDC equity	(218.2		)	(17.1		)	—			(235.3		)
Other investing activities	(0.8		)	—			—			(0.8		)
Net change in long-term intercompany notes receivable	—			89			(89.0		)	—
Net change in short-term intercompany notes receivable	65.9			198.3			(264.2		)	—
Net cash flows from investing activities	(152.9		)	354.8			(437.6		)	(235.7		)
Net change in cash & cash equivalents	3.3			0.3			—			3.6
Cash & cash equivalents at beginning of period	2			0.4			—			2.4
Cash & cash equivalents at end of period	$	5.3		$	0.7		$	—		$	6

Quarterly_Financial_Data_Unaud1

Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2013
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 2013 and 2012 follows:
	(In millions)		Q1		Q2		Q3		Q4
	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
	2012
		Results of Operations:
		Operating revenues	$	432.1	$	265.8	$	267.7	$	368
		Operating income	105.9		49.8		57.1		74
		Net income	56		20.1		26.4		35.5

Organization_and_Nature_of_Ope1

Organization and Nature of Operations (Details)	12 Months Ended
	Dec. 31, 2013
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)	570,000
Estimated number of electric customers located near Evansville in southwestern Indiana serviced by Southern Indiana Gas and Electric Company (in number of customers)	142,000
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)	312,000

Summary_of_Significant_Account2

Summary of Significant Accounting Policies (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Accounting Policies [Abstract]	'	'	'
Excise taxes and a portion of utility receipts taxes	$29.60	$26.90	$29

Utility_Nonutility_Plant_Detai

Utility & Nonutility Plant (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Utility & Nonutility Plant	'	'	'
Original Cost	$5,389.60	$5,176.80	'
Cost of Non-Utility plant, net of depreciation and amortization	150.5	146.9	'
Utility Group [Member]	'	'	'
Utility & Nonutility Plant	'	'	'
Original Cost	5,389.60	5,176.80	'
Utility Group [Member] | Gas Utility Plant [Member]	'	'	'
Utility & Nonutility Plant	'	'	'
Original Cost	2,762.20	2,614.30	'
Depreciation Rates as a Percent of Original Cost (in hundredths)	3.50%	3.50%	'
Utility Group [Member] | Electric Utility Plant [Member]	'	'	'
Utility & Nonutility Plant	'	'	'
Original Cost	2,519.80	2,463.60	'
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	53.4	52	'
Depreciation Rates as a Percent of Original Cost (in hundredths)	3.00%	3.00%	'
Utility Group [Member] | Construction Work in Progress [Member]	'	'	'
Utility & Nonutility Plant	'	'	'
Original Cost	54.2	46.9	'
Depreciation Rates as a Percent of Original Cost (in hundredths)	0.00%	0.00%	'
Utility Group [Member] | Warrick Power Plant [Member]	'	'	'
Utility & Nonutility Plant	'	'	'
Size of Unit 4 Warrick Power Plant (in megawatts)	300	'	'
Utility Group [Member] | SIGECO [Member]	'	'	'
Utility & Nonutility Plant	'	'	'
Southern Indiana Gas And Electric Company's Share Of Cost Of Unit 4	186.3	'	'
Southern Indiana Gas And Electric Company's Share Of Accumulated Depreciation Of Unit 4	84.4	'	'
Nonutility Group [Member]	'	'	'
Utility & Nonutility Plant	'	'	'
Cost of Non-Utility plant, net of depreciation and amortization	150.5	146.9	'
Nonutility plant accumulated depreciation and amortization	209.2	201.5	'
Capitalized interest on nonutility plant construction projects	0.4	0.2	0.3
Nonutility Group [Member] | Computer Hardware and Software [Member]	'	'	'
Utility & Nonutility Plant	'	'	'
Cost of Non-Utility plant, net of depreciation and amortization	102.3	96.6	'
Nonutility Group [Member] | Land and Buildings [Member]	'	'	'
Utility & Nonutility Plant	'	'	'
Cost of Non-Utility plant, net of depreciation and amortization	38.3	38.6	'
Nonutility Group [Member] | All Other [Member]	'	'	'
Utility & Nonutility Plant	'	'	'
Cost of Non-Utility plant, net of depreciation and amortization	$9.90	$11.70	'

Regulatory_Assets_Liabilities_1

Regulatory Assets & Liabilities (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Regulatory Assets [Line Items]	'	'
Regulatory Assets Currently Being Recovered in Base Rates	$40	'
Regulatory assets	136.2	126.5
Weighted average recovery period of regulatory assets currently being recovered (in years)	'23	'
Regulatory Liabilities [Abstract]	'	'
Regulatory liabilities	387.3	364.2
Asset Retirement Obligations and Other [Member]	'	'
Regulatory Liabilities [Abstract]	'	'
Regulatory liabilities	373	349.5
Future Amounts Recoverable From Ratepayers [Member]	'	'
Regulatory Assets [Line Items]	'	'
Regulatory assets	-3.5	-1.3
Future Amounts Recoverable From Ratepayers [Member] | Deferred Income Taxes [Member]	'	'
Regulatory Assets [Line Items]	'	'
Regulatory assets	-5.8	-3.9
Future Amounts Recoverable From Ratepayers [Member] | Asset Retirement Obligations and Other [Member]	'	'
Regulatory Assets [Line Items]	'	'
Regulatory assets	2.3	2.6
Amounts Deferred for Future Recovery [Member]	'	'
Regulatory Assets [Line Items]	'	'
Regulatory assets	61	52.6
Amounts Deferred for Future Recovery [Member] | Deferred Coal Costs [Member]	'	'
Regulatory Assets [Line Items]	'	'
Regulatory assets	42.4	42.4
Amounts Deferred for Future Recovery [Member] | Cost Recovery Riders Other [Member]	'	'
Regulatory Assets [Line Items]	'	'
Regulatory assets	18.6	10.2
Amounts Currently Recovered in Customer Rates [Member]	'	'
Regulatory Assets [Line Items]	'	'
Regulatory assets	78.7	75.2
Amounts Currently Recovered in Customer Rates [Member] | Unamortized Debt Issue Costs and Hedging Proceeds [Member]	'	'
Regulatory Assets [Line Items]	'	'
Regulatory assets	34.6	32.6
Amounts Currently Recovered in Customer Rates [Member] | Demand Side Management Programs [Member]	'	'
Regulatory Assets [Line Items]	'	'
Regulatory assets	2.5	4.4
Amounts Currently Recovered in Customer Rates [Member] | Indiana Authorized Trackers [Member]	'	'
Regulatory Assets [Line Items]	'	'
Regulatory assets	30.8	32.1
Amounts Currently Recovered in Customer Rates [Member] | Ohio Authorized Trackers [Member]	'	'
Regulatory Assets [Line Items]	'	'
Regulatory assets	7.9	1.5
Amounts Currently Recovered in Customer Rates [Member] | Premiums Paid to Reaquire Debt [Member]	'	'
Regulatory Assets [Line Items]	'	'
Regulatory assets	2.2	2.7
Amounts Currently Recovered in Customer Rates [Member] | Other Base Rate Recoveries [Member]	'	'
Regulatory Assets [Line Items]	'	'
Regulatory assets	$0.70	$1.90

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, 2013	Dec. 31, 2012	Dec. 31, 2011
Transactions with Other Vectren Companies and Affiliates [Line Items]	'	'	'
Number of qualified defined benefit pension plans	3	'	'
Defined Benefit Plan, Contributions by Employer	$0	$0	$33.40
Defined Benefit Plan, Funded Percentage	101.00%	82.00%	'
Defined Benefit Plan, Net Periodic Benefit Cost	8	7.2	6.6
Deferred Credits and Other Liabilities	83.5	73.9	'
Amount of Share Based Compensation and Deferred Compensation Liability included in Deferred Credits and Other Liabilities	29.6	23.6	'
Current: [Abstract]	'	'	'
Federal	48	6.1	10.4
State	11	6.9	7.9
Total current taxes	59	13	18.3
Deferred: [Abstract]	'	'	'
Federal	26.8	68.7	58.6
State	0.1	4.2	6.6
Total deferred taxes	26.9	72.9	65.2
Amortization of investment tax credits	-0.6	-0.6	-0.6
Total income tax expense	85.3	85.3	82.9
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)	3.50%	3.70%	3.90%
Amortization of investment tax credit (in hundredths)	-0.30%	-0.30%	-0.30%
State apportionment impacts	0.00%	0.00%	0.90%
All other - net	-0.60%	-0.20%	0.80%
Effective tax rate (in hundredths)	37.60%	38.20%	40.30%
Noncurrent deferred tax liabilities (assets) [Abstract]	'	'	'
Depreciation and cost recovery timing differences	627.9	597.1	'
Regulatory assets recoverable through future rates	22.8	23.5	'
Alternative minimum tax carryforward	-18.5	-44	'
Employee benefit obligations	5.2	13.4	'
Regulatory liabilities to be settled through future rates	-18.7	-18.3	'
Other - net	8.7	6.8	'
Net noncurrent deferred tax liability	627.4	578.5	'
Deferred Tax (Assets) Liabilities Current [Abstract]	'	'	'
Deferred fuel costs-net	22.9	25.7	'
Alternative minimum tax carryforward	-36.4	-2.7	'
Demand side management programs	0.1	2.7	'
Deferred Tax Assets Operating Loss Carryforwards And General Business CreditsCurrent	-1.2	0	'
Other - net	9.1	-5.9	'
Net current deferred tax liability (asset)	-5.5	19.8	'
Net deferred tax liability	621.9	598.3	'
Investment tax credits	3.2	3.8	'
Indiana House Bill 1004 [Abstract]	'	'	'
Phase in period of new legislation	4	'	'
Total rate reduction as a result of new legislation	2.00%	'	'
Annual phase in percentage	0.50%	'	'
Final tax rate after legislation phase in	6.50%	'	'
Uncertain tax positions [Roll Forward]	'	'	'
Unrecognized tax benefits at beginning of period	3.7	11	11.8
Gross increases - tax positions in prior periods	0	0.1	3.3
Gross decreases - tax positions in prior periods	-0.2	-9.3	-4.4
Gross increases - current period tax positions	1.2	1.9	0.6
Settlements	0	0	-0.3
Unrecognized tax benefits at end of period	4.7	3.7	11
Uncertain tax positions [Abstract]	'	'	'
Net liability for unrecognized tax benefits inclusive of interest, penalties and net of secondary impacts which are a component of the deferred income taxes and are benefits	4.5	3.6	'
Interest and penalties	0	-0.7	0.4
Payment of interest and penalties accrued	0.2	'	'
Pension Plans, Defined Benefit [Member]	'	'	'
Transactions with Other Vectren Companies and Affiliates [Line Items]	'	'	'
Other Assets	23.6	31.1	'
Other Postretirement Benefit Plans, Defined Benefit [Member]	'	'	'
Transactions with Other Vectren Companies and Affiliates [Line Items]	'	'	'
Deferred Credits and Other Liabilities	11.2	10.7	'
Vectren Fuels Inc. [Member]	'	'	'
Transactions with Other Vectren Companies and Affiliates [Line Items]	'	'	'
Expenses from transactions with related party	103.7	115.6	144.1
Vectren Source [Member]	'	'	'
Transactions with Other Vectren Companies and Affiliates [Line Items]	'	'	'
Number of residential and commercial customers that were provided natural gas and other related products and services in the Midwest and Northeast United States by Vectren Source	'	'	283,000
Number of customers in VEDObs service territory that remained customers of the regulated utility	'	'	143,000
Payments to Acquire Receivables	'	'	66.5
ProLiance [Member]	'	'	'
Transactions with Other Vectren Companies and Affiliates [Line Items]	'	'	'
Expenses from transactions with related party	200.5	274.5	375.7
Amounts owed to ProLiance for those purchases	'	29.7	'
Percentage of purchases from single third party	91.00%	'	'
Percentage of gas purchased by VUHI	52.00%	97.00%	'
Support Services & Purchases [Member]	'	'	'
Transactions with Other Vectren Companies and Affiliates [Line Items]	'	'	'
Cost of corporate and general and administrative services	50.9	44.8	46.1
Vectren Infrastructure Services Corporation [Member]	'	'	'
Transactions with Other Vectren Companies and Affiliates [Line Items]	'	'	'
Expenses from transactions with related party	$54.20	$46.60	$43.10

Common_Shareholders_Equity_Det

Common Shareholder's Equity (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Common Shareholders Equity [Line Items]	'	'	'
Additional capital contribution	$6.10	$7	$0
Common Shareholders Equity [Member]	'	'	'
Common Shareholders Equity [Line Items]	'	'	'
Additional capital contribution	$13.10	$11.70	$11.70

Borrowing_Arrangements_ShortTe

Borrowing Arrangements Short-Term Borrowings (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Short-term borrowings [Abstract]	'	'	'
Short-term borrowing capacity	$350	'	'
Short term borrowings available	321	'	'
Short term credit facilities expiration date	30-Sep-16	'	'
Year end [Abstract]	'	'	'
Balance Outstanding, end of period	28.6	116.7	242.8
Weighted Average Interest Rate, end of period (in hundredths)	0.29%	0.40%	0.57%
Annual Average [Abstract]	'	'	'
Balance Outstanding, annual average	119.6	77.6	39.6
Weighted Average Interest Rate, annual average (in hundredths)	0.34%	0.47%	0.48%
Maximum Month End Balance Outstanding	$176.10	$214.20	$242.80

Borrowing_Arrangements_Details

Borrowing Arrangements (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Long term debt [Abstract]	'	'	'
Total long term debt outstanding	$1,258,500,000	$1,210,100,000	'
Current maturities of long-term debt	0	-105,000,000	'
Unamortized debt premium and discount - net	-1,400,000	-1,700,000	'
Long-term debt - net of current maturities and debt subject to tender	1,257,100,000	1,103,400,000	'
Letters of Credit Outstanding, Amount	41,700,000	'	'
Long-term debt death put repayments	0	800,000	1,800,000
Maturities of long term debt [Abstract]	'	'	'
Debt maturing within 12 months following date of latest balance sheet	0	'	'
Debt maturing within two years following date of latest balance sheet	104,800,000	'	'
Debt maturing within three years following date of latest balance sheet	13,000,000	'	'
Debt maturing within four years following date of latest balance sheet	0	'	'
Debt maturing within five years following date of latest balance sheet	100,000,000	'	'
Debt maturing thereafter 5 years following date of the latest balance sheet	1,039,300,000	'	'
Debt guarantees [Abstract]	'	'	'
Long-term guarantees	875,000,000	'	'
Short-term debt guarantees	29,000,000	'	'
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	821,600,000	'
Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2013, 5.25% [Member]	'	'	'
Long term debt [Abstract]	'	'	'
Total long term debt outstanding	0	100,000,000	'
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]	'	'	'
Debt Issuance	'	'	55,000,000
Proceeds from debt issuance	'	'	149,000,000
Fixed rate stated percentage (in hundredths)	'	'	4.67%
Maturity date	'	'	30-Nov-21
Debt Instrument Issuance Date	'	'	30-Nov-11
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	0	'
Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2026, 5.02% [Member]	'	'	'
Long term debt [Abstract]	'	'	'
Debt Issuance	'	'	60,000,000
Fixed rate stated percentage (in hundredths)	'	'	5.02%
Maturity date	'	'	30-Nov-26
Debt Instrument Issuance Date	'	'	30-Nov-11
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	0	'
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] | 2039, 6.25% [Member]	'	'	'
Long term debt [Abstract]	'	'	'
Total long term debt outstanding	0	121,600,000	'
Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2041, 5.99% [Member]	'	'	'
Long term debt [Abstract]	'	'	'
Debt Issuance	'	'	35,000,000
Fixed rate stated percentage (in hundredths)	'	'	5.99%
Maturity date	'	'	2-Dec-41
Debt Instrument Issuance Date	'	'	30-Nov-11
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] | 2036, 5.95% [Member]	'	'	'
Long term debt [Abstract]	'	'	'
Fixed rate stated percentage (in hundredths)	'	'	5.95%
Maturity date	'	'	31-Dec-36
Total long term debt outstanding	'	'	96,200,000
Debt Instrument Put And Call Exercise Date	'	'	21-Nov-11
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	0	'
Utility Holdings [Member] | Senior Guaranteed Notes [Member] | 2043, 4.25% [Member]	'	'	'
Long term debt [Abstract]	'	'	'
Debt Issuance	'	80,000,000	'
Fixed rate stated percentage (in hundredths)	'	4.25%	'
Maturity date	'	5-Jun-43	'
Debt Instrument Issuance Date	'	5-Jun-13	'
Utility Holdings [Member] | Senior Guaranteed Notes [Member] | 2028, 3.20% [Member]	'	'	'
Long term debt [Abstract]	'	'	'
Debt Issuance	'	45,000,000	'
Fixed rate stated percentage (in hundredths)	'	3.20%	'
Maturity date	'	5-Jun-28	'
Debt Instrument Issuance Date	'	5-Jun-13	'
Indiana Gas [Member] | Fixed Rate Senior Unsecured Notes [Member]	'	'	'
Long term debt [Abstract]	'	'	'
Total long term debt outstanding	116,000,000	121,000,000	'
Indiana Gas [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2013, Series E, 6.69% [Member]	'	'	'
Long term debt [Abstract]	'	'	'
Total long term debt outstanding	0	5,000,000	'
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 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] | 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] | 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, 4.00 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, 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, 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	'August 13, 2013	'	'
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	1,200,000,000	'	'
Gross utility plant balance subject to the mortgage indenture	2,900,000,000	'	'
SIGECO [Member] | Mortgages [Member] | 2015, 1985 Pollution Control Series A, current adjustable rate 0.15%, tax exempt, 2012 weighted average: 0.17%	'	'	'
Long term debt [Abstract]	'	'	'
Total long term debt outstanding	9,800,000	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] | 2020, 1998 Pollution Control Series B, 4.50%, tax exempt [Member]	'	'	'
Long term debt [Abstract]	'	'	'
Total long term debt outstanding	0	4,600,000	'
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	0	'
SIGECO [Member] | Mortgages [Member] | 2023, 1993 Environmental Improvement Series B, 5.15%, tax exempt [Member]	'	'	'
Long term debt [Abstract]	'	'	'
Total long term debt outstanding	0	22,600,000	'
SIGECO [Member] | Mortgages [Member] | 2024, 2000 Environmental Improvement Series A, 4.65%, tax exempt [Member]	'	'	'
Long term debt [Abstract]	'	'	'
Total long term debt outstanding	0	22,500,000	'
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	0	'
SIGECO [Member] | Mortgages [Member] | 2025, 1998 Pollution Control Series A, current adjustable rate 0.15%, tax exempt, 2012 weighted average: 0.16%	'	'	'
Long term debt [Abstract]	'	'	'
Total long term debt outstanding	31,500,000	31,500,000	'
SIGECO [Member] | Mortgages [Member] | 2029, 1999 Senior Notes, 6.72% [Member]	'	'	'
Long term debt [Abstract]	'	'	'
Total long term debt outstanding	80,000,000	80,000,000	'
SIGECO [Member] | Mortgages [Member] | 2030, 1998 Pollution Control Series B, 5.00%, tax exempt [Member]	'	'	'
Long term debt [Abstract]	'	'	'
Total long term debt outstanding	0	22,000,000	'
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	0	'
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	0	'
SIGECO [Member] | Mortgages [Member] | 2030, 1998 Pollution Control Series C, 5.35%, tax exempt [Member]	'	'	'
Long term debt [Abstract]	'	'	'
Total long term debt outstanding	0	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	22,300,000	22,300,000	'
SIGECO [Member] | Mortgages [Member] | 2041, 2007 Pollution Control Series, 5.45%, tax exempt [Member]	'	'	'
Long term debt [Abstract]	'	'	'
Total long term debt outstanding	0	17,000,000	'
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	0	'
Vectren Utility Holdings Inc [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2023, 3.72% [Member]	'	'	'
Long term debt [Abstract]	'	'	'
Debt Issuance	150,000,000	'	'
Proceeds from debt issuance	149,100,000	'	'
Fixed rate stated percentage (in hundredths)	3.72%	'	'
Maturity date	5-Dec-23	'	'
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] | 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	'	'
Current maturities of long-term debt	-121,600,000	'	'
Debt redemption date	1-Apr-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	'	'

Commitments_and_Contingencies_

Commitments and Contingencies (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Commitments [Abstract]	'	'	'
Future minimum operating lease payments due within one year of the balance sheet date	$0.80	'	'
Future minimum operating lease payments due within the second year of the balance sheet date	0.4	'	'
Future minimum operating lease payments due within the third year of the balance sheet date	0.3	'	'
Future minimum operating lease payments due within the fourth year of the balance sheet date	0.3	'	'
Future minimum operating lease payments due within the fifth year	0.2	'	'
Future minimum operating lease payments due after the fifth year of the balance sheet date	0	'	'
Total lease expense	1.1	1.2	0.6
Unrecorded Unconditional Purchase Obligation, Due within One Year	0.5	'	'
Unrecorded Unconditional Purchase Obligation, Due within Two Years	$0	'	'

Rate_Regulatory_Matters_Detail

Rate & Regulatory Matters (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items]	'	'	'
Other Nonoperating Income (Expense)	$10,500,000	$8,000,000	$4,300,000
Vectren South Electric Environmental Compliance Filing [Abstract]	'	'	'
Lower range of request for approval of capital investments on coal-fired generation units	70,000,000	'	'
Upper range of request for approval of capital investments on coal-fired generation units	90,000,000	'	'
Vectren South Electric Base Rate Filing [Abstract]	'	'	'
Amount of infrastructure construction in the three years leading up to December 2009 rate filing	325,000,000	'	'
Dollar amount of the rate base included in rate increase	1,295,600,000	'	'
Amount of rate of return on equity included in rate base (in hundredths)	10.40%	'	'
Rate of return included in rate increase (in hundredths)	7.29%	'	'
Amount of expected capital investment invested to date related to investment in dense pack technology	28,700,000	'	'
Coal Procurement Procedures [Abstract]	'	'	'
Number of years for recovery of coal costs	6	'	'
Cumulative total deferrals related to coal purchases	'	42,400,000	'
Vectren South Electric Demand Side Management Program Filing [Abstract]	'	'	'
Number of years in initial demand side management program approved by the IURC (in years)	'	'	3
Maximum deferral of lost margin associated with small customer demand side programs	'	3,000,000	1,000,000
Electric revenue recognized associated with lost margin recovery	5,000,000	'	'
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	9.15%	'	'
Equity component, upper limit, as a percentage, sought by third party	50.00%	'	'
Percentage return recommended by FERC on ROE complaint against NETO	9.70%	'	'
Incentive return granted on qualifying investments in NETO	11.14%	'	'
Estimate of basis point change that could affect the Company's net income	100	'	'
Net income effect of a 100 basis point change on an annual basis	800,000	'	'
Ohio Recovery and Deferral Mechanisms [Member]	'	'	'
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items]	'	'	'
Bill impact per customer per month	1	'	'
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	109,000,000	'	'
Distribution Replacement Rider revenues	9,800,000	6,500,000	3,600,000
Other income (AFUDC borrowed)	2,000,000	1,800,000	2,000,000
Regulatory Asset associated with DRR deferrals of depreciation and post in-service carrying costs	9,300,000	6,500,000	3,000,000
Initial DRR term	5	'	'
Amount of Capital Investment Expected Over Next Five Years Recoverable Under DRR	187,000,000	'	'
Ohio [Member] | Ohio House Bill95 [Member]	'	'	'
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items]	'	'	'
Estimated budget related to Ohio capital expenditure program	23,500,000	'	'
Time period (in months) included in VEDO application	'15	'	'
Bill impact per customer per month	1.5	'	'
Amount approved for capital expenditure program	61,500,000	'	'
Other Nonoperating Income (Expense)	2,200,000	900,000	'
Amount of deferral related to depreciation and property tax expense	1,700,000	600,000	'
Increase in regulatory assets associated with Ohio infrastructure programs	6,700,000	'	'
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	12,100,000	8,500,000	'
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%	'	'
Length of project plan required for recovery under new legislation	7	'	'
Adjustment mechanism cap % based on annual retail revenue increase	2.00%	'	'
Indiana [Member] | Pipeline Safety Law [Member]	'	'	'
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items]	'	'	'
Expected Seven Year Period Modernization Investment	865,000,000	'	'
Seven Year Plan of Eligible Investments Under Indiana Legislation (In Years)	7	'	'
Expected annual operating costs associated with new pipeline safety regulations	13,000,000	'	'
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	'	'

Environmental_Matters_Details

Environmental Matters (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified	MW
Air Quality [Abstract]	'	'
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	'
Lower range of request for approval of capital investments on coal-fired generation units	70	'
Upper range of request for approval of capital investments on coal-fired generation units	90	'
Clean Water Act [Abstract]	'	'
Estimated capital expenditures related to Clean Water Act	40	'
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	'
Indiana Senate Bill 251 [Abstract]	'	'
Percentage of total electricity obtained by supplier to meet customer needs	10.00%	'
Power generation capacity for acquired landfill gas generations facility (in megawatts)	3	'
Long term contract for purchase of electric power generated by wind energy (in megawatts)	80	'
Percentage of total electricity obtained by the supplier to meet the energy needs of its retail customers provided by clean energy sources (in hundredths)	5.00%	'
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	5.7	4.6
Indiana Gas [Member]	'	'
Manufactured Gas Plants	'	'
Number of sites identified with potential remedial responsibility for entity (in number of sites)	26	'
Site contingency, accrual, undiscounted amount	23.2	'
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, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2012
		Carrying Amount [Member]	Carrying Amount [Member]	Estimated Fair Value [Member]	Estimated Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'	'	'	'
Long-term debt	'	$1,257.10	$1,208.40	$1,317.40	$1,372.60
Short-term Debt, Fair Value	'	28.6	116.7	28.6	116.7
Cash and cash equivalents	'	$8.60	$13.30	$8.60	$13.30
Period to recover call premiums on reacquisition of long-term debt	'15	'	'	'	'

Segment_Reporting_Details

Segment Reporting (Details) (USD $)	3 Months Ended								12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
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	$403.60	$267.70	$292.80	$465.50	$368	$267.70	$265.80	$432.10	$1,429.60	$1,333.60	$1,457
Net income (loss)	37.2	25.3	24.2	55.1	35.5	26.4	20.1	56	141.8	138	122.9
Assets	4,140.80	'	'	'	4,046.80	'	'	'	4,140.80	4,046.80	3,974.50
Amounts Included in Profitability Measures [Abstract]	'	'	'	'	'	'	'	'	'	'	'
Depreciation and Amortization	'	'	'	'	'	'	'	'	196.4	190	192.3
Interest Expense	'	'	'	'	'	'	'	'	65	71.5	80.3
Income Taxes	'	'	'	'	'	'	'	'	85.3	85.3	82.9
Property, Plant and Equipment, Additions	'	'	'	'	'	'	'	'	262.5	247.6	235.3
Gas Utility Services [Member]	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Revenues	'	'	'	'	'	'	'	'	810	738.1	819.1
Net income (loss)	'	'	'	'	'	'	'	'	55.7	60	52.5
Assets	2,287.90	'	'	'	2,173.50	'	'	'	2,287.90	2,173.50	2,125.20
Amounts Included in Profitability Measures [Abstract]	'	'	'	'	'	'	'	'	'	'	'
Depreciation and Amortization	'	'	'	'	'	'	'	'	90.5	85.4	84.3
Interest Expense	'	'	'	'	'	'	'	'	30.6	31.8	37.1
Income Taxes	'	'	'	'	'	'	'	'	36.6	39.1	34.5
Property, Plant and Equipment, Additions	'	'	'	'	'	'	'	'	150.5	128.8	113.5
Electric Utility Services [Member]	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Revenues	'	'	'	'	'	'	'	'	619.3	594.9	635.9
Net income (loss)	'	'	'	'	'	'	'	'	75.8	68	65
Assets	1,679	'	'	'	1,705.10	'	'	'	1,679	1,705.10	1,656.50
Amounts Included in Profitability Measures [Abstract]	'	'	'	'	'	'	'	'	'	'	'
Depreciation and Amortization	'	'	'	'	'	'	'	'	84	81.3	80.2
Interest Expense	'	'	'	'	'	'	'	'	29.2	33.8	36.4
Income Taxes	'	'	'	'	'	'	'	'	48.3	46.4	45.3
Property, Plant and Equipment, Additions	'	'	'	'	'	'	'	'	100	108.8	102.2
Other Operations [Member]	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Revenues	'	'	'	'	'	'	'	'	38.1	40.1	43.9
Net income (loss)	'	'	'	'	'	'	'	'	10.3	10	5.4
Assets	173.9	'	'	'	168.2	'	'	'	173.9	168.2	192.8
Amounts Included in Profitability Measures [Abstract]	'	'	'	'	'	'	'	'	'	'	'
Depreciation and Amortization	'	'	'	'	'	'	'	'	21.9	23.3	27.8
Interest Expense	'	'	'	'	'	'	'	'	5.2	5.9	6.8
Income Taxes	'	'	'	'	'	'	'	'	0.4	-0.2	3.1
Property, Plant and Equipment, Additions	'	'	'	'	'	'	'	'	25.8	16.2	17.8
Intersegment Elimination [Member]	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Revenues	'	'	'	'	'	'	'	'	-37.8	-39.5	-41.9
Non-Cash Cost and Change in Accruals [Member]	'	'	'	'	'	'	'	'	'	'	'
Amounts Included in Profitability Measures [Abstract]	'	'	'	'	'	'	'	'	'	'	'
Property, Plant and Equipment, Additions	'	'	'	'	'	'	'	'	($13.80)	($6.20)	$1.80

Additional_Balance_Sheet_Opera2

Additional Balance Sheet & Operational Information (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Inventory, Net [Abstract]	'	'	'
Gas in storage - at LIFO cost	$33.20	$22.40	'
Materials and supplies	39	38.4	'
Coal and Oil for electric generation - at average cost	16.5	52	'
Other	1.2	1.2	'
Total inventories	89.9	114	'
Amount by which cost of replacing inventories carried at LIFO cost exceeded carrying value	9	12	'
Prepayments and other current assets [Abstract]	'	'	'
Prepaid gas delivery service	32.9	28.5	'
Prepaid taxes	0.2	21.1	'
Deferred income taxes	5.5	0	'
Other prepayments and current assets	3.8	2.7	'
Total prepayments and other current assets	42.4	52.3	'
Other utility and corporate investments [Abstract]	'	'	'
Cash surrender value of life insurance policies	22.3	27.4	'
Municipal bond	3.4	3.6	'
Restricted cash & other investments	1.6	1.6	'
Other utility and corporate investments	27.3	32.6	'
Accrued liabilities [Abstract]	'	'	'
Refunds to customers and customer deposits	50.2	53.1	'
Accrued taxes	32.3	30.7	'
Accrued interest	16.2	19.4	'
Deferred income taxes	0	19.8	'
Accrued salaries and other	28.7	16.3	'
Total accrued liabilities	127.4	139.3	'
Asset Retirement Obligation [Roll Forward]	'	'	'
Asset retirement obligation, beginning balance	27.3	34	'
Accretion	1.6	2.2	'
Changes in estimates, net of cash payments	0.2	-8.9	'
Asset retirement obligation, ending balance	29.1	27.3	34
Other - net in the consolidated statement of income [Abstract]	'	'	'
AFUDC - borrowed funds	5.9	4.6	2.5
AFUDC - equity funds	0.8	0.4	0.2
Nonutility plant capitalized interest	0.4	0.2	0.3
Interest income, net	0.6	0.6	0.6
Cash surrender value of life insurance policies	1.7	1.4	0.1
All other income	1.1	0.8	0.6
Total other income (expense) b net	10.5	8	4.3
Cash paid (received) for [Abstract]	'	'	'
Interest	68.2	69.6	82.5
Income taxes	30.9	30.1	-3.4
Accruals related to utility and nonutility plant purchases [Abstract]	'	'	'
Accruals related to utility and nonutility plant purchases	$13.10	$7.10	'

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, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
ASSETS	'	'	'	'
Cash & cash equivalents	$8.60	$13.30	$6	$2.40
Accounts receivable - less reserves	112.1	81.8	'	'
Accrued unbilled revenues	113.5	93.6	'	'
Inventories	89.9	114	'	'
Recoverable fuel & natural gas costs	5.5	25.3	'	'
Prepayments & other curent assets	42.4	52.3	'	'
Total current assets	372	380.3	'	'
Original Cost	5,389.60	5,176.80	'	'
Less: accumulated depreciation & amortization	2,165.30	2,057.20	'	'
Net utility plant	3,224.30	3,119.60	'	'
Investments in unconsolidated affiliates	0.2	0.2	'	'
Other Investments	27.3	32.6	'	'
Nonutility plant - net	150.5	146.9	'	'
Goodwill - net	205	205	'	'
Regulatory assets	136.2	126.5	'	'
Other assets	25.3	35.7	'	'
TOTAL ASSETS	4,140.80	4,046.80	3,974.50	'
LIABILITIES & SHAREHOLDERS' EQUITY	'	'	'	'
Accounts payable	172.1	121	'	'
Accounts payable to affiliated companies	0	29.7	'	'
Payables to other Vectren companies	24.6	25.1	'	'
Accrued liabilities	127.4	139.3	'	'
Short-term borrowings	28.6	116.7	242.8	'
Current maturities of long-term debt payable to VUHI	0	105	'	'
Total current liabilities	352.7	536.8	'	'
Long-term Debt - Net of Current Maturities	1,257.10	1,103.40	'	'
Deferred income taxes	627.4	578.5	'	'
Regulatory liabilities	387.3	364.2	'	'
Deferred Credits and Other Liabilities	83.5	73.9	'	'
Total deferred credits and other liabilities	1,098.20	1,016.60	'	'
Common stock (no par value)	787.7	781.6	'	'
Retained earnings	645.1	608.4	'	'
Total common shareholders' equity	1,432.80	1,390	'	'
TOTAL LIABILITIES and SHAREHOLDERS' EQUITY	4,140.80	4,046.80	'	'
Line of Credit Facility, Maximum Borrowing Capacity	350	'	'	'
Line of Credit Facility, Amount Outstanding	29	'	'	'
Unsecured Debt	875	'	'	'
Subsidiary Ownership Percentage	100.00%	'	'	'
Subsidiary Guarantors [Member]	'	'	'	'
ASSETS	'	'	'	'
Cash & cash equivalents	8.2	12.5	5.3	2
Accounts receivable - less reserves	112.1	81.8	'	'
Intercompany Receivables	0.3	0	'	'
Accrued unbilled revenues	113.5	93.6	'	'
Inventories	89.9	114	'	'
Recoverable fuel & natural gas costs	5.5	25.3	'	'
Prepayments & other curent assets	37.3	52	'	'
Total current assets	366.8	379.2	'	'
Original Cost	5,389.60	5,176.60	'	'
Less: accumulated depreciation & amortization	2,165.30	2,057.20	'	'
Net utility plant	3,224.30	3,119.40	'	'
Investments in consolidated subsidiaries	0	0	'	'
Notes receivable from consolidated subsidiaries	0	0	'	'
Investments in unconsolidated affiliates	0.2	0.2	'	'
Other Investments	22.8	27.8	'	'
Nonutility plant - net	2.2	2.6	'	'
Goodwill - net	205	205	'	'
Regulatory assets	113.4	104.1	'	'
Other assets	32.2	40.4	'	'
TOTAL ASSETS	3,966.90	3,878.70	'	'
LIABILITIES & SHAREHOLDERS' EQUITY	'	'	'	'
Accounts payable	161.6	114.8	'	'
Accounts payable to affiliated companies	'	29.7	'	'
Intercompany Payables	11.7	10.6	'	'
Payables to other Vectren companies	24.6	25.1	'	'
Accrued liabilities	150.3	131.3	'	'
Short-term borrowings	0	0	'	'
Intercompany short-term borrowings	73.1	134.5	'	'
Current maturities of long-term debt payable to VUHI	'	5	'	'
Total current liabilities	421.3	451	'	'
Long-term Debt - Net of Current Maturities	382.5	382.3	'	'
Long-term debt due to VUHI	696.4	679.7	'	'
Total long-term debt - net	1,078.90	1,062	'	'
Deferred income taxes	616.9	595.4	'	'
Regulatory liabilities	385.7	362.2	'	'
Deferred Credits and Other Liabilities	88.3	78.9	'	'
Total deferred credits and other liabilities	1,090.90	1,036.50	'	'
Common stock (no par value)	800.9	787.8	'	'
Retained earnings	574.9	541.4	'	'
Total common shareholders' equity	1,375.80	1,329.20	'	'
TOTAL LIABILITIES and SHAREHOLDERS' EQUITY	3,966.90	3,878.70	'	'
Parent Company [Member]	'	'	'	'
ASSETS	'	'	'	'
Cash & cash equivalents	0.4	0.8	0.7	0.4
Accounts receivable - less reserves	0	0	'	'
Intercompany Receivables	84.8	145.1	'	'
Accrued unbilled revenues	0	0	'	'
Inventories	0	0	'	'
Recoverable fuel & natural gas costs	0	0	'	'
Prepayments & other curent assets	40.1	5.8	'	'
Total current assets	125.3	151.7	'	'
Original Cost	0	0.2	'	'
Less: accumulated depreciation & amortization	0	0	'	'
Net utility plant	0	0.2	'	'
Investments in consolidated subsidiaries	1,375.80	1,329.20	'	'
Notes receivable from consolidated subsidiaries	696.4	679.7	'	'
Investments in unconsolidated affiliates	0	0	'	'
Other Investments	4.5	4.8	'	'
Nonutility plant - net	148.3	144.3	'	'
Goodwill - net	0	0	'	'
Regulatory assets	22.8	22.4	'	'
Other assets	1	1.7	'	'
TOTAL ASSETS	2,374.10	2,334	'	'
LIABILITIES & SHAREHOLDERS' EQUITY	'	'	'	'
Accounts payable	10.5	6.2	'	'
Accounts payable to affiliated companies	'	0	'	'
Intercompany Payables	0	0	'	'
Payables to other Vectren companies	0	0	'	'
Accrued liabilities	12.1	13.5	'	'
Short-term borrowings	28.6	116.7	'	'
Intercompany short-term borrowings	0.3	0	'	'
Current maturities of long-term debt payable to VUHI	'	100	'	'
Total current liabilities	51.5	236.4	'	'
Long-term Debt - Net of Current Maturities	874.6	721.1	'	'
Long-term debt due to VUHI	0	0	'	'
Total long-term debt - net	874.6	721.1	'	'
Deferred income taxes	10.5	-16.9	'	'
Regulatory liabilities	1.6	2	'	'
Deferred Credits and Other Liabilities	3.1	1.4	'	'
Total deferred credits and other liabilities	15.2	-13.5	'	'
Common stock (no par value)	787.7	781.6	'	'
Retained earnings	645.1	608.4	'	'
Total common shareholders' equity	1,432.80	1,390	'	'
TOTAL LIABILITIES and SHAREHOLDERS' EQUITY	2,374.10	2,334	'	'
Consolidation, Eliminations [Member]	'	'	'	'
ASSETS	'	'	'	'
Cash & cash equivalents	0	0	0	0
Accounts receivable - less reserves	0	0	'	'
Intercompany Receivables	-85.1	-145.1	'	'
Accrued unbilled revenues	0	0	'	'
Inventories	0	0	'	'
Recoverable fuel & natural gas costs	0	0	'	'
Prepayments & other curent assets	-35	-5.5	'	'
Total current assets	-120.1	-150.6	'	'
Original Cost	0	0	'	'
Less: accumulated depreciation & amortization	0	0	'	'
Net utility plant	0	0	'	'
Investments in consolidated subsidiaries	-1,375.80	-1,329.20	'	'
Notes receivable from consolidated subsidiaries	-696.4	-679.7	'	'
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	-7.9	-6.4	'	'
TOTAL ASSETS	-2,200.20	-2,165.90	'	'
LIABILITIES & SHAREHOLDERS' EQUITY	'	'	'	'
Accounts payable	0	0	'	'
Accounts payable to affiliated companies	'	0	'	'
Intercompany Payables	-11.7	-10.6	'	'
Payables to other Vectren companies	0	0	'	'
Accrued liabilities	-35	-5.5	'	'
Short-term borrowings	0	0	'	'
Intercompany short-term borrowings	-73.4	-134.5	'	'
Current maturities of long-term debt payable to VUHI	'	0	'	'
Total current liabilities	-120.1	-150.6	'	'
Long-term Debt - Net of Current Maturities	0	0	'	'
Long-term debt due to VUHI	-696.4	-679.7	'	'
Total long-term debt - net	-696.4	-679.7	'	'
Deferred income taxes	0	0	'	'
Regulatory liabilities	0	0	'	'
Deferred Credits and Other Liabilities	-7.9	-6.4	'	'
Total deferred credits and other liabilities	-7.9	-6.4	'	'
Common stock (no par value)	-800.9	-787.8	'	'
Retained earnings	-574.9	-541.4	'	'
Total common shareholders' equity	-1,375.80	-1,329.20	'	'
TOTAL LIABILITIES and SHAREHOLDERS' EQUITY	-2,200.20	-2,165.90	'	'
Consolidated Entities [Member]	'	'	'	'
ASSETS	'	'	'	'
Cash & cash equivalents	8.6	13.3	6	2.4
Accounts receivable - less reserves	112.1	81.8	'	'
Intercompany Receivables	0	0	'	'
Accrued unbilled revenues	113.5	93.6	'	'
Inventories	89.9	114	'	'
Recoverable fuel & natural gas costs	5.5	25.3	'	'
Prepayments & other curent assets	42.4	52.3	'	'
Total current assets	372	380.3	'	'
Original Cost	5,389.60	5,176.80	'	'
Less: accumulated depreciation & amortization	2,165.30	2,057.20	'	'
Net utility plant	3,224.30	3,119.60	'	'
Investments in consolidated subsidiaries	0	0	'	'
Notes receivable from consolidated subsidiaries	0	0	'	'
Investments in unconsolidated affiliates	0.2	0.2	'	'
Other Investments	27.3	32.6	'	'
Nonutility plant - net	150.5	146.9	'	'
Goodwill - net	205	205	'	'
Regulatory assets	136.2	126.5	'	'
Other assets	25.3	35.7	'	'
TOTAL ASSETS	4,140.80	4,046.80	'	'
LIABILITIES & SHAREHOLDERS' EQUITY	'	'	'	'
Accounts payable	172.1	121	'	'
Accounts payable to affiliated companies	'	29.7	'	'
Intercompany Payables	0	0	'	'
Payables to other Vectren companies	24.6	25.1	'	'
Accrued liabilities	127.4	139.3	'	'
Short-term borrowings	28.6	116.7	'	'
Intercompany short-term borrowings	0	0	'	'
Current maturities of long-term debt payable to VUHI	'	105	'	'
Total current liabilities	352.7	536.8	'	'
Long-term Debt - Net of Current Maturities	1,257.10	1,103.40	'	'
Long-term debt due to VUHI	0	0	'	'
Total long-term debt - net	1,257.10	1,103.40	'	'
Deferred income taxes	627.4	578.5	'	'
Regulatory liabilities	387.3	364.2	'	'
Deferred Credits and Other Liabilities	83.5	73.9	'	'
Total deferred credits and other liabilities	1,098.20	1,016.60	'	'
Common stock (no par value)	787.7	781.6	'	'
Retained earnings	645.1	608.4	'	'
Total common shareholders' equity	1,432.80	1,390	'	'
TOTAL LIABILITIES and SHAREHOLDERS' EQUITY	$4,140.80	$4,046.80	'	'

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, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
OPERATING REVENUES [Abstract]	'	'	'	'	'	'	'	'	'	'	'
Gas utility	'	'	'	'	'	'	'	'	$810	$738.10	$819.10
Electric utility	'	'	'	'	'	'	'	'	619.3	594.9	635.9
Other	'	'	'	'	'	'	'	'	0.3	0.6	2
Total operating revenues	403.6	267.7	292.8	465.5	368	267.7	265.8	432.1	1,429.60	1,333.60	1,457
OPERATING EXPENSES [Abstract]	'	'	'	'	'	'	'	'	'	'	'
Cost of Gas Sold	'	'	'	'	'	'	'	'	358.1	301.3	375.4
Cost of fuel & purchased power	'	'	'	'	'	'	'	'	202.9	192	240.4
Other operating	'	'	'	'	'	'	'	'	333.4	310.1	313.1
Depreciation & Amortization	'	'	'	'	'	'	'	'	196.4	190	192.3
Taxes other than income taxes	'	'	'	'	'	'	'	'	57.2	53.4	54
Total operating expenses	'	'	'	'	'	'	'	'	1,148	1,046.80	1,175.20
OPERATING INCOME	70.5	54.5	51.2	105.4	74	57.1	49.8	105.9	281.6	286.8	281.8
Other Nonoperating Income (Expense)	'	'	'	'	'	'	'	'	10.5	8	4.3
Interest Expense	'	'	'	'	'	'	'	'	65	71.5	80.3
INCOME BEFORE INCOME TAXES	'	'	'	'	'	'	'	'	227.1	223.3	205.8
Income taxes	'	'	'	'	'	'	'	'	85.3	85.3	82.9
NET INCOME	37.2	25.3	24.2	55.1	35.5	26.4	20.1	56	141.8	138	122.9
Subsidiary Guarantors [Member]	'	'	'	'	'	'	'	'	'	'	'
OPERATING REVENUES [Abstract]	'	'	'	'	'	'	'	'	'	'	'
Gas utility	'	'	'	'	'	'	'	'	810	738.1	819.1
Electric utility	'	'	'	'	'	'	'	'	619.3	594.9	635.9
Other	'	'	'	'	'	'	'	'	0	0	0
Total operating revenues	'	'	'	'	'	'	'	'	1,429.30	1,333	1,455
OPERATING EXPENSES [Abstract]	'	'	'	'	'	'	'	'	'	'	'
Cost of Gas Sold	'	'	'	'	'	'	'	'	358.1	301.3	375.4
Cost of fuel & purchased power	'	'	'	'	'	'	'	'	202.9	192	240.4
Other operating	'	'	'	'	'	'	'	'	369.2	348.5	354.6
Depreciation & Amortization	'	'	'	'	'	'	'	'	174.6	166.8	164.6
Taxes other than income taxes	'	'	'	'	'	'	'	'	55.6	51.7	52.3
Total operating expenses	'	'	'	'	'	'	'	'	1,160.40	1,060.30	1,187.30
OPERATING INCOME	'	'	'	'	'	'	'	'	268.9	272.7	267.7
Equity in earnings of consolidated companies, net of tax	'	'	'	'	'	'	'	'	0	0	0
Other Nonoperating Income (Expense)	'	'	'	'	'	'	'	'	7.1	6.2	3.1
Nonoperating Income (Expense)	'	'	'	'	'	'	'	'	7.1	6.2	3.1
Interest Expense	'	'	'	'	'	'	'	'	59.8	65.6	73.5
INCOME BEFORE INCOME TAXES	'	'	'	'	'	'	'	'	216.2	213.3	197.3
Income taxes	'	'	'	'	'	'	'	'	84.9	85.4	79.8
NET INCOME	'	'	'	'	'	'	'	'	131.3	127.9	117.5
Parent Company [Member]	'	'	'	'	'	'	'	'	'	'	'
OPERATING REVENUES [Abstract]	'	'	'	'	'	'	'	'	'	'	'
Gas utility	'	'	'	'	'	'	'	'	0	0	0
Electric utility	'	'	'	'	'	'	'	'	0	0	0
Other	'	'	'	'	'	'	'	'	37.9	40.1	43.9
Total operating revenues	'	'	'	'	'	'	'	'	37.9	40.1	43.9
OPERATING EXPENSES [Abstract]	'	'	'	'	'	'	'	'	'	'	'
Cost of Gas Sold	'	'	'	'	'	'	'	'	0	0	0
Cost of fuel & purchased power	'	'	'	'	'	'	'	'	0	0	0
Other operating	'	'	'	'	'	'	'	'	0	0.4	0
Depreciation & Amortization	'	'	'	'	'	'	'	'	21.3	22.7	27.1
Taxes other than income taxes	'	'	'	'	'	'	'	'	1.5	1.6	1.5
Total operating expenses	'	'	'	'	'	'	'	'	22.8	24.7	28.6
OPERATING INCOME	'	'	'	'	'	'	'	'	15.1	15.4	15.3
Equity in earnings of consolidated companies, net of tax	'	'	'	'	'	'	'	'	131.3	127.9	117.5
Other Nonoperating Income (Expense)	'	'	'	'	'	'	'	'	38.5	41.4	48.9
Nonoperating Income (Expense)	'	'	'	'	'	'	'	'	169.8	169.3	166.4
Interest Expense	'	'	'	'	'	'	'	'	42.7	46.8	55.7
INCOME BEFORE INCOME TAXES	'	'	'	'	'	'	'	'	142.2	137.9	126
Income taxes	'	'	'	'	'	'	'	'	0.4	-0.1	3.1
NET INCOME	'	'	'	'	'	'	'	'	141.8	138	122.9
Consolidation, Eliminations [Member]	'	'	'	'	'	'	'	'	'	'	'
OPERATING REVENUES [Abstract]	'	'	'	'	'	'	'	'	'	'	'
Gas utility	'	'	'	'	'	'	'	'	0	0	0
Electric utility	'	'	'	'	'	'	'	'	0	0	0
Other	'	'	'	'	'	'	'	'	-37.6	-39.5	-41.9
Total operating revenues	'	'	'	'	'	'	'	'	-37.6	-39.5	-41.9
OPERATING EXPENSES [Abstract]	'	'	'	'	'	'	'	'	'	'	'
Cost of Gas Sold	'	'	'	'	'	'	'	'	0	0	0
Cost of fuel & purchased power	'	'	'	'	'	'	'	'	0	0	0
Other operating	'	'	'	'	'	'	'	'	-35.8	-38.8	-41.5
Depreciation & Amortization	'	'	'	'	'	'	'	'	0.5	0.5	0.6
Taxes other than income taxes	'	'	'	'	'	'	'	'	0.1	0.1	0.2
Total operating expenses	'	'	'	'	'	'	'	'	-35.2	-38.2	-40.7
OPERATING INCOME	'	'	'	'	'	'	'	'	-2.4	-1.3	-1.2
Equity in earnings of consolidated companies, net of tax	'	'	'	'	'	'	'	'	-131.3	-127.9	-117.5
Other Nonoperating Income (Expense)	'	'	'	'	'	'	'	'	-35.1	-39.6	-47.7
Nonoperating Income (Expense)	'	'	'	'	'	'	'	'	-166.4	-167.5	-165.2
Interest Expense	'	'	'	'	'	'	'	'	-37.5	-40.9	-48.9
INCOME BEFORE INCOME TAXES	'	'	'	'	'	'	'	'	-131.3	-127.9	-117.5
Income taxes	'	'	'	'	'	'	'	'	0	0	0
NET INCOME	'	'	'	'	'	'	'	'	-131.3	-127.9	-117.5
Consolidated Entities [Member]	'	'	'	'	'	'	'	'	'	'	'
OPERATING REVENUES [Abstract]	'	'	'	'	'	'	'	'	'	'	'
Gas utility	'	'	'	'	'	'	'	'	810	738.1	819.1
Electric utility	'	'	'	'	'	'	'	'	619.3	594.9	635.9
Other	'	'	'	'	'	'	'	'	0.3	0.6	2
Total operating revenues	'	'	'	'	'	'	'	'	1,429.60	1,333.60	1,457
OPERATING EXPENSES [Abstract]	'	'	'	'	'	'	'	'	'	'	'
Cost of Gas Sold	'	'	'	'	'	'	'	'	358.1	301.3	375.4
Cost of fuel & purchased power	'	'	'	'	'	'	'	'	202.9	192	240.4
Other operating	'	'	'	'	'	'	'	'	333.4	310.1	313.1
Depreciation & Amortization	'	'	'	'	'	'	'	'	196.4	190	192.3
Taxes other than income taxes	'	'	'	'	'	'	'	'	57.2	53.4	54
Total operating expenses	'	'	'	'	'	'	'	'	1,148	1,046.80	1,175.20
OPERATING INCOME	'	'	'	'	'	'	'	'	281.6	286.8	281.8
Equity in earnings of consolidated companies, net of tax	'	'	'	'	'	'	'	'	0	0	0
Other Nonoperating Income (Expense)	'	'	'	'	'	'	'	'	10.5	8	4.3
Nonoperating Income (Expense)	'	'	'	'	'	'	'	'	10.5	8	4.3
Interest Expense	'	'	'	'	'	'	'	'	65	71.5	80.3
INCOME BEFORE INCOME TAXES	'	'	'	'	'	'	'	'	227.1	223.3	205.8
Income taxes	'	'	'	'	'	'	'	'	85.3	85.3	82.9
NET INCOME	'	'	'	'	'	'	'	'	$141.80	$138	$122.90

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, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Net cash flows from operating activities	$399.90	$373.40	$334.30	'
Additional capital contribution	6.1	7	0	'
Long-term debt - net of issuance costs	381.7	99.5	148.9	'
Dividends to parent	-105.1	-101.5	-91.6	'
Retirement of long-term debt, including premiums paid	-337.5	0	-347	'
Other Financing Activities	0	0	-1.1	'
Net change in short-term borrowings	-88.1	-126.1	195.8	'
Net cash flows from financing activities	-142.9	-121.1	-95	'
Proceeds from other investing activities	0.8	2.6	0.4	'
Capital expenditures, excluding AFUDC equity	-262.5	-247.6	-235.3	'
Other investing activities	0	0	-0.8	'
Net cash flows from investing activities	-261.7	-245	-235.7	'
Net change in cash and cash equivalents	-4.7	7.3	3.6	'
Cash & cash equivalents	8.6	13.3	6	2.4
Subsidiary Guarantors [Member]	'	'	'	'
Net cash flows from operating activities	371	335.6	316.2	'
Additional capital contribution	13.1	0	248.4	'
Long-term debt - net of issuance costs	232.6	0	'	'
Dividends to parent	-97.9	-70.9	-84.4	'
Retirement of long-term debt, including premiums paid	-223.6	'	-337.4	'
Other Financing Activities	'	'	0	'
Net change in intercompany short-term borrowings	-61.5	-24	13.4	'
Net change in short-term borrowings	0	0	0	'
Net cash flows from financing activities	-137.3	-94.9	-160	'
Consolidated subsidiary distributions	0	0	0	'
Proceeds from other investing activities	0.6	0.3	0.2	'
Capital expenditures, excluding AFUDC equity	-238.3	-233.8	-218.2	'
Requirements for consolidated subsidiary investments	0	'	'	'
Other investing activities	'	'	-0.8	'
Increase decrease in long term intercompany notes receivable	0	'	0	'
Net change in short term intercompany notes receivable	-0.3	0	65.9	'
Net cash flows from investing activities	-238	-233.5	-152.9	'
Net change in cash and cash equivalents	-4.3	7.2	3.3	'
Cash & cash equivalents	8.2	12.5	5.3	2
Parent Company [Member]	'	'	'	'
Net cash flows from operating activities	28.9	37.8	18.1	'
Additional capital contribution	6.1	7	148.9	'
Long-term debt - net of issuance costs	273.5	99.5	'	'
Dividends to parent	-105.1	-101.5	-91.6	'
Retirement of long-term debt, including premiums paid	-221.6	'	-347	'
Other Financing Activities	'	'	-1.1	'
Net change in intercompany short-term borrowings	0.3	0	-277.6	'
Net change in short-term borrowings	-88.1	-126.1	195.8	'
Net cash flows from financing activities	-134.9	-121.1	-372.6	'
Consolidated subsidiary distributions	97.9	70.9	84.4	'
Proceeds from other investing activities	0.2	2.3	0.2	'
Capital expenditures, excluding AFUDC equity	-24.2	-13.8	-17.1	'
Requirements for consolidated subsidiary investments	-13.1	'	'	'
Other investing activities	'	'	0	'
Increase decrease in long term intercompany notes receivable	-16.7	'	89	'
Net change in short term intercompany notes receivable	61.5	24	198.3	'
Net cash flows from investing activities	105.6	83.4	354.8	'
Net change in cash and cash equivalents	-0.4	0.1	0.3	'
Cash & cash equivalents	0.4	0.8	0.7	0.4
Consolidation, Eliminations [Member]	'	'	'	'
Net cash flows from operating activities	0	0	0	'
Additional capital contribution	-13.1	0	-248.4	'
Long-term debt - net of issuance costs	-124.4	0	'	'
Dividends to parent	97.9	70.9	84.4	'
Retirement of long-term debt, including premiums paid	107.7	'	337.4	'
Other Financing Activities	'	'	0	'
Net change in intercompany short-term borrowings	61.2	24	264.2	'
Net change in short-term borrowings	0	0	0	'
Net cash flows from financing activities	129.3	94.9	437.6	'
Consolidated subsidiary distributions	-97.9	-70.9	-84.4	'
Proceeds from other investing activities	0	0	0	'
Capital expenditures, excluding AFUDC equity	0	0	0	'
Requirements for consolidated subsidiary investments	13.1	'	'	'
Other investing activities	'	'	0	'
Increase decrease in long term intercompany notes receivable	16.7	'	-89	'
Net change in short term intercompany notes receivable	-61.2	-24	-264.2	'
Net cash flows from investing activities	-129.3	-94.9	-437.6	'
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	399.9	373.4	334.3	'
Additional capital contribution	6.1	7	148.9	'
Long-term debt - net of issuance costs	381.7	99.5	'	'
Dividends to parent	-105.1	-101.5	-91.6	'
Retirement of long-term debt, including premiums paid	-337.5	'	-347	'
Other Financing Activities	'	'	-1.1	'
Net change in intercompany short-term borrowings	0	0	0	'
Net change in short-term borrowings	-88.1	-126.1	195.8	'
Net cash flows from financing activities	-142.9	-121.1	-95	'
Consolidated subsidiary distributions	0	0	0	'
Proceeds from other investing activities	0.8	2.6	0.4	'
Capital expenditures, excluding AFUDC equity	-262.5	-247.6	-235.3	'
Requirements for consolidated subsidiary investments	0	'	'	'
Other investing activities	'	'	-0.8	'
Increase decrease 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	-261.7	-245	-235.7	'
Net change in cash and cash equivalents	-4.7	7.3	3.6	'
Cash & cash equivalents	$8.60	$13.30	$6	$2.40

Quarterly_Financial_Data_Unaud2

Quarterly Financial Data (Unaudited) (Details) (USD $)	3 Months Ended								12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Quarterly Financial Information Disclosure [Abstract]	'	'	'	'	'	'	'	'	'	'	'
Total operating revenues	$403.60	$267.70	$292.80	$465.50	$368	$267.70	$265.80	$432.10	$1,429.60	$1,333.60	$1,457
Operating Income	70.5	54.5	51.2	105.4	74	57.1	49.8	105.9	281.6	286.8	281.8
Net Income	$37.20	$25.30	$24.20	$55.10	$35.50	$26.40	$20.10	$56	$141.80	$138	$122.90

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, 2013	Dec. 31, 2012	Dec. 31, 2011
Accumulated Provision for Uncollectible Accounts [Member]	'	'	'
Valuation and Qualifying Accounts Disclosure [Line Items]	'	'	'
Balance, at beginning of year	$5	$5.90	$4.50
Additions charged to expenses	6.5	7.4	11.4
Additions charged to other accounts	0	0	0
Deductions from Reserves, Net	6.5	8.3	10
Balance, at end of period	5	5	5.9
Restructuring Costs [Member]	'	'	'
Valuation and Qualifying Accounts Disclosure [Line Items]	'	'	'
Balance, at beginning of year	0.3	0.4	0.4
Additions charged to expenses	0	0	0
Additions charged to other accounts	0	0	0
Deductions from Reserves, Net	0.1	0.1	0
Balance, at end of period	$0.20	$0.30	$0.40