Vectren (VVC) Inactive 10-Q7 May 152015 Q1 Quarterly reportFinancial data

Company Profile

Document_and_Entity_Informatio

Document and Entity Information	3 Months Ended
Document and Entity Information	Mar. 31, 2015	Apr. 30, 2015
Document and Entity Information [Abstract]
Entity Registrant Name	VECTREN CORP
Entity Central Index Key	1096385
Current Fiscal Year End Date	-19
Entity Filer Category	Large Accelerated Filer
Document Type	10-Q
Document Period End Date	31-Mar-15
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	Q1
Amendment Flag	FALSE
Entity Common Stock, Shares Outstanding		82,628,697

CONDENSED_CONSOLIDATED_BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Millions, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Current Assets [Abstract]
Cash & cash equivalents	$17.10	$86.40
Accounts receivable - less reserves of $7.3 & $6.0, respectively	243.3	196
Accrued unbilled revenues	144.4	164.8
Inventories	92.7	118.5
Recoverable fuel & natural gas costs	0	9.8
Prepayments & other current assets	46.5	110.9
Total current assets	544	686.4
Utility Plant [Abstract]
Original cost	5,778	5,718.70
Less: accumulated depreciation & amortization	2,316.90	2,279.70
Net utility plant	3,461.10	3,439
Investments in unconsolidated affiliates	23.4	23.4
Other utility & corporate investments	37.5	37.2
Other nonutility investments	33.8	33.6
Nonutility plant - net	380.8	378
Goodwill - net	289.9	289.9
Regulatory assets	224.8	233.6
Other assets	40.1	41.2
TOTAL ASSETS	5,035.40	5,162.30
Current Liabilities [Abstract]
Accounts payable	216.1	248.9
Refundable fuel & natural gas costs	23	2.5
Accrued liabilities	190.5	184.9
Short-term borrowings	6.4	156.4
Current maturities of long-term debt	225	170
Total current liabilities	661	762.7
Long-term Debt - Net of Current Maturities	1,347.40	1,407.30
Deferred Credits & Other Liabilities [Abstract]
Commitments & Contingencies (Notes 7, 10-12)
Deferred income taxes	753.3	741.2
Regulatory liabilities	417.1	410.3
Deferred credits & other liabilities	222.7	234.2
Total deferred credits & other liabilities	1,393.10	1,385.70
Common Shareholders' Equity [Abstract]
Common stock (no par value) â€“ issued & outstanding 82.6 shares	717.5	715.7
Retained earnings	917.7	892.2
Accumulated other comprehensive (loss)	-1.3	-1.3
Total common shareholders' equity	1,633.90	1,606.60
TOTAL LIABILITIES & SHAREHOLDERS' EQUITY	$5,035.40	$5,162.30

CONDENSED_CONSOLIDATED_BALANCE1

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Millions, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Current Assets [Abstract]
Reserves	$7.30	$6
Common Shareholders' Equity [Abstract]
Common Stock, Shares, Issued	82.6	82.6
Common Stock, Shares, Outstanding	82.6	82.6

CONDENSED_CONSOLIDATED_STATEME

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited) (USD $)	3 Months Ended
In Millions, except Per Share data, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
OPERATING REVENUES [Abstract]
Gas utility	$352.90	$443.60
Electric utility	153.9	163
Nonutility	199.4	190.2
Total operating revenues	706.2	796.8
OPERATING EXPENSES [Abstract]
Cost of gas sold	172	270.9
Cost of fuel & purchased power	50.1	57
Cost of nonutility revenues	64.3	67.7
Other operating	231.1	207.6
Depreciation & amortization	62.9	73.8
Taxes other than income taxes	19.7	20.8
Total operating expenses	600.1	697.8
OPERATING INCOME	106.1	99
OTHER INCOME (EXPENSE) [Abstract]
Equity in earnings (losses) of unconsolidated affiliates	0	-0.1
Other income - net	5.6	4.3
Total other income	5.6	4.2
INTEREST EXPENSE	21	22.1
INCOME BEFORE INCOME TAXES	90.7	81.1
INCOME TAXES	33.7	29.9
NET INCOME AND COMPREHENSIVE INCOME	$57	$51.20
AVERAGE COMMON SHARES OUTSTANDING	82.6	82.4
DILUTED COMMOM SHARES OUTSTANDING	82.6	82.5
EARNINGS PER SHARE OF COMMON STOCK:
BASIC	$0.69	$0.62
DILUTED	$0.69	$0.62
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK	$0.38	$0.36

CONDENSED_CONSOLIDATED_STATEME1

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
CASH FLOWS FROM OPERATING ACTIVITES [Abstract]
Net income	$57	$51.20
Adjustments to reconcile net income to cash from operating activities:
Depreciation & amortization	62.9	73.8
Deferred income taxes & investment tax credits	14.6	5.7
Provision for uncollectible accounts	3.3	2.3
Expense portion of pension & postretirement benefit cost	1.6	1
Other noncash charges - net	1.6	3
Changes in working capital accounts [Abstract]
Accounts receivable & accrued unbilled revenues	-30.2	-4.9
Inventories	25.8	29.1
Recoverable/refundable fuel & natural gas costs	30.3	-24.2
Prepayments & other current assets	61.2	38.4
Accounts payable, including to affiliated companies	-27.6	-20
Accrued liabilities	5.6	19.2
Employer contributions to pension & postretirement plans	-20.9	-0.9
Changes in noncurrent assets	11.3	9.1
Changes in noncurrent liabilities	3.6	-0.8
Net cash provided by operating activities	200.1	182
Proceeds from:
Dividend reinvestment plan & other common stock issuances	1.6	1.7
Requirements for:
Dividends on common stock	-31.5	-29.7
Retirement of long-term debt	-5	-30
Net change in short-term borrowings	-150	-14.4
Net cash used in financing activities	-184.9	-72.4
Proceeds from:
Proceeds from other collections	0.8	1.1
Requirements for:
Capital expenditures, excluding AFUDC equity	-85.3	-77.7
Net cash used in investing activities	-84.5	-76.6
Net change in cash & cash equivalents	-69.3	33
Cash & cash equivalents at beginning of period	86.4	21.5
Cash & cash equivalents at end of period	$17.10	$54.50

Organization_and_Nature_of_Ope

Organization and Nature of Operations	3 Months Ended
Organization and Nature of Operations	Mar. 31, 2015
Organization and Nature of Operations [Abstract]
Organization and Nature of Operations	Organization and Nature of Operations

	Vectren Corporation (the Company or Vectren), an Indiana corporation, is an energy holding company headquartered in Evansville, Indiana. The Company’s wholly-owned subsidiary, Vectren Utility Holdings, Inc. (Utility Holdings or VUHI), serves as the intermediate holding company for three public utilities: Indiana Gas Company, Inc. (Indiana Gas), Southern Indiana Gas and Electric Company (SIGECO), and Vectren Energy Delivery of Ohio, Inc. (VEDO). Utility Holdings also has other assets that provide information technology and other services to the three utilities. Utility Holdings’ consolidated operations are collectively referred to as the Utility Group. Both Vectren and Utility Holdings are holding companies as defined by the Energy Policy Act of 2005 (Energy Act). Vectren was incorporated under the laws of Indiana on June 10, 1999.

	Indiana Gas provides energy delivery services to over 585,000 natural gas customers located in central and southern Indiana. SIGECO provides energy delivery services to over 143,000 electric customers and over 111,000 gas customers located near Evansville in southwestern Indiana. SIGECO also owns and operates electric generation assets to serve its electric customers and optimizes those assets in the wholesale power market. Indiana Gas and SIGECO generally do business as Vectren Energy Delivery of Indiana. VEDO provides energy delivery services to over 317,000 natural gas customers located near Dayton in west-central Ohio.

	The Company, through Vectren Enterprises, Inc. (Enterprises), is involved in nonutility activities in two primary business areas: Infrastructure Services and Energy Services. Infrastructure Services provides underground pipeline construction and repair services. Energy Services provides energy performance contracting and sustainable infrastructure, such as renewables, distributed generation, and combined heat and power projects. Prior to August 29, 2014, the Company had activities in its Coal Mining business. Results in the financial statements include the results of Vectren Fuels, Inc. (Vectren Fuels) through the date of sale of August 29, 2014, when the Company exited the coal mining business through the sale of Vectren Fuels. Enterprises has other legacy businesses that have invested in energy-related opportunities and services, real estate, and a leveraged lease, among other investments. All of the above are collectively referred to as the Nonutility Group.

Basis_of_Presentation

Basis of Presentation	3 Months Ended
Basis of Presentation	Mar. 31, 2015
Basis of Presentation [Abstract]
Basis of Presentation	Basis of Presentation

	The interim condensed consolidated financial statements included in this report have been prepared by the Company, without audit, as provided in the rules and regulations of the Securities and Exchange Commission and include a review of subsequent events through the date the financial statements were issued. Certain information and note disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States have been omitted as provided in such rules and regulations. The information in this report reflects all adjustments which are, in the opinion of management, necessary to fairly state the interim periods presented, inclusive of adjustments that are normal and recurring in nature. These condensed consolidated financial statements and related notes should be read in conjunction with the Company’s audited annual consolidated financial statements for the year ended December 31, 2014, filed with the Securities and Exchange Commission on February 17, 2015, on Form 10-K. Because of the seasonal nature of the Company’s operations, the results shown on a quarterly basis are not necessarily indicative of annual results.

	The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates.

Earnings_Per_Share

Earnings Per Share	3 Months Ended
	Mar. 31, 2015
Earnings Per Share [Abstract]
Earnings Per Share	Earnings Per Share

	The Company uses the two class method to calculate earnings per share (EPS). The two class method is an earnings allocation formula that treats a participating security as having rights to earnings that otherwise would have been available to common shareholders. Under the two class method, earnings for a period are allocated between common shareholders and participating security holders based on their respective rights to receive dividends as if all undistributed book earnings for the period were distributed.

	Basic EPS is computed by dividing net income attributable to only the common shareholders by the weighted-average number of common shares outstanding for the period. Diluted EPS includes the impact of stock options and other equity based instruments to the extent the effect is dilutive.

	The following table illustrates the basic and dilutive EPS calculations for the periods presented in these financial statements.



		Three Months Ended
		March 31,
	(In millions, except per share data)	2015		2014
	Numerator:
	Reported net income (Numerator for Basic and Diluted EPS)	$	57	$	51.2

	Denominator:

	Weighted average common shares outstanding	82.6		82.4
	(Denominator for Basic EPS)
	Conversion of share based compensation arrangements	0		0.1

	Adjusted weighted average shares outstanding and assumed
	conversions outstanding (Denominator for Diluted EPS)	82.6		82.5


	Basic EPS	$	0.69	$	0.62

	Diluted EPS	$	0.69	$	0.62


	For the three months ended March 31, 2015 and 2014, all options and equity based instruments were dilutive and immaterial.

Excise_and_Utility_Receipts_Ta

Excise and Utility Receipts Taxes	3 Months Ended
Excise and Utility Receipts Taxes	Mar. 31, 2015
Excise and Utility Receipts Taxes [Abstract]
Excise and Utility Receipts Taxes	Excise and 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, which totaled $11.7 million and $12.9 million in the three months ended March 31, 2015 and 2014, respectively, as a component of operating revenues. Expenses associated with excise and utility receipts taxes are recorded as a component of Taxes other than income taxes.

Retirement_Plans_and_Other_Pos

Retirement Plans and Other Postretirement Benefits	3 Months Ended
	Mar. 31, 2015
Pension and Other Postretirement Benefit Expense [Abstract]
Retirement Plans and Other Postretirement Benefits	Retirement Plans & Other Postretirement Benefits

	The Company maintains three qualified defined benefit pension plans, a nonqualified supplemental executive retirement plan (SERP), and a postretirement benefit plan. The defined benefit pension plans and postretirement benefit plan, which cover eligible full-time regular employees, are primarily noncontributory. The postretirement health care and life insurance plans are a combination of self-insured and fully insured plans. The qualified pension plans and the SERP plan are aggregated under the heading “Pension Benefits.” The postretirement benefit plan is presented under the heading “Other Benefits.”

	Net Periodic Benefit Costs
	A summary of the components of net periodic benefit cost follows and the amortizations shown below are primarily reflected in Regulatory assets as a majority of pension and other postretirement benefits are being recovered through rates.


		Three Months Ended
		March 31,
		Pension Benefits						Other Benefits
	(In millions)	2015			2014			2015			2014
	Service cost	$	2		$	1.8		$	0.1		$	0.1

	Interest cost	3.6			3.9			0.5			0.5

	Expected return on plan assets	(5.6		)	(5.7		)	—			—

	Amortization of prior service cost	0.2			0.3			(0.7		)	(0.7		)

	Amortization of transitional obligation	—			—			—			—

	Amortization of actuarial loss	2.1			1.2			0.1			0.1

	Settlement charge	—			—			—			—

	Net periodic benefit cost	$	2.3		$	1.5		$	—		$	—



	Employer Contributions to Qualified Pension Plans
	As of March 31, 2015, the Company has made $20.0 million in contributions to its qualified pension plans. The Company does not anticipate making further contributions in 2015.

Supplemental_Cash_Flow_Informa

Supplemental Cash Flow Information	3 Months Ended
Supplemental Cash Flow Information	Mar. 31, 2015
Supplemental Cash Flow Information [Abstract]
Supplemental Cash Flow Information	Supplemental Cash Flow Information

	As of March 31, 2015 and December 31, 2014, the Company has accruals related to utility and nonutility plant purchases totaling approximately $12.6 million and $20.2 million, respectively.

ProLiance_Holdings_LLC

ProLiance Holdings, LLC	3 Months Ended
	Mar. 31, 2015
Equity Method Investments and Joint Ventures [Abstract]
ProLiance Holdings, LLC	ProLiance Holdings, LLC

	The Company has a remaining investment in ProLiance Holdings, LLC (ProLiance or ProLiance Holdings), an affiliate of the Company and Citizens Energy Group (Citizens). Much of the ProLiance business was sold on June 18, 2013 when ProLiance exited the natural gas marketing business through the disposition of certain of the net assets of its energy marketing business, ProLiance Energy, LLC. The Company's remaining investment in ProLiance relates primarily to an investment in LA Storage, LLC (LA Storage). Consistent with its ownership percentage, the Company is allocated 61 percent of ProLiance’s profits and losses; however, governance and voting rights remain at 50 percent for each member, and therefore, the Company accounts for its investment in ProLiance using the equity method of accounting.

	The Company's investment in ProLiance at March 31, 2015, shown at its 61 percent ownership share, is as follows.



		As of
		March 31,
	(In millions)	2015
	Cash	$	4.5

	Investment in LA Storage	21.8

	Other midstream asset investment	4.3

	Total investment in ProLiance	$	30.6

	Included in:
	Investments in unconsolidated affiliates	20.5

	Other nonutility investments	10.1


	LA Storage
	ProLiance Transportation and Storage, LLC (PT&S), a subsidiary of ProLiance, and Sempra Energy International, a subsidiary of Sempra Energy, through a joint venture, have a 100 percent interest in a development project for salt-cavern natural gas storage facilities known as LA Storage. PT&S is the minority member with a 25 percent interest, which it accounts for using the equity method. The project, which includes a pipeline system, is expected to include 12-19 Bcf of storage capacity, and has the potential for further expansion. This pipeline system is currently connected with several interstate pipelines, including the Cameron Interstate Pipeline operated by Sempra Pipelines & Storage, and will connect area liquefied natural gas regasification terminals to an interstate natural gas transmission system and storage facilities.

	Approximately 12 Bcf of the storage, which comprises three of the four FERC certified caverns, is fully tested but additional work is required to further develop the caverns. The timing and extent of development of these caverns is dependent on market conditions, including pricing, need for storage capacity, and development of the liquefied natural gas market, among other factors. As of March 31, 2015 and December 31, 2014, ProLiance's investment in the joint venture was $35.7 million and $35.4 million, respectively.

	The joint venture received a demand for arbitration from Williams Midstream Natural Gas Liquids, Inc. (Williams) in February 2011 related to a sublease agreement. Williams alleges that the joint venture was negligent in its attempt to convert certain salt caverns to natural gas storage and seeks damages of $56.7 million. The joint venture intends to vigorously defend itself and has asserted counterclaims substantially in excess of the amounts asserted by Williams. As such, as of March 31, 2015, ProLiance has no material reserve recorded related to this matter and this litigation has not materially impacted ProLiance's results of operations or statement of financial position.

Sale_of_Vectren_Fuels_Inc

Sale of Vectren Fuels, Inc.	3 Months Ended
Sale of Vectren Fuels, Inc.	Mar. 31, 2015
Discontinued Operations and Disposal Groups [Abstract]
Disposal Groups, Including Discontinued Operations, Disclosure [Text Block]	Sale of Vectren Fuels, Inc.

	On July 1, 2014, the Company announced that it had reached an agreement to sell its wholly owned coal mining subsidiary, Vectren Fuels, to Sunrise Coal, LLC (Sunrise Coal), an Indiana-based wholly owned subsidiary of Hallador Energy Company. Sunrise Coal owns and operates coal mines in the Illinois Basin. On August 29, 2014, the transaction closed. The sale of Vectren Fuels did not meet the requirements under GAAP to qualify as discontinued operations since Vectren has significant continuing cash flows related to the purchase of coal from the buyer of these mines. After the exit of the coal mining business by Vectren, Sunrise has assumed Vectren Fuels' supply contracts and has also negotiated new contracts for similar quality coal that will result in the Company purchasing most of its coal supply from Sunrise.

Financing_Activities

Financing Activities	3 Months Ended
Financing Activities	Mar. 31, 2015
Debt Disclosure [Abstract]
Financing Activities	Financing Activities

	Indiana Gas Unsecured Note Retirement
	On March 15, 2015, a $5.0 million Indiana Gas senior unsecured note matured. The Series E note carried a fixed interest rate of 7.15%. The repayment of debt was funded from the Company's short term credit facility.

Commitments_and_Contingencies

Commitments and Contingencies	3 Months Ended
Commitments and Contingencies	Mar. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments & Contingencies

	Performance Guarantees & Product Warranties
	In the normal course of business, wholly owned subsidiaries, including Energy Systems Group (ESG), issue payment and performance bonds and other forms of assurance that commit them to timely install infrastructure, operate facilities, pay vendors and subcontractors, and/or support warranty obligations.

	Specific to ESG, in its role as a general contractor in the performance contracting industry, at March 31, 2015, there are 47 open surety bonds supporting future performance. The average face amount of these obligations is $7.3 million, and the largest obligation has a face amount of $57.3 million, where construction related to the project is 95 percent complete. The maximum exposure from these obligations is limited by the level of work already completed and guarantees issued to ESG by various subcontractors. At March 31, 2015, approximately 36 percent of work was completed on projects with open surety bonds. A significant portion of these open surety bonds will be released within one year. In instances where ESG operates facilities, project guarantees extend over a longer period. In addition to its performance obligations, ESG also warrants the functionality of certain installed infrastructure generally for one year and the associated energy savings over a specified number of years.

	Based on a history of meeting performance obligations and installed products operating effectively, no significant liability or cost has been recognized for the periods presented.

	Corporate Guarantees
	The Company issues parent level guarantees to certain vendors and customers of its wholly owned subsidiaries. These guarantees do not represent incremental consolidated obligations; rather, they represent parental guarantees of subsidiary obligations in order to allow those subsidiaries the flexibility to conduct business without posting other forms of collateral. At March 31, 2015, parent level guarantees support a maximum of $195 million of ESG’s performance contracting commitments, warranty obligations, project guarantees, and energy savings guarantees. Further, an energy facility operated by ESG and managed by Keenan Ft. Detrick Energy, LLC (Keenan), is governed by an operations agreement. All payment obligations to Keenan under this agreement are also guaranteed by the Company. The Company guarantee of the Keenan Ft. Detrick Energy operations agreement, does not state a maximum guarantee. Due to the nature of work performed under this contract, the Company cannot estimate a maximum potential amount of future payments.

	In addition, the Company also has other guarantees outstanding, including letters of credit, supporting other consolidated subsidiary operations.

	While there can be no assurance that the Company guarantee provisions will be called upon, the Company believes that the likelihood of a material amount being triggered under any of these provisions is remote.

	Commitments
	The Company's regulated utilities have both firm and non-firm commitments to purchase natural gas, electricity, and coal as well as certain transportation and storage rights. Costs arising from these commitments, while significant, are pass-through costs, generally collected dollar-for-dollar from retail customers through regulator-approved cost recovery mechanisms.

	Legal & Regulatory Proceedings
	The Company is party to various legal proceedings, audits, and reviews by taxing authorities and other government agencies arising in the normal course of business. In the opinion of management, there are no legal proceedings or other regulatory reviews or audits pending against the Company that are likely to have a material adverse effect on its financial position, results of operations or cash flows.

Gas_Rate_Regulatory_Matters

Gas Rate & Regulatory Matters	3 Months Ended
Gas Rate & Regulatory Matters	Mar. 31, 2015
Public Utilities, General Disclosures [Abstract]
Gas Rate and Regulatory Matters	Gas Rate & Regulatory Matters

	Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement

	The Company monitors and maintains its natural gas distribution system to ensure that natural gas is delivered in a safe and efficient manner. The Company's natural gas utilities are currently engaged in programs to replace bare steel and cast iron infrastructure and other activities in both Indiana and Ohio to mitigate risk, improve the system, and comply with applicable regulations, many of which are a result of federal pipeline safety requirements. Laws in both Indiana and Ohio were passed that provide utilities the opportunity to timely recover costs of federally mandated projects and other infrastructure improvement projects outside of a base rate proceeding.

	In April 2011, Indiana Senate Bill 251 (Senate Bill 251) was signed into Indiana law. The law provides a framework to recover 80 percent of federally mandated costs through a periodic rate adjustment mechanism outside of a general rate case. Such costs include a return on the federally mandated capital investment, along with recovery of depreciation and other operating costs associated with these mandates. The remaining 20 percent of those costs is deferred for future recovery in the utility's next general rate case.

	In April 2013, Indiana Senate Bill 560 (Senate Bill 560) was signed into Indiana law. This legislation supplements Senate Bill 251 described above, and provides for cost recovery outside of a base rate proceeding for projects that either improve electric and gas system reliability and safety or are economic development projects that provide rural areas with access to gas service. Provisions of the legislation require that, among other things, requests for recovery include a seven-year project plan. Once the plan is approved by the IURC, 80 percent of such costs are eligible for current recovery using a periodic rate adjustment mechanism. Recoverable costs include a return on and of the investment, as well as property taxes and operating expenses. The remaining 20 percent of project costs is deferred and recovered in the utility’s next general rate case, which must be filed before the expiration of the seven year plan. The adjustment mechanism is capped at an annual increase in retail revenues of no more than two percent.

	In June 2011, Ohio House Bill 95 (House Bill 95) was signed into law. Outside of a base rate proceeding, this legislation permits a natural gas utility to apply for recovery of much of its capital expenditure program. By allowing for the deferral of costs, such as depreciation, property taxes, and debt-related post in service carrying costs until recovery is approved by the Ohio Commission.

	Indiana Recovery and Deferral Mechanisms
	The Company's Indiana natural gas utilities received Orders in 2008 and 2007 associated with the most recent base rate cases. These Orders authorized the deferral of financial impacts associated with bare steel and cast iron replacement activities. The Orders provide for the deferral of depreciation and post in service carrying costs on qualifying projects totaling $20 million annually at Indiana Gas and $3 million annually at SIGECO. The debt-related post-in-service carrying costs are recognized in the Condensed Consolidated Statements of Income currently. The recording of post-in-service carrying costs and depreciation deferral is limited by individual qualifying project to three years after being placed into service at SIGECO and four years after being placed into service at Indiana Gas. At March 31, 2015 and December 31, 2014, the Company has regulatory assets totaling $17.3 million and $16.4 million, respectively, associated with the deferral of depreciation and debt-related post-in-service carrying cost activities. Beginning in 2014, all bare steel and cast iron replacement activities are now part of the Company’s seven-year capital investment plan filed pursuant to Senate Bill 251, discussed further below.

	Requests for Recovery Under Indiana Regulatory Mechanisms
	On August 27, 2014, the IURC issued an Order approving the Company’s seven-year capital infrastructure replacement and improvement plan, beginning in 2014, and the proposed accounting authority and recovery, pursuant to Senate Bill 251 and 560. As provided in the two laws, the Order approved semi-annual filings for rate recovery of 100 percent of the costs, inclusive of return, related to these capital investments and operating expenses, with 80 percent of the costs recovered currently via an approved tracking mechanism and 20 percent of the costs deferred and recovered in the Company’s next base rate proceeding. In addition, the Order established guidelines to annually update the seven-year capital investment plan. Finally, the Order approved the Company’s proposal to recover eligible costs via a fixed monthly charge per residential customer.

	On September 26, 2014, the OUCC filed an appeal of the IURC's finding that the remaining value of retired assets replaced during the infrastructure projects should not be netted against the cost being recovered in the tracking mechanism. In April 2015, the Indiana Court of Appeals issued an opinion on an appeal involving Northern Indiana Public Service Company’s (NIPSCO) infrastructure cost recovery mechanism finding that the value of retired assets should not be netted against the current recovery of costs. Although the opinion is specific to NIPSCO, the Company believes this decision is a positive outcome related to its pending appeal.

	Additionally, in the NIPSCO appeal, the IURC’s approval of the reasonableness of that infrastructure investment plan was challenged. The Court found that NIPSCO had failed to provide sufficient detail regarding its planned projects after year one of the plan to support the IURC's approval. An industrial group has asked the Court of Appeals to now consider that issue as part of the pending appeal of the Company's Order. Given this issue was never raised during the Company's IURC case or on appeal during the briefing period, the Company believes the opportunity to raise this issue has been waived and has asked the Court to strike the filing. The Court should decide these issues later this year.

	On January 14, 2015, the IURC issued an Order approving the Company’s initial request for recovery of the revenue requirement through June 30, 2014 as part of its approved seven-year plan. As the next step of the recovery process, as outlined in the legislation, this Order initiates the rates and charges necessary to begin cash recovery of 80 percent of the revenue requirement, with the remaining 20 percent deferred for recovery in the Company's next rate cases. Also, consistent with the guidelines set forth in the original August 2014 Order, the IURC approved the Company’s update to its seven-year plan, to reflect changes to project prioritization as a result of both additional risk modeling and cost increases. The updated plan reflects capital expenditures of approximately $900 million, an increase of $35 million from the previous plan and is inclusive of an estimated $30 million of economic development related expenditures, over the seven-year period beginning in 2014. The plan also includes approximately $15 million of annual operating costs associated with pipeline safety rules.

	On April 1, 2015, the Company filed its second request for recovery of the revenue requirement associated with capital investment and applicable operating costs through December 31, 2014. A procedural schedule has not been set in this proceeding. The Company expects an order in this proceeding mid-year in 2015.

	Ohio Recovery and Deferral Mechanisms
	The PUCO Order approving the Company's 2009 base rate case in the Ohio service territory authorized a distribution replacement rider (DRR). The DRR's primary purpose is recovery of investments in utility plant and related operating expenses associated with replacing bare steel and cast iron pipelines and certain other infrastructure. This rider is updated annually for qualifying capital expenditures and allows for a return to be earned on those capital expenditures based on the rate of return approved in the 2009 base rate case. In addition, deferral of depreciation and the ability to accrue debt-related post-in-service carrying costs is also allowed until the related capital expenditures are included in the DRR. The Order also initially established a prospective bill impact evaluation on the annual deferrals. To date, the Company has made capital investments under this rider totaling $156.5 million. Regulatory assets associated with post-in-service carrying costs and depreciation deferrals were $14.2 million and $13.1 million at March 31, 2015 and December 31, 2014, respectively. Due to the expiration of the initial five-year term for the DRR in early 2014, the Company filed a request in August 2013 to extend and expand the DRR. On February 19, 2014, the PUCO issued an Order approving a Stipulation entered into by the PUCO Staff and the Company which provided for the extension of the DRR for the recovery of costs incurred through 2017 and expanded the types of investment covered by the DRR to include recovery of other infrastructure investments. The Order limits the resulting DRR fixed charge per month for residential and small general service customers to specific graduated levels over the next five years. The Company's five-year capital expenditure plan related to these infrastructure investments for calendar years 2013 through 2017 totals approximately $200 million. The capital expenditure plan is subject to the graduated caps on the fixed DRR monthly charge applicable to residential and small general service customers approved in the Order however is not expected to exceed those caps. In addition, the Order approved the Company's commitment that the DRR can only be further extended as part of a base rate case. On May 1, 2014, the Company filed its annual request to adjust the DRR for recovery of costs incurred through December 31, 2013. On August 27, 2014 the PUCO issued an Order approving the Company’s revised DRR rates and charges, effective September 1, 2014.

	Given the extension of the DRR through 2017 as discussed above and the continued ability to defer other capital expenses under House Bill 95, it is anticipated that the Company will file a general rate case for the inclusion in rate base of the above costs near the expiration of the DRR. As such, the bill impact limits discussed below are not expected to be reached given the Company's capital expenditure plan during the remaining three-year time frame.

	The PUCO has also issued Orders approving the Company's filings under Ohio House Bill 95. These Orders approve deferral of the Company’s Ohio capital expenditure program for items not covered by the DRR as well as expenditures necessary to comply with PUCO rules, regulations, orders, and system expansion to some new customers. Ohio House Bill 95 Orders also have established a prospective bill impact evaluation on the cumulative deferrals, limiting the total deferrals at a level which would equal $1.50 per residential and small general service customer per month. As of March 31, 2015, the Company's deferrals have not reached this bill impact cap. In addition, the Orders approved the Company's proposal that subsequent requests for accounting authority will be filed annually in April. The Company submitted its most recent annual filing on April 30, 2014, which covers the Company’s capital expenditure program through calendar year 2014.

	Other Regulatory Matters
	Indiana Gas GCA Cost Recovery Issue
	On July 1, 2014, Indiana Gas filed its recurring quarterly Gas Cost Adjustment (GCA) mechanism, which included recovery of gas cost variances incurred for the period January through March 2014. In August 2014, the OUCC filed testimony opposing the recovery of approximately $3.9 million of natural gas commodity purchases incurred during this period on the basis that a gas cost incentive calculation had not been properly performed. The calculation at issue is performed by the Company's supply administrator. In the winter period at issue, a pipeline force majeure event caused the gas to be priced at a location that was impacted by the extreme winter temperatures. After further review, the OUCC modified its position in testimony filed on November 5, 2014, and suggested a reduced disallowance of $3 million. The IURC moved this specific issue to a sub-docket proceeding. On April 1, 2015, a stipulation and settlement agreement between the Company, the OUCC, and the Company’s supply administrator was filed in this proceeding. Pending a final order from the IURC approving the stipulation, the agreement results in recovery of approximately $1.4 million of the disputed amount via the Company’s GCA mechanism, with the remaining $1.6 million from the gas supply administrator.

	Indiana Gas & SIGECO Gas Decoupling Extension Filing
	On August 18, 2011, the IURC issued an Order granting the extension of the current decoupling mechanism in place at both Indiana gas companies and recovery of new conservation program costs through December 2015. The Companies have reached an agreement in principle with the OUCC to extend the decoupling mechanism through 2020. The settlement was filed for approval on March 1, 2015. The settlement was unopposed and a hearing has been set for May 2015. The Company expects an order later in 2015.

Electric_Rate_and_Regulatory_M

Electric Rate and Regulatory Matters	3 Months Ended
Electric Rate and Regulatory Matters	Mar. 31, 2015
Public Utilities, General Disclosures [Abstract]
Electric Rate and Regulatory Matters	Electric Rate & Regulatory Matters

	SIGECO Electric Environmental Compliance Filing
	On January 28, 2015, the IURC issued an Order approving the Company’s request for approval of capital investments on its coal-fired generation units to comply with new EPA mandates related to mercury and air toxin standards effective in 2015 and to address an outstanding Notice of Violation (NOV) from the EPA. As of March 31, 2015, approximately $29 million has been spent on equipment to control mercury in both air and water emissions, and $16 million to address the issues raised in the NOV proceeding on the increase in sulfur trioxide emissions. The total investment is estimated to be between $80 and $90 million. The Order approved the Company’s request for deferred accounting treatment, as supported by provisions under Indiana Senate Bill 29 (Senate Bill 29) and Senate Bill 251. The accounting treatment includes the deferral of depreciation and property tax expense related to these investments, accrual of post-in-service carrying costs, and deferral of incremental operating expenses related to compliance with these standards. The initial phase of the projects went into service in 2014, with the remaining investment expected to occur in 2015 and 2016. As of March 31, 2015, the Company has approximately $0.7 million deferred related to depreciation, property tax, and operating expense, and $0.3 million deferred related to post-in-service carrying costs.

	In March 2015, the Company was notified that certain parties had filed a Notice of Appeal with the Indiana Court of Appeals in response to the IURC's Order. Appellate briefs will be presented to the Court later in 2015 and it is expected the Court will decide on these issues in the second half of this year.

	Coal Procurement Procedures
	Entering 2014, SIGECO had in place staggered term coal contracts with Vectren Fuels and one other supplier to provide supply for its generating units. During 2014, SIGECO entered into separate negotiations with Vectren Fuels and Sunrise Coal to modify its existing contracts as well as enter into new long-term contracts in order to secure its supply of coal with specifications that support its compliance with the Mercury and Air Toxins Rule. Subsequent to the sale of Vectren Fuels to Sunrise Coal in August 2014, all such contracts have been assigned to Sunrise Coal. Those contracts were submitted to the IURC for review as part of the 2014 annual sub docket proceeding. In December 2014, the IURC determined that the terms of the coal contracts were reasonable. The annual sub docket proceeding is no longer required.

	On December 5, 2011 within the quarterly FAC filing, SIGECO submitted a joint proposal with the OUCC to reduce its fuel costs billed to customers by accelerating into 2012 the impact of lower cost coal under new term contracts effective after 2012. The cost difference was deferred to a regulatory asset and is being recovered over a 6 year period without interest beginning in 2014. The IURC approved this proposal on January 25, 2012, with the reduction to customer’s rates effective February 1, 2012. The total balance deferred for recovery through the Company’s FAC, which began February 2014, was $42.4 million, of which $33.6 million remains as of March 31, 2015.

	SIGECO Electric Demand Side Management (DSM) Program Filing
	On August 31, 2011 the IURC issued an Order approving an initial three year DSM plan in the SIGECO electric service territory that complied with the IURC’s energy saving targets. Consistent with the Company’s proposal, the Order approved, among other items, the following: 1) recovery of costs associated with implementing the DSM Plan; 2) the recovery of a performance incentive mechanism based on measured savings related to certain DSM programs; 3) lost margin recovery associated with the implementation of DSM programs for large customers; and 4) deferral of lost margin up to $3 million in 2012 and $1 million in 2011 associated with small customer DSM programs for subsequent recovery under a tracking mechanism to be proposed by the Company. On June 20, 2012, the IURC issued an Order approving a small customer lost margin recovery mechanism, inclusive of all previous deferrals. This mechanism is an alternative to the electric decoupling proposal that was denied by the IURC in the Company's last base rate proceeding. For the three months ended March 31, 2015 and 2014, the Company recognized Electric utility revenue of $2.3 million and $1.6 million, respectively, associated with this approved lost margin recovery mechanism.

	On March 28, 2014, Indiana Senate Bill 340 was signed into law. This legislation ended electric DSM programs on December 31, 2014 that have been conducted to meet the energy savings requirements established in the IURC's December 2009 Order. The legislation also allows for industrial customers to opt out of participating in energy efficiency programs. As of January 1, 2015, approximately 80 percent of the Company’s eligible industrial load has opted out of participation in the applicable energy efficiency programs. Indiana's governor has requested that the IURC make new recommendations for energy efficiency programs to be proposed for 2015 and beyond, and has also asked the legislature to consider further legislation requiring some level of utility sponsored energy efficiency programs. The Company filed a request for IURC approval of a new portfolio of DSM programs on May 29, 2014 to be offered in 2015. On October 15, 2014, the IURC issued an Order approving a Settlement between the OUCC and the Company regarding the new portfolio of DSM programs effective January 2015, and new programs were implemented during the first quarter 2015. On May 6, 2015, Indiana's governor signed Indiana Senate Bill 412 into law requiring electricity suppliers to create and submit energy-efficiency plans to the IURC at least one time every three years. Senate Bill 412 also supports the recovery of all program costs, including lost revenues and financial incentives associated with those plans and approved by the IURC. The Company will make its first filing pursuant to this bill in May 2015.

	FERC Return on Equity (ROE) Complaint
	On November 12, 2013, certain parties representing a group of industrial customers filed a joint complaint with the FERC under Section 206 of the Federal Power Act against MISO and various MISO transmission owners, including SIGECO. The joint parties seek to reduce the 12.38 percent return on equity used in the MISO transmission owners’ rates, including SIGECO’s formula transmission rates, to 9.15 percent, and to set a capital structure in which the equity component does not exceed 50 percent. The MISO transmission owners filed their response to the complaint on January 6, 2014, opposing any change to the return. As of March 31, 2015, the Company had invested approximately $157.7 million in qualifying projects. The net plant balance for these projects totaled $142.8 million at March 31, 2015.

	This joint complaint is similar to a complaint against the New England Transmission Owners (NETO) filed in September 2011, which requested that the 11.14 percent incentive return granted on qualifying investments in NETO be lowered. On October 16, 2014, the FERC issued an Order in the NETO case approving a 10.57 percent return on equity and a methodology set out in its June 19, 2014 decision.

	In addition to the NETO ruling, the FERC acknowledged that the pending complaint raised against the MISO transmission owners is reasonable, and ordered the initiation of a formal settlement discussion, mediated by a FERC appointed judge, in November 2014. A settlement has not been reached, and the case will move to a formal evidentiary hearing before the FERC. A procedural schedule was set on January 22, 2015, which defines a targeted date of final resolution from the FERC. An initial decision is expected later in 2015, but the timing of the final order from the FERC is unknown at this time. The Company has established a reserve pending the outcome of this complaint.

	Separately, on January 6, 2015, the FERC approved a MISO transmission owner joint request for an adder to the approved ROE. Under FERC regulations, transmission owners that are part of a Regional Transmission Organization (RTO) such as MISO are authorized to earn an incentive of 50 basis points above the FERC approved ROE. The FERC deferred the implementation of this adder until the pending complaint is resolved. Once the FERC sets a new ROE in the complaint case, this adder will be applied to that ROE, with retroactive billing to occur back to January 7, 2015.

Environmental_Matters

Environmental Matters	3 Months Ended
Environmental Matters	Mar. 31, 2015
Environmental Matters Disclosure [Abstract]
Environmental Matters	Environmental Matters
	Indiana Senate Bill 251
	Senate Bill 251 is also applicable to federal environmental mandates impacting SIGECO electric operations in addition to the impact on its gas utility operations. The Company continues with its ongoing evaluation of the impact Senate Bill 251 may have on its operations, including applicability of the stricter regulations the EPA is currently considering involving air quality, fly ash disposal, cooling tower intake facilities, waste water discharges, and greenhouse gases. These issues are further discussed below.

	Air Quality
	Cross-State Air Pollution Rule
	In July 2011, the EPA finalized the Cross-State Air Pollution Rule (CSAPR). CSAPR was the EPA’s response to the US Court of Appeals for the District of Columbia’s (the Court) remand of the Clean Air Interstate Rule (CAIR). CAIR was originally established in 2005 as an allowance cap and trade program that required reductions from coal-burning power plants for NOX emissions beginning January 1, 2009 and SO2 emissions beginning January 1, 2010, with a second phase of reductions in 2015. In an effort to address the Court’s finding that CAIR did not adequately ensure attainment of pollutants in certain downwind states due to unlimited trading of SO2 and NOX allowances, CSAPR reduced the ability of facilities to meet emission reduction targets through allowance trading. CSAPR reductions were to be achieved with initial step reductions beginning January 1, 2012, and final compliance to be achieved in 2014. After a series of legal challenges, the United States Supreme Court upheld CSAPR in April 2014, and the EPA finalized a new deadline schedule for entities that must comply, with CSAPR’s first phase caps starting in 2015 and 2016, and the second phase in 2017. The Company is in full compliance with all requirements of CSAPR.

	Mercury and Air Toxics (MATS) Rule
	On December 21, 2011, the EPA finalized the utility MATS Rule. The MATS Rule sets emission limits for hazardous air pollutants for existing and new coal-fired power plants and identifies the following broad categories of hazardous air
	pollutants: mercury, non-mercury hazardous air pollutants (primarily arsenic, chromium, cobalt, and selenium), and acid gases (hydrogen cyanide, hydrogen chloride, and hydrogen fluoride). The rule imposes mercury emission limits for two sub-categories of coal and proposed surrogate limits for non-mercury and acid gas hazardous air pollutants. Reductions are to be achieved within three years of publication of the final rule in the Federal Register. The EPA did not grant blanket compliance extensions but asserted that states have broad authority to grant one year extensions for individual electric generating units where potential reliability impacts have been demonstrated. Legal challenges to the MATS Rule continue. In July, a coalition of twenty-one states, including Indiana, filed a petition for certiorari with the U.S. Supreme Court seeking review of the decision of the appellate court. On November 25, 2014, the U.S. Supreme Court agreed to hear the case, with oral arguments completed, a decision is expected later in 2015. MATS compliance was required to commence April 16, 2015, and Company is in full compliance with all requirements of MATS.

	Notice of Violation for A.B. Brown Power Plant
	The Company received a NOV from the EPA in November 2011 pertaining to its A.B. Brown generating station. The NOV asserts that when the facility was equipped with Selective Catalytic Reduction (SCR) systems, the correct permits were not obtained or the best available control technology to control incidental sulfuric acid mist was not installed. The Company reached a settlement in principle with the EPA to resolve the NOV. That settlement was contemplated in the plan filed and approved by the IURC on January 28, 2015 in the SIGECO Electric Environmental Compliance Filing.

	Ozone NAAQS
	On November 26, 2014, the EPA proposed to tighten the current National Ambient Air Quality Standard (NAAQS) for ozone from the current standard of 75 parts per billion (ppb) to a level with the range of 65 to 70 ppb. The EPA has stated that it intends to finalize the rule by October 2015. Upon finalization, the EPA will then determine whether a particular region is in attainment with the new standard. While it is possible that counties in southwest Indiana could be declared in non-attainment with the new standard, and thus may have an effect on future economic development activities in the Company's service territory, the Company does not anticipate any significant compliance cost impacts from the determination given its previous investment in SCR technology for NOx control on its units.

	Water
	Section 316(b) of the Clean Water Act requires that generating facilities use the “best technology available” (BTA) to minimize adverse environmental impacts on a body of water. More specifically, Section 316(b) is concerned with impingement and entrainment of aquatic species in once-through cooling water intake structures used at electric generating facilities. A final rule was issued by the EPA on May 19, 2014. The final rule does not mandate cooling water tower retrofits but requires a state level case by case assessment of BTA for each facility. The final rule lists seven presumptive technologies which would qualify as BTA. These technologies range from intake screen modifications to cooling water tower retrofits. Ecological and technology assessment studies must be completed prior to determining BTA for the Company’s facilities. To comply, the Company believes that capital investments will likely be in the range of $4 million to $8 million. Costs for compliance with these final regulations should qualify as federally mandated regulatory requirements and be recoverable under Indiana Senate Bill 251 referenced above.

	Under the Clean Water Act, the EPA sets technology-based guidelines for water discharges from new and existing facilities. The EPA is currently in the process of revising the existing steam electric effluent limitation guidelines that set the technology-based water discharge limits for the electric power industry. The EPA is focusing its rulemaking on wastewater generated primarily by pollution control equipment necessitated by the comprehensive air regulations. The EPA released proposed rules on April 19, 2013 however the rule is not yet finalized. At this time, it is not possible to estimate what potential costs may be required to meet these new water discharge limits, however costs for compliance with these regulations should qualify as federally mandated regulatory requirements and be recoverable under Senate Bill 251 referenced above.

	Conclusions Regarding Air and Water Regulations
	To comply with Indiana’s implementation plan of the Clean Air Act, the Company obtained authority from the IURC to invest in clean coal technology. Using this authorization, the Company invested approximately $411 million starting in 2001 with the last equipment being placed into service on January 1, 2010. The pollution control equipment included SCR systems, fabric filters, and an SO2 scrubber at its generating facility that is jointly owned with AGC. SCR technology is the most effective method of reducing NOX emissions where high removal efficiencies are required and fabric filters control particulate matter emissions. The unamortized portion of the $411 million clean coal technology investment was included in rate base for purposes of determining SIGECO’s electric base rates approved in the latest base rate order obtained April 27, 2011. SIGECO’s coal-fired generating fleet is 100 percent scrubbed for SO2 and 90 percent controlled for NOX.

	Utilization of the Company’s NOX and SO2 allowances can be impacted as regulations are revised and implemented. Most of these allowances were granted to the Company at zero cost; therefore, any reduction in carrying value that could result from future changes in regulations would be immaterial.

	As noted previously, on January 28, 2015, the IURC issued an Order approving the Company’s request for approval of capital investments on its coal-fired generation units to comply with new EPA mandates related to mercury and air toxin standards effective in 2015 and to address an outstanding Notice of Violation (NOV) from the EPA. The total investment is estimated to be between $80 and $90 million, roughly half of which will be made to control mercury in both air and water emissions, and the remaining investment will be made to address the issues raised in the NOV proceeding on the increase in sulfur trioxide emissions.

	Coal Ash Waste Disposal & Ash Ponds
	In December 2014 the EPA released its final coal ash rule which regulates ash as non-hazardous material under Subtitle D of the Resource Conservation and Recovery Act (RCRA). On April 17, 2015, the final rule was published in the Federal Register. Under the final rule the Company will be required to perform additional safety and structural assessments and an enhanced groundwater monitoring program to determine whether its existing ash ponds may remain in operation, be closed, or retrofitted with liners. The final rule allows beneficial reuse of ash and the Company will continue to reuse a majority of its ash. Legislation is currently being considered by Congress that would provide for enforcement of the federal program by states.

	Under the final CCR rule, the Company is required to complete a series of integrity assessments and groundwater monitoring studies to determine whether one or more of the Company's ash ponds can continue in service, or whether a pond must be retrofitted with liners or closed and bottom ash handling conversions completed. The Company estimates capital expenditures to comply with the alternatives in the final rule could range from minor additional capital expenditures, if the ponds are permitted to continue to operate, and could exceed $100 million if all existing ponds at both F.B. Culley and A.B. Brown generating stations must be closed and bottom ash conversions completed at each generating unit. The Company is in the process of evaluating the impact of this rule and any impact on its asset retirement obligation (ARO). It is expected that any costs for compliance with these regulations should qualify as federally mandated regulatory requirements and be recoverable under Senate Bill 251 referenced above.

	Climate Change
	In April 2007, the US Supreme Court determined that greenhouse gases (GHG's) meet the definition of "air pollutant" under the Clean Air Act and ordered the EPA to determine whether GHG emissions cause or contribute to air pollution that may reasonably be anticipated to endanger public health or welfare. The endangerment finding was finalized in December 2009, concluding that carbon emissions pose an endangerment to public health and the environment.

	The EPA has finalized two sets of GHG regulations that apply to the Company’s generating facilities. In 2009, the EPA finalized a mandatory GHG emissions registry which requires the reporting of emissions. The EPA has also finalized a revision to the Prevention of Significant Deterioration (PSD) and Title V permitting rules which would require facilities that emit 75,000 tons or more of GHG's a year to obtain a PSD permit for new construction or a significant modification of an existing facility. The EPA's PSD and Title V permitting rules for GHG's were upheld by the US Court of Appeals for the District of Columbia, and in June 2014 the US Supreme Court upheld the regulations with respect to applicability to major sources such as coal-fired power plants that are required to hold PSD construction and Title V air operating permits for other criteria pollutants.

	While the Company has no plans to invest in new coal-fired generation, there is also a rule making and related legal challenge involving new source performance standards for new construction. This rulemaking must be finalized and withstand legal scrutiny in order for the EPA to implement its proposed new source performance standards for existing units discussed below.

	In July 2013, the President announced a Climate Action Plan, which calls on the EPA to finalize the rule for new construction expeditiously and by June 2015 finalize, New Source Performance Standards (NSPS) for GHG's for existing electric generating units which would apply to the Company's power plants. States must have their implementation plans to the EPA no later than June 2016. On June 2, 2014, the EPA proposed its rule for states to regulate CO2 emissions from existing electric generating units. The rule, when final, will require states to adopt plans that reduce CO2 emissions by 30 percent from 2005 levels by 2030. The EPA provided an extended time frame for public commentary to December 1, 2014. The proposal sets state-specific CO2 emission rate-based CO2 goals (measured in lb CO2/MWh) and guidelines for the development, submission and implementation of state plans to achieve the state goals. These state-specific goals are calculated based upon 2012 average emission rates aggregated for all fossil fuel-based units in the state. For Indiana, the proposal uses a 2012 emission rate of 1,923 lb CO2/MWh, and sets an interim goal of 1,607 lb CO2/MWh and a final emission goal of 1,531 lb CO2/MWh that must be met by 2030. Under this proposal, these CO2 emission rate goals do not apply directly to individual units, or generating systems. They instead are state goals. As such, the state must establish a framework that will guide how compliance will be met on a statewide basis. Indiana’s interim or “phase in” goal of 1,607 lb CO2/MWh must be met as averaged over a ten-year period (2020 - 2029) with progress toward this goal to be demonstrated for every two rolling calendar years starting in 2020, with the first report due in 2022.

	Under the proposal all states have unique goals based upon each state’s mix of electric generating assets. The EPA is proposing a 20 percent reduction in Indiana’s total CO2 emission rate compared to 2012. At 20 percent Indiana’s CO2 emission rate reduction requirement is tied with West Virginia as the 9th lowest reduction requirement. This is due in part to the EPA’s attempt to recognize the existing generating resource mix in the state and take into account each state’s ability to cost effectively lower its CO2 emission rate through a portfolio approach including energy efficiency and renewables, improving power plant heat rates, and dispatching lower emitting fuel sources. Each state’s goals were set by taking 2012 emissions data and applying four “building blocks” of emission rate improvements that the EPA asserts can be achieved by that state. These four building blocks constitute the EPA’s determination of “Best System of Emission Reductions that has been adequately demonstrated,” which defines the EPA’s authority under § 111(d) for existing sources. When applied to each state, the portfolio approach leads to significant differences in requirements across state lines. With the exception of building block number 1 (heat rate improvement of 6 percent), other building blocks are tailored to individual states based upon each state’s existing generating mix and what the EPA concluded a state could reasonably accomplish to reduce its CO2 emission rate. The Company timely filed comments to the Clean Power Plan proposal on December 1, 2014. The State of Indiana also filed public comments, asking that the proposal be withdrawn. Despite having just been recently proposed and not expected to be finalized until summer of 2015, legal challenges to the EPA's proposal have begun. On July 31, 2014, litigation was filed by the state of Indiana and other parties challenging the rules which may delay the timing of approval of the various state plans. Oral arguments have been completed before the U.S. Court of Appeals for the D.C. Circuit, with a decision expected later in the summer.

	With respect to the state of Indiana, the four building blocks that support Indiana’s goal are as follows:
	(1)Heat rate (HR) improvements of 6 percent (this is consistently applied to all states).
	(2)Increasing the dispatch of existing natural gas baseload generation sources to 70 percent.
	(3)Renewable energy portfolio requirements of 5 percent (interim) and 7 percent (final).
	(4)Energy efficiency / DSM that results in reductions of 1.5 percent annually starting in 2020, ending at a sustained 11 percent by 2030.

	Under the proposal, Indiana may choose to implement a program based upon an annual average emission rate target or convert that target rate to a comparable CO2 emission cap. Indiana is the 5th largest carbon emitter in the nation in tons of CO2 produced from electric generation. In 2013, Indiana’s electric utilities generated 105.6 million tons of CO2. The Company’s share of that total was 6.3 million, or less than 6 percent. Since 2005, the Company’s emissions of CO2 have declined 23 percent (on a tonnage basis). These reductions have come from the retirement of F.B. Culley Unit 1, expiration of municipal contracts, electric conservation and the addition of renewable generation and the installation of more efficient dense pack turbine technology. With respect to renewable generation, in 2008 and 2009, the Company executed long-term purchase power commitments for a total of 80 MW of wind energy. The Company currently has approximately 4 percent of its electricity being provided by clean energy sources due to the long-term wind contracts and landfill gas investment. With respect to CO2 emission rate, since 2005 the Company has lowered its CO2 emission rate (as measured in lbs CO2/MWh) from 1967 lbs CO2/MWh to 1922 lbs CO2/MWh, for a reduction of 3 percent. The Company’s CO2 emission rate of 1922 lbs/MWh is basically the same as the State’s average CO2 emission rate of 1923 lb CO2/MWh.

	Impact of Legislative Actions & Other Initiatives is Unknown
	If the regulations referenced above are finalized by the EPA, or if legislation requiring reductions in CO2 and other GHG's or legislation mandating a renewable energy portfolio standard is adopted, such regulation could substantially affect both the costs and operating characteristics of the Company’s fossil fuel generating plants and natural gas distribution businesses. At this time and in the absence of final legislation or rulemaking, compliance costs and other effects associated with reductions in GHG emissions or obtaining renewable energy sources remain uncertain. The Company has gathered preliminary estimates of the costs to control GHG emissions. A preliminary investigation demonstrated costs to comply would be significant, first with regard to operating expenses and later for capital expenditures as technology becomes available to control GHG emissions. However, these compliance cost estimates were based on highly uncertain assumptions, including allowance prices if a cap and trade approach were employed, and energy efficiency targets. As the EPA moves toward finalization of the NSPS for existing sources and the State of Indiana begins formulation of its state implementation plan, the Company will continue to remain engaged with the state to develop a plan for compliance and have more information to enable it to better assess potential compliance costs with a final regulation. Costs to purchase allowances that cap GHG emissions or expenditures made to control emissions or lower carbon emission rates should be considered a federally mandated cost of providing electricity, and as such, the Company believes such costs and expenditures should be recoverable from customers through Senate Bill 251 as referenced above or Senate Bill 29, which was used by the Company to recover its initial pollution control investments.

	Manufactured Gas Plants
	In the past, the Company operated facilities to manufacture natural gas. Given the availability of natural gas transported by pipelines, these facilities have not been operated for many years. Under current environmental laws and regulations, those that owned or operated these facilities may now be required to take remedial action if certain contaminants are found above the regulatory thresholds.

	In the Indiana Gas service territory, the existence, location, and certain general characteristics of 26 gas manufacturing and storage sites have been identified for which the Company may have some remedial responsibility. A remedial investigation/ feasibility study (RI/FS) was completed at one of the sites under an agreed upon order between Indiana Gas and the IDEM, and a Record of Decision was issued by the IDEM in January 2000. The remaining sites have been submitted to the IDEM's Voluntary Remediation Program (VRP). The Company has identified its involvement in five manufactured gas plant sites in SIGECO’s service territory, all of which are currently enrolled in the IDEM’s VRP. The Company is currently conducting some level of remedial activities, including groundwater monitoring at certain sites.

	The Company has accrued the estimated costs for further investigation, remediation, groundwater monitoring, and related costs for the sites. While the total costs that may be incurred in connection with addressing these sites cannot be determined at this time, the Company has recorded cumulative costs that it has incurred or reasonably expects to incur totaling approximately $43.4 million ($23.2 million at Indiana Gas and $20.2 million at SIGECO). The estimated accrued costs are limited to the Company’s share of the remediation efforts and are therefore net of exposures of other potentially responsible parties (PRP).

With respect to insurance coverage, Indiana Gas has received approximately $20.8 million from all known insurance carriers under insurance policies in effect when these plants were in operation. Likewise, SIGECO has settlement agreements with all known insurance carriers and has received to date approximately $14.3 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 March 31, 2015 and December 31, 2014, approximately $3.5 million and $3.6 million, respectively, of accrued, but not yet spent, costs are included in Other Liabilities related to the Indiana Gas and SIGECO sites.

Impact_of_Recently_Issued_Acco

Impact of Recently Issued Accounting Principles	3 Months Ended
Impact of Recently Issued Accounting Principles	Mar. 31, 2015
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
Impact of Recently Issued Accounting Principles	Impact of Recently Issued Accounting Principles

	Revenue Recognition Guidance
	In May 2014, the FASB issued new accounting guidance to clarify the principles for recognizing revenue and to develop a common revenue standard for GAAP and IFRS. The amendments in this guidance state that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This new guidance requires improved disclosures to help users of financial statements better understand the nature, amount, timing, and uncertainty of revenue that is recognized. For a public entity, the guidance is effective for annual reporting periods beginning after December 15, 2016, with early adoption not permitted. An entity should apply the amendments in this update retrospectively to each prior reporting period presented or retrospectively with the cumulative effect of initially applying this update recognized at the date of initial application. The Company is currently evaluating the standard to understand the overall impact it will have on the financial statements.
	Financial Reporting of Discontinued Operations
	In April 2014, the FASB issued new accounting guidance on reporting discontinued operations and disclosures of disposals of a company or entity. The guidance changes the criteria for reporting discontinued operations and provides for enhanced disclosures in this area. Under the new guidance, only disposals representing a strategic shift in operations should be presented as discontinued operations. Those strategic shifts should have a major effect on the organization's operations and financial results. Additionally, the new guidance requires expanded disclosures about discontinued operations to provide more information about the assets, liabilities, income, and expenses of discontinued operations. The new guidance also requires disclosure of the pre-tax income attributable to a disposal of a significant part of an organization that does not qualify for discontinued operations reporting. This guidance is effective for fiscal years beginning on or after December 15, 2014, with early adoption permitted. The Company adopted this guidance on January 1, 2015. The Company did not early adopt this guidance in accounting for the sale of its Coal Mining assets. The adoption of this guidance had no impact on the Company's financial statements.

	Accounting for Stock Compensation
	In June 2014, the FASB issued new accounting guidance on accounting for share-based payments when the terms of an award provide that a performance target could be achieved after the requisite service period. These amendments provide explicit guidance on whether to treat a performance target that could be achieved after the requisite service period as a performance condition that affects vesting or as a non-vesting condition that affects the grant-date fair value of an award. This guidance is effective for annual periods and interim periods within those periods beginning after December 15, 2015, with early adoption permitted. The Company’s current practice for accounting for stock compensation follows the prescribed manner as suggested by the update. Adoption of this guidance will not have a material impact on the Company’s financial statements.

	Financial Reporting of Going Concern
	In August 2014, the FASB issued new accounting guidance with respect to reporting on an entity's ability to continue as a going concern. This new guidance requires management to assess an entity's ability to continue as a going concern by incorporating and expanding upon certain principles that are currently in U.S. auditing standards, which requires disclosure surrounding what constitutes substantial doubt for the entity, including disclosure of management's plans to mitigate and alleviate substantial doubt. This guidance is effective for annual periods beginning after December 15, 2016, and for annual and interim periods thereafter, with early adoption permitted. Adoption of this guidance will not have a material impact on the Company’s financial statements.

	Amendments to the Consolidation Analysis
	In February 2015, the FASB issued new accounting guidance on amendments to the consolidation analysis, which is intended to improve certain areas of consolidation guidance for legal entities such as limited partnerships, limited liability companies, and securitization structures. The ASU will reduce the number of consolidation models and will be effective for annual reporting periods beginning after December 15, 2015. Early adoption is permitted, including adoption in an interim period. The Company is currently evaluating the standard to understand the overall impact it will have on the financial statements, if any.

	Simplifying the Presentation of Debt Issuance Costs
	In April 2015, the FASB issued new accounting guidance on accounting for debt issuance costs which changes the presentation of debt issuance costs in financial statements. This ASU requires an entity to present such costs in the balance sheet as a direct deduction from the related debt liability rather than as an asset. Amortization of the costs will continue to be reported as interest expense. This ASU is effective for annual reporting periods beginning after December 15, 2015. Early adoption is permitted. The new guidance will be applied retrospectively to each prior period presented. The Company is currently evaluating the standard to understand the overall impact it will have on the financial statements. Adoption will have no impact on the Company's consolidated income statement.

Fair_Value_Measurements

Fair Value Measurements

3 Months Ended

Mar. 31, 2015

Fair Value Disclosures [Abstract]

Fair Value Measurements

The carrying values and estimated fair values using primarily Level 2 assumptions of the Company's other financial instruments follow:

March 31, 2015

December 31, 2014

(In millions)

Carrying

Est. Fair

Carrying

Est. Fair

Amount

Value

Amount

Value

Long-term debt

1,572.40

1,754.50

1,577.30

1,754.50

Short-term borrowings

6.4

156.4

Cash & cash equivalents

17.1

86.4

For the balance sheet dates presented in these financial statements, the Company had no material assets or liabilities marked to fair value.

Certain methods and assumptions must be used to estimate the fair value of financial instruments. The fair value of the Company's long-term debt was estimated based on the quoted market prices for the same or similar issues or on the current rates offered to the Company for instruments with similar characteristics. Because of the maturity dates and variable interest rates of short-term borrowings and cash & cash equivalents, those carrying amounts approximate fair value. Because of the inherent difficulty of estimating interest rate and other market risks, the methods used to estimate fair value may not always be indicative of actual realizable value, and different methodologies could produce different fair value estimates at the reporting date.

Under current regulatory treatment, call premiums on reacquisition of utility-related long-term debt are generally recovered in customer rates over the life of the refunding issue or over a 15-year period. Accordingly, any reacquisition of this debt would not be expected to have a material effect on the Company's results of operations.

Because of the nature of certain other investments and lack of a readily available market, it is not practical to estimate the fair value of these financial instruments at specific dates without considerable effort and cost. At March 31, 2015 and December 31, 2014, the fair value for these financial instruments was not estimated. The carrying value of these investments was approximately $10.4 million at both March 31, 2015 and December 31, 2014, and is included in Other nonutility investments.

Segment_Reporting

Segment Reporting	3 Months Ended
	Mar. 31, 2015
Segment Reporting [Abstract]
Segment Reporting	Segment Reporting

	The Company segregates its operations into three groups: 1) Utility Group, 2) Nonutility Group, and 3) Corporate and Other.

	The Utility Group is comprised of Vectren Utility Holdings, Inc.’s operations, which consist of the Company’s regulated operations and other operations that provide information technology and other support services to those regulated operations. The Company segregates its regulated operations between a Gas Utility Services operating segment and an Electric Utility Services operating segment. The Gas Utility Services segment provides natural gas distribution and transportation services to nearly two-thirds of Indiana and to west-central Ohio. The Electric Utility Services segment provides electric transmission and distribution services primarily to southwestern Indiana, and includes the Company’s power generating and wholesale power operations. Regulated operations supply natural gas and/or electricity to over one million customers. In total, the Utility Group reports is comprised of three operating segments: Gas Utility Services, Electric Utility Services, and Other operations.

	The Nonutility Group has historically reported the following segments: Infrastructure Services, Energy Services, Coal Mining, and Other Businesses. In the 2015 periodic reports, the 2014 results for the Coal Mining segment include the results of Vectren Fuels through August 29, 2014 when it exited the coal mining business through the sale of Vectren Fuels (see Note 8 for additional information on this transaction).

	Corporate and Other includes unallocated corporate expenses such as advertising and charitable contributions, among other activities, that benefit the Company’s other operations. Net income is the measure of profitability used by management for all operations.

	Information related to the Company’s reportable segments is summarized as follows:



		Three Months Ended
		March 31,
	(In millions)	2015				2014
	Revenues
	Utility Group
	Gas Utility Services	$	352.9			$	443.6

	Electric Utility Services	153.9				163

	Other Operations	10.2				9.6

	Eliminations	(10.1		)		(9.6		)
	Total Utility Group	506.9				606.6

	Nonutility Group

	Infrastructure Services	176.9				123

	Energy Services	23.1				17.5

	Coal Mining	—				81.5

	Total Nonutility Group	200				222

	Corporate & Other Group	0.2				0.3

	Eliminations	(0.9		)		(32.1		)
	Consolidated Revenues	$	706.2			$	796.8


	Profitability Measure - Net Income (Loss)

	Utility Group Net Income

	Gas Utility Services	$	40.4			$	38.3

	Electric Utility Services	19.2				19.3

	Other Operations	3.4				3.7

	Utility Group Net Income	63				61.3

	Nonutility Group Net Income (Loss)

	Infrastructure Services	(2.6		)		(5.3		)
	Energy Services	(3.1		)		(3.0		)
	Coal Mining	—				(1.1		)

	Other Businesses	(0.2		)		(0.3		)
	Nonutility Group Net (Loss)	(5.9		)		(9.7		)
Corporate & Other Group Net (Loss)	(0.1		)		(0.4		)
Consolidated Net Income	$	57			$	51.2

Earnings_Per_Share_Tables

Earnings Per Share (Tables)	3 Months Ended
	Mar. 31, 2015
Earnings Per Share [Abstract]
Basic and dilutive EPS	The following table illustrates the basic and dilutive EPS calculations for the periods presented in these financial statements.



		Three Months Ended
		March 31,
	(In millions, except per share data)	2015		2014
	Numerator:
	Reported net income (Numerator for Basic and Diluted EPS)	$	57	$	51.2

	Denominator:

	Weighted average common shares outstanding	82.6		82.4
	(Denominator for Basic EPS)
	Conversion of share based compensation arrangements	0		0.1

	Adjusted weighted average shares outstanding and assumed
	conversions outstanding (Denominator for Diluted EPS)	82.6		82.5


	Basic EPS	$	0.69	$	0.62

	Diluted EPS	$	0.69	$	0.62

Retirement_Plans_and_Other_Pos1

Retirement Plans and Other Postretirement Benefits (Tables)	3 Months Ended
	Mar. 31, 2015
Pension and Other Postretirement Benefit Expense [Abstract]
Schedule of Defined Benefit Plans Disclosures [Table Text Block]	A summary of the components of net periodic benefit cost follows and the amortizations shown below are primarily reflected in Regulatory assets as a majority of pension and other postretirement benefits are being recovered through rates.


		Three Months Ended
		March 31,
		Pension Benefits						Other Benefits
	(In millions)	2015			2014			2015			2014
	Service cost	$	2		$	1.8		$	0.1		$	0.1

	Interest cost	3.6			3.9			0.5			0.5

	Expected return on plan assets	(5.6		)	(5.7		)	—			—

	Amortization of prior service cost	0.2			0.3			(0.7		)	(0.7		)

	Amortization of transitional obligation	—			—			—			—

	Amortization of actuarial loss	2.1			1.2			0.1			0.1

	Settlement charge	—			—			—			—

	Net periodic benefit cost	$	2.3		$	1.5		$	—		$	—

ProLiance_Holdings_LLC_Tables

ProLiance Holdings, LLC (Tables)	3 Months Ended
	Mar. 31, 2015
Equity Method Investments and Joint Ventures [Abstract]
Summarized Financial Information of Equity Investment [Table Text Block]	The Company's investment in ProLiance at March 31, 2015, shown at its 61 percent ownership share, is as follows.



		As of
		March 31,
	(In millions)	2015
	Cash	$	4.5

	Investment in LA Storage	21.8

	Other midstream asset investment	4.3

	Total investment in ProLiance	$	30.6

	Included in:
	Investments in unconsolidated affiliates	20.5

	Other nonutility investments	10.1

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	3 Months Ended
	Mar. 31, 2015
Fair Value Disclosures [Abstract]
Fair Value, by Balance Sheet Grouping [Table Text Block]	The carrying values and estimated fair values using primarily Level 2 assumptions of the Company's other financial instruments follow:


		March 31, 2015				December 31, 2014
	(In millions)	Carrying		Est. Fair		Carrying		Est. Fair
		Amount		Value		Amount		Value
	Long-term debt	$	1,572.40	$	1,754.50	$	1,577.30	$	1,754.50

	Short-term borrowings	6.4		6.4		156.4		156.4

	Cash & cash equivalents	17.1		17.1		86.4		86.4

Segment_Reporting_Tables

Segment Reporting (Tables)	3 Months Ended
	Mar. 31, 2015
Segment Reporting [Abstract]
Schedule of Segment Reporting Information, by Segment [Table Text Block]	Information related to the Company’s reportable segments is summarized as follows:



		Three Months Ended
		March 31,
	(In millions)	2015			2014
	Revenues
	Utility Group
	Gas Utility Services	$	352.9		$	443.6

	Electric Utility Services	153.9			163

	Other Operations	10.2			9.6

	Eliminations	(10.1		)	(9.6		)
	Total Utility Group	506.9			606.6

	Nonutility Group

	Infrastructure Services	176.9			123

	Energy Services	23.1			17.5

	Coal Mining	—			81.5

	Total Nonutility Group	200			222

	Corporate & Other Group	0.2			0.3

	Eliminations	(0.9		)	(32.1		)
	Consolidated Revenues	$	706.2		$	796.8


	Profitability Measure - Net Income (Loss)

	Utility Group Net Income

	Gas Utility Services	$	40.4		$	38.3

	Electric Utility Services	19.2			19.3

	Other Operations	3.4			3.7

	Utility Group Net Income	63			61.3

	Nonutility Group Net Income (Loss)

	Infrastructure Services	(2.6		)	(5.3		)
	Energy Services	(3.1		)	(3.0		)
	Coal Mining	—			(1.1		)

	Other Businesses	(0.2		)	(0.3		)
	Nonutility Group Net (Loss)	(5.9		)	(9.7		)
	Corporate & Other Group Net (Loss)	(0.1		)	(0.4		)
	Consolidated Net Income	$	57		$	51.2

Organization_and_Nature_of_Ope1

Organization and Nature of Operations (Details)	3 Months Ended
Organization and Nature of Operations (Details)	Mar. 31, 2015
Organization and Nature of Operations [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, Inc. (in number of customers)	585,000
Estimated number of electric customers located near Evansville in southwestern Indiana serviced by Southern Indiana Gas and Electric Company (in number of customers)	143,000
Estimated number of natural gas customers located near Evansville in southwestern Indiana serviced by Southern Indiana Gas and Electric Company (in number of customers)	111,000
Estimated number of natural gas customers located near Dayton in west central Ohio serviced by the Ohio operations (in number of customers)	317,000

Earnings_Per_Share_Details

Earnings Per Share (Details) (USD $)	3 Months Ended
In Millions, except Per Share data, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Numerator [Abstract]
Net income	$57	$51.20
Denominator [Abstract]
Weighted average common shares outstanding (Denominator for Basic EPS) (in shares)	82.6	82.4
Conversion of share based compensation arrangements (in shares)	0	0.1
Adjusted weighted average shares outstanding and assumed conversions outstanding (Denominator for Diluted EPS) (in shares)	82.6	82.5
Basic EPS (in dollars per share)	$0.69	$0.62
Diluted EPS (in dollars per share)	$0.69	$0.62

Excise_and_Utility_Receipts_Ta1

Excise and Utility Receipts Taxes (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Excise and Utility Receipts Taxes [Abstract]
Excise and utility taxes collected and reported in operating revenue	$11.70	$12.90

Retirement_Plans_and_Other_Pos2

Retirement Plans and Other Postretirement Benefits (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Regulatory assets	$224.80		$233.60
Number of qualified defined benefit pension plans	3
Expected contribution to defined benefit plans for current year by employer	20
Pension Benefits [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service cost	2	1.8
Interest cost	3.6	3.9
Expected return on plan assets	-5.6	-5.7
Amortization of prior service cost	0.2	0.3
Amortization of transitional obligation	0	0
Amortization of actuarial loss	2.1	1.2
Settlement Charge	0	0
Net periodic benefit cost	2.3	1.5
Other Benefits [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service cost	0.1	0.1
Interest cost	0.5	0.5
Expected return on plan assets	0	0
Amortization of prior service cost	-0.7	-0.7
Amortization of transitional obligation	0	0
Amortization of actuarial loss	0.1	0.1
Settlement Charge	0	0
Net periodic benefit cost	$0	$0

Supplemental_Cash_Flow_Informa1

Supplemental Cash Flow Information (Details) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Millions, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Supplemental Cash Flow Information [Abstract]
Accruals related to utility and nonutility plant purchases	$12.60	$20.20

ProLiance_Holdings_LLC_Details

ProLiance Holdings, LLC (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Equity Method Investment, Ownership Percentage	61.00%
Equity method investment,governance and voting rights percentage (in hundredths)	50.00%
Equity method investment, investment in equity method investee's subsidiary (ProLiance Energy)	$4.50
Equity method investment, investment in storage assets and cash from sale of storage assets	21.8
Equity method investment, minority interest in joint venture, investor's portion of interest	4.3
Equity method investment, gross investment in equity method investee	30.6
Investments in unconsolidated affiliates	23.4	23.4
Other nonutility investments	33.8	33.6
LA Storage [Member]
Combined Joint Venture Ownership Percentage	100.00%
Equity method investment holding minority interest in equity method investment (in hundredths)	25.00%
Equity method investment minority interest in joint ventures	35.7	35.4
Loss contingency, gross damages sought from a party that entered into a sub-lease agreement with a party that is an investment of an equity method investee	56.7
Proliance Holdings Llc [Member]
Investments in unconsolidated affiliates	20.5
Other nonutility investments	$10.10

Financing_Activities_Details

Financing Activities (Details) (Utility Group [Member], Indiana Gas [Member], Unsecured Debt [Member], Fixed Rate Senior Unsecured Notes 2015 Series E 715 [Member], USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015
Utility Group [Member] \| Indiana Gas [Member] \| Unsecured Debt [Member] \| Fixed Rate Senior Unsecured Notes 2015 Series E 715 [Member]
Debt Instrument [Line Items]
Stated percentage rate (in hundredths)	7.15%
Maturity date	15-Mar-15
Debt Instrument, Face Amount	$5

Commitments_and_Contingencies_

Commitments and Contingencies (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015
Performance Guarantees and Product Warranties [Abstract]
Product Warranty Accrual	$0
Guarantees for ESG [Member]
Corporate Guarantees [Abstract]
Maximum exposure by parent company on guarantees	195
Performance Guarantee [Member] \| Guarantees for ESG [Member]
Performance Guarantees and Product Warranties [Abstract]
Number of surety bonds wholly owned subsidiary has outstanding in role as general contractor (in number of surety bonds)	47
Average face amount of surety bonds wholly owned subsidiary has outstanding	7.3
Maximum face amount of surety bond wholly owned subsidiary has outstanding	$57.30
Percentage of work completed on open surety bond with largest face amount (in hundredths)	0.95
Percentage of work completed on projects covered by open surety bonds (in hundredths)	36.00%
Timeframe when significant portion of performance guarantee commitments will be fulfilled	1

Gas_Rate_Regulatory_Matters_De

Gas Rate & Regulatory Matters (Details) (USD $)	3 Months Ended
Gas Rate & Regulatory Matters (Details) (USD $)	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items]
Other Nonoperating Income (Expense)	$5,600,000	$4,300,000
OHIO \| Ohio Recovery and Deferral Mechanisms [Member]
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items]
Cumulative gross plant invesment made under Distribution Replacement Rider	156,500,000
Regulatory Asset associated with DRR deferrals of depreciation and post in-service carrying costs	14,200,000		13,100,000
Initial distribution replacement rider mechanism term.	5 years
Extension period requested to recover capital investments	5 years
Amount of Capital Investment Expected Over Next Five Years Recoverable Under DRR	200,000,000
Bill impact per customer per month	1.5
INDIANA \| Indiana Recovery and Deferral Mechanisms [Member]
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items]
Regulatory Assset balance associated with Vectren north and south programs	17,300,000		16,400,000
Length of project plan required for recovery under new legislation	7 years
SIGECO [Member] \| INDIANA \| Indiana Recovery and Deferral Mechanisms [Member]
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items]
Allowable capital expenditures under Vectren programs	3,000,000
Limitations of deferrals of debt-related post in service carrying costs	P3Y
Indiana Gas [Member] \| INDIANA \| Indiana Recovery and Deferral Mechanisms [Member]
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items]
Allowable capital expenditures under Vectren programs	20,000,000
Limitations of deferrals of debt-related post in service carrying costs	P4Y
INDIANA \| Senate Bill 251 and 560 [Member]
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items]
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%
INDIANA \| Pipeline Safety Law [Member]
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items]
Expected Seven Year Period Modernization Investment	900,000,000
Capital Expenditure Increases	35,000,000
Expected annual operating costs associated with new pipeline safety regulations	30,000,000
Upper range of expected annual operating costs associated with new pipeline safety regulations	15,000,000
INDIANA \| Indiana Gas [Member] \| Indiana Gas GCA Cost Recovery [Member]
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items]
Original amount of recovery opposed by OUCC	3,900,000
Amount of recovery supported by OUCC	3,000,000
Estimated amount of settlement recoverable through the Company's GCA mechanism	1,400,000
Estimated amount of settlement recoverable through the gas supply administrator	$1,600,000

Electric_Rate_and_Regulatory_M1

Electric Rate and Regulatory Matters (Details) (USD $)	3 Months Ended		12 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2012	Dec. 31, 2011	Feb. 01, 2014
Vectren South Electric Environmental Compliance Filing [Abstract]
Amount of capital investments to date in equipment for mercury control	$29
Amount of capital investments to date in equipment to control sulfur trioxide emissions	16
Lower range of request for approval of capital investments on coal-fired generation units	80
Upper range of request for approval of capital investments on coal-fired generation units	90
Amount of deferred costs to date related to depreciation, property tax, and operating expenses under Senate Bill 29 and Senate Bill 251	0.7
Amount of deferred costs to date related to post in-service carrying costs under Senate Bill 29 and Senate Bill 251.	0.3
Coal Procurement Procedures [Abstract]
Number of years for recovery of coal costs	6 years
Cumulative total deferrals related to coal purchases	33.6				42.4
Vectren South Electric Demand Side Management Program Filing [Abstract]
Number of years in initial demand side management program	3 years
Maximum Deferral Of Lost Margin Associated With Small Customer DSM Programs			3	1
Electric revenue recognized associated with lost margin recovery	2.3	1.6
Percent of industrial load opt out of applicable energy efficiency programs	80.00%
FERC Return On Equity Complaint [Abstract]
Current return on equity used in MISO transmission owners rates	12.38%
Reduced return on equity percentage sought by third party through joint complaint	9.15%
Equity component, upper limit, as a percentage, sought by third party through joint complaint	50.00%
Gross Investment In Qualifying Transmission Projects	157.7
Net Investment in Qualifying Transmission Projects	$142.80
Incentive return granted on qualifying investments in NETO	11.14%
Percentage return approved by FERC on ROE complaint against NETO	10.57%
Number of incentive basis point above and beyond approved FERC approved ROE	50

Environmental_Matters_Details

Environmental Matters (Details) (USD $)	3 Months Ended	12 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2013	Dec. 31, 2014
	MW	T	Dec. 31, 2014
Clean Water Act [Abstract]
Potential capital investment of using 'best technology available' (BTA) to minimize adverse impacts in a body of water - lower range	$4
Potential capital investment of using 'best technology available' (BTA) to minimize adverse impacts in a body of water - upper range	8
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
Coal Ash Waste Disposal and Ash Ponds [Abstract]
Potential estimated capital expenditures to comply with ash pond and coal ash disposal regulations with stringent alternative	100
Climate Changes [Abstract]
Maximum level of greenhouse gas emissions that prompts requirement to obtain permit for facilities to construct new facility of significant modification to existing facility (in tons)	75,000
Vectren's share of Indiana's total CO2 emmisions in 2013 (in tons)		6,300,000
Vectren's share of Indiana's CO2 emissions in 2013 (as a percent)		6.00%
Percent reduction of Vectren's CO2 emissions since 2005	23.00%
Vectren's emission rate (as measured in lbs CO2/MWh) prior to installation of new technology	1,967
Vectren's emission rate (as measured in lbs CO2/MWh) after installation of new technology	1,922
Percentage reduction of lbs CO2/MWh since 2005	3.00%
Indiana Senate Bill 251 [Abstract]
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)	4.00%
Manufactured Gas Plants
Site contingency, accrual, undiscounted amount	43.4
Accrual for Environmental Loss Contingencies	3.5		3.6
Indiana Gas [Member]
Manufactured Gas Plants
Site contingency, accrual, undiscounted amount	23.2
Number of sites identified with potential remedial responsibility for entity (in number of sites)	26
Environmental cost recognized, recover from insurance carriers credited to expense	20.8
SIGECO [Member]
Manufactured Gas Plants
Site contingency, accrual, undiscounted amount	20.2
Number of sites identified with potential remedial responsibility for entity (in number of sites)	5
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 $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Recovery period for call premiums on reacquisition of utility long-term debt (in years)	15
Notes Receivable, Fair Value Disclosure	$10.40	$10.40
Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	1,572.40	1,577.30
Short-term Debt, Fair Value	6.4	156.4
Cash and cash equivalents	17.1	86.4
Estimated Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	1,754.50	1,754.50
Short-term Debt, Fair Value	6.4	156.4
Cash and cash equivalents	$17.10	$86.40

Segment_Reporting_Details

Segment Reporting (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
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%
Segment Reporting Information [Line Items]
Number of operational groups	3
Revenues	$706.20	$796.80
Net income	57	51.2
Number of reportable segments	3
Utility Group [Member]
Segment Reporting Information [Line Items]
Revenues	506.9	606.6
Net income	63	61.3
Number of reportable segments	3
Utility Group [Member] \| Gas Utility Services [Member]
Segment Reporting Information [Line Items]
Revenues	352.9	443.6
Net income	40.4	38.3
Utility Group [Member] \| Electric Utility Services [Member]
Segment Reporting Information [Line Items]
Revenues	153.9	163
Net income	19.2	19.3
Utility Group [Member] \| Other Segments [Member]
Segment Reporting Information [Line Items]
Revenues	10.2	9.6
Net income	3.4	3.7
Utility Group [Member] \| Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues	-10.1	-9.6
Nonutility Group [Member]
Segment Reporting Information [Line Items]
Revenues	200	222
Net income	-5.9	-9.7
Number of reportable segments	4
Nonutility Group [Member] \| Infrastructure Services [Member]
Segment Reporting Information [Line Items]
Revenues	176.9	123
Net income	-2.6	-5.3
Nonutility Group [Member] \| Energy Services [Member]
Segment Reporting Information [Line Items]
Revenues	23.1	17.5
Net income	-3.1	-3
Nonutility Group [Member] \| Coal Mining [Member]
Segment Reporting Information [Line Items]
Revenues	0	81.5
Net income	0	-1.1
Nonutility Group [Member] \| Other Businesses [Member]
Segment Reporting Information [Line Items]
Net income	-0.2	-0.3
Corporate and Other [Member]
Segment Reporting Information [Line Items]
Revenues	0.2	0.3
Net income	-0.1	-0.4
Number of reportable segments	1
Consolidation, Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues	($0.90)	($32.10)