Vectren (VVC) 10-Q 2 May 18 2018 Q1 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2018	Apr. 30, 2018
Document and Entity Information [Abstract]
Entity Registrant Name	VECTREN CORP
Entity Central Index Key	1,096,385
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-Q
Document Period End Date	Mar. 31, 2018
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	Q1
Amendment Flag	false
Entity Common Stock, Shares Outstanding		83,080,695

CONDENSED CONSOLIDATED BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Current Assets
Cash & cash equivalents	$ 19.1	$ 16.6
Accounts receivable - less reserves of $6.5 & $5.1, respectively	237.1	262.9
Accrued unbilled revenues	146.5
Inventories	110.3	126.6
Recoverable fuel & natural gas costs	11.1	19.2
Prepayments & other current assets	27.9
Total current assets	552	679.4
Utility Plant
Original cost	7,105.8	7,015.4
Less: accumulated depreciation & amortization	2,770.3	2,738.7
Net utility plant	4,335.5	4,276.7
Investments in unconsolidated affiliates	19.6	19.7
Other utility & corporate investments	43.1	43.7
Other nonutility investments	9.6	9.6
Nonutility plant - net	476.9	464.1
Goodwill	293.5	293.5
Regulatory assets	418.8	416.8
Other assets	35.2	35.8
TOTAL ASSETS	6,184.2	6,239.3
Current Liabilities
Accounts payable	237.5	366.2
Accrued liabilities	216.9
Short-term borrowings	287.9	249.5
Current maturities of long-term debt	160	100
Total current liabilities	902.3	938
Long-term Debt - Net of Current Maturities	1,678.5	1,738.7
Deferred Credits & Other Liabilities
Deferred income taxes	495.9	491.3
Regulatory liabilities	954.9	937.2
Deferred credits & other liabilities	275.8	284.8
Total deferred credits & other liabilities	1,726.6	1,713.3
Commitments & Contingencies (Notes 8, 11-14)
Common Shareholders' Equity
Common stock (no par value) – issued & outstanding 83.1 & 83.0, respectively	739.3	736.9
Retained earnings	1,138.8
Accumulated other comprehensive (loss)	(1.3)	(1.3)
Total common shareholders' equity	1,876.8	1,849.3
TOTAL LIABILITIES & SHAREHOLDERS' EQUITY	$ 6,184.2	$ 6,239.3

CONDENSED CONSOLIDATED BALANCE3

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) shares in Millions, $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Current Assets
Reserves	$ 6.5	$ 5.1
Common Shareholders' Equity
Common stock, shares issued (in shares)	83.1	83
Common stock, shares outstanding (in shares)	83.1	83

CONDENSED CONSOLIDATED STATEMEN

CONDENSED CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
OPERATING REVENUES
Gas utility	$ 329.3	$ 292.8
Electric utility	134	132.1
Nonutility	195.1	199.6
Total operating revenues	658.4	624.5
OPERATING EXPENSES
Cost of gas sold	145.2	112.9
Cost of fuel & purchased power	42.2	41.2
Cost of nonutility revenues	66.8	61.8
Other operating	228.5	224.3
Depreciation & amortization	71.4	67.8
Taxes other than income taxes	20	15.1
Total operating expenses	574.1	523.1
OPERATING INCOME	84.3	101.4
OTHER INCOME
Equity in (losses) of unconsolidated affiliates	(0.1)	(0.5)
Other income – net	9	8
Total other income	8.9	7.5
INTEREST EXPENSE	23.5	21.3
INCOME BEFORE INCOME TAXES	69.7	87.6
INCOME TAXES	6.2	32.2
NET INCOME AND COMPREHENSIVE INCOME	$ 63.5	$ 55.4
WEIGHTED AVERAGE AND DILUTED COMMON SHARES OUTSTANDING (in shares)	83.1	82.9
BASIC AND DILUTED EARNINGS PER SHARE OF COMMON STOCK (in dollars per share)	$ 0.76	$ 0.67
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK (in dollars per share)	$ 0.45000000	$ 0.42000000

CONDENSED CONSOLIDATED STATEME5

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$ 63.5	$ 55.4
Adjustments to reconcile net income to cash from operating activities:
Depreciation & amortization	71.4	67.8
Deferred income taxes & investment tax credits	(2.1)	26.7
Provision for uncollectible accounts	2.8	1.8
Expense portion of pension & postretirement benefit cost	1.1	1
Other non-cash items - net	5.4	2.6
Changes in working capital accounts:
Accounts receivable & accrued unbilled revenues	83.6	82.6
Inventories	16.3	12.6
Recoverable/refundable fuel & natural gas costs	8.1	2.8
Prepayments & other current assets	18.7	16.8
Accounts payable	(125.4)	(48.8)
Accrued liabilities	(4.6)	0.2
Employer contributions to pension & postretirement plans	(4.9)	(1.4)
Changes in noncurrent assets	3	(5.5)
Changes in noncurrent liabilities	2.8	(2.1)
Net cash from operating activities	139.7	212.5
CASH FLOWS FROM FINANCING ACTIVITIES
Long-term debt, net of issuance costs	(0.9)	0
Dividend reinvestment plan & other common stock issuances	1.6	1.5
Requirements for dividends on common stock	(37.4)	(34.9)
Net change in short-term borrowings	38.4	(93)
Net cash from financing activities	1.7	(126.4)
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from sale of assets and other collections	1.5	0.6
Requirements for:
Capital expenditures, excluding AFUDC equity	(140.4)	(123.6)
Changes in restricted cash	0	0.9
Net cash from investing activities	(138.9)	(122.1)
Net change in cash & cash equivalents	2.5	(36)
Cash & cash equivalents at beginning of period	16.6	68.6
Cash & cash equivalents at end of period	$ 19.1	$ 32.6

Organization and Nature of Oper

Organization and Nature of Operations	3 Months Ended
	Mar. 31, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization and Nature of Operations	Organization and Nature of Operations Vectren Corporation (the Company or Vectren), an Indiana corporation, is an energy holding company headquartered in Evansville, Indiana. The Company’s wholly owned subsidiary, Vectren Utility Holdings, Inc. (Utility Holdings or VUHI), serves as the intermediate holding company for three public utilities: Indiana Gas Company, Inc. (Indiana Gas or Vectren Energy Delivery of Indiana - North), Southern Indiana Gas and Electric Company (SIGECO or Vectren Energy Delivery of Indiana - South), and Vectren Energy Delivery of Ohio, Inc. (VEDO). Utility Holdings also has other assets that provide information technology and other services to the three utilities. Utility Holdings’ consolidated operations are collectively referred to as the Utility Group. Both Vectren and Utility Holdings are holding companies as defined by the Energy Policy Act of 2005. Vectren was incorporated under the laws of Indiana on June 10, 1999. Indiana Gas provides energy delivery services to approximately 603,000 natural gas customers located in central and southern Indiana. SIGECO provides energy delivery services to approximately 146,000 electric customers and approximately 112,000 gas customers located near Evansville in southwestern Indiana. SIGECO also owns and operates electric generation assets to serve its electric customers and optimizes those assets in the wholesale power market. Indiana Gas and SIGECO generally do business as Vectren Energy Delivery of Indiana. VEDO provides energy delivery services to approximately 323,000 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. Enterprises also has other legacy businesses that have investments in energy-related opportunities and services and other investments. All of the above is collectively referred to as the Nonutility Group. Enterprises supports the Company's regulated utilities by providing infrastructure services. Merger with CenterPoint Energy, Inc. On April 21, 2018, the Company entered into an Agreement and Plan of Merger (the “Merger Agreement”), with CenterPoint Energy, Inc., a Texas corporation (“CenterPoint”), and Pacer Merger Sub, Inc., an Indiana corporation and wholly owned subsidiary of CenterPoint (“Merger Sub”). Pursuant to the Merger Agreement, and subject to the terms and conditions of the agreement, Merger Sub will merge with and into the Company (the “Merger”), with the Company continuing as the surviving corporation and becoming a wholly owned subsidiary of CenterPoint. Subject to the terms and conditions in the Merger Agreement, upon closing, each share of common stock of the Company shall be converted into the right to receive $72.00 in cash without interest. The Company, CenterPoint and Merger Sub each have made various representations, warranties and covenants in the Merger Agreement. Among other things, the Company has agreed, subject to certain exceptions, to conduct its businesses in the ordinary course, consistent with past practice, from the date of the Merger Agreement until closing, and not to take certain actions prior to the closing of the Merger without the approval of CenterPoint. The Company has made certain additional customary covenants, including, subject to certain exceptions: (1) to cause a meeting of the Company’s shareholders to be held to consider approval of the Merger Agreement, (2) not to solicit proposals relating to alternative business combination transactions and not to participate in discussions concerning, or furnish information in connection with, alternative business combination transactions and (3) not to withdraw its recommendation to the Company’s shareholders regarding the Merger. In addition, subject to the terms of the Merger Agreement, the Company, CenterPoint and Merger Sub are required to use reasonable best efforts to obtain all required regulatory approvals, which will include clearance under federal antitrust laws and certain approvals by federal regulatory bodies, including FERC, subject to certain exceptions, including that such efforts not result in a "Burdensome Condition" (as defined in the Merger Agreement). While approval of the Merger Agreement is not required by the Indiana Utility Regulatory Commission ("IURC") or the Public Utilities Commission of Ohio ("PUCO"), informational filings will be made with each commission. Consummation of the Merger is subject to various conditions, including: (1) approval of the shareholders of the Company, (2) expiration or termination of the applicable Hart-Scott-Rodino Act waiting period, (3) receipt of all required regulatory and statutory approvals without the imposition of a "Burdensome Condition," (4) absence of any law or order prohibiting the consummation of the Merger and (5) other customary closing conditions, including (a) subject to materiality qualifiers, the accuracy of each party's representations and warranties, (b) each party's compliance in all material respects with its obligations and covenants under the Merger Agreement and (c) the absence of a material adverse effect with respect to the Company and its subsidiaries. The Merger Agreement contains certain termination rights for both the Company and CenterPoint, including if the Merger is not consummated by April 21, 2019 (subject to extension for an additional six months if all of the conditions to closing, other than the conditions related to obtaining regulatory approvals, have been satisfied). The Merger Agreement also provides for certain termination rights for each of the Company and CenterPoint, and provides that, upon termination of the Merger Agreement under certain specified circumstances, CenterPoint would be required to pay a termination fee of $210 million to the Company, and under other specified circumstances the Company would be required to pay CenterPoint a termination fee of $150 million .

Basis of Presentation

Basis of Presentation	3 Months Ended
	Mar. 31, 2018
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 interim 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, 2017 , filed with the Securities and Exchange Commission on February 21, 2018, 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.

Revenue

Revenue	3 Months Ended
	Mar. 31, 2018
Revenue from Contract with Customer [Abstract]
Revenue	Revenue In May 2014, the FASB issued new accounting guidance, ASC 606, Revenue from Contracts with Customers, to clarify the principles for recognizing revenue and to develop a common revenue standard for GAAP. The amendments in this guidance state 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 enhanced disclosures to help users of financial statements better understand the nature, amount, timing, and uncertainty of revenue that is recognized. On January 1, 2018, the Company adopted the new accounting standard and all the related amendments (“new revenue standard”) to all contracts not complete at the date of initial application using the modified retrospective method, which resulted in a cumulative effect reduction of $1.1 million to retained earnings. The Company expects ongoing application to continue to be immaterial to financial condition and net income. The comparative information has not been restated and continues to be reported under the accounting standards in effect for those periods. The cumulative effect recorded resulted from a change in the accounting for revenue associated with certain specialized equipment used on projects in the Energy Services segment of the Nonutility Group, where under the new revenue standard, recognition is proportionate to progress in satisfying the performance obligation, and previously was recognized when the equipment was procured. The cumulative effect of the changes made to the Company's consolidated January 1, 2018 balance sheet for the adoption of the new revenue standard is as follows: Balance Sheet (In millions) Balance at December 31, 2017 Adjustments due to ASC 606 Balance at January 1, 2018 Assets Accrued unbilled revenues $ 207.1 $ (7.0 ) $ 200.1 Prepayments and other current assets 47.0 5.6 52.6 Liabilities Accrued liabilities 222.3 (0.3 ) 222.0 Common Shareholders’ Equity Retained earnings $ 1,113.7 $ (1.1 ) $ 1,112.6 The adoption of the new revenue standard had an immaterial impact to the Condensed Consolidated Income Statement for the period ended March 31, 2018 and the Condensed Consolidated Balance Sheet as of March 31, 2018, increasing net income by less than $1 million . The impact was also a result of the change in revenue recognition on specialized equipment. Substantially all the Company’s revenues are within the scope of the new revenue standard. Revenue Policy Revenue is recognized when obligations under the terms of a contract with the customer are satisfied. Revenue is measured as the amount of consideration the Company expects to receive in exchange for transferring goods or providing services. The satisfaction of performance obligation occurs when the transfer of goods and services occur, which may be at a point in time or over time; resulting in revenue being recognized over the course of the underlying contract or at a single point in time based upon the delivery of services to customers. The Company determines that disaggregating revenue into these categories achieves the disclosure objective to depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. These material revenue generating categories, as disclosed in Note 17, include: Gas Utility Services, Electric Utility Services, Infrastructure Services, and Energy Services. Utility Group (Gas Utility Services and Electric Utility Services) The Utility Group provides commodity service to customers at rates, charges, and terms and conditions included in tariffs approved by regulators. The Company’s utilities bill customers on a monthly basis and have the right to consideration from customers in an amount that corresponds directly with the performance obligation satisfied to date. The performance obligation is satisfied and revenue is recognized upon the delivery of services to customers. The Company records revenues for services and goods delivered but not billed at the end of an accounting period in Accrued unbilled revenues , derived from estimated unbilled consumption and tariff rates. The Company's revenues are also adjusted for the effects of regulation including tracked operating expenses, infrastructure replacement mechanisms, decoupling mechanisms, and lost margin recovery. Decoupling and lost margin recovery mechanisms are considered alternative revenue programs, which are excluded from the scope of the new revenue standard. Revenues from alternative revenue programs are not material to any reporting period. Customers are billed monthly and payment terms, set by the regulator, require payment within a month of billing. The Utility Group's revenues are not subject to significant returns, refunds, or warranty obligations. In the following table, Utility Group revenue is disaggregated by customer class. (In millions) Three Months Ended March 31, 2018 Gas Utility Services Residential $ 219.7 Commercial 82.6 Industrial 23.8 Other 3.2 Total Gas Utility Services $ 329.3 Electric Utility Services Residential $ 49.7 Commercial 34.5 Industrial 37.3 Other 12.5 Total Electric Utility Services $ 134.0 Infrastructure Services Infrastructure Services provides underground pipeline construction and repair services. The duration of the contracts are generally less than one year and consist of fixed price, unit, and time and material customer contracts. Under unit or time and material contracts, the Company performs construction and repair services under specific work-orders at prices established by master service agreements. The performance obligation is defined at the work-order level. These services are billed to customers monthly or more frequently for work completed based on units completed or time and material cost incurred, and generally require payment within 30 days of billing. The Company has the right to consideration from customers in an amount that corresponds directly with the performance obligation satisfied, and therefore recognizes revenue at a point in time in the amount to which it has the right to invoice, which results in Accrued unbilled revenues at the end of each accounting period. Under fixed price contracts, the Company performs larger scale construction and repair services. Each contract is typically viewed as a single performance obligation. Services performed under fixed price contracts are typically billed per the terms of the contract, which can range from completion of specific milestones or scheduled billing intervals. Billings occur monthly or more frequently for work completed, and generally require payment within 30 days of billing. Revenue for fixed price contracts are recognized over time as control is transferred using the input method, considering costs incurred relative to total expected cost. Total expected cost is therefore a significant judgment affecting the amount and timing of revenue recognition. Infrastructure Services' revenues are not subject to significant returns, refunds, or warranty obligations. The following table disaggregates Infrastructure Services revenue by type of contract and timing of transfer of control: (In millions) Three Months Ended March 31, 2018 Revenue Unit or time and material (point in time) $ 124.4 Fixed price (over time) 10.9 Total Infrastructure Services $ 135.3 Energy Services Energy Services provides energy performance contracting and sustainable infrastructure services. While a majority of Energy Services' revenues are from construction services, some customer contracts also include operation and maintenance services. The performance obligations are distinct as the customer can realize benefits from the construction services without the operation and maintenance services. The prices of each performance obligation are specifically stated in the contract and have been developed independently. Billing methods can vary. Most construction performance obligations require an initial deposit and are either billed monthly for progress completed or according to a contractual draw schedule, which results in Accrued Unbilled Revenues at the end of each accounting period. Payments are typically required within 30 days of billing. Revenues on construction performance obligations, which may have durations greater than one year, are recognized over time as control is transferred using the input method, considering costs incurred relative to total expected cost. Total expected cost is therefore a significant judgment affecting the amount and timing of revenue recognition. Revenue on operations and maintenance performance obligations are recognized ratably over the life of the contract. Energy Services' contracts may be subject to performance guarantees and product warranties as discussed in Note 11. The following table disaggregates Energy Services revenue by type of performance obligation: (In millions) Three Months Ended March 31, 2018 Revenue Construction $ 53.7 Operations and Maintenance and other 6.9 Total Energy Services $ 60.6 Nonutility Contract Balances When the timing of the Company’s delivery of nonutility service is different from the timing of the payments made by customers and when the right to consideration is conditioned on something other than the passage of time, the Company recognizes either a contract asset (performance precedes billing) or a contract liability (customer payment precedes performance). Those customers that prepay are represented by contract liabilities until the performance obligations are satisfied. The Company’s contract liabilities are included in Accrued Liabilities in the Condensed Consolidated Balance Sheets. The Company’s contract liabilities primarily relate to contracts in the Energy Services segments where revenue is recognized using the input method. The Company did no t have contract assets as of January 1, 2018 or March 31, 2018. The opening and closing balances of the Company's accounts receivable, accrued unbilled revenue, and contract liabilities are as follows: (In millions) Accounts Receivable Accrued Unbilled Revenues Contract Liabilities Opening (01/01/2018) $ 262.9 $ 200.1 $ 38.3 Closing (03/31/2018) 237.1 146.5 35.6 Increase/(decrease) $ (25.8 ) $ (53.6 ) $ (2.7 ) The amount of revenue recognized in the period that was included in the opening contract liability was $26.3 million . The difference between the opening and closing balances of the company’s contract liabilities primarily results from the timing difference between the Company’s performance and the customer’s payment. Remaining Performance Obligations The table below discloses (1) the aggregate amount of the transaction price allocated to performance obligations that are unsatisfied (or partially unsatisfied) as of the end of the reporting period for contracts and (2) when the company expects to recognize this revenue. Such contracts include both construction and operations and maintenance performance obligations from the Energy Services segment and fixed price contracts in the Infrastructure Services segment. (In millions) Rolling 12 Months Thereafter Total Revenue expected to be recognized on contracts in place as of March 31, 2018: Energy Services - operations and maintenance $ 24.2 $ 380.6 $ 404.8 Energy Services - construction 179.1 14.2 193.3 Infrastructure Services - fixed price (bid) 258.4 — 258.4 Total $ 461.7 $ 394.8 $ 856.5 For the Company’s contracts for which revenue from the satisfaction of the performance obligations is recognized in the amount invoiced, the Company elected the simplified option available in the standard, known as practical expedient, and has not disclosed the revenue expected to be recognized on these contracts.

Earnings Per Share

Earnings Per Share	3 Months Ended
	Mar. 31, 2018
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. The amount of net income attributable to participating securities is immaterial. 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 share-based compensation 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) 2018 2017 Numerator: Reported net income (Numerator for Basic and Diluted EPS) $ 63.5 $ 55.4 Denominator: Weighted-average common shares outstanding (Denominator for Basic and Diluted EPS) 83.1 82.9 Basic and Diluted EPS $ 0.76 $ 0.67 For the three months ended March 31, 2018 and 2017 , all share-based compensation was dilutive and immaterial.

Excise & Utility Receipts Taxes

Excise & Utility Receipts Taxes	3 Months Ended
	Mar. 31, 2018
Excise and Utility Receipts Taxes [Abstract]
Excise & Utility Receipts Taxes	Excise & Utility Receipts Taxes Excise taxes and a portion of utility receipts taxes are included in rates charged to customers. Accordingly, the Company records these taxes billed to customers, which totaled $10.5 million and $9.4 million in the three months ended March 31, 2018 and 2017 , 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 & Other Postre

Retirement Plans & Other Postretirement Benefits	3 Months Ended
	Mar. 31, 2018
Pension and Other Postretirement Benefits Cost (Reversal of Cost) [Abstract]
Retirement Plans & Other Postretirement Benefits	Retirement Plans & Other Postretirement Benefits The Company maintains three closed qualified defined benefit pension plans, a nonqualified supplemental executive retirement plan (SERP), and a postretirement benefit plan. The defined benefit pension plans and postretirement benefit plan, which cover eligible full-time regular employees, are primarily noncontributory. The postretirement benefit plan includes health care and life insurance benefits which are a combination of self-insured and fully insured plans. The qualified pension plans and the SERP are aggregated under the heading “Pension Benefits.” The postretirement benefit plan is presented under the heading “Other Benefits.” Net Periodic Benefit Costs A summary of the components of net periodic benefit cost 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) 2018 2017 2018 2017 Service cost $ 1.7 $ 1.6 $ — $ — Interest cost 3.2 3.5 0.3 0.4 Expected return on plan assets (5.3 ) (5.3 ) — — Amortization of prior service cost 0.1 0.1 (0.5 ) (0.6 ) Amortization of actuarial loss 2.1 1.9 — — Net periodic cost (benefit) $ 1.8 $ 1.8 $ (0.2 ) $ (0.2 ) The service cost component is either included within Other operating in the Condensed Consolidated Statements of Income or is capitalized. The components of the net periodic benefit cost other than the service cost component are included within Other income - net in the Condensed Consolidated Statements of Income. In March 2017, the FASB issued new accounting guidance to improve the presentation of net periodic pension and postretirement benefit costs. This ASU is effective for annual periods beginning after December 15, 2017, and relevant interim periods. This ASU requires the Company to report the service cost component in the same line items as other compensation costs arising from services rendered by the pertinent employees during the period. The other components of net benefit cost are required to be presented in the income statement separately from the service cost component and outside of income from operations. Capitalization of net benefit cost is limited to only the service cost component of benefit costs, when applicable. The ASU requires retrospective presentation of the service and non-service costs components in the income statement and prospective application regarding the capitalization of only the service cost component of net benefit costs. The Company has adopted the guidance effective January 1, 2018. There was no retrospective adjustment to the first quarter of 2017, and the Company expects the guidance to have an immaterial impact to the Company's financial statements on an ongoing basis. Employer Contributions to Qualified Pension Plans In the first quarter of 2018, the Company has made $3.5 million in contributions to its qualified pension plans.

Supplemental Cash Flow Informat

Supplemental Cash Flow Information	3 Months Ended
	Mar. 31, 2018
Supplemental Cash Flow Information [Abstract]
Supplemental Cash Flow Information	Supplemental Cash Flow Information As of March 31, 2018 and December 31, 2017 , the Company has accruals related to utility and nonutility plant purchases totaling approximately $26.9 million and $28.6 million , respectively.

Investment in ProLiance Holding

Investment in ProLiance Holdings, LLC	3 Months Ended
	Mar. 31, 2018
Equity Method Investments and Joint Ventures [Abstract]
Investment in ProLiance Holdings, LLC	Investment in ProLiance Holdings, LLC The Company has an investment in ProLiance Holdings, LLC (ProLiance), 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 remaining investment at March 31, 2018 , shown at its 61 percent ownership share of the individual net assets of ProLiance, is as follows. (In millions) As of March 31, 2018 Cash $ 0.7 Investment in LA Storage 22.4 Total investment in ProLiance $ 23.1 Included in: Investments in unconsolidated affiliates $ 18.7 Other nonutility investments $ 4.4 LA Storage, LLC Storage Asset Investment ProLiance Transportation and Storage, LLC (PT&S), a subsidiary of ProLiance, and Sempra Energy International (SEI), a subsidiary of Sempra Energy (SE), through a joint venture, have a 100 percent interest in a development project for salt-cavern natural gas storage facilities known as LA Storage. PT&S is the minority member with 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 can 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 and pipeline system is dependent on market conditions, including pricing, need for storage and transmission capacity, and development of the liquefied natural gas market, among other factors. To date, development activity has been modest due to the current low demand for storage facilities. The development of the storage market and related pricing are critical assumptions in the analysis of the recoverability of the investment's carrying value. To the extent market conditions indicate other than temporary impairment, the Company will evaluate the carrying value of the assets. As of March 31, 2018 and December 31, 2017 , ProLiance's investment in the joint venture was $36.7 million and $36.8 million , respectively.

Income Taxes Income Taxes

Income Taxes Income Taxes	3 Months Ended
	Mar. 31, 2018
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes Tax Cuts and Jobs Act On December 22, 2017, the United States government enacted comprehensive tax legislation commonly referred to as the Tax Cuts and Jobs Act (“TCJA”). The TCJA makes broad and complex changes to the Internal Revenue Code (“IRC”), many of which were effective on January 1, 2018, including, but not limited to, (1) reducing the Federal corporate income tax rate from 35 percent to 21 percent, (2) eliminating the use of bonus depreciation for regulated utilities, while permitting full expensing of qualified property for non-regulated entities, (3) eliminating the domestic production activities deduction previously allowable under Section 199 of the IRC, (4) creating a new limitation on the deductibility of interest expense for non-regulated businesses, (5) eliminating the corporate Alternative Minimum Tax (“AMT”) and changing how existing AMT credits can be realized, (6) limiting the deductibility of certain executive compensation, (7) restricting the deductibility of entertainment and lobbying-related expenses, (8) requiring regulated entities to employ the average rate assumption method (“ARAM”) to refund excess deferred taxes created by the rate change to their customers, and (9) changing the rules regarding taxability of contributions made by government or civic groups. The Company's gas and electric utilities currently recover corporate income tax expense in Commission approved rates charged to customers. The IURC and the PUCO both issued orders which initiated proceedings to investigate the impact of the TCJA on utility companies and customers within each state. In addition, both Commissions have ordered each utility to establish regulatory assets and liabilities to record all estimated impacts of tax reform starting January 1, 2018. The Company is complying with both orders. In Indiana, the IURC held an initial conference of parties on February 6, 2018, and an order was issued by the Commission on February 16, 2018, outlining the process the utility companies are to follow. In accordance with the order, the Company filed March 26, 2018 for proposed changes to its rates and charges to consider the impact of the lower corporate federal income tax rate. An order is expected in the second quarter of 2018 and rates will then be adjusted. In Ohio, in response to the PUCO's request for comments from utilities, Vectren submitted its response indicating that the issues should be addressed in its base rate case, which was filed on March 30, 2018. On February 9, 2018, through the signing into law of the Bipartisan Budget Act of 2018, Section 179D of the Internal Revenue Code, which provides for the energy efficiency commercial buildings tax deduction, was retroactively extended to 2017 for one year.

Financing Activities

Financing Activities	3 Months Ended
	Mar. 31, 2018
Debt Disclosure [Abstract]
Financing Activities	Financing Activities SIGECO Variable Rate Tax-Exempt Bonds On March 1, 2018 and May 1, 2018, the Company, through SIGECO, executed first and second amendments to a Bond Purchase and Covenants Agreement originally signed in September 2017. These amendments provided SIGECO the ability to remarket bonds that were callable from current bondholders on those dates. Pursuant to these amendments, lenders purchased the following SIGECO bonds on March 1 and May 1, respectively: • 2013 Series A Notes with a principal of $22.2 million and final maturity date of March 1, 2038; and • 2013 Series B Notes with a principal of $39.6 million and final maturity date of May 1, 2043. Prior to the call, the 2013 Series A Notes had an interest rate of 4.0% and the 2013 Series B Notes had an interest rate of 4.05% . The bonds converted to a variable rate based on the one month LIBOR through May 1, 2023. The Company has now remarketed $ 152 million of tax exempt bonds through the Bonds Purchase and Covenants Agreement, which is the agreement’s full capacity. Bonds remarketed through the Bond Purchase and Covenants Agreement in 2017 were: • 2013 Series C Notes with a principal of $4.6 million and final maturity date of January 1, 2022; • 2013 Series D Notes with a principal of $22.5 million and final maturity date of March 1, 2024; • 2013 Series E Notes with a principal of $22.0 million and final maturity date of May 1, 2037; and • 2014 Series B Notes with a principal of $41.3 million and final maturity date of July 1, 2025. These bonds also have a variable interest rate based on the one month LIBOR through May 1, 2023. The Company, through SIGECO, executed forward starting interest rate swaps during 2017 providing that on January 1, 2020, the Company will begin hedging the variability in interest rates on the 2013 Series A, B, and E Notes through final maturity dates. The swaps contain customary terms and conditions and generally provide offset for changes in the one month LIBOR rate. Other interest rate variability that may arise through the Bond Purchase and Covenants Agreement, such as variability caused by changes in tax law or SIGECO’s credit rating, among others, may result in an actual interest rate above or below the anticipated fixed rate. Regulatory orders require SIGECO to include the impact of its interest rate risk management activities, such as gains and losses arising from these swaps, in its cost of capital utilized in rate cases and other periodic filings. Utility Holdings and Vectren Capital Long-Term Borrowing Facilities The Merger would constitute a “Change of Control” under the note agreements pursuant to which Senior Notes issued by Utility Holdings in an aggregate principal amount of $1.025 billion and Senior Notes issued by Vectren Capital in an aggregate principal amount of $260 million were issued. While the Merger would not result in an event of default under such note agreements, upon the consummation of the Merger the issuer would be required to offer to repurchase these notes at 100% of the principal amount thereof plus accrued interest.

Commitments & Contingencies

Commitments & Contingencies	3 Months Ended
	Mar. 31, 2018
Commitments and Contingencies Disclosure [Abstract]
Commitments & Contingencies	Commitments & Contingencies Performance Guarantees & Product Warranties In the normal course of business, wholly owned subsidiaries, such as Energy Systems Group, LLC (ESG), a subsidiary of the Energy Services operating segment, issue payment and performance bonds and other forms of assurance that commit them to timely install infrastructure, operate facilities, pay vendors and subcontractors, and support warranty obligations. Specific to ESG's role as a general contractor in the performance contracting industry, at March 31, 2018 , there were 55 open surety bonds supporting future performance. The average face amount of these obligations is $11.2 million , and the largest obligation has a face amount of $75.9 million . The maximum exposure from these obligations is limited to the level of uncompleted work and further limited by bonds issued to ESG by various contractors. At March 31, 2018 , approximately 25 percent of work was yet to be completed on projects with open surety bonds. A significant portion of these open surety bonds will be released within one year. In instances where ESG operates facilities, project guarantees extend over a longer period. In addition to its performance obligations, ESG also warrants the functionality of certain installed infrastructure generally for one year and the associated energy savings over a specified number of years. Based on a history of meeting performance obligations and installed products operating effectively, no liability or cost has been recognized for the periods presented as the Company assesses the likelihood of loss as remote. Since inception, ESG has paid a de minimis amount on energy savings guarantees. Corporate Guarantees & Other Support The Company issues parent level guarantees to certain vendors and customers of its wholly owned subsidiaries. These guarantees do not represent incremental consolidated obligations; but rather, represent guarantees of subsidiary obligations in order to allow those subsidiaries the flexibility to conduct business without posting other forms of collateral. At March 31, 2018 , parent level guarantees support a maximum of $388 million of ESG’s performance contracting commitments, warranty obligations, project guarantees, and energy savings guarantees. Given the infrequent occurrence of any performance shortfalls historically on any of these commitments, no reserve for a potential liability has been deemed warranted. Further, an energy facility operated by ESG and managed by Keenan Ft. Detrick Energy, LLC (Keenan), is governed by an operations agreement. Under this agreement, all payment obligations to Keenan are also guaranteed by the Company. The Company guarantee of the Keenan 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 but assesses the likelihood of loss as remote based on, primarily, the nature of the project. The Company has not been called on to perform under these guarantees historically. While there can be no assurance that performance under these provisions will not be required in the future, the Company believes the likelihood of a material amount being incurred under these provisions is remote given the nature of the projects, the manner in which the savings estimates are developed, and the fact that the value of the guarantees decrease over time as actual energy savings are achieved. The Company issues letters of credit that support consolidated operations. At March 31, 2018 , letters of credit outstanding total $22.3 million . Commitments The Company's regulated utilities have both firm and non-firm commitments, some of which are between five and twenty year agreements 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 condition, results of operations or cash flows.

Gas Rate & Regulatory Matters

Gas Rate & Regulatory Matters	3 Months Ended
	Mar. 31, 2018
Public Utilities, General Disclosures [Abstract]
Gas Rate & 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 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 the result of federal pipeline safety requirements. Laws passed in both Indiana and Ohio provide utilities the opportunity to timely recover costs of federally mandated projects and other infrastructure improvement projects outside of a base rate proceeding. Indiana Senate Bill 251 (Senate Bill 251) provides a framework to recover 80 percent of federally mandated costs through a periodic rate adjustment mechanism outside of a general rate case. Such costs include a return on the federally mandated capital investment, based on the overall rate of return most recently approved by the IURC, through a base rate case or other proceeding, 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. Indiana Senate Bill 560 (Senate Bill 560) 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, among other things, requests for recovery including a seven-year project plan. Once the plan is approved by the IURC, 80 percent of such costs are eligible for current recovery using a periodic rate adjustment mechanism. Recoverable costs include a return on the investment that reflects the current capital structure and associated costs, with the exception of the rate of return on equity, which remains fixed at the rate determined in the Company's last rate case. Recoverable costs also include recovery of depreciation and other operating expenses. The remaining 20 percent of project costs are deferred for future recovery 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. Ohio House Bill 95 (House Bill 95) permits a natural gas utility to apply for recovery of much of its capital expenditure program. This legislation also allows for the deferral of costs, such as depreciation, property taxes, and debt-related post-in-service carrying costs until recovery is approved by the PUCO. Requests for Recovery under Indiana Regulatory Mechanisms In August 2014, the IURC issued an Order approving the Company’s seven -year capital infrastructure replacement and improvement plan (the Plan), beginning in 2014, and the proposed accounting authority and recovery. Compliance projects and other infrastructure improvement projects were approved pursuant to Senate Bill 251 and 560, respectively. As provided in the two laws, the Order approved semi-annual filings for rate recovery of 100 percent of the costs, inclusive of return, related to these capital investments and operating expenses, with 80 percent of the costs, including a return, recovered currently via an approved tracking mechanism and 20 percent of the costs deferred and recovered in the Company’s next base rate proceeding. In addition, the Order established guidelines to annually update the seven -year capital investment plan. Finally, the Order approved the Company’s proposal to recover eligible costs assigned to the residential customer class via a fixed monthly charge per residential customer. On January 24, 2018, the IURC issued an order (January 2018 order) approving the inclusion in rates of investments made from January 2017 to June 2017. Through the January 2018 Order, approximately $482 million of the approved capital investment has been incurred and included for recovery. The January 2018 Order also approved the Company's plan update, which now totals $995 million through 2020. On April 2, 2018, the Company submitted its eighth semi-annual filing, seeking approval of the recovery in rates of investments made through December 31, 2017. In December 2016, PHMSA issued interim final rules related to integrity management for storage operations. Efforts are underway to implement the new requirements. Further, the Company reviewed the Underground Natural Gas Storage Safety Recommendations from a joint Department of Energy and PHMSA led task force. On August 3, 2017, the Company filed for authority to recover the associated costs using the mechanism allowed under Senate Bill 251. Approximately $15 million of operating expenses and $17 million of capital investments will be included in the plan over a four -year period beginning in 2018. The Company received the IURC Order approving the request for recovery on December 28, 2017. The Company does not have company-owned storage operations in Ohio. At March 31, 2018 and December 31, 2017 , the Company has regulatory assets related to the Plan totaling $78.8 million and $78.0 million , respectively. 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, as well as certain other infrastructure investments. This rider is updated annually for qualifying capital expenditures and allows for a return on those capital expenditures based on the rate of return approved in the 2009 base rate case. In addition, deferral of depreciation and the ability to accrue debt-related post-in-service carrying costs is also allowed until the related capital expenditures are included in the DRR. The Order also initially established a prospective bill impact evaluation on the annual deferrals. 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 certain other infrastructure investments. The Order limits the resulting DRR fixed charge per month for residential and small general service customers to specific graduated levels through 2017. 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. In the event the Company exceeds these caps, amounts in excess can be deferred for future recovery. The Order also approved the Company's commitment that the DRR can only be further extended as part of a base rate case. In the Company's base rate case, it requested extension to include investments made starting 2018 through completion of the program, currently estimated at 2023. In total, the Company has made capital investments on projects that are now in-service under the DRR totaling $326.5 million as of March 31, 2018 , of which $261.1 million has been approved for recovery under the DRR through December 31, 2016. On May 1, 2018, the Company submitted its annual request for an adjustment in the DRR rates to recover investments made through December 31, 2017. Regulatory assets associated with post-in-service carrying costs and depreciation deferrals were $32.9 million and $31.2 million at March 31, 2018 and December 31, 2017 , respectively. 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 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. The Company has requested recovery of these deferrals through December 31, 2017 in its rate case, along with a mechanism to recover future Ohio House Bill 95 deferrals. At March 31, 2018 and December 31, 2017 , the Company has regulatory assets totaling $73.7 million and $66.1 million , respectively, associated with the deferral of depreciation, post-in-service carrying costs, and property taxes. On May 1, 2018, the Company submitted its most recent annual report required under its House Bill 95 Order. This report covers the Company's capital expenditure program through calendar year 2017. Vectren Ohio Gas Rate Case On March 30, 2018, the Company filed with the PUCO a request for a $34 million increase in its base rates and charges for VEDO’s distribution business in its 17 county service area in west-central Ohio. The requested increase includes the benefit of the TCJA, which decreased the corporate rate from 35 percent to 21 percent. The filing is necessary to extend the DRR mechanism beyond 2017 through completion of the accelerated replacement program, and to recover the costs of capital investments made over the past ten years, much of which has been deferred as part of the Company’s capital expenditure program under Ohio House Bill 95. The filing also addresses the recovery of the current Ohio House Bill 95 regulatory asset balance, and a proposed mechanism to recover future Ohio House Bill 95 deferrals. The Company expects the PUCO staff to file its report, including recommendations, in the third quarter of 2018 and an order by early 2019. Pipeline and Hazardous Materials Safety Administration (PHMSA) In March 2016, PHMSA published a notice of proposed rulemaking (NOPR) on the safety of gas transmission and gathering lines. The proposed rule addresses many of the remaining requirements of the 2011 Pipeline Safety Act, with a particular focus on extending integrity management rules to address a much larger portion of the natural gas infrastructure and adds requirements to address broader threats to the integrity of a pipeline system. The Company continues to evaluate the impact these proposed rules will have on its integrity management programs and transmission and distribution systems. Progress on finalizing the rule continues to work through the administrative process. The rule is expected to be finalized in 2019 and the Company believes the costs to comply with the new rules would be considered federally mandated and therefore should be recoverable under Senate Bill 251 in Indiana and eligible for deferral under House Bill 95 in Ohio.

Electric Rate & Regulatory Matt

Electric Rate & Regulatory Matters	3 Months Ended
	Mar. 31, 2018
Public Utilities, General Disclosures [Abstract]
Electric Rate & Regulatory Matters	Electric Rate & Regulatory Matters Electric Requests for Recovery under Senate Bill 560 The provisions of Senate Bill 560, as described in the Gas Rate & Regulatory Matters footnote for gas projects, are the same for qualifying electric projects. On February 23, 2017, the Company filed for authority to recover costs related to its electric system modernization plan, using the mechanism allowed under Senate Bill 560. The electric system modernization plan includes investments to upgrade portions of the Company’s network of substations, transmission and distribution systems, to enhance reliability and allow the grid to accept advanced technology to improve the information and service provided to customers. On September 20, 2017, the IURC issued an Order approving the Company’s electric system modification as reflected in the settlement agreement reached between the Company, the OUCC and a coalition of industrial customers. The settlement agreement includes defined annual caps on recoverable capital investments. The settlement agreement also addresses how the eligible costs would be recoverable in rates, with a cap on the residential and small general service fixed monthly charge per customer in each semi-annual filing. The remaining costs to residential and small general service customers would be recovered via a volumetric energy charge. The settlement agreement removed advanced metering infrastructure (AMI or digital meters) from the plan. However, deferral of the costs for AMI was agreed upon in the settlement whereby the company can move forward with deployment in the near-term. The request for cost recovery for the AMI project will not occur until the next base rate review proceeding, which is expected to be filed by the end of 2023. In that proceeding, settling parties have agreed not to oppose inclusion of the AMI project in rate base. On August 1, 2017, the Company filed with the IURC its initial request for approval of the revenue requirement associated with a capital investment of $7.1 million through April 30, 2017. On December 20, 2017, the IURC issued an Order approving the initial rates necessary to begin cash recovery of 80 percent of the revenue requirement, inclusive of return, with the remaining 20 percent deferred for recovery in the utility's next general rate case. On February 1, 2018, the Company submitted its second semi-annual filing, seeking approval of the recovery in rates of investments made of approximately $31 million through October 31, 2017. As of March 31, 2018 and December 31, 2017 , the Company has regulatory assets related to the Electric TDSIC plan totaling $4.5 million and $4.3 million , respectively. SIGECO Electric Environmental Compliance Filing On January 28, 2015, the IURC issued an Order approving the Company’s request for approval of capital investments in its coal-fired generation units to comply with new EPA mandates related to mercury and air toxic standards (MATS) effective in 2015 and to address an outstanding Notice of Violation (NOV) from the EPA pertaining to its A.B. Brown generating station sulfur trioxide emissions. 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. As of 2017, the Company has completed investments of $30 million on equipment to control mercury in both air and water emissions, and $40 million to address the issues raised in the NOV. The Order approved the Company’s request for deferred accounting treatment, as supported by provisions under Indiana 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 going into service in 2016. As of March 31, 2018 , the Company has approximately $14.0 million deferred related to depreciation and operating expenses, and $5.1 million deferred related to post-in-service carrying costs. MATS compliance was required beginning April 16, 2015 and the Company continues to operate in full compliance with the MATS rule. On February 20, 2018, the Company filed a request to commence recovery, under Senate Bill 251, of its already approved investments associated with the MATS and NOV Compliance Projects, including recovery of the authorized deferred balance. As proposed, recovery would reflect 80 percent of the authorized costs, including a return, recovery of depreciation and incremental operating expenses, and recovery of the prior deferred balance over a proposed period of 15 years. The remaining 20 percent will be deferred until the Company’s next base rate proceeding. The Company expects an order in the first half of 2019 since filed as a part of the electric generation transition plan case discussed below. SIGECO Electric Demand Side Management (DSM) Program Filing On March 28, 2014, Indiana Senate Bill 340 was signed into law. The legislation allows for industrial customers to opt out of participating in energy efficiency programs and as a result of this legislation, customers representing most of the eligible load have since opted out of participation in the applicable energy efficiency programs. Indiana Senate Bill 412 (Senate Bill 412) requires electricity suppliers to submit energy efficiency plans to the IURC at least once every three years. Senate Bill 412 also requires the recovery of all program costs, including lost revenues and financial incentives associated with those plans and approved by the IURC. The Company made its first filing pursuant to this bill in June 2015, which proposed energy efficiency programs for calendar years 2016 and 2017. On March 23, 2016, the IURC issued an Order approving the Company’s 2016-2017 energy efficiency plan. The Order provided for cost recovery of program and administrative expenses and included performance incentives for reaching energy savings goals. The Order also included a lost margin recovery mechanism that would have limited recovery related to new programs to the shorter of four years or the life of the installed energy efficiency measure. Prior electric energy efficiency orders did not limit lost margin recovery in this manner. This ruling followed other IURC decisions implementing the same lost margin recovery limitation with respect to other electric utilities in Indiana. The Company appealed this lost margin recovery restriction based on the Company’s commitment to promote and drive participation in its energy efficiency programs. On March 7, 2017, the Indiana Court of Appeals reversed the IURC finding on the Company's 2016-2017 energy efficiency plan that the four year cap on lost margin recovery was arbitrary and the IURC failed to properly interpret the governing statute requiring it to review the utility's originally submitted DSM proposal and either approve or reject it as a whole, including the proposed lost margin recovery. The case was remanded to the IURC for further proceedings. On June 13, 2017, the Company filed additional testimony supporting the plan. In response to the proposals to cap lost margin recovery, the Company filed supplemental testimony that supported lost margin recovery based on the average measure life of the plan, estimated at nine years, on 90 percent of the direct energy savings attributed to the programs. Testimony of intervening parties was filed on July 26, 2017, opposing the Company's proposed lost margin recovery. An evidentiary hearing was held in September 2017. On December 20, 2017, the Commission issued an order approving the DSM Plan for 2016-2017 including the recovery of lost margins consistent with the Company’s proposal. On January 22, 2018, certain intervening parties initiated an appeal to the Indiana Court of Appeals. The briefs of appealing parties are currently due on May 3, 2018. While no assurance as to the ultimate outcome can be provided, based upon the record of the proceedings, as well as the findings in the Commission’s order, the Company expects to prevail in this appeal. On April 10, 2017, the Company submitted its request for approval to the IURC of its Energy Efficiency Plan for calendar years 2018 through 2020. Consistent with prior filings, this filing included a request for continued cost recovery of program and administrative expenses, including performance incentives for reaching energy savings goals and continued recovery of lost margins consistent with the modified proposal in the 2016-2017 plan. Filed testimony of intervening parties was received on July 26, 2017, opposing the Company's proposed lost margin recovery. An evidentiary hearing was held in September 2017. On December 28, 2017, the Commission issued an order approving the 2018 through 2020 Plan, inclusive of recovery of lost margins consistent with the Order issued on December 20, 2017. On January 26, 2018, certain intervening parties initiated an appeal to the Indiana Court of Appeals. The briefs of appealing parties are currently due on May 3, 2018. While no assurance as to the ultimate outcome can be provided, based upon the record of the proceedings, as well as the findings in the Commission’s order, the Company expects to prevail in this appeal. For the three months ended March 31, 2018 and 2017 , the Company recognized electric utility revenue of $3.1 million and $3.0 million , respectively, associated with lost margin recovery approved by the Commission. FERC Return on Equity (ROE) Complaints On November 12, 2013, certain parties representing a group of industrial customers filed a joint complaint with the FERC under Section 206 of the Federal Power Act against the MISO and various MISO transmission owners, including SIGECO (first complaint case). The joint parties sought to reduce the 12.38 percent base ROE used in the MISO transmission owners’ rates, including SIGECO’s formula transmission rates, to 9.15 percent covering the refund period from November 12, 2013 through February 11, 2015 (first refund period). On September 28, 2016, the FERC issued a final order authorizing a 10.32 percent base ROE for the first refund period and prospectively through the date of the order in a second complaint case as detailed below. A second customer complaint case was filed on February 11, 2015 covering the refund period from February 12, 2015 through May 11, 2016 (second refund period). An initial decision from the FERC administrative law judge on June 30, 2016, authorized a base ROE of 9.70 percent for the second refund period. The FERC was expected to rule on the proposed order in the second complaint case in 2017, which would authorize a base ROE for this period and prospectively from the date of the order. The timing of such action is uncertain. Separately, on January 6, 2015, the FERC approved a MISO transmission owner joint request for an adder to the approved ROE. Under FERC regulations, transmission owners that are part of a Regional Transmission Organization (RTO) such as the MISO are authorized to earn an incentive of 50 basis points above the FERC approved ROE. The adder is applied retroactively from January 6, 2015 through May 11, 2016 and prospectively from the September 28, 2016 order in the first complaint case. The Company has reflected these results in its financial statements. As of March 31, 2018, the Company had invested approximately $157.7 million in qualifying projects. The net plant balance for these projects totaled $132.6 million at March 31, 2018 . On April 14, 2017, the U.S. Court of Appeals for the District of Columbia circuit vacated the FERC Opinion in a prior case that established a new methodology for calculating ROE. This methodology was utilized in the final order in the Company's first complaint case, and the initial decision in the Company's second complaint case. The Appeals Court stated that FERC did not prove the existing ROE was not just and reasonable, failed to provide any reasoned basis for their selected ROE, and remanded to the FERC for further justification of its ROE calculation. The Company will continue to monitor this proceeding and evaluate any potential impacts on the Company's complaint cases but would not expect them to be material. Electric Generation Transition Plan As required by Indiana regulation, the Company filed its 2016 Integrated Resource Plan (IRP) with the IURC on December 16, 2016. The State requires each electric utility to perform and submit an IRP that uses economic modeling to consider the costs and risks associated with available resource options to provide reliable electric service for the next twenty-year period. During 2016, the Company held three public stakeholder meetings to gather input and feedback as well as communicate results of the IRP process as it progressed. In developing its IRP, the Company considered both the cost to continue operating its existing generation units in a manner that complies with current and anticipated future environmental requirements, as well as various resource alternatives, such as the use of energy efficiency programs and renewable resources as part of its overall generation portfolio. After submission, parties to the IRP provided comments on the plan. While the IURC does not approve or reject the IRP, the process involves the issuance of a staff report that provides comments on the IRP. The final report was issued on November 2, 2017. The Company has taken the comments provided in the report into consideration in its generation transition plan. The Company’s IRP considered a broad range of potential resources and variables and is focused on ensuring it offers a reliable, reasonably priced generation portfolio as well as a balanced energy mix. Consistent with the recommendations presented in the Company’s IRP and as a direct result of significant environmental investments required to comply with current regulations, the Company plans to retire a significant portion of its generating fleet by the end of 2023. On February 20, 2018, the Company filed a petition seeking authorization from the IURC to construct a new 800 - 900 MW natural gas combined cycle generating facility to replace this capacity at an approximate cost of $900 million , which includes the cost of a new natural gas pipeline to serve the plant. The Company is requesting a certificate of public convenience and necessity (CPCN) authorizing construction timelines and costs of new generation resources, as well as necessary unit retrofits, to implement the generation transition plan. In that filing, the Company seeks approval of its generation transition plan, including the authority to defer the cost of new generation, including the ability to accrue AFUDC and defer depreciation until the facility is placed in base rates. As a part of this same proceeding, the Company seeks recovery under Senate Bill 251 of costs to be incurred for environmental investments to be made at its F.B. Culley generating plant to comply with Effluent Limitation Guidelines and Coal Combustion Residuals rules. The F.B. Culley investments, estimated to be approximately $90 million , will begin in 2019 and will allow the F.B. Culley Unit 3 generating facility to comply with environmental requirements and continue to provide generating capacity to the Company’s electric customers. Under Senate Bill 251, the Company is seeking recovery of 80 percent of the approved costs, including a return, using a tracking mechanism, with the remaining 20 percent of the costs deferred for recovery in the Company’s next base rate proceeding. Intervenors must file testimony by August 10, 2018. Evidentiary hearings are scheduled to commence October 9, 2018. The Company expects an order from the Commission in this proceeding in the first half of 2019. On August 30, 2017, the IURC issued an Order approving the Company’s request to recover costs related to the construction of three solar projects, using the mechanism allowed under Senate Bill 29, which allows for timely recovery of costs and expenses incurred during the construction and operation of clean energy projects. These investments, presented as part of the Company’s (IRP) submitted in December 2016, allow the Company to add approximately 4 MW of universal solar generation, rooftop solar generation, and 1 MW of battery storage resources to its portfolio. The approved cost of the projects cannot exceed the approximate $16 million estimate submitted by the Company, without seeking further Commission approval. On February 20, 2018, the Company announced it is finalizing details to install an additional 50 MW of universal solar energy, consistent with its IRP. The Company will seek authority from the IURC pursuant to Senate Bill 29 to recover the costs associated with the project in early May of 2018. In addition, the Company intends to continue to offer energy efficiency programs annually. Similarly, as discussed in more detail below, the extension of preliminary compliance deadlines related to ELG implementation are not expected to have a significant impact on the Company’s long term generation transition plan. On September 21, 2017, the Company and Alcoa agreed to continue the joint ownership and operation of Warrick Unit 4 through 2023. This aligns with the Company's long-term electric generation transition plan, and the expected exit at the end of 2023 is consistent with the IRP which reflects having completed all planned unit retirements and bringing new resources online by that date.

Environmental & Sustainability

Environmental & Sustainability Matters	3 Months Ended
	Mar. 31, 2018
Environmental Matters Disclosure [Abstract]
Environmental & Sustainability Matters	Environmental & Sustainability Matters The Company initiated a corporate sustainability program in 2012 with the publication of the initial corporate sustainability report. Since that time, the Company continues to develop strategies that focus on environmental, social, and governance (ESG) factors that contribute to the long-term growth of a sustainable business model. The sustainability policies and efforts, and in particular its policies and procedures designed to ensure compliance with applicable laws and regulations, are directly overseen by the Company's Corporate Responsibility and Sustainability Committee, as well as vetted with the Company's Board of Directors. Further discussion of key goals, strategies, and governance practices can be found in the Company’s current sustainability report, at www.vectren.com/sustainability, which received core level certification from the Global Reporting Initiative. In furtherance of the Company’s commitment to a sustainable business model, and as detailed further below, the Company is transitioning its electric generation portfolio from nearly total reliance on baseload coal to a fully diversified and balanced portfolio of fuels that will provide long-term electric supply needs in a safe and reliable manner while dramatically lowering emissions of carbon and the carbon intensity of its electric generating fleet. If authorized by the Commission, by 2024 the Company plans to construct a new natural gas combined cycle generating facility to replace four coal-fired units totaling over 700 MWs which, when combined with its planned 54 MWs of new renewable generation, will achieve a 60 percent reduction in carbon emissions from 2005 levels and reduce carbon intensity to 980 lbs CO2 / MMBTU and position the Company to comply with future carbon emission reduction requirements. In addition to diversification of its fuel portfolio, the Company is also seeking authorization to significantly upgrade wastewater treatment for its remaining coal-fired unit and exploring opportunities to continue to recycle ash from its coal ash ponds. This generation diversification strategy aligns with the Company’s ongoing investments in new electric infrastructure through the approved $450 million grid modernization program, and is set forth in more detail in the Company’s upcoming 2017 corporate sustainability report. Further, as part of its commitment to a culture of compliance excellence and continuous improvement, the Company continues to enhance its Safety Management System (SMS) which was implemented several years ago. The risk analysis and process review provides valuable input into the assessment process used to drive the ongoing infrastructure improvement plans being executed by the Company’s gas and electric utilities. The Company is subject to extensive environmental regulation pursuant to a variety of federal, state, and municipal laws and regulations. These environmental regulations impose, among other things, restrictions, liabilities, and obligations in connection with the storage, transportation, treatment, and disposal of hazardous substances and limit airborne emissions from electric generating facilities including particulate matter, sulfur dioxide (SO2), nitrogen oxide (NOx), and mercury, among others. Environmental legislation and regulation also requires that facilities, sites, and other properties associated with the Company's operations be operated, maintained, abandoned, and reclaimed to the satisfaction of applicable regulatory authorities. The Company's current costs to comply with these laws and regulations are significant to its results of operations and financial condition. Similar to the costs associated with federal mandates in the Pipeline Safety Law, Senate Bill 251 is also applicable to federal environmental mandates impacting SIGECO's electric operations. Coal Ash Waste Disposal, Ash Ponds and Water Coal Combustion Residuals Rule In April 2015, the EPA finalized its Coal Combustion Residuals (CCR) rule which regulates ash as non-hazardous material under Subtitle D of the Resource Conservation and Recovery Act (RCRA). The final rule allows beneficial reuse of ash and the majority of the ash generated by the Company’s generating plants will continue to be reused. As it relates to the CCR Rule, the Water Infrastructure Improvements for the Nation (WIIN) Act was passed in December 2016 by Congress that would provide for enforcement of the federal program by states under approved state programs rather than citizen suits. Additionally, aspects of the CCR rule are currently being challenged by multiple parties in judicial review proceedings. In August 2017, the EPA issued guidance to states to clarify their ability to implement the Federal CCR rule through state permit programs as allowed in the WIIN Act legislation. Alternative compliance mechanisms for groundwater, corrective action and other areas of the rule could be granted under the regulatory oversight of a state enforced program. On September 14, 2017, the EPA announced its intent to reconsider portions of the Federal CCR rule in line with the guidance issued to states. On March 15, 2018, EPA published its proposed reconsideration of certain provisions of the existing CCR rule to bring the rule consistent with the WIIN Act. The Company does not anticipate the reconsideration to change its current plans for pond closure as announced in its generation transition plan. While the state program development and EPA reconsideration move forward, the existing CCR compliance obligations remain in effect. Under the existing CCR rule, the Company is required to complete a series of integrity assessments, including seismic modeling given the Company’s facilities are located within two seismic zones, and groundwater monitoring studies to determine the remaining service life of the ponds and whether a pond must be retrofitted with liners or closed in place, with bottom ash handling conversions completed. In late 2015, using general utility industry data, the Company prepared cost estimates for the retirement of the ash ponds at the end of their useful lives, based on its interpretation of the closure alternatives contemplated in the final rule. The resulting estimates ranged from approximately $35 million to $80 million . These estimates contemplated final capping and monitoring costs of the ponds at both F.B. Culley and A.B. Brown generating stations. These rules are not applicable to the Company's Warrick generating unit, as this unit has historically been part of a larger generating station that predominantly serves an adjacent industrial facility. In March 2018, the Company posted to its public website a first report of preliminary groundwater monitoring data in accordance with the requirements of the CCR rule. This data preliminarily suggests potential groundwater impacts very close to the Company's ash impoundments, and further analysis is ongoing; however, at this time the Company does not believe that there are any impacts to public or private drinking water sources. Since 2015, the Company continues to refine site specific estimates and now estimates the costs to be in the range of $45 million to $135 million . Significant factors impacting the resulting cost estimates include the closure time frame and the method of closure. Current estimates contemplate complete removal under the assumption of beneficial reuse of the ash at A.B. Brown, as well as implications of the Company’s generation transition plan. Ongoing analysis, the continued refinement of assumptions, or the inability to beneficially reuse the ash, either from a technological or economical perspective, could result in estimated costs in excess of the current range. As of March 31, 2018 , the Company has recorded an approximate $40 million asset retirement obligation (ARO). The recorded ARO reflects the present value of the approximate $45 million in estimated costs in the range above. These assumptions and estimations are subject to change in the future and could materially impact the amount of the estimated ARO. In order to maintain current operations of the ponds, the Company spent approximately $17 million on the reinforcement of the ash pond dams and other operational changes in 2016 to meet the more stringent 2,500 year seismic event structural and safety standard in the CCR rule. Effluent Limitation Guidelines (ELG) Under the Clean Water Act, the EPA sets technology-based guidelines for water discharges from new and existing electric generation facilities. In September 2015, the EPA finalized revisions to the existing steam electric ELG setting stringent technology-based water discharge limits for the electric power industry. The EPA focused this rulemaking on wastewater generated primarily by pollution control equipment necessitated by the comprehensive air regulations, specifically setting strict water discharge limits for arsenic, mercury and selenium for scrubber waste waters. The ELG will be implemented when existing water discharge permits for the plants are renewed, with compliance activities expected to commence where operations continue, within the 2018-2023 time frame. The ELG work in tandem with the aforementioned CCR requirements, effectively prohibiting the use of less costly lined sediment basin options for disposal of coal combustion residuals, and virtually mandate conversions to dry bottom ash handling. At the time of ELG finalization, the wastewater discharge permit for the A.B. Brown power plant had an expiration date of October 2016 and, for the F.B. Culley plant, a date of December 2016, and final renewals were issued by the Indiana Department of Environmental Management (IDEM) in February 2017 and March 2017, respectively. As part of the permit renewals, the Company requested alternate compliance dates for ELG, which were approved by IDEM. For plants identified in the Company’s IRP to be retired prior to December 31, 2023, the Company has requested those plants would not require new treatment technology, which was approved by IDEM provided the Company notifies IDEM within one year of issuance of the renewal of its intent to retire the unit. For the F.B. Culley 3 plant, the Company requested a 2020 compliance date for dry bottom ash and 2023 compliance date for flue gas desulfurization wastewater, which was approved by IDEM and finalized in the permit renewal. Discussion of these environmental investments at the F.B. Culley 3 plant is included in the generation transition plan in Note 13. On April 13, 2017, as part of the Administration's regulatory reform initiative, which is focused on the number and nature of regulations, the EPA granted petitions to reconsider the ELG rule, and indicated it would stay the current implementation deadlines in the rule during the pendency of the reconsideration. The EPA has also sought a stay of the current judicial review litigation in federal district court. The court has yet to grant the indefinite stay sought by EPA, and instead placed the parties on a periodic status update schedule. On September 13, 2017, EPA finalized a rule postponing certain interim compliance dates by two years, but did not postpone the final compliance deadline of December 31, 2023. As the Company does not currently have short-term ELG implementation deadlines in its recently renewed wastewater discharge permits, the Company does not anticipate immediate impacts from the EPA’s two-year extension of preliminary implementation deadlines due to the longer compliance time frames granted by IDEM, and will continue to work with IDEM to evaluate further implementation plans. Moreover, the Company believes the two year extension of the ELG preliminary implementation deadlines and reconsideration process does not impact its generation transition plan as modeled in the IRP because the final compliance deadline of December 31, 2023 is still in place and enhanced wastewater treatment for scrubber discharge water will still be required by a reconsidered ELG rule even if the EPA revises stringency levels. Cooling Water Intake Structures Section 316(b) of the Clean Water Act requires 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 that IDEM conduct a 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. The Company is currently undertaking the required ecological studies and anticipates timely compliance in 2021-2022. To comply, the Company believes capital investments will likely be in the range of $4 million to $8 million . Air Quality 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 within the range of 65 to 70 ppb. On October 1, 2015, the EPA finalized a new NAAQS for ozone at the high end of the range, or 70 ppb. On September 16, 2016, Indiana submitted its initial determination to the EPA recommending counties in southwest Indiana, specifically Vanderburgh, Posey and Warrick, be declared in attainment of the new more stringent ozone standard based upon air monitoring data from 2014-2016. In November 2017, EPA finalized its designations of Vanderburgh, Posey, and Warrick counties as being in attainment with the current 70 ppb standard. One Hour SO2 NAAQS On February 16, 2016, the EPA notified states of the commencement of a 120 day consultation period between IDEM and the EPA with respect to the EPA's recommendations for new non-attainment designations for the 2010 One Hour SO2 NAAQS. Identified on the list was Posey County, Indiana, where the Company's A.B. Brown Generating Station is located. While the Company is in compliance with all applicable SO2 limits in its permits, the Company reached an agreement with IDEM on voluntary measures the Company was able to implement without significant incremental costs to ensure Posey County remains in attainment with the 2010 One Hour SO2 NAAQS. The Company's coal-fired generating fleet is 100 percent scrubbed for SO2 and 90 percent controlled for NOx. Climate Change and Carbon Strategy On August 3, 2015, the EPA released its final Clean Power Plan rule (CPP) which required a 32 percent reduction in carbon emissions from 2005 levels. This would result in a final emission rate goal for Indiana of 1,242 lb CO2/MWh to be achieved by 2030 and implemented through a state implementation plan. The final rule was published in the Federal Register on October 23, 2015, and that action was immediately followed by litigation initiated by Indiana and 23 other states as a coalition challenging the rule. In January 2016, the reviewing court denied the states’ and other parties requests to stay the implementation of the CPP pending completion of judicial review. On January 26, 2016, 29 states and state agencies, including the 24 state coalition referenced above, filed a request for immediate stay of implementation of the rule with the U.S. Supreme Court. On February 9, 2016, the U.S. Supreme Court granted the stay request to delay the implementation of the regulation while being challenged in court. Oral argument was held in September 2016. The stay will remain in place while the lower court concludes its review. In March 2017, as part of the ongoing regulatory reform efforts of the Administration, the EPA filed a motion with the U.S. Court of Appeals for the District of Columbia circuit to suspend litigation pending the EPA’s reconsideration of the CPP rule, which was granted on April 28, 2017. Moreover, as indicated above, in October 2017, EPA published its proposal to repeal the CPP. Comments to the repeal proposal were due in April 2018. EPA's repeal proposal was quickly followed by an advanced notice of proposed rulemaking intended to solicit public comments on issues related to formulating a CPP replacement rule, which were similarly due in April 2018. Repeal without replacement of the CPP could create potential litigation risk arising from the absence of direct federal regulation in this area that courts have previously determined preempt common law nuisance claims. Impact of Legislative Actions & Other Initiatives At this time, compliance costs and other effects associated with reductions in GHG emissions or obtaining renewable energy sources remain uncertain. However, Vectren's generation transition plan, as set forth in its electric generation and compliance filing, will achieve 60 percent reductions in 2005 GHG emission levels by 2025, positioning the Company to comply with future regulatory or legislative actions with respect to mandatory GHG reductions. In addition to the federal programs, the United States and 194 other countries agreed by consensus to limit GHG emissions beginning after 2020 in the 2015 United Nations Framework Convention on Climate Change Paris Agreement. The United States has proposed a 26-28 percent GHG emission reduction from 2005 levels by 2025. The Administration has indicated it intends to withdraw the United States' participation; however the Agreement provides that parties cannot petition to withdraw until November 2019. S ince 2005 through 2017, the Company has achieved reduced emissions of CO2 by an average of 35 percent (on a tonnage basis), and will increase that total to 60 percent at the conclusion of its generation transition plan, well above the 32 percent reduction that would be required under the CPP. While the litigation and the EPA's reconsideration of the CPP rules remains uncertain, the Company will continue to monitor regulatory activity regarding GHG emission standards that may affect its electric generating units. 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 $44.2 million ( $23.9 million at Indiana Gas and $20.3 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 approximately $15.7 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 both March 31, 2018 and December 31, 2017 , approximately $2.5 million of accrued, but not yet spent, costs are included in Other Liabilities related to the Indiana Gas and SIGECO sites.

Impact of Recently Issued Accou

Impact of Recently Issued Accounting Standards	3 Months Ended
	Mar. 31, 2018
Accounting Policies [Abstract]
Impact of Recently Issued Accounting Standards	Impact of Recently Issued Accounting Standards Leases In February 2016, the FASB issued new accounting guidance for the recognition, measurement, presentation and disclosure of leasing arrangements. This ASU requires the recognition of lease assets and liabilities for those leases currently classified as operating leases while also refining the definition of a lease. In addition, lessees will be required to disclose key information about the amount, timing, and uncertainty of cash flows arising from leasing arrangements. This ASU is effective for the interim and annual reporting periods beginning January 1, 2019 and is required to be applied using a modified retrospective approach. In January 2018, the FASB issued amendments to the new lease standard, ASU No. 2018-01, allowing an entity to elect not to assess whether certain land easements are, or contain, leases when transitioning to the new lease standard. The Company is currently evaluating the standard to determine the impact it will have on the financial statements and will adopt the guidance effective January 1, 2019. Other Recently Issued Standards Management believes other recently issued standards, which are not yet effective, will not have a material impact on the Company's financial condition, results of operations, or cash flows upon adoption.

Fair Value Measurements

Fair Value Measurements	3 Months Ended
	Mar. 31, 2018
Fair Value Disclosures [Abstract]
Fair Value Measurements	Fair Value Measurements The carrying values and estimated fair values using primarily Level 2 assumptions of the Company's other financial instruments follow: March 31, 2018 December 31, 2017 (In millions) Carrying Amount Est. Fair Value Carrying Amount Est. Fair Value Long-term debt $ 1,838.5 $ 1,926.1 $ 1,838.7 $ 1,981.2 Short-term borrowings 287.9 287.9 249.5 249.5 Cash & cash equivalents 19.1 19.1 16.6 16.6 Natural gas purchase instrument assets (1) 0.3 0.3 0.5 0.5 Natural gas purchase instrument liabilities (2) 5.1 5.1 4.5 4.5 Interest rate swap assets (3) 0.5 0.5 — — Interest rate swap liabilities (4) — — 1.4 1.4 (1) Presented in "Prepayments & other current assets" for current and "Other utility & corporate investments" for noncurrent on the Condensed Consolidated Balance Sheets (unaudited). (2) Presented in "Accrued liabilities" for current and "Deferred credits & other liabilities" for noncurrent on the Condensed Consolidated Balance Sheets (unaudited). (3) Presented in "Other utility & corporate investments" on the Condensed Consolidated Balance Sheets (unaudited). (4) Presented in "Deferred credits & other liabilities" on the Condensed Consolidated Balance Sheets (unaudited). 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. Accordingly, any reacquisition of this debt would not be expected to have a material effect on the Company's results of operations. The Company’s Indiana gas utilities entered into multiple five -year forward purchase arrangements to fix the price of natural gas for a portion of the Company’s gas supply. These arrangements, approved by the IURC, replaced normal purchase or normal sale long-term physical fixed-price purchases. The Company values these contracts using a pricing model that incorporates market-based information, and are classified within Level 2 of the fair value hierarchy. Gains and losses on these derivative contracts are deferred as regulatory liabilities or assets and are refunded to or collected from customers through the Company’s respective gas cost recovery mechanisms. The Company, through SIGECO, executed forward starting interest rate swaps during 2017 providing that on January 1, 2020, the Company will begin hedging the variability in interest rates on the 2013 Series A, B, and E Notes, through final maturity dates. The Company values these contracts using a pricing model that incorporates market-based information, and are classified within Level 2 of the fair value hierarchy. Regulatory orders require SIGECO to include the impact of its interest rate risk management activities, such as gains and losses arising from these swaps, in its cost of capital utilized in rate cases and other periodic filings. 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, 2018 and December 31, 2017 , the fair value for these financial instruments was not estimated. The carrying value of these investments was $9.6 million at each of March 31, 2018 and December 31, 2017 .

Segment Reporting

Segment Reporting	3 Months Ended
	Mar. 31, 2018
Segment Reporting [Abstract]
Segment Reporting	Segment Reporting The Company segregates its operations into three groups: 1) Utility Group, 2) Nonutility Group, and 3) Corporate and Other. The Utility Group is comprised of Vectren Utility Holdings, Inc.’s operations, which consist of the Company’s regulated operations and other operations that provide information technology and other support services to those regulated operations. The Company segregates its regulated operations between a Gas Utility Services operating segment and an Electric Utility Services operating segment. The Gas Utility Services segment provides natural gas distribution and transportation services to nearly two-thirds of Indiana and to west-central Ohio. The Electric Utility Services segment provides electric distribution services primarily to southwestern Indiana, and includes the Company’s power generating and wholesale power operations. Regulated operations supply natural gas and/or electricity to over one million customers. In total, the Utility Group is comprised of three operating segments: Gas Utility Services, Electric Utility Services, and Other Utility Operations. The Nonutility Group reports the following segments: Infrastructure Services, Energy Services, and Other Nonutility Businesses. The Infrastructure Services segment, through wholly owned subsidiaries Miller Pipeline, LLC and Minnesota Limited, LLC, provides underground pipeline construction and repair services for customers that include Vectren Utility Holdings' utilities. Fees incurred by Vectren Utility Holdings and its subsidiaries for these pipeline construction and repair services totaled $24.6 million and $25.8 million for the three months ended March 31, 2018 and 2017 , respectively. Energy Services, through the wholly owned subsidiary Energy Systems Group, LLC, provides energy performance contracting and sustainable infrastructure, such as renewables, distributed generation, and combined heat and power projects. Corporate and Other includes unallocated corporate expenses such as advertising and certain charitable contributions, among other activities, that benefit the Company’s other operating segments. 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) 2018 2017 Revenues Utility Group Gas Utility Services $ 329.3 $ 292.8 Electric Utility Services 134.0 132.1 Other Operations 11.8 11.4 Eliminations (11.7 ) (11.3 ) Total Utility Group 463.4 425.0 Nonutility Group Infrastructure Services 135.3 147.3 Energy Services 60.6 52.8 Total Nonutility Group 195.9 200.1 Corporate & Other Group 0.1 0.1 Eliminations (1.0 ) (0.7 ) Consolidated Revenues $ 658.4 $ 624.5 Profitability Measure - Net Income Utility Group Net Income Gas Utility Services $ 56.0 $ 47.9 Electric Utility Services 14.0 13.7 Other Operations 4.3 4.3 Utility Group Net Income 74.3 65.9 Nonutility Group Net Income (Loss) Infrastructure Services (15.8 ) (9.3 ) Energy Services 5.5 (1.2 ) Other Nonutility Businesses (0.3 ) — Nonutility Group Net Income (Loss) (10.6 ) (10.5 ) Corporate & Other Group Net Income (Loss) (0.2 ) — Consolidated Net Income $ 63.5 $ 55.4

Impact of Recently Issued Acc23

Impact of Recently Issued Accounting Standards Impact of Recently Issued Accounting Standards (Policies)	3 Months Ended
	Mar. 31, 2018
Accounting Policies [Abstract]
Recently Issued Accounting Policies	Leases In February 2016, the FASB issued new accounting guidance for the recognition, measurement, presentation and disclosure of leasing arrangements. This ASU requires the recognition of lease assets and liabilities for those leases currently classified as operating leases while also refining the definition of a lease. In addition, lessees will be required to disclose key information about the amount, timing, and uncertainty of cash flows arising from leasing arrangements. This ASU is effective for the interim and annual reporting periods beginning January 1, 2019 and is required to be applied using a modified retrospective approach. In January 2018, the FASB issued amendments to the new lease standard, ASU No. 2018-01, allowing an entity to elect not to assess whether certain land easements are, or contain, leases when transitioning to the new lease standard. The Company is currently evaluating the standard to determine the impact it will have on the financial statements and will adopt the guidance effective January 1, 2019. Other Recently Issued Standards Management believes other recently issued standards, which are not yet effective, will not have a material impact on the Company's financial condition, results of operations, or cash flows upon adoption.

Revenue (Tables)

Revenue (Tables)	3 Months Ended
	Mar. 31, 2018
Revenue from Contract with Customer [Abstract]
Schedule of New Accounting Pronouncements	The cumulative effect of the changes made to the Company's consolidated January 1, 2018 balance sheet for the adoption of the new revenue standard is as follows: Balance Sheet (In millions) Balance at December 31, 2017 Adjustments due to ASC 606 Balance at January 1, 2018 Assets Accrued unbilled revenues $ 207.1 $ (7.0 ) $ 200.1 Prepayments and other current assets 47.0 5.6 52.6 Liabilities Accrued liabilities 222.3 (0.3 ) 222.0 Common Shareholders’ Equity Retained earnings $ 1,113.7 $ (1.1 ) $ 1,112.6
Disaggregation of Revenue	In the following table, Utility Group revenue is disaggregated by customer class. (In millions) Three Months Ended March 31, 2018 Gas Utility Services Residential $ 219.7 Commercial 82.6 Industrial 23.8 Other 3.2 Total Gas Utility Services $ 329.3 Electric Utility Services Residential $ 49.7 Commercial 34.5 Industrial 37.3 Other 12.5 Total Electric Utility Services $ 134.0 The following table disaggregates Energy Services revenue by type of performance obligation: (In millions) Three Months Ended March 31, 2018 Revenue Construction $ 53.7 Operations and Maintenance and other 6.9 Total Energy Services $ 60.6 The following table disaggregates Infrastructure Services revenue by type of contract and timing of transfer of control: (In millions) Three Months Ended March 31, 2018 Revenue Unit or time and material (point in time) $ 124.4 Fixed price (over time) 10.9 Total Infrastructure Services $ 135.3
Summary of Contract Liabilities	The opening and closing balances of the Company's accounts receivable, accrued unbilled revenue, and contract liabilities are as follows: (In millions) Accounts Receivable Accrued Unbilled Revenues Contract Liabilities Opening (01/01/2018) $ 262.9 $ 200.1 $ 38.3 Closing (03/31/2018) 237.1 146.5 35.6 Increase/(decrease) $ (25.8 ) $ (53.6 ) $ (2.7 )
Summary of Remaining Performance Obligations	The table below discloses (1) the aggregate amount of the transaction price allocated to performance obligations that are unsatisfied (or partially unsatisfied) as of the end of the reporting period for contracts and (2) when the company expects to recognize this revenue. Such contracts include both construction and operations and maintenance performance obligations from the Energy Services segment and fixed price contracts in the Infrastructure Services segment. (In millions) Rolling 12 Months Thereafter Total Revenue expected to be recognized on contracts in place as of March 31, 2018: Energy Services - operations and maintenance $ 24.2 $ 380.6 $ 404.8 Energy Services - construction 179.1 14.2 193.3 Infrastructure Services - fixed price (bid) 258.4 — 258.4 Total $ 461.7 $ 394.8 $ 856.5

Earnings Per Share (Tables)

Earnings Per Share (Tables)	3 Months Ended
	Mar. 31, 2018
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) 2018 2017 Numerator: Reported net income (Numerator for Basic and Diluted EPS) $ 63.5 $ 55.4 Denominator: Weighted-average common shares outstanding (Denominator for Basic and Diluted EPS) 83.1 82.9 Basic and Diluted EPS $ 0.76 $ 0.67

Retirement Plans & Other Post26

Retirement Plans & Other Postretirement Benefits (Tables)	3 Months Ended
	Mar. 31, 2018
Pension and Other Postretirement Benefits Cost (Reversal of Cost) [Abstract]
Summary of 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) 2018 2017 2018 2017 Service cost $ 1.7 $ 1.6 $ — $ — Interest cost 3.2 3.5 0.3 0.4 Expected return on plan assets (5.3 ) (5.3 ) — — Amortization of prior service cost 0.1 0.1 (0.5 ) (0.6 ) Amortization of actuarial loss 2.1 1.9 — — Net periodic cost (benefit) $ 1.8 $ 1.8 $ (0.2 ) $ (0.2 )

Investment in ProLiance Holdi27

Investment in ProLiance Holdings, LLC (Tables)	3 Months Ended
	Mar. 31, 2018
Equity Method Investments and Joint Ventures [Abstract]
Summarized Financial Information of Equity Investment	The Company's remaining investment at March 31, 2018 , shown at its 61 percent ownership share of the individual net assets of ProLiance, is as follows. (In millions) As of March 31, 2018 Cash $ 0.7 Investment in LA Storage 22.4 Total investment in ProLiance $ 23.1 Included in: Investments in unconsolidated affiliates $ 18.7 Other nonutility investments $ 4.4

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	3 Months Ended
	Mar. 31, 2018
Fair Value Disclosures [Abstract]
Fair Value By Balance Sheet Grouping	The carrying values and estimated fair values using primarily Level 2 assumptions of the Company's other financial instruments follow: March 31, 2018 December 31, 2017 (In millions) Carrying Amount Est. Fair Value Carrying Amount Est. Fair Value Long-term debt $ 1,838.5 $ 1,926.1 $ 1,838.7 $ 1,981.2 Short-term borrowings 287.9 287.9 249.5 249.5 Cash & cash equivalents 19.1 19.1 16.6 16.6 Natural gas purchase instrument assets (1) 0.3 0.3 0.5 0.5 Natural gas purchase instrument liabilities (2) 5.1 5.1 4.5 4.5 Interest rate swap assets (3) 0.5 0.5 — — Interest rate swap liabilities (4) — — 1.4 1.4 (1) Presented in "Prepayments & other current assets" for current and "Other utility & corporate investments" for noncurrent on the Condensed Consolidated Balance Sheets (unaudited). (2) Presented in "Accrued liabilities" for current and "Deferred credits & other liabilities" for noncurrent on the Condensed Consolidated Balance Sheets (unaudited). (3) Presented in "Other utility & corporate investments" on the Condensed Consolidated Balance Sheets (unaudited). (4) Presented in "Deferred credits & other liabilities" on the Condensed Consolidated Balance Sheets (unaudited).

Segment Reporting (Tables)

Segment Reporting (Tables)	3 Months Ended
	Mar. 31, 2018
Segment Reporting [Abstract]
Schedule of Segment Reporting	Information related to the Company’s reportable segments is summarized as follows: Three Months Ended March 31, (In millions) 2018 2017 Revenues Utility Group Gas Utility Services $ 329.3 $ 292.8 Electric Utility Services 134.0 132.1 Other Operations 11.8 11.4 Eliminations (11.7 ) (11.3 ) Total Utility Group 463.4 425.0 Nonutility Group Infrastructure Services 135.3 147.3 Energy Services 60.6 52.8 Total Nonutility Group 195.9 200.1 Corporate & Other Group 0.1 0.1 Eliminations (1.0 ) (0.7 ) Consolidated Revenues $ 658.4 $ 624.5 Profitability Measure - Net Income Utility Group Net Income Gas Utility Services $ 56.0 $ 47.9 Electric Utility Services 14.0 13.7 Other Operations 4.3 4.3 Utility Group Net Income 74.3 65.9 Nonutility Group Net Income (Loss) Infrastructure Services (15.8 ) (9.3 ) Energy Services 5.5 (1.2 ) Other Nonutility Businesses (0.3 ) — Nonutility Group Net Income (Loss) (10.6 ) (10.5 ) Corporate & Other Group Net Income (Loss) (0.2 ) — Consolidated Net Income $ 63.5 $ 55.4

Organization and Nature of Op30

Organization and Nature of Operations (Details) $ / shares in Units, customer in Thousands, $ in Millions	3 Months Ended
	Mar. 31, 2018customerbusiness_areapublic_utility	Apr. 21, 2018USD ($)$ / shares
Public Utilities, General Disclosures [Line Items]
Public utilities subsidiaries owned by wholly owned subsidiary | public_utility	3
Number of primary business areas | business_area	2
Vectren Corp And CenterPoint Energy, Inc. Merger | Subsequent Event
Public Utilities, General Disclosures [Line Items]
Business merger, cash received per share (in dollars per share) | $ / shares		$ 72
Business merger, termination fees | $		$ 150
CenterPoint Energy, Inc. [Member] | Vectren Corp And CenterPoint Energy, Inc. Merger | Subsequent Event
Public Utilities, General Disclosures [Line Items]
Business merger, termination fees | $		$ 210
INDIANA | Natural Gas Customers | Indiana Gas
Public Utilities, General Disclosures [Line Items]
Approximate number of customers	603
INDIANA | Natural Gas Customers | SIGECO
Public Utilities, General Disclosures [Line Items]
Approximate number of customers	112
INDIANA | Electric Customers | SIGECO
Public Utilities, General Disclosures [Line Items]
Approximate number of customers	146
OHIO | Natural Gas Customers | VEDO
Public Utilities, General Disclosures [Line Items]
Approximate number of customers	323

Revenue - Additional Informatio

Revenue - Additional Information (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Jan. 01, 2018
Disaggregation of Revenue [Line Items]
Reduction to retained earnings	$ (1,138.8)		$ (1,112.6)
Net income	63.5	$ 55.4
Contract with customer, liability, revenue recognized	26.3
Accounting Standards Update 2014-09
Disaggregation of Revenue [Line Items]
Net income	$ 1
Accounting Standards Update 2014-09 | Difference between Revenue Guidance in Effect before and after Topic 606
Disaggregation of Revenue [Line Items]
Reduction to retained earnings			$ 1.1

Revenue - Cumulative Effect Of

Revenue - Cumulative Effect Of Changes Due To Adoption Of New Revenue Standard(Details) - USD ($) $ in Millions	Mar. 31, 2018	Jan. 01, 2018	Dec. 31, 2017
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Accrued unbilled revenues	$ 146.5	$ 200.1
Prepayments & other current assets	27.9	52.6
Accrued liabilities	216.9	222
Retained earnings	$ 1,138.8	1,112.6
Calculated under Revenue Guidance in Effect before Topic 606
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Accrued unbilled revenues			$ 207.1
Prepayments & other current assets			47
Accrued liabilities			222.3
Retained earnings			$ 1,113.7
Accounting Standards Update 2014-09 | Difference between Revenue Guidance in Effect before and after Topic 606
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Accrued unbilled revenues		(7)
Prepayments & other current assets		5.6
Accrued liabilities		(0.3)
Retained earnings		$ (1.1)

Revenue - Utility Services Reve

Revenue - Utility Services Revenue (Details) - Operating Segments - Utility Group $ in Millions	3 Months Ended
	Mar. 31, 2018USD ($)
Gas Utility Services
Disaggregation of Revenue [Line Items]
Revenue from contract with customers	$ 329.3
Gas Utility Services | Residential
Disaggregation of Revenue [Line Items]
Revenue from contract with customers	219.7
Gas Utility Services | Commercial
Disaggregation of Revenue [Line Items]
Revenue from contract with customers	82.6
Gas Utility Services | Industrial
Disaggregation of Revenue [Line Items]
Revenue from contract with customers	23.8
Gas Utility Services | Other
Disaggregation of Revenue [Line Items]
Revenue from contract with customers	3.2
Electric Utility Services
Disaggregation of Revenue [Line Items]
Revenue from contract with customers	134
Electric Utility Services | Residential
Disaggregation of Revenue [Line Items]
Revenue from contract with customers	49.7
Electric Utility Services | Commercial
Disaggregation of Revenue [Line Items]
Revenue from contract with customers	34.5
Electric Utility Services | Industrial
Disaggregation of Revenue [Line Items]
Revenue from contract with customers	37.3
Electric Utility Services | Other
Disaggregation of Revenue [Line Items]
Revenue from contract with customers	$ 12.5

Revenue - Infrastructure Servic

Revenue - Infrastructure Services Revenue (Details) - Nonutility Group - Infrastructure Services - Operating Segments $ in Millions	3 Months Ended
	Mar. 31, 2018USD ($)
Disaggregation of Revenue [Line Items]
Revenue from contract with customers	$ 135.3
Unit or time and material (point in time)
Disaggregation of Revenue [Line Items]
Revenue from contract with customers	124.4
Fixed price (over time)
Disaggregation of Revenue [Line Items]
Revenue from contract with customers	$ 10.9

Revenue - Energy Services Reven

Revenue - Energy Services Revenue (Details) - Operating Segments - Energy Services - Nonutility Group $ in Millions	3 Months Ended
	Mar. 31, 2018USD ($)
Disaggregation of Revenue [Line Items]
Revenue from contract with customers	$ 60.6
Construction
Disaggregation of Revenue [Line Items]
Revenue from contract with customers	53.7
Operations and Maintenance and other
Disaggregation of Revenue [Line Items]
Revenue from contract with customers	$ 6.9

Revenue - Contract Liabilities

Revenue - Contract Liabilities (Details) - USD ($)	3 Months Ended
	Mar. 31, 2018	Jan. 01, 2018
Revenue from Contract with Customer [Abstract]
Contract assets	$ 0	$ 0
Accounts Receivable
Opening (01/01/2018)	262,900,000
Increase (decrease) in accounts receivable	(25,800,000)
Closing (03/31/2018)	237,100,000
Accrued Unbilled Revenues
Opening (01/01/2018)	200,100,000
Increase (decrease) in accrued unbilled revenues	(53,600,000)
Closing (03/31/2018)	146,500,000
Contract Liabilities
Opening (01/01/2018)	38,300,000
Increase (decrease) in contract liability	(2,700,000)
Closing (03/31/2018)	$ 35,600,000

Revenue - Remaining Performance

Revenue - Remaining Performance Obligation (Details) $ in Millions	3 Months Ended
	Mar. 31, 2018USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2018-04-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligation	$ 461.7
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2018-04-01 | Energy Services - operations and maintenance
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligation	$ 24.2
Remaining performance obligation period	12 months
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2018-04-01 | Energy Services - construction
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligation	$ 179.1
Remaining performance obligation period	12 months
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2018-04-01 | Infrastructure Services - fixed price (bid)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligation	$ 258.4
Remaining performance obligation period	12 months
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-04-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligation	$ 394.8
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-04-01 | Energy Services - operations and maintenance
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligation	380.6
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-04-01 | Energy Services - construction
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligation	14.2
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-04-01 | Infrastructure Services - fixed price (bid)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligation	0
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: (nil)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligation	856.5
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: (nil) | Energy Services - operations and maintenance
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligation	$ 404.8
Remaining performance obligation period
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: (nil) | Energy Services - construction
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligation	$ 193.3
Remaining performance obligation period
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: (nil) | Infrastructure Services - fixed price (bid)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligation	$ 258.4
Remaining performance obligation period

Earnings Per Share (Details)

Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Numerator:
Reported net income (Numerator for Basic and Diluted EPS)	$ 63.5	$ 55.4
Denominator:
Weighted-average common shares outstanding (in dollars per share)	83.1	82.9
Basic and Diluted EPS (in dollars per share)	$ 0.76	$ 0.67

Excise & Utility Receipts Tax39

Excise & Utility Receipts Taxes (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Excise and Utility Receipts Taxes [Abstract]
Excise and utility receipts taxes billed to customers	$ 10.5	$ 9.4

Retirement Plans & Other Post40

Retirement Plans & Other Postretirement Benefits - Additional Information (Details) $ in Millions	3 Months Ended
	Mar. 31, 2018USD ($)pension_plan
Pension and Other Postretirement Benefits Cost (Reversal of Cost) [Abstract]
Number of qualified defined benefit pension plans | pension_plan	3
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Employer contribution to qualified pension plans | $	$ 3.5

Retirement Plans & Other Post41

Retirement Plans & Other Postretirement Benefits - Net Periodic Benefit Costs (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Pension Benefits
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service cost	$ 1.7	$ 1.6
Interest cost	3.2	3.5
Expected return on plan assets	(5.3)	(5.3)
Amortization of prior service cost	0.1	0.1
Amortization of actuarial loss	2.1	1.9
Net periodic cost (benefit)	1.8	1.8
Other Benefits
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service cost	0	0
Interest cost	0.3	0.4
Expected return on plan assets	0	0
Amortization of prior service cost	(0.5)	(0.6)
Amortization of actuarial loss	0	0
Net periodic cost (benefit)	$ (0.2)	$ (0.2)

Supplemental Cash Flow Inform42

Supplemental Cash Flow Information (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2018	Dec. 31, 2017
Supplemental Cash Flow Information [Abstract]
Accruals related to utility and nonutility plant purchases	$ 26.9	$ 28.6

Investment in ProLiance Holdi43

Investment in ProLiance Holdings, LLC (Details) $ in Millions	Mar. 31, 2018USD ($)cavernBcf	Dec. 31, 2017USD ($)
Schedule of Equity Method Investments [Line Items]
Ownership share (as a percent)	61.00%
Voting rights (as a percent)	50.00%
Summarized balance sheet information [Abstract]
Investment in Proliance	$ 19.6	$ 19.7
FERC certified caverns, fully tested with additional work to further develop | cavern	3
FERC certified caverns | cavern	4
Proliance Holdings LLC
Summarized balance sheet information [Abstract]
Cash	$ 0.7
Investment in LA Storage	22.4
Total investment in ProLiance	$ 23.1
LA Storage
Summarized balance sheet information [Abstract]
Ownership interest (as a percent)	100.00%
Storage capacity | Bcf	12
LA Storage | Proliance Holdings LLC
Summarized balance sheet information [Abstract]
Investment in joint venture	$ 36.7	$ 36.8
LA Storage | Affiliated Entity
Schedule of Equity Method Investments [Line Items]
Ownership share (as a percent)	25.00%
Investments in unconsolidated affiliates | Proliance Holdings LLC
Summarized balance sheet information [Abstract]
Investment in Proliance	$ 18.7
Other nonutility investments | Proliance Holdings LLC
Summarized balance sheet information [Abstract]
Investment in Proliance	$ 4.4
Maximum | LA Storage
Summarized balance sheet information [Abstract]
Storage capacity | Bcf	19
Minimum | LA Storage
Summarized balance sheet information [Abstract]
Storage capacity | Bcf	12

Financing Activities (Details)

Financing Activities (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	May 01, 2018	Mar. 01, 2018
Mortgages | SIGECO | Series A Notes Due March 2038
Line of Credit Facility [Line Items]
Bonds callable or called			$ 22.2
Interest rate			4.00%
Mortgages | SIGECO | Series B Notes Due May 2043 | Subsequent Event
Line of Credit Facility [Line Items]
Bonds callable or called		$ 39.6
Interest rate		4.05%
Variable Rate Tax-Exempt Bonds | SIGECO
Line of Credit Facility [Line Items]
Long term debt, gross	$ 152
Variable Rate Tax-Exempt Bonds | SIGECO | 2013 Series C Notes due 2022
Line of Credit Facility [Line Items]
Long term debt, gross	4.6
Variable Rate Tax-Exempt Bonds | SIGECO | 2013 Series D Notes due 2024
Line of Credit Facility [Line Items]
Long term debt, gross	22.5
Variable Rate Tax-Exempt Bonds | SIGECO | 2013 Series E Notes due 2037
Line of Credit Facility [Line Items]
Long term debt, gross	22
Variable Rate Tax-Exempt Bonds | SIGECO | 2014 Series B Notes Due 2025
Line of Credit Facility [Line Items]
Long term debt, gross	$ 41.3
Senior Notes
Line of Credit Facility [Line Items]
Redemption price percent	100.00%
Senior Notes | Utility Holdings
Line of Credit Facility [Line Items]
Senior notes, face amount	$ 1,025
Senior Notes | Vectren Capital Corp
Line of Credit Facility [Line Items]
Senior notes, face amount	$ 260

Commitments & Contingencies (De

Commitments & Contingencies (Details)	3 Months Ended
	Mar. 31, 2018USD ($)surety_bond
Performance Guarantees and Product Warranties [Abstract]
Warranty liability recognized	$ 0
Letters of credit outstanding	$ 22,300,000
Firm purchase commitment term one	5 years
Firm purchase commitment term two	20 years
Energy Systems Group
Performance Guarantees and Product Warranties [Abstract]
Maximum exposure by parent company on guarantees	$ 388,000,000
Energy Systems Group | Performance Guarantee
Performance Guarantees and Product Warranties [Abstract]
Number of surety bonds open to support future performance | surety_bond	55
Face amount of surety bonds outstanding	$ 11,200,000
Work yet to be completed on surety bond projects (as a percent)	25.00%
Period for release of significant portion of surety bonds	1 year
Energy Systems Group | Performance Guarantee | Maximum
Performance Guarantees and Product Warranties [Abstract]
Face amount of surety bonds outstanding	$ 75,900,000

Gas Rate & Regulatory Matters (

Gas Rate & Regulatory Matters (Details) - USD ($)	Mar. 30, 2018	Jan. 24, 2018	Aug. 03, 2017	Aug. 31, 2014	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017	Dec. 31, 2016
Public Utilities, General Disclosures [Line Items]
Regulatory assets					$ 418,800,000		$ 416,800,000
Other income – net					9,000,000	$ 8,000,000
INDIANA | Indiana Recovery and Deferral Mechanisms
Public Utilities, General Disclosures [Line Items]
Length of project plan required for recovery under new legislation				7 years
INDIANA | Senate Bill 251 and 560
Public Utilities, General Disclosures [Line Items]
Regulatory assets					78,800,000		78,000,000
Project spend life to date		$ 482,000,000
Capital expenditures under plan		$ 995,000,000
INDIANA | Senate Bill 251
Public Utilities, General Disclosures [Line Items]
Operating expenses			$ 15,000,000
Capital investments			$ 17,000,000
Recovery period beginning in 2018			4 years
OHIO | Ohio Recovery and Deferral Mechanisms
Public Utilities, General Disclosures [Line Items]
Regulatory assets					32,900,000		31,200,000
Payments for capital improvements							326,500,000	$ 261,100,000
OHIO | Ohio House Bill 95
Public Utilities, General Disclosures [Line Items]
Bill impact per customer per month					1.50
Other income – net					$ 73,700,000		$ 66,100,000
Increase in base rates and charges	$ 34,000,000
Period to recover costs of capital investments	10 years

Electric Rate & Regulatory Ma47

Electric Rate & Regulatory Matters (Details) $ in Millions

Feb. 20, 2018USD ($)MW

Jun. 13, 2017

Mar. 07, 2017

Apr. 30, 2017USD ($)

Mar. 31, 2018USD ($)

Mar. 31, 2017USD ($)

Oct. 31, 2017USD ($)

Dec. 31, 2017USD ($)

Aug. 30, 2017USD ($)projectMW

Sep. 28, 2016

Jun. 30, 2016

Jan. 06, 2015

Nov. 12, 2013

Public Utilities, General Disclosures [Line Items]

Investment under plan

$ 7.1

Number of solar projects filed for authority to recover costs | project

3

Additional solar generation resulting from project | MW

4

Additional battery storage resources resulting from project | MW

1

Estimated cost of equipment to comply with MATS

$ 14

Estimated cost of equipment required by the NOV

5.1

SIGECO Electric Demand Side Management Program Filing [Abstract]

Estimated Average Measure Life Of Lost Margin Recovery Plan

9 years

Electric utility revenue

134

$ 132.1

FERC Return On Equity Complaints [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%

FERC authorized base ROE percentage for first refund period

10.32%

FERC authorized base ROE percentage for second refund period

9.70%

FERC authorized incentive ROE percentage for first refund period

0.50%

Gross investment in qualifying projects

157.7

Net plant balance for qualifying projects

132.6

Electric Modernization Program - SB 560

Public Utilities, General Disclosures [Line Items]

Requested recovery in rates of investments

$ 31

Regulatory assets

4.5

$ 4.3

Renewable Generation - SB 29

Public Utilities, General Disclosures [Line Items]

Estimated cost of project

$ 16

SIGECO Electric Environmental Compliance Filing

Public Utilities, General Disclosures [Line Items]

Amount of capital investments to date in equipment for mercury control

30

Amount of capital investments to date in equipment to control sulfur trioxide emissions

$ 40

Electric Demand Side Management Program

SIGECO Electric Demand Side Management Program Filing [Abstract]

Maximum period for recovery under energy efficiency program

4 years

Electric utility revenue

$ 3.1

$ 3

Electric Generation and Compliance

FERC Return On Equity Complaints [Abstract]

Gas combined cycle generating facility, cost

$ 900

Requested recovery of environmental investments

$ 90

Universal solar energy | MW

50

Electric Generation and Compliance | Minimum

FERC Return On Equity Complaints [Abstract]

Gas combined cycle generating facility | MW

800,000,000

Electric Generation and Compliance | Maximum

FERC Return On Equity Complaints [Abstract]

Gas combined cycle generating facility | MW

900,000,000

Environmental & Sustainabilit48

Environmental & Sustainability Matters (Details) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2018USD ($)lb / MWhunitsiteMW	Dec. 31, 2015USD ($)	Dec. 31, 2017USD ($)
Site Contingency [Line Items]
Number of coal fired units | unit	4
Additional capacity from new plant | MW	700
New renewable generation power | MW	54
Reduction of carbon emissions	60.00%
Emission rate after installation of new technology | lb / MWh	980
Grid modernization costs	$ 450
Coal Ash Waste Disposal, Ash Ponds and Water [Abstract]
Estimated spend for ash pond dam reinforcement and other operational changes			$ 17
Notification period of issuance of the renewal of its intent to retire a unit	1 year
Air Quality [Abstract]
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%
Climate Changes [Abstract]
Reduction of carbon dioxide emissions			35.00%
Manufactured Gas Plants
Cumulative costs recorded	$ 44.2
Accrued costs included in Other Liabilities	$ 2.5		$ 2.5
Indiana Gas
Manufactured Gas Plants
Number of sites identified with potential remedial responsibility for entity (in number of sites) | site	26
Cumulative costs recorded	$ 23.9
Insurance coverage, amount received	$ 20.8
SIGECO
Manufactured Gas Plants
Number of sites identified with potential remedial responsibility for entity (in number of sites) | site	5
Cumulative costs recorded	$ 20.3
Insurance coverage, amount received	15.7
Total estimated insurance recoveries	15.8
Ash Ponds | SIGECO
Coal Ash Waste Disposal, Ash Ponds and Water [Abstract]
Asset retirement obligation (ARO)	40
Minimum
Coal Ash Waste Disposal, Ash Ponds and Water [Abstract]
Estimated capital expenditures to comply with Ash Pond and Coal Ash disposal regulations		$ 35
Ash Pond and Coal Ash Disposal Exit Costs Revised Anticipated Cost	45
Estimated capital expenditures to comply with Clean Water Act	4
Maximum
Coal Ash Waste Disposal, Ash Ponds and Water [Abstract]
Estimated capital expenditures to comply with Ash Pond and Coal Ash disposal regulations		$ 80
Ash Pond and Coal Ash Disposal Exit Costs Revised Anticipated Cost	135
Estimated capital expenditures to comply with Clean Water Act	$ 8

Fair Value Measurements (Detail

Fair Value Measurements (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Dec. 31, 2017
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Value of investments not practical to estimate fair value	$ 9.6	$ 9.6
Forward Contracts
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Forward purchase arrangements, term	5 years
Carrying Amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	$ 1,838.5	1,838.7
Short-term borrowings	287.9	249.5
Cash & cash equivalents	19.1	16.6
Natural gas purchase instrument assets	0.3	0.5
Natural gas purchase instrument liabilities	5.1	4.5
Interest rate swap assets	0.5	0
Interest rate swap liabilities	0	1.4
Est. Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	1,926.1	1,981.2
Short-term borrowings	287.9	249.5
Cash & cash equivalents	19.1	16.6
Natural gas purchase instrument assets	0.3	0.5
Natural gas purchase instrument liabilities	5.1	4.5
Interest rate swap assets	0.5	0
Interest rate swap liabilities	$ 0	$ 1.4

Segment Reporting - Additional

Segment Reporting - Additional Information (Details) customer in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2018USD ($)customersegment	Mar. 31, 2017USD ($)
Segment Reporting Information [Line Items]
Number of operational groups	3
Portion of Indiana that is provided natural gas distribution and transportation services by the Gas Utility Services segment (in hundredths)	66.67%
Number of customers (greater than) | customer	1
Utility Group
Segment Reporting Information [Line Items]
Number of operating segments	3
Fees incurred for pipeline construction and repair services | $	$ 24.6	$ 25.8

Segment Reporting - Summary of

Segment Reporting - Summary of Reportable Segments (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Segment Reporting Information [Line Items]
Revenues	$ 658.4	$ 624.5
Net income	63.5	55.4
Utility Group
Segment Reporting Information [Line Items]
Revenues	463.4	425
Operating Segments | Utility Group
Segment Reporting Information [Line Items]
Net income	74.3	65.9
Operating Segments | Utility Group | Gas Utility Services
Segment Reporting Information [Line Items]
Revenues	329.3	292.8
Net income	56	47.9
Operating Segments | Utility Group | Electric Utility Services
Segment Reporting Information [Line Items]
Revenues	134	132.1
Net income	14	13.7
Operating Segments | Utility Group | Other Operations
Segment Reporting Information [Line Items]
Revenues	11.8	11.4
Net income	4.3	4.3
Operating Segments | Nonutility Group
Segment Reporting Information [Line Items]
Revenues	195.9	200.1
Net income	(10.6)	(10.5)
Operating Segments | Nonutility Group | Infrastructure Services
Segment Reporting Information [Line Items]
Revenues	135.3	147.3
Net income	(15.8)	(9.3)
Operating Segments | Nonutility Group | Energy Services
Segment Reporting Information [Line Items]
Revenues	60.6	52.8
Net income	5.5	(1.2)
Operating Segments | Nonutility Group | Other Nonutility Businesses
Segment Reporting Information [Line Items]
Net income	(0.3)	0
Eliminations | Utility Group
Segment Reporting Information [Line Items]
Revenues	(11.7)	(11.3)
Corporate & Other Group
Segment Reporting Information [Line Items]
Revenues	0.1	0.1
Net income	(0.2)	0
Eliminations
Segment Reporting Information [Line Items]
Revenues	$ (1)	$ (0.7)