Vectren Utility 10-K 9 Mar 17 2016 FY Annual report Financial data

Document And Entity Information

Document And Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2016	Feb. 28, 2017	Jun. 30, 2016
Document and Entity Information [Abstract]
Entity Registrant Name	VECTREN UTILITY HOLDINGS INC
Entity Central Index Key	1,129,542
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Document Type	10-K
Document Period End Date	Dec. 31, 2016
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Common Stock, Shares Outstanding		10
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 0

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Current Assets
Cash & cash equivalents	$ 9.4	$ 6.2
Accounts receivable - less reserves of $4.1 & $3.0, respectively	102.6	92.3
Accrued unbilled revenues	112	85.7
Inventories	119	125.3
Recoverable fuel & natural gas costs	29.9	0
Prepayments & other current assets	38.6	49
Total current assets	411.5	358.5
Utility Plant
Original cost	6,545.4	6,090.4
Less: accumulated depreciation & amortization	2,562.5	2,415.5
Net utility plant	3,982.9	3,674.9
Investments in unconsolidated affiliates	0.2	0.2
Other investments	21.3	20.1
Nonutility plant - net	164.8	149.7
Goodwill	205	205
Regulatory assets	206.2	152.1
Other assets	49	32.2
TOTAL ASSETS	5,040.9	4,592.7
Current Liabilities
Accounts payable	205.4	168.5
Payables to other Vectren companies	25.4	25.7
Accrued liabilities	140.1	128.4
Short-term borrowings	194.4	14.5
Current maturities of long-term debt	49.1	13
Total current liabilities	614.4	350.1
Long-Term Debt - Net of Current Maturities	1,331	1,379.2
Deferred Credits & Other Liabilities
Deferred income taxes	854.5	758.4
Regulatory liabilities	453.7	433.9
Deferred credits & other liabilities	163.3	135.9
Total deferred credits & other liabilities	1,471.5	1,328.2
Commitments & Contingencies (Notes 8-11)
Common Shareholder's Equity
Common stock (no par value)	831.2	799.9
Retained earnings	792.8	735.3
Total common shareholder's equity	1,624	1,535.2
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	$ 5,040.9	$ 4,592.7

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Current Assets
Reserves	$ 4.1	$ 3

CONSOLIDATED STATEMENTS OF INCO

CONSOLIDATED STATEMENTS OF INCOME - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
OPERATING REVENUES
Gas utility									$ 771.7	$ 792.6	$ 944.6
Electric utility									605.8	601.6	624.8
Other									0.3	0.3	0.3
Total operating revenues	$ 383.5	$ 291.3	$ 279.8	$ 423.4	$ 338.1	$ 273	$ 276.5	$ 506.9	1,377.8	1,394.5	1,569.7
OPERATING EXPENSES
Cost of gas sold									266.7	305.4	468.7
Cost of fuel & purchased power									183.6	187.5	201.8
Other operating									333.6	339.1	354.5
Depreciation & amortization									219.1	208.8	203.1
Taxes other than income taxes									58.3	57.1	60.2
Total operating expenses									1,061.3	1,097.9	1,288.3
OPERATING INCOME	93.5	64	52.2	106.8	81.3	54.1	50.5	110.8	316.5	296.6	281.4
Other income - net									26.3	18.7	16.8
Interest expense									69.7	66.3	66.6
INCOME BEFORE INCOME TAXES									273.1	249	231.6
Income taxes									99.5	88.1	83.2
NET INCOME	$ 51.3	$ 34.9	$ 26.3	$ 61.1	$ 46.6	$ 26.9	$ 24.4	$ 63	$ 173.6	$ 160.9	$ 148.4

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$ 173.6	$ 160.9	$ 148.4
Adjustments to reconcile net income to cash from operating activities:
Depreciation & amortization	219.1	208.8	203.1
Deferred income taxes & investment tax credits	96.7	85.8	55.7
Expense portion of pension & postretirement benefit cost	4	4.8	4.7
Provision for uncollectible accounts	6.6	6.9	6.1
Other non-cash charges - net	3.5	7	3.2
Changes in working capital accounts:
Accounts receivable, including to Vectren companies & accrued unbilled revenues	(48.8)	50.5	(15.8)
Inventories	6.3	(12.1)	(23.3)
Recoverable/refundable fuel & natural gas costs	(37.8)	15.2	(4.4)
Prepayments & other current assets	5	30	(34.4)
Accounts payable, including to Vectren companies & affiliated companies	23.9	(15.2)	7.5
Accrued liabilities	18.7	0.7	(2.2)
Cash to fund pension and postretirement plans	(15)	(19.6)	0
Changes in noncurrent assets	(46.5)	(23.7)	6.4
Changes in noncurrent liabilities	(11.9)	(7.1)	(17.5)
Net cash provided by operating activities	397.4	492.9	337.5
Proceeds from:
Long-term debt, net of issuance costs	0	236.3	62.4
Additional capital contribution	31.3	6.2	6
Requirements for:
Dividends to parent	(116.1)	(110.4)	(108.7)
Retirement of long-term debt	(13)	(95)	(63.6)
Net change in short-term borrowings	179.9	(141.9)	127.8
Net cash used in financing activities	82.1	(104.8)	23.9
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from other investing activities	15.3	3.9	0.3
Requirements for:
Capital expenditures, excluding AFUDC equity	(496.6)	(399.2)	(351)
Changes in restricted cash	5	(5.9)	0
Net cash used in investing activities	(476.3)	(401.2)	(350.7)
Net change in cash & cash equivalents	3.2	(13.1)	10.7
Cash & cash equivalents at beginning of period	6.2	19.3	8.6
Cash & cash equivalents at end of period	$ 9.4	$ 6.2	$ 19.3

CONSOLIDATED STATEMENTS OF COMM

CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER'S EQUITY - USD ($) $ in Millions	Total	Common Stock [Member]	Retained Earnings [Member]
Balance at beginning of period at Dec. 31, 2013	$ 1,432.8	$ 787.7	$ 645.1
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	148.4		148.4
Common stock:
Additional capital contribution	6	6
Dividends to parent	(108.7)		(108.7)
Balance at end of period at Dec. 31, 2014	1,478.5	793.7	684.8
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	160.9		160.9
Common stock:
Additional capital contribution	6.2	6.2
Dividends to parent	(110.4)		(110.4)
Balance at end of period at Dec. 31, 2015	1,535.2	799.9	735.3
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	173.6		173.6
Common stock:
Additional capital contribution	31.3	31.3
Dividends to parent	(116.1)		(116.1)
Balance at end of period at Dec. 31, 2016	$ 1,624	$ 831.2	$ 792.8

Organization and Nature of Oper

Organization and Nature of Operations	12 Months Ended
	Dec. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization and Nature of Operations	Organization and Nature of Operations Vectren Utility Holdings, Inc. (the Company, Utility Holdings or VUHI), an Indiana corporation, was formed on March 31, 2000, to serve as the intermediate holding company for Vectren Corporation’s (Vectren or the Company's parent) three operating public utilities: Indiana Gas Company, Inc. (Indiana Gas or Vectren Energy Delivery of Indiana - North), Southern Indiana Gas and Electric Company (SIGECO or Vectren Energy Delivery of Indiana - South), and Vectren Energy Delivery of Ohio, Inc. (VEDO). Herein, 'the Company' may also refer to Indiana Gas Company, Inc., Southern Indiana Gas and Electric Company, Inc. and/or Vectren Energy Delivery of Ohio, Inc. The Company also has other assets that provide information technology and other services to the three utilities. Vectren, an Indiana corporation, is an energy holding company headquartered in Evansville, Indiana, and was organized on June 10, 1999. Both Vectren and the Company are holding companies as defined by the Energy Policy Act of 2005 (Energy Act). Indiana Gas provides energy delivery services to approximately 587,000 natural gas customers located in central and southern Indiana. SIGECO provides energy delivery services to approximately 144,000 electric customers and approximately 111,000 gas customers located near Evansville in southwestern Indiana. SIGECO also owns and operates electric generation assets to serve its electric customers and optimizes those assets in the wholesale power market. Indiana Gas and SIGECO generally do business as Vectren Energy Delivery of Indiana. VEDO provides energy delivery services to approximately 316,000 natural gas customers located near Dayton in west-central Ohio.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Summary of Significant Accounting Policies In applying its accounting policies, the Company makes judgments, assumptions, and estimates that affect the amounts reported in these consolidated financial statements and related footnotes. Examples of transactions for which estimation techniques are used include valuing deferred tax obligations, unbilled revenue, uncollectible accounts, regulatory assets and liabilities, asset retirement obligations, and derivatives and other financial instruments. Estimates also impact the depreciation of utility and nonutility plant and the testing of goodwill and other assets for impairment. Recorded estimates are revised when better information becomes available or when actual amounts can be determined. Actual results could differ from current estimates. Principles of Consolidation The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries, after appropriate elimination of intercompany transactions. Subsequent Events Review Management performs a review of subsequent events for any events occurring after the balance sheet date but prior to the date the financial statements are issued. Cash & Cash Equivalents Highly liquid investments with an original maturity of three months or less at the date of purchase are considered cash equivalents. Cash and cash equivalents are stated at cost plus accrued interest to approximate fair value. Allowance for Uncollectible Accounts The Company maintains allowances for uncollectible accounts for estimated losses resulting from the inability of its customers to make required payments. The Company estimates the allowance for uncollectible accounts based on a variety of factors including the length of time receivables are past due, the financial health of its customers, unusual macroeconomic conditions, and historical experience. If the financial condition of its customers deteriorates or other circumstances occur that result in an impairment of customers’ ability to make payments, the Company records additional allowances as needed. Inventories In most circumstances, the Company’s inventory components are recorded using an average cost method; however, natural gas in storage at the Company’s Indiana utilities are recorded using the Last In – First Out (LIFO) method. Inventory related to the Company’s regulated operations is valued at historical cost consistent with ratemaking treatment. Materials and supplies are recorded as inventory when purchased and subsequently charged to expense or capitalized to plant when installed. Property, Plant & Equipment Both the Company’s Utility Plant and Nonutility Plant is stated at historical cost, inclusive of financing costs and direct and indirect construction costs, less accumulated depreciation and when necessary, impairment charges. The cost of renewals and betterments that extend the useful life are capitalized. Maintenance and repairs, including the cost of removal of minor items of property and planned major maintenance projects, are charged to expense as incurred. Utility Plant & Related Depreciation Both the IURC and PUCO allow the Company’s utilities to capitalize financing costs associated with Utility Plant based on a computed interest cost and a designated cost of equity funds. These financing costs are commonly referred to as AFUDC and are capitalized for ratemaking purposes and for financial reporting purposes instead of amounts that would otherwise be capitalized when acquiring nonutility plant. The Company reports both the debt and equity components of AFUDC in Other – net in the Consolidated Statements of Income . When property that represents a retirement unit is replaced or removed, the remaining historical value of such property is charged to Utility Plant , with an offsetting charge to Accumulated depreciation , resulting in no gain or loss. Costs to dismantle and remove retired property are recovered through the depreciation rates as determined by the IURC and PUCO. The Company’s portion of jointly owned Utility Plant , along with that plant’s related operating expenses, is presented in these financial statements in proportion to the ownership percentage. Nonutility Plant & Related Depreciation The depreciation of Nonutility Plant is charged against income over its estimated useful life, using the straight-line method of depreciation. When nonutility property is retired, or otherwise disposed of, the asset and accumulated depreciation are removed, and the resulting gain or loss is reflected in income, typically impacting operating expenses. Impairment Reviews Property, plant and equipment along with other long-lived assets are reviewed as facts and circumstances indicate the carrying amount may be impaired. This impairment review involves the comparison of an asset’s (or group of assets’) carrying value to the estimated future cash flows the asset (or asset group) is expected to generate over a remaining life. If this evaluation were to conclude the carrying value is impaired, an impairment charge would be recorded based on the difference between the carrying amount and its fair value (less costs to sell for assets to be disposed of by sale) as a charge to operations or discontinued operations. Goodwill Goodwill recorded on the Consolidated Balance Sheets results from business acquisitions and is based on a fair value allocation of the businesses’ purchase price at the time of acquisition. Goodwill is charged to expense only when it is impaired. The Company tests its goodwill for impairment at an operating segment level because the components within the segments are similar. These tests are performed at least annually and at the beginning of each year. Impairment reviews consist of a comparison of fair value to the carrying amount. If the fair value is less than the carrying amount, an impairment loss is recognized in operations. No goodwill impairments have been recorded during the periods presented. Regulation Retail public utility operations affecting Indiana customers are subject to regulation by the IURC, and retail public utility operations affecting Ohio customers are subject to regulation by the PUCO. The Company’s accounting policies give recognition to the ratemaking and accounting practices authorized by these agencies. Refundable or Recoverable Gas Costs & Cost of Fuel & Purchased Power All metered gas rates in Indiana contain a gas cost adjustment clause that allows the Company to charge for changes in the cost of purchased gas. Metered electric rates contain a fuel adjustment clause that allows for adjustment in charges for electric energy to reflect changes in the cost of fuel. The net energy cost of purchased power, subject to a variable benchmark based on NYMEX natural gas prices, is also recovered through regulatory proceedings. The Company records any under-or-over-recovery resulting from gas and fuel adjustment clauses each month in revenues. A corresponding asset or liability is recorded until the under-or-over-recovery is billed or refunded to utility customers. The cost of gas sold is charged to operating expense as delivered to customers, and the cost of fuel and purchased power for electric generation is charged to operating expense when consumed. Regulatory Assets & Liabilities Regulatory assets represent certain incurred costs, which will result in probable future cash recoveries from customers through the ratemaking process. Regulatory liabilities represent probable expenditures by the Company for removal costs or future reductions in revenues associated with amounts to be credited to customers through the ratemaking process. The Company continually assesses the recoverability of costs recognized as regulatory assets and liabilities and the ability to recognize new regulatory assets and liabilities associated with its regulated utility operations. Given the current regulatory environment in its jurisdictions, the Company believes such accounting is appropriate. The Company collects an estimated cost of removal of its utility plant through depreciation rates established in regulatory proceedings. The Company records amounts expensed in advance of payments as a Regulatory liability because the liability does not meet the threshold of an asset retirement obligation. Asset Retirement Obligations A portion of removal costs related to interim retirements of gas utility pipeline and utility poles, certain asbestos-related issues, and reclamation activities meet the definition of an asset retirement obligation (ARO). The Company records the fair value of a liability for a legal ARO in the period in which it is incurred. When the liability is initially recorded, the Company capitalizes a cost by increasing the carrying amount of the related long-lived asset. The liability is accreted, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, the Company settles the obligation for its recorded amount or incurs a gain or loss. To the extent regulation is involved, regulatory assets and liabilities result when accretion and amortization is adjusted to match rates established by regulators and any gain or loss is subject to deferral. Energy Contracts & Derivatives The Company will periodically execute derivative contracts in the normal course of operations while buying and selling commodities to be used in operations, optimizing its generation assets, and managing risk. A derivative is recognized on the balance sheet as an asset or liability measured at its fair market value and the change in the derivative's fair market value is recognized currently in earnings unless specific hedge criteria are met. When an energy contract that is a derivative is designated and documented as a normal purchase or normal sale (NPNS), it is exempt from mark-to-market accounting. Most energy contracts executed by the Company are subject to the NPNS exclusion or are not considered derivatives. Such energy contracts include Real Time and Day Ahead purchase and sale contracts with the MISO, natural gas purchases, and wind farm and other electric generating contracts. When the Company engages in energy contracts and financial contracts that are derivatives and are not subject to the NPNS or other exclusions, such contracts are recorded at market value as current or noncurrent assets or liabilities depending on their value and when the contracts are expected to be settled. Contracts and any associated collateral with counter-parties subject to master netting arrangements are presented net in the Consolidated Balance Sheets . The offset resulting from carrying the derivative at fair value on the balance sheet is charged to earnings unless it qualifies as a hedge or is subject to regulatory accounting treatment. When hedge accounting is appropriate, the Company assesses and documents hedging relationships between the derivative contract and underlying risks as well as its risk management objectives and anticipated effectiveness. When the hedging relationship is highly effective, derivatives are designated as hedges. The market value of the effective portion of the hedge is marked to market in Accumulated other comprehensive income for cash flow hedges. Ineffective portions of hedging arrangements are marked to market through earnings. For fair value hedges, both the derivative and the underlying hedged item are marked to market through earnings. The offset to contracts affected by regulatory accounting treatment are marked to market as a regulatory asset or liability. Market value for derivative contracts is determined using quoted market prices from independent sources. The Company rarely enters into contracts that have a significant impact to the financial statements where internal models are used to calculate fair value. As of and for the periods presented, related derivative activity is not material to these financial statements. Revenues Revenues are recorded as products and services are delivered to customers. To more closely match revenues and expenses, the Company records revenues for all gas and electricity delivered to customers but not billed at the end of an accounting period in Accrued unbilled revenues . Substantially all revenue sources are subject to unbillled accruals. MISO Transactions With the IURC’s approval, the Company is a member of the MISO, a FERC approved regional transmission organization. The MISO serves the electrical transmission needs of much of the Midcontinent region and maintains operational control over the Company’s electric transmission facilities as well as other utilities in the region. The Company is an active participant in the MISO energy markets, bidding its owned generation into the Day Ahead and Real Time markets and procuring power for its retail customers at Locational Marginal Pricing (LMP) as determined by the MISO market. MISO-related purchase and sale transactions are recorded using settlement information provided by the MISO. These purchase and sale transactions are accounted for on a net hourly position. Net purchases in a single hour are recorded in Cost of fuel & purchased power and net sales in a single hour are recorded in Electric utility revenues . On occasion, prior period transactions are resettled outside the routine process due to a change in the MISO’s tariff or a material interpretation thereof. Expenses associated with resettlements are recorded once the resettlement is probable and the resettlement amount can be estimated. Revenues associated with resettlements are recognized when the amount is determinable and collectability is reasonably assured. The Company also receives transmission revenue that results from other members’ use of the Company’s transmission system. These revenues are also included in Electric utility revenues. Generally, these transmission revenues along with costs charged by the MISO are considered components of base rates and any variance from that included in base rates is recovered from / refunded to retail customers through tracking mechanisms. Excise & Utility Receipts Taxes Excise taxes and a portion of utility receipts taxes are included in rates charged to customers. Accordingly, the Company records these taxes received as a component of operating revenues, which totaled $28.3 million in 2016 , $29.4 million in 2015 , and $32.3 million in 2014 . Expense associated with excise and utility receipts taxes are recorded as a component of Taxes other than income taxes . Operating Segments The Company's chief operating decision maker is the Chief Executive Officer. The Company uses net income calculated in accordance with generally accepted accounting principles as its most relevant performance measure. The Company’s operations consist of regulated operations and other operations that provide information technology and other support services to those regulated operations. The Company segregates its regulated operations between a Gas Utility Services operating segment and an Electric Utility Services operating segment. Fair Value Measurements Certain assets and liabilities are valued and disclosed at fair value. Nonfinancial assets and liabilities include the initial measurement of an asset retirement obligation or the use of fair value in goodwill, intangible assets, and long-lived assets impairment tests. FASB guidance provides the framework for measuring fair value. That framework provides a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of the fair value hierarchy are described as follows: Level 1 Inputs to the valuation methodology are unadjusted quoted prices for identical assets or liabilities in active markets. Level 2 Inputs to the valuation methodology include · quoted prices for similar assets or liabilities in active markets; · quoted prices for identical or similar assets or liabilities in inactive markets; · inputs other than quoted prices that are observable for the asset or liability; · inputs that are derived principally from or corroborated by observable market data by correlation or other means If the asset or liability has a specified (contractual) term, the Level 2 input must be observable for substantially the full term of the asset or liability. Level 3 Inputs to the valuation methodology are unobservable and significant to the fair value measurement. The asset or liability’s fair value measurement level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement. Valuation techniques used maximize the use of observable inputs and minimize the use of unobservable inputs. Earnings Per Share Earnings per share are not presented as the Company's common stock is wholly owned by the Company's parent. Other Significant Policies Included elsewhere in these notes are significant accounting policies related to retirement plans and other postretirement benefits, intercompany allocations and income taxes (Note 5).

Utility & Nonutility Plant

Utility & Nonutility Plant	12 Months Ended
	Dec. 31, 2016
Property, Plant and Equipment [Abstract]
Utility and Nonutility Plant	Utility & Nonutility Plant The original cost of Utility Plant , together with depreciation rates expressed as a percentage of original cost, follows: At and For the Year Ended December 31, (In millions) 2016 2015 Original Cost Depreciation Rates as a Percent of Original Cost Original Cost Depreciation Rates as a Percent of Original Cost Gas utility plant $ 3,627.0 3.4 % $ 3,279.7 3.4 % Electric utility plant 2,799.1 3.4 % 2,695.8 3.3 % Common utility plant 56.3 3.2 % 55.0 3.2 % Construction work in progress 63.0 — 59.9 — Total original cost $ 6,545.4 $ 6,090.4 SIGECO and Alcoa Generating Corporation (AGC), a subsidiary of Alcoa, Inc. (Alcoa), own a 300 MW unit at the Warrick Power Plant (Warrick Unit 4) as tenants in common. SIGECO's share of the cost of this unit at December 31, 2016 , is $190.4 million with accumulated depreciation totaling $110.8 million . AGC and SIGECO share equally in the cost of operation and output of the unit. SIGECO's share of operating costs is included in Other operating expenses in the Consolidated Statements of Income . In the first quarter of 2016, Alcoa closed its smelter operations. Historically, on-site generation owned and operated by AGC has been used to provide power to the smelter, as well as other mill operations, which will continue. Generation from Alcoa's share of the Warrick Unit 4 has historically been sold into the MISO market. The Company is actively working with Alcoa on plans related to continued operation of this generation. Nonutility Plant , net of accumulated depreciation and amortization follows: At December 31, (In millions) 2016 2015 Computer hardware & software $ 120.5 $ 107.6 Land & buildings 37.6 35.0 All other 6.7 7.1 Nonutility plant - net $ 164.8 $ 149.7 Nonutility plant is presented net of accumulated depreciation and amortization totaling $264.7 million and $248.0 million as of December 31, 2016 and 2015 , respectively. For the years ended December 31, 2016 , 2015 , and 2014 , the Company capitalized interest totaling $1.0 million , $0.4 million , and $0.6 million , respectively, on nonutility plant construction projects.

Regulatory Assets & Liabilities

Regulatory Assets & Liabilities	12 Months Ended
	Dec. 31, 2016
Regulatory Assets and Liabilities Disclosure [Abstract]
Regulatory Assets and Liabilities	Regulatory Assets & Liabilities Regulatory Assets Regulatory assets consist of the following: At December 31, (In millions) 2016 2015 Future amounts recoverable from ratepayers related to: Net deferred income taxes $ (17.1 ) $ (16.9 ) (17.1 ) (16.9 ) Amounts deferred for future recovery related to: Cost recovery riders & other 91.6 54.6 91.6 54.6 Amounts currently recovered in customer rates related to: Unamortized debt issue costs, reacquisition premiums & hedging proceeds 24.1 25.8 Indiana authorized trackers 64.2 42.6 Deferred coal costs 21.2 28.3 Ohio authorized trackers 22.2 17.6 Other base rate recoveries — 0.1 131.7 114.4 Total regulatory assets $ 206.2 $ 152.1 Of the $132 million currently being recovered in customer rates, no amounts are earning a return. The weighted average recovery period of regulatory assets currently being recovered in base rates, which totals $24 million , is 24 years. The remainder of the regulatory assets are being recovered timely through periodic recovery mechanisms. The Company has rate orders for all deferred costs not yet in rates and therefore believes future recovery is probable. Regulatory Liabilities At December 31, 2016 and 2015 , the Company has approximately $453.7 million and $433.9 million , respectively, in Regulatory liabilities . Of these amounts most relate to cost of removal obligations.

Transactions with Other Vectren

Transactions with Other Vectren Companies and Affiliates	12 Months Ended
	Dec. 31, 2016
Transactions with Other Vectren Companies and Affiliates [Abstract]
Transactions With Other Vectren Companies and Affiliates	Transactions with Other Vectren Companies and Affiliates Vectren Infrastructure Services Corporation (VISCO) VISCO, a wholly owned subsidiary of the Company's parent, provides underground pipeline construction and repair services. VISCO’s customers include the Company's utilities and fees incurred by the Company totaled $117.8 million in 2016 , $109.5 million in 2015 , and $94.0 million in 2014 . Amounts owed to VISCO at December 31, 2016 and 2015 are included in Payables to other Vectren companies. Vectren Fuels, Inc . On August 29, 2014, the Company's parent closed on a transaction to sell its wholly-owned coal mining subsidiary, Vectren Fuels, Inc. (Vectren Fuels), to Sunrise Coal, LLC (Sunrise), an Indiana-based wholly-owned subsidiary of Hallador Energy Company. Prior to the sale date, SIGECO purchased coal used for electric generation from Vectren Fuels. The amount purchased for the year ended December 31, 2014 totaled $98.6 million . After the exit of the coal mining business by the Company's parent, Sunrise has assumed Vectren Fuels' supply contracts and has also negotiated new contracts for similar quality coal that will result in the Company purchasing most of its coal supply from Sunrise. Support Services & Purchases The Company's parent provides corporate and general and administrative services to the Company and allocates certain costs to the Company, including costs for share-based compensation and for pension and other postretirement benefits that are not directly charged to subsidiaries. These costs are allocated using various allocators, including number of employees, number of customers and/or the level of payroll, revenue contribution and capital expenditures. Allocations are at cost. The Company received corporate allocations totaling $57.6 million , $52.3 million , and $57.0 million for the years ended December 31, 2016 , 2015 and 2014 , respectively. Retirement Plans & Other Postretirement Benefits At December 31, 2016 , the Company's parent maintains three closed qualified defined benefit pension plans (Vectren Corporation Non-Bargaining Retirement Plan, The Indiana Gas Company, Inc. Bargaining Unit Retirement Plan, Pension Plan for Hourly Employees of Southern Indiana Gas and Electric Company), a nonqualified supplemental executive retirement plan (SERP), and a postretirement benefit plan. The defined benefit pension plans and postretirement benefit plan, which cover the Company’s eligible full-time regular employees, are primarily noncontributory. The postretirement health care and life insurance plans are a combination of self-insured and fully insured plans. The Company's current and former employees comprise the vast majority of the participants and retirees covered by these plans. The Company's parent satisfies the future funding requirements and the payment of benefits from general corporate assets and, as necessary, relies on the Company to support the funding of these obligations. Although the Company has no contractual funding obligation, the company contributed $15.0 million and $19.6 million to Vectren's defined benefit pension plans during 2016 and 2015 , respectively. The combined funded status of the plans was approximately 92 percent at December 31, 2016 and 90 percent at December 31, 2015 . The Company's parent allocates the periodic cost of its retirement plans calculated pursuant to US GAAP to its subsidiaries. Periodic cost, comprised of service cost and interest on that service cost, is directly charged to the Company based on labor at each measurement date and that cost is charged to operating expense and capital projects, using labor charges as the allocation method. For the years ended December 31, 2016 , 2015 and 2014 , costs totaling $6.1 million , $7.0 million and $6.7 million , respectively, were directly charged to the Company. Other components of periodic costs (such as interest cost, asset returns, and amortizations) and the service cost related to Vectren Corporate operations are charged to subsidiaries through the allocation process discussed above. Any difference between funding requirements and allocated periodic costs is recognized as an asset or liability until reflected in periodic costs. Neither plan assets nor the ending liability is allocated to individual subsidiaries since these assets and obligations are derived from corporate level decisions. The allocation methodology is consistent with FASB guidance related to “multiemployer” benefit accounting. As of December 31, 2016 and 2015 , $12.2 million and $12.0 million , respectively, is included in Deferred credits & other liabilities and represents costs related to other postretirement benefits directly charged to the Company that is yet to be funded to the Company's parent. As impacted by increased funding of pension plans, at December 31, 2016 and 2015 , the Company has $40.9 million , and $30.3 million , respectively, included in Other Assets representing defined benefit funding by the Company that is yet to be reflected in costs. Share-Based Incentive Plans & Deferred Compensation Plans The Company does not have share-based compensation plans separate from the Company's parent. The Company recognizes its allocated portion of expenses related to share-based incentive plans and deferred compensation plans in accordance with FASB guidance and to the extent these awards are expected to be settled in cash that liability is pushed down to the Company. As of December 31, 2016 and 2015 , $42.3 million and $35.7 million , respectively, is included in Accrued liabilities and Deferred credits & other liabilities and represents obligations that are yet to be funded to the Company's parent. Income Taxes The Company does not file federal or state income tax returns separate from those filed by its parent, Vectren Corporation. The Company's parent files a consolidated U.S. federal income tax return, and Vectren and/or certain of its subsidiaries file income tax returns in various states. Pursuant to a tax sharing agreement and for financial reporting purposes, Vectren subsidiaries record income taxes on a separate company basis. The Company's allocated share of tax effects resulting from it being a part of this consolidated tax group are recorded at the parent company level. Current taxes payable/receivable are settled with the Company's parent in cash quarterly and after filing the consolidated federal and state income tax returns. Deferred income taxes are provided for temporary differences between the tax basis (adjusted for related unrecognized tax benefits, if any) of an asset or liability and its reported amount in the financial statements. Deferred tax assets and liabilities are computed based on the currently-enacted statutory income tax rates that are expected to be applicable when the temporary differences are scheduled to reverse. The Company’s rate-regulated utilities recognize regulatory liabilities for deferred taxes provided in excess of the current statutory tax rate and regulatory assets for deferred taxes provided at rates less than the current statutory tax rate. Such tax-related regulatory assets and liabilities are reported at the revenue requirement level and amortized to income as the related temporary differences reverse, generally over the lives of the related properties. A valuation allowance is recorded to reduce the carrying amounts of deferred tax assets unless it is more likely than not that the deferred tax assets will be realized. Tax benefits associated with income tax positions taken, or expected to be taken, in a tax return are recorded only when the more-likely-than-not recognition threshold is satisfied and measured at the largest amount of benefit that is greater than 50 percent likely of being realized upon settlement. The Company reports interest and penalties associated with unrecognized tax benefits within Income taxes in the Consolidated Statements of Income and reports tax liabilities related to unrecognized tax benefits as part of Deferred credits & other liabilities . Investment tax credits (ITCs) are deferred and amortized to income over the approximate lives of the related property. Production tax credits (PTCs) are recognized as energy is generated and sold based on a per kilowatt hour rate prescribed in applicable federal and state statutes. The components of income tax expense and amortization of investment tax credits follow: Year Ended December 31, (In millions) 2016 2015 2014 Current: Federal $ (1.4 ) $ (1.9 ) $ 16.6 State 4.2 4.2 10.9 Total current taxes 2.8 2.3 27.5 Deferred: Federal 93.5 81.7 57.8 State 3.7 4.6 (1.6 ) Total deferred taxes 97.2 86.3 56.2 Amortization of investment tax credits (0.5 ) (0.5 ) (0.5 ) Total income tax expense $ 99.5 $ 88.1 $ 83.2 A reconciliation of the federal statutory rate to the effective income tax rate follows: Year Ended December 31, 2016 2015 2014 Statutory rate 35.0 % 35.0 % 35.0 % State and local taxes-net of federal benefit 2.6 2.8 3.3 Amortization of investment tax credit (0.2 ) (0.2 ) (0.2 ) Domestic production deduction (0.5 ) (0.9 ) (0.9 ) Research and development credit (0.8 ) (2.0 ) (0.3 ) All other - net 0.3 0.7 (1.0 ) Effective tax rate 36.4 % 35.4 % 35.9 % Significant components of the net deferred tax liability follow: At December 31, (In millions) 2016 2015 Noncurrent deferred tax liabilities (assets): Depreciation & cost recovery timing differences $ 821.6 $ 752.6 Regulatory assets recoverable through future rates 17.6 31.6 Alternative minimum tax carryforward (29.3 ) (34.5 ) Employee benefit obligations 10.2 7.2 Regulatory liabilities to be settled through future rates (15.9 ) (29.9 ) Deferred fuel costs 25.9 14.2 Other – net 24.4 17.2 Net noncurrent deferred tax liability $ 854.5 $ 758.4 At December 31, 2016 and 2015 , investment tax credits totaling $1.6 million and $2.1 million , respectively, are included in Deferred credits & other liabilities . At December 31, 2016 , the Company has alternative minimum tax carryforwards of $29.3 million , which do not expire. Uncertain Tax Positions Unrecognized tax benefits for all periods presented were not material to the Company. The net liability on the Consolidated Balance Sheet for unrecognized tax benefits inclusive of interest and penalties totaled $1.1 million and $0.7 million , respectively, at December 31, 2016 and 2015 . The Company's parent and/or certain of its subsidiaries file income tax returns in the U.S. federal jurisdiction and various states. The Internal Revenue Service (IRS) has concluded examinations of Vectren's U.S. federal income tax returns for tax years through December 31, 2012. The State of Indiana, Vectren's primary state tax jurisdiction, has conducted examinations of state income tax returns for tax years through December 31, 2010. The statutes of limitations for assessment of federal income tax and Indiana income tax have expired with respect to tax years through 2012 except to the extent of refunds claimed on amended tax returns. The statutes of limitations for assessment of the 2009, 2011 and 2012 tax years related to the amended Indiana income tax returns will expire in 2018 for tax years 2009 and 2011, and 2019 for the tax year 2012. Indiana Senate Bill 1 In March 2014, Indiana Senate Bill 1 was signed into law. This legislation phases in a 1.6 percent rate reduction to the Indiana Adjusted Gross Income Tax Rate for corporations over a six year period. Pursuant to this legislation, the tax rate will be lowered by 0.25 percent each year for the first five years and 0.35 percent in year six beginning on July 1, 2016 to the final rate of 4.9 percent effective July 1, 2021. Pursuant to FASB guidance, the Company accounted for the effect of the change in tax law on its deferred taxes in the first quarter of 2014, the period of enactment. The impact was not material to results of operations.

Borrowing Arrangements

Borrowing Arrangements	12 Months Ended
	Dec. 31, 2016
Debt Disclosure [Abstract]
Borrowing Arrangements	Borrowing Arrangements Short-Term Borrowings At December 31, 2016 , the Company had $350 million of short-term borrowing capacity. As reduced by borrowings outstanding at December 31, 2016 , approximately $156 million was available. This short-term credit facility is available through October 2019 . The maximum limit of the facility remained unchanged. This facility is used to supplement working capital needs and also to fund capital investments and debt redemptions until financed on a long-term basis. The facility has a letter of credit limit of $100 million . As of December 31, 2016 , there was no letters of credit outstanding under the facility. The Company has historically funded the short-term borrowing needs through the commercial paper market and expects to use the short-term borrowing facility in instances where the commercial paper market is not efficient. Following is certain information regarding these short-term borrowing arrangements: (In millions) 2016 2015 2014 Year End Balance Outstanding $ 194.4 $ 14.5 $ 156.4 Weighted Average Interest Rate 1.05 % 0.55 % 0.50 % Annual Average Balance Outstanding $ 59.8 $ 53.8 $ 35.6 Weighted Average Interest Rate 0.71 % 0.38 % 0.34 % Maximum Month End Balance Outstanding $ 194.4 $ 121.5 $ 156.4 Throughout the years presented, the Company has successfully placed commercial paper as needed. Long-Term Debt Long-term senior unsecured obligations and first mortgage bonds outstanding by subsidiary follow: At December 31, (In millions) 2016 2015 Utility Holdings Fixed Rate Senior Unsecured Notes 2018, 5.75% 100.0 100.0 2020, 6.28% 100.0 100.0 2021, 4.67% 55.0 55.0 2023, 3.72% 150.0 150.0 2026, 5.02% 60.0 60.0 2028, 3.20% 45.0 45.0 2035, 6.10% 75.0 75.0 2035, 3.90% 25.0 25.0 2041, 5.99% 35.0 35.0 2042, 5.00% 100.0 100.0 2043, 4.25% 80.0 80.0 2045, 4.36% 135.0 135.0 2055, 4.51% 40.0 40.0 Total Utility Holdings 1,000.0 1,000.0 SIGECO First Mortgage Bonds 2016, 1986 Series, 8.875% — 13.0 2022, 2013 Series C, 1.95%, tax exempt 4.6 4.6 2024, 2013 Series D, 1.95%, tax exempt 22.5 22.5 2025, 2014 Series B, current adjustable rate 1.045%, tax-exempt 41.3 41.3 2029, 1999 Series, 6.72% 80.0 80.0 2037, 2013 Series E, 1.95%, tax exempt 22.0 22.0 2038, 2013 Series A, 4.00%, tax exempt 22.2 22.2 2043, 2013 Series B, 4.05%, tax exempt 39.6 39.6 2044, 2014 Series A, 4.00%, tax exempt 22.3 22.3 2055, 2015 Series Mt. Vernon, 2.375%, tax-exempt 23.0 23.0 2055, 2015 Series Warrick County, 2.375%, tax-exempt 15.2 15.2 Total SIGECO 292.7 305.7 Indiana Gas Fixed Rate Senior Unsecured Notes 2025, Series E, 6.53% 10.0 10.0 2027, Series E, 6.42% 5.0 5.0 2027, Series E, 6.68% 1.0 1.0 2027, Series F, 6.34% 20.0 20.0 2028, Series F, 6.36% 10.0 10.0 2028, Series F, 6.55% 20.0 20.0 2029, Series G, 7.08% 30.0 30.0 Total Indiana Gas 96.0 96.0 Total long-term debt outstanding 1,388.7 1,401.7 Current maturities of long-term debt (49.1 ) (13.0 ) Debt issuance costs (7.9 ) (8.6 ) Unamortized debt premium & discount - net (0.7 ) (0.9 ) Total long-term debt-net $ 1,331.0 $ 1,379.2 Simplifying the Presentation of Debt Issuance Costs In April 2015, the FASB issued new accounting guidance on accounting for debt issuance costs which changes the presentation of debt issuance costs in financial statements. This ASU requires an entity to present such costs in the balance sheet as a direct reduction from the related debt liability rather than as an asset. Amortization of the costs will continue to be reported as interest expense. This ASU is effective for annual reporting periods beginning after December 15, 2015. The guidance was adopted as of January 1, 2016 and has been applied retrospectively to all periods presented. The effect of the change on the December 31, 2015 balance sheet was the reclassification of $8.6 million from Regulatory assets to Long-term Debt . The reclassification had no material impact on the Company's financial condition, results of operations, or cash flows as a result of the adoption. SIGECO Bond Retirement On June 1, 2016, a $13 million SIGECO bond matured. The First Mortgage Bond, which was a portion of an original $25 million public issuance sold on June 1, 1986, carried a fixed interest rate of 8.875 percent. The repayment of debt was funded from the Company’s commercial paper program Indiana Gas Unsecured Note Retirement On March 15, 2015 , a $5 million Indiana Gas senior unsecured note matured. The Series E note carried a fixed interest rate of 7.15 percent . The repayment of debt was funded by the Company's commercial paper program. SIGECO Debt Issuance On September 9, 2015 , SIGECO completed a $38.2 million tax-exempt first mortgage bond issuance. The principal terms of the two new series of tax-exempt debt are: (i) $23.0 million in Environmental Improvement Revenue Bonds, Series 2015, issued by the City of Mount Vernon, Indiana and (ii) $15.2 million in Environmental Improvement Revenue Bonds, Series 2015, issued by Warrick County, Indiana. Both bonds were sold in a public offering at an initial interest rate of 2.375 percent per annum that is fixed until September 1, 2020 when the bonds will be remarketed. The bonds have a final maturity of September 1, 2055 . Vectren Utility Holdings and Indiana Gas Debt Transactions On December 15, 2015 , the Company issued Guaranteed Senior Notes in a private placement to various institutional investors in the following tranches: (i) $25 million of 3.90 percent Guaranteed Senior Notes, Series A, due December 15, 2035 , (ii) $135 million of 4.36 percent Guaranteed Senior Notes, Series B, due December 15, 2045 , and (iii) $40 million of 4.51 percent Guaranteed Senior Notes, Series C, due December 15, 2055 . The notes are unconditionally guaranteed by Indiana Gas, SIGECO and VEDO. A portion of the proceeds received from this issuance was used to finance the following retirements of debt: (i) $75 million of 5.45 percent Utility Holdings senior unsecured notes that matured on December 1, 2015, and (ii) $5 and $10 million of 6.69 percent Indiana Gas senior unsecured notes that matured on December 21, 2015 and December 29, 2015, respectively. SIGECO Debt Refund and Issuance On September 24, 2014 , SIGECO issued two new series of tax-exempt debt totaling $63.6 million . Proceeds from the issuance were used to retire three series of tax-exempt bonds aggregating $63.6 million at a redemption price of par plus accrued interest. The principal terms of the two new series of tax-exempt debt are: (i) $22.3 million sold in a public offering and bear interest at 4.00 percent per annum, due September 1, 2044 and (ii) $41.3 million , due July 1, 2025, sold in a private placement at variable rates through September 2019. Mandatory Tenders At December 31, 2016, certain series of SIGECO bonds, aggregating $87.3 million , currently bear interest at fixed rates, of which $49.1 million is subject to mandatory tender in September 2017 and $38.2 million is subject to mandatory tender in September 2020. Additionally, SIGECO Bond Series 2014B, in the amount of $41.3 million , with a variable interest rate that is reset monthly, is subject to mandatory tender in September 2019. Future Long-Term Debt Sinking Fund Requirements and Maturities The annual sinking fund requirement of SIGECO's first mortgage bonds is 1 percent of the greatest amount of bonds outstanding under the Mortgage Indenture. This requirement may be satisfied by certification to the Trustee of unfunded property additions in the prescribed amount as provided in the Mortgage Indenture. SIGECO met the 2016 sinking fund requirement by this means and, expects to also meet this requirement in 2017 in this manner. Accordingly, the sinking fund requirement is excluded from Current liabilities in the Consolidated Balance Sheets . At December 31, 2016 , $1.4 billion of SIGECO's utility plant remained unfunded under SIGECO's Mortgage Indenture. SIGECO’s gross utility plant balance subject to the Mortgage Indenture approximated $3.3 billion at December 31, 2016 . Consolidated maturities of long-term debt during the years following 2016 (in millions) are $49.1 in 2017, $100.0 in 2018, $100.0 in 2020, $55.0 in 2021, and $1,076.0 thereafter. There are no maturities of long-term debt in 2019. Debt Guarantees The Company's currently outstanding long-term and short-term debt is jointly and severally guaranteed by SIGECO, Indiana Gas, and VEDO. The Company’s long-term debt and short-term debt outstanding at December 31, 2016 , totaled $996 million and $194 million , respectively. Covenants Both long-term and short-term borrowing arrangements contain customary default provisions; restrictions on liens, sale-leaseback transactions, mergers or consolidations, and sales of assets; and restrictions on leverage, among other restrictions. Multiple debt agreements contain a covenant that the ratio of consolidated total debt to consolidated total capitalization will not exceed 65 percent . As of December 31, 2016 , the Company was in compliance with all debt covenants.

Common Shareholder's Equity

Common Shareholder's Equity	12 Months Ended
	Dec. 31, 2016
Stockholders' Equity Note [Abstract]
Common Shareholder's Equity	Common Shareholder’s Equity During the years ended December 31, 2016 , 2015 , and 2014 , the Company has cumulatively received additional capital of $43.5 million from the Company's parent, of which $18.5 million was funded by new share issues from its dividend reinvestment plan and $25.0 million was received during 2016 from the nonutility operations of the Company's parent to fund the Company's capital expenditure program.

Commitments & Contingencies

Commitments & Contingencies	12 Months Ended
	Dec. 31, 2016
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments & Contingencies Commitments Future minimum lease payments required under operating leases that have initial or remaining noncancelable lease terms in excess of one year during the five years following 2016 and thereafter (in millions) are $0.8 in 2017 , $0.8 in 2018 , $0.6 in 2019 , $0.6 in 2020 , $0.6 in 2021 , and $1.6 thereafter. Total lease expense (in millions) was $1.1 in 2016 , $0.8 in 2015 , and $1.5 in 2014 . Firm purchase commitments for utility plant total $4.4 million in 2017 and $1.5 million in 2018 . The Company’s regulated utilities have both firm and non-firm commitments to purchase natural gas, coal, and electricity as well as certain transportation and storage rights and certain contracts are firm commitments under five and twenty year arrangements. Costs arising from these commitments, while significant, are pass-through costs, generally collected dollar-for-dollar from retail customers through regulator-approved cost recovery mechanisms. Legal and Regulatory Proceedings The Company is party to various legal proceedings, audits, and reviews by taxing authorities and other government agencies arising in the normal course of business. In the opinion of management, there are no legal proceedings or other regulatory reviews or audits pending against the Company that are likely to have a material adverse effect on its financial position, results of operations or cash flows.

Gas Rate and Regulatory Matters

Gas Rate and Regulatory Matters	12 Months Ended
	Dec. 31, 2016
Public Utilities, General Disclosures [Abstract]
Gas Rate and Regulatory Matters	Gas Rate and Regulatory Matters Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement The Company monitors and maintains its natural gas distribution system to ensure natural gas is delivered in a safe and efficient manner. The Company's natural gas utilities are currently engaged in programs to replace bare steel and cast iron infrastructure and other activities in both Indiana and Ohio to mitigate risk, improve the system, and comply with applicable regulations, many of which are 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, 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 that, among other things, requests for recovery include a seven-year project plan. Once the plan is approved by the IURC, 80 percent of such costs are eligible for current recovery using a periodic rate adjustment mechanism. Recoverable costs include a return on the investment that reflects the current capital structure and associated costs, with the exception of the rate of return on equity, which remains fixed at the rate determined in the Company's last rate case. Recoverable costs also include recovery of depreciation and other operating expenses. The remaining 20 percent of project costs are deferred and recovered in the utility’s next general rate case, which must be filed before the expiration of the seven-year plan. The adjustment mechanism is capped at an annual increase in retail revenues of no more than two percent. 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. Indiana Recovery and Deferral Mechanisms The Company's Indiana natural gas utilities received Orders in 2008 and 2007 associated with the most recent base rate cases. These Orders authorized the deferral of financial impacts associated with bare steel and cast iron replacement activities. The Orders provide for the deferral of depreciation and post-in-service carrying costs on qualifying projects totaling $20 million annually at Indiana Gas and $3 million annually at SIGECO. The debt-related post-in-service carrying costs are currently recognized in the Consolidated Statements of Income . The recording of post-in-service carrying costs and depreciation deferral is limited by individual qualifying project to three years after being placed into service at SIGECO and four years after being placed into service at Indiana Gas. At December 31, 2016 and December 31, 2015 , the Company has regulatory assets totaling $21.9 million and $19.9 million , respectively, associated with the deferral of depreciation and debt-related post-in-service carrying cost activities. Beginning in 2014, all bare steel and cast iron replacement activities are now part of the Company’s seven -year capital investment plan discussed below. 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. In March 2016, the IURC issued an Order re-approving approximately $890 million of the Company’s gas infrastructure modernization projects requested in the third update of the Plan, and approving the inclusion in rates of actual investments made through June 30, 2015. While most of the proposed capital spend has been approved as proposed, approximately $80 million of projects were not approved for recovery through the mechanisms pursuant to these filings. Specifically, the Company proposed to add a new project to its Plan pursuant to Senate Bill 560 totaling approximately $65 million . The project, which consists of a 20-mile transmission line and other related investments required to support industrial customer growth and ongoing system reliability in the Lafayette, Indiana area, as well as allows the Company to further diversify its gas supply portfolio via access to shale gas in the Marcellus and Utica reserves, was excluded for recovery under the Plan. The IURC stated because the project was not in the original plan filed in 2013, it does not qualify for cost recovery under this law. In the Order, the IURC did pre-approve the project for rate base inclusion upon the filing of the next base rate case. The Company believes such plan updates should be expected to accommodate new projects that emerge during the term of the plan as ongoing risk assessments determine new projects are required. The Company filed an appeal of the March 2016 Order on April 29, 2016 to challenge the IURC's finding which limits the scope of the Plan updates. The outcome of the appeal is expected in the first half of 2017. Subsequent to the March 2016 Order, the Company has received two additional Orders approving plan investments. On June 29, 2016, the IURC issued an Order approving the inclusion in rates of investments made from July 2015 to December 2015. On January 25, 2017 the IURC issued an Order (January 2017 Order) approving the inclusion in rates of investments made from January 2016 to June 2016. Through the January 2017 Order, approximately $338 million of the approved capital investment plan has been incurred and included for recovery. The January 2017 Order also approved the Company's plan update, which is now $950 million through 2020. The plan increase of $60 million is due to additional investment related to pipeline safety and compliance requirements under Senate Bill 251. At December 31, 2016 and December 31, 2015 , the Company has regulatory assets related to the Plan totaling $51.1 million and $28.6 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 remaining capital expenditure plan to be included for recovery in future DRR filings is estimated to be approximately $100 million to $120 million . The Order also approved the Company's commitment that the DRR can only be further extended as part of a base rate case. In total, the Company has made capital investments on projects that are now in-service under the DRR totaling $259.6 million as of December 31, 2016 , of which $204 million has been approved for recovery under the DRR through December 31, 2015 . Regulatory assets associated with post-in-service carrying costs and depreciation deferrals were $24.4 million and $18.2 million at December 31, 2016 and December 31, 2015 , respectively. In August 2016, the Company received approval to adjust the DRR rates, effective September 1, 2016, for recovery of investments placed in-service through December 31, 2015. 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. At December 31, 2016 and December 31, 2015 , the Company has regulatory assets totaling $41.9 million and $24.1 million , respectively, associated with the deferral of depreciation, post-in-service carrying costs, and property taxes. As of December 31, 2016 , the Company's deferrals have not reached this bill impact cap. On May 2, 2016, 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 2016. Given the extension of the DRR through 2017, as discussed above, and the continued ability to defer other capital expenses under House Bill 95, it is anticipated that the Company will file a general rate case for the inclusion in rate base of the above costs in early 2018. Pipeline and Hazardous Materials Safety Administration (PHMSA) In March of 2016, PHMSA published a notice of proposed rulemaking (NPRM) 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 is evaluating the impact that these proposed rules will have on its integrity management programs and transmission and distribution systems. In December of 2016, PHMSA issued final rules related to integrity management for storage operations. These rules are being evaluated with efforts 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 interagency task force. PHMSA has final rules pending that address requirements related to plastic pipe, operator qualifications, valve installation and rupture detection, and incident notification. Each of these rules is expected to be published by PHMSA in 2017. Additionally, PHMSA has recently finalized a rule on excess flow valves, which will go into effect in April 2017. These rules will increase the potential for capital expenditures and increase operating and maintenance expenses. The Company believes that the cost to comply with these new rules should be recoverable using the regulatory recovery mechanisms referenced above.

Electric Rate and Regulatory Ma

Electric Rate and Regulatory Matters	12 Months Ended
	Dec. 31, 2016
Public Utilities, General Disclosures [Abstract]
Electric Rate and Regulatory Matters	Electric Rate and Regulatory Matters Regulatory Treatment of Investments in Electric Infrastructure 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. The filing requests the recovery of associated capital expenditures estimated to be approximately $500 million over the seven -year period beginning in 2017. A procedural schedule has not been set in this proceeding, but under Senate Bill 560, an order is expected within 210 days of filing. Renewable Generation Resources On February 22, 2017, the Company also filed for authority 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 Integrated Resource Plan (IRP) submitted in December 2016, allow the Company to add an initial 4 MW of universal solar generation, rooftop solar generation, and 1 MW of battery storage resources to its portfolio. See more information on the IRP below in Environmental and Sustainability Matters. The cost of the projects is estimated to be approximately $15 million . A procedural schedule has not been set in this proceeding, however an order is expected later in 2017. SIGECO Electric Environmental Compliance Filing In January 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) related to sulfur trioxide emissions from the EPA. As of December 31, 2016 , $30 million has been spent 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 December 31, 2016 , the Company has approximately $6.9 million deferred related to depreciation and operating expense, and $2.8 million deferred related to post-in-service carrying costs. In June 2015, Joint Appellants’ Citizens Action Coalition of Indiana, Inc., Sierra Club, Inc., and Valley Watch, Inc. (the appellants) challenged the IURC's January Order. On October 29, 2015, the Indiana Court of Appeals issued an opinion that affirmed the IURC’s findings with regard to equipment required to comply with MATS and certain national pollutant discharge elimination system rules (approximately $30 million ) but remanded the case to the IURC to determine whether a certificate of public convenience and necessity (CPCN) should be issued for the equipment required by the NOV (approximately $40 million ). On June 22, 2016, the IURC issued an Order granting the Company a CPCN for the NOV-required equipment. On July 21, 2016, the appellants initiated an appeal of the IURC's June 22, 2016 Order challenging the findings made by the IURC. On February 14, 2017, the Court affirmed the IURC's June 22, 2016 Order. SIGECO Electric Demand Side Management (DSM) Program Filing On August 31, 2011, the IURC issued an Order approving an initial three -year DSM plan in the Company's electric service territory that complied with the IURC’s energy saving targets. Consistent with the Company’s proposal, the Order approved, among other items, the following: 1) recovery of costs associated with implementing the DSM Plan; 2) the recovery of a performance incentive mechanism based on measured savings related to certain DSM programs; and 3) lost margin recovery associated with the implementation of DSM programs for large customers. On June 20, 2012, the IURC issued an Order approving a small customer lost margin recovery mechanism, inclusive of all previous deferrals. For the twelve months ended December 31, 2016 , 2015 , and 2014 , the Company recognized electric utility revenue of $11.1 million , $10.1 million and $8.7 million , respectively, associated with this approved lost margin recovery mechanism. 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, most of the Company’s eligible industrial customers 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 programs. The Order provides for cost recovery of program and administrative expenses and includes performance incentives for reaching energy savings goals. The Order also included a lost margin recovery mechanism that now limits that 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 follows other recent IURC decisions implementing the same lost margin recovery limitation with respect to other electric utilities in Indiana. The Company is committed to continuing to promote and drive participation in its energy efficiency programs and has therefore appealed this lost margin recovery restriction. On March 7, 2017, the Court of Appeals reversed the IURC’s finding that the four year cap on lost margin recovery was arbitrary and the IURC failed to properly interpret the governing statute requiring that it review the utility's entire DSM proposal and approve or reject it as a whole, including the proposed lost margin recovery. On remand, the IURC must complete its review and can only reject the Company’s lost margin recovery if found to be unreasonable. Once the Court’s decision is final, the Company will again seek IURC approval of its energy efficiency plan. 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 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 is expected to rule on the proposed order in the second complaint case in 2017, which will authorize a base ROE for this period and prospectively from the date of the order. Separately, on January 6, 2015, the FERC approved a MISO transmission owner joint request for an adder to the approved ROE. Under FERC regulations, transmission owners that are part of a Regional Transmission Organization (RTO) such as the MISO are authorized to earn an incentive of 50 basis points above the FERC approved ROE. The FERC deferred the implementation of this adder until the pending complaint is resolved. The adder will be 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 December 31, 2016 , the Company had invested approximately $157.7 million in qualifying projects. The net plant balance for these projects totaled $136.8 million at December 31, 2016 .

Environmental and Sustainabilit

Environmental and Sustainability Matters	12 Months Ended
	Dec. 31, 2016
Environmental Matters Disclosure [Abstract]
Environmental and Sustainability Matters	Environmental and Sustainability Matters The Company initiated a corporate sustainability program in 2012 with the publication of the initial corporate sustainability report of the Company's parent. Since that time the Company continues to develop strategies that focus on those environmental, social and governance (ESG) factors that contribute to the long-term growth of a sustainable business model. As detailed further below and in the upcoming corporate sustainability report for 2016, the Company continues to set out its plans, among other things, to upgrade and diversify its generation portfolio. 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 Vectren's Corporate Responsibility and Sustainability Committee, as well as vetted with Vectren's full Board of Directors. Further discussion of key goals, strategies, and governance practices can be found in the Company’s latest sustainability report at www.vectren.com/sustainability, which received core level certification from the Global Reporting Initiative. 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. Integrated Resource Planning Process As required by the state of Indiana, the Company completed its 2016 Integrated Resource Plan (IRP) and submitted to the IURC for review on December 16, 2016. The Company anticipates the IURC will, likely in the summer of 2017, release a director’s report to the other state utilities that filed their IRPs in 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. Currently, the Company operates approximately 1,000 MW of coal-fired generation, 245 MW of natural gas peaking units, and 3 MW via a landfill-gas-to-electricity facility. The Company also has 80 MW of wind power through two long-term power purchase agreements and 32 MW of coal generation through its ownership in OVEC. The Company’s 2016 IRP preferred portfolio illustrates a future less reliant on coal. The twenty year plan reflects the retirement of a portion of the Company’s current coal-fired fleet, transitions a significant portion of generation to natural gas and includes new renewable energy sources, specifically universal solar. The detailed plan would introduce approximately 54 MW of universal solar installed by 2019. The plan suggests the Company will exit its joint operations of Warrick Unit 4, a 300 MW unit shared with Alcoa, by 2020. The Company would complete upgrades to its existing coal-fired Culley Unit 3, a 270 -megawatt unit, to comply with federal water regulations specific to the Effluent Limitations Guidelines (ELG) around 2023 in order to keep the unit in operation. In 2024, the plan points to the retirement of coal-fired AB Brown plant Units 1 & 2 along with Culley Unit 2, collectively representing 580 MW. This generation would be replaced by a newly constructed combined cycle natural gas plant, with the capability of producing approximately 890 MW by 2024. In addition, the Company intends to continue to offer energy efficiency programs annually. The Company’s plan 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. The Company plans to finalize this generation portfolio transition plan and submit a regulatory filing, including construction timelines and costs of new generation resources, to the IURC in late 2017 to begin the generation transition process. The Company believes that all compliance costs, including cost of new generation as well as the cost of retiring generation, would be considered a federally mandated cost of providing electricity and therefore should be recoverable either from customers through Senate Bill 251 as referenced above, Senate Bill 29 used by the Company to recover its initial pollution control investments, or through other forms of rate recovery. Coal Ash Waste Disposal, Ash Ponds and Water Coal Combustion Residuals Rule In December 2014, the EPA released its final Coal Combustion Residuals (CCR) rule which regulates ash as non-hazardous material under Subtitle D of the Resource Conservation and Recovery Act (RCRA). On April 17, 2015, the final rule was published in the Federal Register. The final rule allows beneficial reuse of ash and the majority of the ash generated by the Company’s generating plants will continue to be reused. As it relates to the CCR rule, legislation was passed in December 2016 by Congress that would provide for enforcement of the federal program by states rather than through citizen suits. Additionally, the CCR rule is currently being challenged by multiple parties in judicial review proceedings. Under the final CCR rule, the Company is required to complete a series of integrity assessments, including seismic modeling given the Company’s facilities are located within two seismic zones, and groundwater monitoring studies to determine the remaining service life of the ponds and whether a pond must be retrofitted with liners or closed in place, with bottom ash handling conversions completed. In late 2015, 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. Throughout 2016, the Company has continued to refine site specific estimates and now estimates the costs to be in the range of $45 million to $100 million . Significant factors impacting the resulting cost estimates include the closure time frame and the method of closure. Current estimates contemplate additional beneficial reuse of the ash, as well as implications of the Company’s preferred IRP. Ongoing analysis, the continued refinement of assumptions, or the inability to beneficially reuse the ash may result in estimated costs in excess of the current range. As of December 31, 2016, the Company had 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 has 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 (ELGs) Under the Clean Water Act, the EPA sets technology-based guidelines for water discharges from new and existing electric generation facilities. On September 30, 2015, the EPA released final revisions to the existing steam electric ELGs setting stringent technology-based water discharge limits for the electric power industry. The EPA focused this rulemaking on wastewater generated primarily by pollution control equipment necessitated by the comprehensive air regulations, specifically setting strict water discharge limits for arsenic, mercury and selenium for scrubber waste waters. The ELGs will be implemented when existing water discharge permits for the plants are renewed, with compliance activities expected to commence where operations continue, within the 2018-2023 time frame. The ELGs 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. The current 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. The Company is continuing ongoing discussions with the state environmental agency during the first half of 2017 and anticipates final permits will be issued in the second quarter of 2017. During the renewal process, existing permits remain in place. As part of the permit renewals, the Company requested alternate compliance dates for ELGs. Compliance with the ELGs will not be required prior to November 2018, but no later than December 31, 2023. For plants identified in the Company’s preferred IRP to be retired prior to December 31, 2023, the Company has requested those plants would not require new treatment technology. For the F.B. Culley plant, the Company has proposed a 2020 compliance date for dry bottom ash and 2023 compliance date for flue gas desulfurization wastewater. The Company anticipates acceptance of the proposed schedule. 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 a state level case-by-case assessment of BTA for each facility. The final rule lists seven presumptive technologies which would qualify as BTA. These technologies range from intake screen modifications to cooling water tower retrofits. Ecological and technology assessment studies must be completed prior to determining BTA for the Company’s facilities. 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 Mercury and Air Toxics (MATS) Rule On December 21, 2011, the EPA finalized the utility MATS rule. The MATS rule sets emission limits for hazardous air pollutants for existing and new coal-fired power plants and identifies the following broad categories of hazardous air pollutants: mercury, non-mercury hazardous air pollutants (primarily arsenic, chromium, cobalt, and selenium), and acid gases (hydrogen cyanide, hydrogen chloride, and hydrogen fluoride). The rule imposes mercury emission limits for two sub-categories of coal and proposed surrogate limits for non-mercury and acid gas hazardous air pollutants. In July 2014, a coalition of twenty-one states, including Indiana, filed a petition with the U.S. Supreme Court seeking review of the decision of the appellate court that found the EPA appropriately based its decision to list coal and oil fired generation units as a source of the pollutants at issue solely on those pollutants’ impact on public health. On June 29, 2015, the U.S. Supreme Court reversed the appellate court decision on the basis of the EPA’s failure to consider costs before determining whether it was appropriate and necessary to regulate steam electric generating units under Section 112 of the Clean Air Act. The Court did not vacate the rule, but remanded the MATS rule to the appellate court for further proceedings consistent with the opinion. In April 2016, in response to the Court's remand, the EPA affirmed its earlier conclusion in a Supplemental Finding, and in June 2016, a coalition of states and other stakeholders filed challenges to the Supplemental Finding. MATS compliance was required to commence April 16, 2015, and the Company continues to operate in full compliance with the MATS rule. Notice of Violation for A.B. Brown Power Plant The Company received a NOV from the EPA in November 2011 pertaining to its A.B. Brown generating station. The NOV asserts when the facility was equipped with Selective Catalytic Reduction (SCR) systems, the correct permits were not obtained or the best available control technology to control incidental sulfuric acid mist was not installed. While the Company did not agree with the notice, it reached a final settlement with the EPA to resolve the NOV in December 2015. As noted previously, on January 28, 2015, the IURC issued an Order approving the Company’s request for approval of capital investments on its coal-fired generation units to comply with new EPA mandates related to MATS effective in 2015 and to address the outstanding NOV. The total investment was $70 million of which $30 million was spent to control mercury in both air and water emissions, and the remaining investment was made to address the issues raised in the NOV. In June 2015, Joint Appellants’ Citizens Action Coalition of Indiana, Inc., Sierra Club, Inc., and Valley Watch, Inc. (the appellants) challenged the IURC's January Order. On October 29, 2015, the Indiana Court of Appeals issued an opinion that affirmed the IURC’s findings with regard to equipment required to comply with MATS and certain national pollutant discharge elimination system rules (approximately $30 million ) but remanded the case to the IURC to determine whether a certificate of public convenience and necessity (CPCN) should be issued for the equipment required by the NOV (approximately $40 million ). On June 22, 2016, the IURC issued an Order granting Vectren a CPCN for the NOV-required equipment. On July 21, 2016, the appellants initiated an appeal of the IURC's June 22, 2016 Order challenging the findings made by the IURC. On February 14, 2017, the Court affirmed the IURC's June 22, 2016 Order. Ozone NAAQS On November 26, 2014, the EPA proposed to tighten the current National Ambient Air Quality Standard (NAAQS) for ozone from the current standard of 75 parts per billion (ppb) to a level with the range of 65 to 70 ppb. On October 1, 2015, the EPA finalized a new NAAQS for ozone at the high end of the range, or 70 ppb. On September 16, 2016, Indiana submitted its initial determination to the EPA recommending that 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. The EPA is expected to make final determinations as to whether a region is in attainment for the new NAAQS in 2017. While it is possible that counties in southwest Indiana could be declared in non-attainment with the new standard, and thus could have an effect on future economic development activities in the Company's service territory, the Company does not anticipate any significant compliance cost impacts from the determination given its previous investment in SCR technology for NOx control on its units. In September 2016, the EPA finalized a supplement to the Cross State Air Pollution Rule (CSAPR) that requires further NOx reductions during the ozone season (May - September). The Company is positioned to comply with these NOx reduction requirements through its current investment in SCR technology. One Hour SO2 NAAQS On February 16, 2016, the EPA notified states of the commencement of a 120 day consultation period between the state and the EPA with respect to the EPA's recommendations for new non-attainment designations for the 2010 One Hour SO2 NAAQS. Identified on the list was Posey County, Indiana, 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 the state of Indiana on voluntary measures that the Company was able to implement without significant incremental costs to ensure that Posey County remains in attainment with the 2010 One Hour SO2 NAAQS. The Company's coal-fired generating fleet is 100 percent scrubbed for SO2 and 90 percent controlled for NOx. Climate Change On August 3, 2015, the EPA released its final CPP rule which requires a 32 percent reduction in carbon emissions from 2005 levels. This results in a final emission rate goal for Indiana of 1,242 lb CO2/MWh to be achieved by 2030. The new rule gives states the option of seeking a two-year extension from the initial deadline of September 2016 to submit a final state implementation plan (SIP). Under the CPP, states have the flexibility to include energy efficiency and other measures should they choose to implement a SIP as provided in the final rule. While states are given an interim goal (1,451 lb CO2/MWh for Indiana), the final rule gives states the flexibility to shape their own emissions reduction over the 2022-2029 time period. The final rule was published in the Federal Register on October 23, 2015 and that action was immediately followed by litigation initiated by Indiana and 23 other states as a coalition challenging the rule. In January of 2016, the reviewing court denied the states’ and other parties requests to stay the implementation of the CPP pending completion of judicial review. On January 26, 2016, 29 states and state agencies, including the 24 state coalition referenced above, filed a request for immediate stay with the U.S. Supreme Court. On February 9, 2016, the U.S. Supreme Court granted a stay to delay the regulation while being challenged in court. Extensive oral argument was held in September. The stay will remain in place while the lower court concludes its review. Among other things, the stay delays the requirement to submit a final SIP by the original September 2016 deadline and could extend implementation to 2024. In the event a state does not submit a SIP, the EPA also released a proposed federal implementation plan (FIP), which would be imposed on those states without an approved SIP. The proposed FIP would apply an emission rate requirement directly on generating units. Under the proposed FIP, the CO2 emission rate limit for coal-fired units would start at 1,671 lbs CO2/MWh in 2022 and decrease to a final emission rate cap of 1,305 lbs CO2/MWh by 2030. While the FIP emission rate cap appears to be slightly less stringent than the state reduction goal for Indiana, the cap would apply directly to generating units and these units would not have the benefit of averaging emission rates with rates from zero-carbon sources as would be available in a SIP. Purchases of emission credits from zero-carbon sources can be made for compliance. The FIP will be subject to extensive public comments prior to finalization. Whether Indiana will file a SIP has yet to be determined. Pending that determination, the electric utilities in Indiana will continue to encourage the state's designated agency to analyze various compliance options and the possible integration into a state plan submittal. At the time of release of the CPP, Indiana was the 5th largest carbon emitter in the nation in tons of CO2 produced from electric generation. The Company’s share of total tons of CO2 generated by Indiana's electric utilities has historically been less than 6 percent . Since 2005 through 2015, the Company has achieved a reduction in emissions of CO2 of 31 percent (on a tonnage basis) through the retirement of F.B. Culley Unit 1, expiration of municipal wholesale power contracts, electric conservation, the addition of renewable generation, and the installation of more efficient dense pack turbine technology. Since emissions are further impacted by coal burn reductions and energy efficiency programs, the Company's emissions of CO2 can vary year to year. With respect to renewable generation, in 2008 and 2009, the Company executed long-term purchase power commitments for a total of 80 MW of wind energy. The Company currently has approximately 4 percent of its electricity being provided by energy sources other than coal and natural gas, due to the long-term wind contracts and landfill gas investment. With respect to CO2 emission rate, since 2005 through 2015, the Company has lowered its CO2 emission rate (as measured in lbs CO2/MWh) from 1,967 lbs CO2/MWh to 1,922 lbs CO2/MWh, for a reduction of 3 percent . The Company’s CO2 emission rate of 1,922 lbs CO2/MWh is basically the same as Indiana's average CO2 emission rate of 1,923 lbs CO2/MWh. The Company plans to consider these reductions in CO2 emissions and renewable generation in future discussions with the state to develop a possible state implementation plan. Impact of Legislative Actions & Other Initiatives is Unknown At this time, compliance costs and other effects associated with reductions in GHG emissions or obtaining renewable energy sources remain uncertain. The Company has gathered preliminary estimates of the costs to control GHG emissions. A preliminary investigation demonstrated costs to comply would be significant, first with regard to operating expenses and later for capital expenditures as technology becomes available to control GHG emissions. However, these compliance cost estimates were based on highly uncertain assumptions, including allowance prices if a cap and trade approach were employed, and energy efficiency targets. The Company is undertaking a detailed review of the requirements of the CPP and the proposed FIP and a review of potential compliance options. The Company will also continue to remain engaged with the Indiana legislators and regulators to assess the final rule and to develop a plan that is the least cost to its customers. 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. As previously noted, since 2005 through 2015, the Company has achieved reduced emissions of CO2 by 31 percent (on a tonnage basis). While the legislative outcome 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 $15.2 million of the expected $15.8 million in insurance recoveries. The costs the Company expects to incur are estimated by management using assumptions based on actual costs incurred, the timing of expected future payments, and inflation factors, among others. While the Company’s utilities have recorded all costs which they presently expect to incur in connection with activities at these sites, it is possible that future events may require remedial activities which are not presently foreseen and those costs may not be subject to PRP or insurance recovery. As of December 31, 2016 and December 31, 2015 , approximately $2.9 million and $3.3 million , respectively, of accrued, but not yet spent, costs are included in Other Liabilities related to the Indiana Gas and SIGECO sites.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2016
Fair Value Disclosures [Abstract]
Fair Value Measurements	Fair Value Measurements The carrying values and estimated fair values using primarily Level 2 assumptions of the Company's other financial instruments follow: At December 31, 2016 2015 (In millions) Carrying Amount Est. Fair Value Carrying Amount Est. Fair Value Long-term debt $ 1,380.1 $ 1,495.3 $ 1,392.2 $ 1,495.0 Short-term borrowings 194.4 194.4 14.5 14.5 Cash & cash equivalents 9.4 9.4 6.2 6.2 Restricted cash 0.9 0.9 5.9 5.9 For the balance sheets dates presented in these financial statements, the Company had no material assets or liabilities marked to fair value. Certain methods and assumptions must be used to estimate the fair value of financial instruments. The fair value of the Company's long-term debt was estimated based on the quoted market prices for the same or similar issues or on the current rates offered to the Company for instruments with similar characteristics. Because of the maturity dates and variable interest rates of short-term borrowings and cash & cash equivalents, those carrying amounts approximate fair value. Because of the inherent difficulty of estimating interest rate and other market risks, the methods used to estimate fair value may not always be indicative of actual realizable value, and different methodologies could produce different fair value estimates at the reporting date. Under current regulatory treatment, call premiums on reacquisition of utility-related long-term debt are generally recovered in customer rates over the life of the refunding issue. Accordingly, any reacquisition of this debt would not be expected to have a material effect on the Company's results of operations.

Segment Reporting

Segment Reporting	12 Months Ended
	Dec. 31, 2016
Segment Reporting [Abstract]
Segment Reporting	Segment Reporting The Company’s operations consist of regulated operations and other operations that provide information technology and other support services to those regulated operations. The Company segregates its regulated operations between a Gas Utility Services operating segment and an Electric Utility Services operating segment. The Gas Utility Services segment provides natural gas distribution and transportation services to nearly two-thirds of Indiana and to west-central Ohio. The Electric Utility Services segment provides electric distribution services primarily to southwestern Indiana, and includes the Company’s power generating and wholesale power operations. Regulated operations supply natural gas and/or electricity to over one million customers. In total, the Company is comprised of three operating segments: Gas Utility Services, Electric Utility Services, and Other Operations. Net income is the measure of profitability used by management for all operations. Information related to the Company’s business segments is summarized below: Year Ended December 31, (In millions) 2016 2015 2014 Revenues Gas Utility Services $ 771.7 $ 792.6 $ 944.6 Electric Utility Services 605.8 601.6 624.8 Other Operations 42.2 40.7 38.3 Eliminations (41.9 ) (40.4 ) (38.0 ) Total revenues $ 1,377.8 $ 1,394.5 $ 1,569.7 Profitability Measure - Net Income Gas Utility Services $ 76.1 $ 64.4 $ 57.0 Electric Utility Services 84.7 82.6 79.7 Other Operations 12.8 13.9 11.7 Total net income $ 173.6 $ 160.9 $ 148.4 Amounts Included in Profitability Measures Depreciation & Amortization Gas Utility Services $ 108.1 $ 98.6 $ 93.3 Electric Utility Services 87.1 85.6 85.7 Other Operations 23.9 24.6 24.1 Total depreciation & amortization $ 219.1 $ 208.8 $ 203.1 Interest Expense Gas Utility Services $ 40.1 $ 35.8 $ 34.9 Electric Utility Services 27.0 27.8 29.0 Other Operations 2.6 2.7 2.7 Total interest expense $ 69.7 $ 66.3 $ 66.6 Income Taxes Gas Utility Services $ 47.1 $ 40.8 $ 35.7 Electric Utility Services 50.1 49.3 48.1 Other Operations 2.3 (2.0 ) (0.6 ) Total income taxes $ 99.5 $ 88.1 $ 83.2 Capital Expenditures Gas Utility Services $ 358.5 $ 291.2 $ 245.9 Electric Utility Services 106.4 87.6 92.4 Other Operations 39.0 25.7 22.8 Non-cash costs & changes in accruals (7.3 ) (5.3 ) (10.1 ) Total capital expenditures $ 496.6 $ 399.2 $ 351.0 At December 31, (In millions) 2016 2015 2014 Assets Gas Utility Services $ 3,091.0 $ 2,706.9 $ 2,604.6 Electric Utility Services 1,788.4 1,778.3 1,656.2 Other Operations, net of eliminations 161.5 107.5 148.5 Total assets $ 5,040.9 $ 4,592.7 $ 4,409.3

Additional Balance Sheet & Oper

Additional Balance Sheet & Operational Information	12 Months Ended
	Dec. 31, 2016
Additional Balance Sheet and Operational Information [Abstract]
Additional Balance Sheet & Operational Information	Additional Balance Sheet & Operational Information Inventories consist of the following: At December 31, (In millions) 2016 2015 Gas in storage – at LIFO cost $ 37.0 $ 40.5 Materials & supplies 38.1 38.4 Coal & oil for electric generation - at average cost 42.6 45.0 Other 1.3 1.4 Total inventories $ 119.0 $ 125.3 Based on the average cost of gas purchased during December, the cost of replacing inventories carried at LIFO cost exceeded carrying value at December 31, 2016 by $1.0 million . Based on the average cost of gas purchased during December, the cost of replacing inventories carried at LIFO cost approximated that carrying value at December 31, 2015 . Prepayments & other current assets in the Consolidated Balance Sheets consist of the following: At December 31, (In millions) 2016 2015 Prepaid gas delivery service $ 26.4 $ 30.0 Prepaid taxes 8.0 3.9 Other prepayments & current assets 4.2 15.1 Total prepayments & other current assets $ 38.6 $ 49.0 Other investments in the Consolidated Balance Sheets consist of the following: At December 31, (In millions) 2016 2015 Cash surrender value of life insurance policies $ 20.4 $ 19.2 Restricted cash & other investments 0.9 0.9 Total other investments $ 21.3 $ 20.1 Accrued liabilities in the Consolidated Balance Sheets consist of the following: At December 31, (In millions) 2016 2015 Refunds to customers & customer deposits $ 49.4 $ 51.4 Accrued taxes 44.8 36.7 Accrued interest 16.4 16.3 Accrued salaries & other 29.5 24.0 Total accrued liabilities $ 140.1 $ 128.4 Asset retirement obligations included in Deferred credits and other liabilities in the Consolidated Balance Sheets roll forward as follows: (In millions) 2016 2015 Asset retirement obligation, January 1 $ 81.9 $ 54.6 Accretion 3.8 3.3 Liabilities incurred in current period — 24.2 Changes in estimates, net of cash payments 20.9 (0.2 ) Asset retirement obligation, December 31 $ 106.6 $ 81.9 Other – net in the Consolidated Statements of Income consists of the following: Year Ended December 31, (In millions) 2016 2015 2014 AFUDC - borrowed funds $ 20.3 $ 16.3 $ 10.8 AFUDC - equity funds 2.2 2.6 3.2 Nonutility plant capitalized interest 1.0 0.4 0.6 Interest income 0.3 0.6 0.7 Other income 2.5 (1.2 ) 1.5 Total other – net $ 26.3 $ 18.7 $ 16.8 Supplemental Cash Flow Information: Year Ended December 31, (In millions) 2016 2015 2014 Cash paid (received) for: Interest $ 69.6 $ 66.2 $ 66.7 Income taxes 6.7 (23.1 ) 63.2 As of December 31, 2016 and 2015 , the Company has accruals related to utility and nonutility plant purchases totaling approximately $27.4 million and $18.1 million , respectively.

Subsidiary Guarantor & Consolid

Subsidiary Guarantor & Consolidating Information	12 Months Ended
	Dec. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Subsidiary Guarantor & Consolidating Information	Subsidiary Guarantor & Consolidating Information The Company’s three operating utility companies, SIGECO, Indiana Gas, and VEDO, are guarantors of the Company’s $350 million in short-term credit facilities, of which $194 million is outstanding at December 31, 2016 , and the Company’s $996 million unsecured senior notes outstanding at December 31, 2016 . The guarantees are full and unconditional and joint and several, and the Company has no subsidiaries other than the subsidiary guarantors. However, it does have operations other than those of the subsidiary guarantors. Pursuant to Item 3-10 of Regulation S-X, disclosure of the results of operations and balance sheets of the subsidiary guarantors, which are wholly owned, separate from the parent company’s operations is required. Following are consolidating financial statements including information on the combined operations of the subsidiary guarantors separate from the other operations of the parent company. Pursuant to a tax sharing agreement, consolidating tax effects, which are calculated on a separate return basis, are reflected at the parent level. Consolidating Statement of Income for the year ended December 31, 2016 (in millions): Subsidiary Guarantors Parent Company Reclassifications and Eliminations Consolidated OPERATING REVENUES Gas utility $ 771.7 $ — $ — $ 771.7 Electric utility 605.8 — — 605.8 Other — 42.2 (41.9 ) 0.3 Total operating revenues 1,377.5 42.2 (41.9 ) 1,377.8 OPERATING EXPENSES Cost of gas sold 266.7 — — 266.7 Cost of fuel & purchased power 183.6 — — 183.6 Other operating 374.0 — (40.4 ) 333.6 Depreciation & amortization 195.2 23.8 0.1 219.1 Taxes other than income taxes 56.8 1.5 — 58.3 Total operating expenses 1,076.3 25.3 (40.3 ) 1,061.3 OPERATING INCOME 301.2 16.9 (1.6 ) 316.5 OTHER INCOME (EXPENSE) Equity in earnings of consolidated companies — 160.8 (160.8 ) — Other – net 24.0 48.3 (46.0 ) 26.3 Total other income (expense) 24.0 209.1 (206.8 ) 26.3 Interest expense 67.2 50.1 (47.6 ) 69.7 INCOME BEFORE INCOME TAXES 258.0 175.9 (160.8 ) 273.1 Income taxes 97.2 2.3 — 99.5 NET INCOME $ 160.8 $ 173.6 $ (160.8 ) $ 173.6 Consolidating Statement of Income for the year ended December 31, 2015 (in millions): Subsidiary Guarantors Parent Company Reclassifications and Eliminations Consolidated OPERATING REVENUES Gas utility $ 792.6 $ — $ — $ 792.6 Electric utility 601.6 — — 601.6 Other — 40.7 (40.4 ) 0.3 Total operating revenues 1,394.2 40.7 (40.4 ) 1,394.5 OPERATING EXPENSES Cost of gas sold 305.4 — — 305.4 Cost of fuel & purchased power 187.5 — — 187.5 Other operating 376.9 — (37.8 ) 339.1 Depreciation & amortization 184.2 24.3 0.3 208.8 Taxes other than income taxes 55.2 1.8 0.1 57.1 Total operating expenses 1,109.2 26.1 (37.4 ) 1,097.9 OPERATING INCOME 285.0 14.6 (3.0 ) 296.6 OTHER INCOME (EXPENSE) Equity in earnings of consolidated companies — 147.0 (147.0 ) — Other – net 15.7 42.7 (39.7 ) 18.7 Total other income (expense) 15.7 189.7 (186.7 ) 18.7 Interest expense 63.7 45.3 (42.7 ) 66.3 INCOME BEFORE INCOME TAXES 237.0 159.0 (147.0 ) 249.0 Income taxes 90.0 (1.9 ) — 88.1 NET INCOME $ 147.0 $ 160.9 $ (147.0 ) $ 160.9 Consolidating Statement of Income for the year ended December 31, 2014 (in millions): Subsidiary Guarantors Parent Company Reclassifications and Eliminations Consolidated OPERATING REVENUES Gas utility $ 944.6 $ — $ — $ 944.6 Electric utility 624.8 — — 624.8 Other — 38.3 (38.0 ) 0.3 Total operating revenues 1,569.4 38.3 (38.0 ) 1,569.7 OPERATING EXPENSES Cost of gas sold 468.7 — — 468.7 Cost of fuel & purchased power 201.8 — — 201.8 Other operating 390.3 — (35.8 ) 354.5 Depreciation & amortization 179.1 23.5 0.5 203.1 Taxes other than income taxes 58.4 1.7 0.1 60.2 Total operating expenses 1,298.3 25.2 (35.2 ) 1,288.3 OPERATING INCOME 271.1 13.1 (2.8 ) 281.4 OTHER INCOME (EXPENSE) Equity in earnings of consolidated companies — 136.7 (136.7 ) — Other – net 13.3 43.2 (39.7 ) 16.8 Total other income (expense) 13.3 179.9 (176.4 ) 16.8 Interest expense 63.9 45.2 (42.5 ) 66.6 INCOME BEFORE INCOME TAXES 220.5 147.8 (136.7 ) 231.6 Income taxes 83.8 (0.6 ) — 83.2 NET INCOME $ 136.7 $ 148.4 $ (136.7 ) $ 148.4 Consolidating Balance Sheet as of December 31, 2016 (in millions): ASSETS Subsidiary Parent Guarantors Company Eliminations Consolidated Current Assets Cash & cash equivalents $ 7.6 $ 1.8 $ — $ 9.4 Accounts receivable - less reserves 102.4 0.2 — 102.6 Intercompany receivables 17.5 157.1 (174.6 ) — Accrued unbilled revenues 112.0 — — 112.0 Inventories 119.0 — — 119.0 Recoverable fuel & natural gas costs 29.9 — — 29.9 Prepayments & other current assets 36.5 4.4 (2.3 ) 38.6 Total current assets 424.9 163.5 (176.9 ) 411.5 Utility Plant Original cost 6,545.4 — — 6,545.4 Less: accumulated depreciation & amortization 2,562.5 — — 2,562.5 Net utility plant 3,982.9 — — 3,982.9 Investments in consolidated subsidiaries — 1,577.2 (1,577.2 ) — Notes receivable from consolidated subsidiaries — 945.4 (945.4 ) — Investments in unconsolidated affiliates 0.2 — — 0.2 Other investments 20.9 0.4 — 21.3 Nonutility plant - net 1.7 163.1 — 164.8 Goodwill - net 205.0 — — 205.0 Regulatory assets 190.0 16.2 — 206.2 Other assets 53.9 3.7 (8.6 ) 49.0 TOTAL ASSETS $ 4,879.5 $ 2,869.5 $ (2,708.1 ) $ 5,040.9 LIABILITIES & SHAREHOLDER'S EQUITY Subsidiary Parent Guarantors Company Eliminations Consolidated Current Liabilities Accounts payable $ 194.6 $ 10.8 $ — $ 205.4 Intercompany payables 14.8 — (14.8 ) — Payables to other Vectren companies 25.4 — — 25.4 Accrued liabilities 126.0 16.4 (2.3 ) 140.1 Short-term borrowings — 194.4 — 194.4 Intercompany short-term borrowings 142.3 17.5 (159.8 ) — Current maturities of long-term debt 49.1 — — 49.1 Total current liabilities 552.2 239.1 (176.9 ) 614.4 Long-Term Debt Long-term debt - net of current maturities & debt subject to tender 335.2 995.8 — 1,331.0 Long-term debt due to VUHI 945.4 — (945.4 ) — Total long-term debt - net 1,280.6 995.8 (945.4 ) 1,331.0 Deferred Income Taxes & Other Liabilities Deferred income taxes 855.4 (0.9 ) — 854.5 Regulatory liabilities 452.4 1.3 — 453.7 Deferred credits & other liabilities 161.7 10.2 (8.6 ) 163.3 Total deferred credits & other liabilities 1,469.5 10.6 (8.6 ) 1,471.5 Common Shareholder's Equity Common stock (no par value) 844.4 831.2 (844.4 ) 831.2 Retained earnings 732.8 792.8 (732.8 ) 792.8 Total common shareholder's equity 1,577.2 1,624.0 (1,577.2 ) 1,624.0 TOTAL LIABILITIES & SHAREHOLDER'S EQUITY $ 4,879.5 $ 2,869.5 $ (2,708.1 ) $ 5,040.9 Consolidating Balance Sheet as of December 31, 2015 (in millions): ASSETS Subsidiary Parent Guarantors Company Eliminations Consolidated Current Assets Cash & cash equivalents $ 5.5 $ 0.7 $ — $ 6.2 Accounts receivable - less reserves 92.3 — — 92.3 Intercompany receivables 51.2 142.9 (194.1 ) — Accrued unbilled revenues 85.7 — — 85.7 Inventories 125.3 — — 125.3 Prepayments & other current assets 49.3 4.1 (4.4 ) 49.0 Total current assets 409.3 147.7 (198.5 ) 358.5 Utility Plant Original cost 6,090.4 — — 6,090.4 Less: accumulated depreciation & amortization 2,415.5 — — 2,415.5 Net utility plant 3,674.9 — — 3,674.9 Investments in consolidated subsidiaries — 1,467.0 (1,467.0 ) — Notes receivable from consolidated subsidiaries — 836.0 (836.0 ) — Investments in unconsolidated affiliates 0.2 — — 0.2 Other investments 19.7 0.4 — 20.1 Nonutility plant - net 1.7 148.0 — 149.7 Goodwill - net 205.0 — — 205.0 Regulatory assets 135.2 16.9 — 152.1 Other assets 39.6 1.3 (8.7 ) 32.2 TOTAL ASSETS $ 4,485.6 $ 2,617.3 $ (2,510.2 ) $ 4,592.7 LIABILITIES & SHAREHOLDER'S EQUITY Subsidiary Parent Guarantors Company Eliminations Consolidated Current Liabilities Accounts payable $ 161.1 $ 7.4 $ — $ 168.5 Intercompany payables 12.4 — (12.4 ) — Payables to other Vectren companies 25.7 — — 25.7 Accrued liabilities 120.2 12.6 (4.4 ) 128.4 Short-term borrowings — 14.5 — 14.5 Intercompany short-term borrowings 130.5 51.2 (181.7 ) — Current maturities of long-term debt 13.0 — — 13.0 Total current liabilities 462.9 85.7 (198.5 ) 350.1 Long-Term Debt Long-term debt - net of current maturities & debt subject to tender 383.9 995.3 — 1,379.2 Long-term debt due to VUHI 836.0 — (836.0 ) — Total long-term debt - net 1,219.9 995.3 (836.0 ) 1,379.2 Deferred Income Taxes & Other Liabilities Deferred income taxes 763.7 (5.3 ) — 758.4 Regulatory liabilities 432.5 1.4 — 433.9 Deferred credits & other liabilities 139.6 5.0 (8.7 ) 135.9 Total deferred credits & other liabilities 1,335.8 1.1 (8.7 ) 1,328.2 Common Shareholder's Equity Common stock (no par value) 813.1 799.9 (813.1 ) 799.9 Retained earnings 653.9 735.3 (653.9 ) 735.3 Total common shareholder's equity 1,467.0 1,535.2 (1,467.0 ) 1,535.2 TOTAL LIABILITIES & SHAREHOLDER'S EQUITY $ 4,485.6 $ 2,617.3 $ (2,510.2 ) $ 4,592.7 Consolidating Statement of Cash Flows for the year ended December 31, 2016 (in millions): Subsidiary Guarantors Parent Company Eliminations Consolidated NET CASH PROVIDED BY OPERATING ACTIVITIES $ 352.2 $ 45.2 $ — $ 397.4 CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from: Long-term debt, net of issuance costs 109.4 — (109.4 ) — Additional capital contribution from Parent 31.3 31.3 (31.3 ) 31.3 Requirements for: Dividends to parent (82.0 ) (116.1 ) 82.0 (116.1 ) Retirement of long-term debt (13.0 ) — — (13.0 ) Net change in intercompany short-term borrowings 11.9 (33.7 ) 21.8 — Net change in short-term borrowings — 179.9 — 179.9 Net cash used in financing activities 57.6 61.4 (36.9 ) 82.1 CASH FLOWS FROM INVESTING ACTIVITIES Proceeds from: Consolidated subsidiary distributions — 82.0 (82.0 ) — Other investing activities 15.3 — — 15.3 Requirements for: Capital expenditures, excluding AFUDC equity (461.7 ) (34.9 ) — (496.6 ) Consolidated subsidiary investments — (31.3 ) 31.3 — Changes in restricted cash 5.0 — — 5.0 Net change in long-term intercompany notes receivable — (109.4 ) 109.4 — Net change in short-term intercompany notes receivable 33.7 (11.9 ) (21.8 ) — Net cash used in investing activities (407.7 ) (105.5 ) 36.9 (476.3 ) Net change in cash & cash equivalents 2.1 1.1 — 3.2 Cash & cash equivalents at beginning of period 5.5 0.7 — 6.2 Cash & cash equivalents at end of period $ 7.6 $ 1.8 $ — $ 9.4 Consolidating Statement of Cash Flows for the year ended December 31, 2015 (in millions): Subsidiary Guarantors Parent Company Eliminations Consolidated NET CASH PROVIDED BY OPERATING ACTIVITIES $ 460.3 $ 32.6 $ — $ 492.9 CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from: Long-term debt, net of issuance costs 126.8 199.0 (89.5 ) 236.3 Additional capital contribution from Parent 6.2 6.2 (6.2 ) 6.2 Requirements for: Dividends to parent (103.2 ) (110.4 ) 103.2 (110.4 ) Retirement of long-term debt (20.0 ) (75.0 ) — (95.0 ) Net change in intercompany short-term borrowings (40.7 ) 51.2 (10.5 ) — Net change in short-term borrowings — (141.9 ) — (141.9 ) Net cash used in financing activities (30.9 ) (70.9 ) (3.0 ) (104.8 ) CASH FLOWS FROM INVESTING ACTIVITIES Proceeds from: Consolidated subsidiary distributions — 103.2 (103.2 ) — Other investing activities — 3.9 — 3.9 Requirements for: Capital expenditures, excluding AFUDC equity (373.7 ) (25.5 ) — (399.2 ) Consolidated subsidiary investments — (6.2 ) 6.2 — Changes in restricted cash (5.9 ) — — (5.9 ) Net change in long-term intercompany notes receivable — (89.5 ) 89.5 — Net change in short-term intercompany notes receivable (51.2 ) 40.7 10.5 — Net cash used in investing activities (430.8 ) 26.6 3.0 (401.2 ) Net change in cash & cash equivalents (1.4 ) (11.7 ) — (13.1 ) Cash & cash equivalents at beginning of period 6.9 12.4 — 19.3 Cash & cash equivalents at end of period $ 5.5 $ 0.7 $ — $ 6.2 Consolidating Statement of Cash Flows for the year ended December 31, 2014 (in millions): Subsidiary Guarantors Parent Company Eliminations Consolidated NET CASH PROVIDED BY OPERATING ACTIVITIES $ 274.4 $ 63.1 $ — $ 337.5 CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from: Long-term debt, net of issuance costs 186.6 — (124.2 ) 62.4 Additional capital contribution from Parent 6.0 6.0 (6.0 ) 6.0 Requirements for: Dividends to parent (101.6 ) (108.7 ) 101.6 (108.7 ) Retirement of long-term debt, including premiums paid (63.6 ) — — (63.6 ) Net change in intercompany short-term borrowings 23.9 (0.3 ) (23.6 ) — Net change in short-term borrowings — 127.8 — 127.8 Net cash used in financing activities 51.3 24.8 (52.2 ) 23.9 CASH FLOWS FROM INVESTING ACTIVITIES Proceeds from: Consolidated subsidiary distributions — 101.6 (101.6 ) — Other investing activities — 0.3 — 0.3 Requirements for: Capital expenditures, excluding AFUDC equity (327.3 ) (23.7 ) — (351.0 ) Consolidated subsidiary investments — (6.0 ) 6.0 — Net change in long-term intercompany notes receivable — (50.1 ) 50.1 — Net change in short-term intercompany notes receivable 0.3 (98.0 ) 97.7 — Net cash used in investing activities (327.0 ) (75.9 ) 52.2 (350.7 ) Net change in cash & cash equivalents (1.3 ) 12.0 — 10.7 Cash & cash equivalents at beginning of period 8.2 0.4 — 8.6 Cash & cash equivalents at end of period $ 6.9 $ 12.4 $ — $ 19.3

Impact of Recently Issued Accou

Impact of Recently Issued Accounting Guidance	12 Months Ended
	Dec. 31, 2016
Accounting Changes and Error Corrections [Abstract]
Impact of Recently Issued Accounting Guidance	Impact of Recently Issued Accounting Guidance Impact of Recently Issued Accounting Guidance Revenue Recognition Guidance In May 2014, the FASB issued new accounting guidance to clarify the principles for recognizing revenue and to develop a common revenue standard for GAAP. The amendments in this guidance state that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This new guidance requires improved disclosures to help users of financial statements better understand the nature, amount, timing, and uncertainty of revenue that is recognized. The guidance can be applied retrospectively to each prior reporting period presented (full retrospective method) or retrospectively with a cumulative effect adjustment to retained earnings for initial application of the guidance at the date of initial adoption (modified retrospective method). While the Company continues to assess the standard and initial conclusions could change based on completion of that assessment, the Company preliminarily plans to adopt the guidance under the modified retrospective method. On July 9, 2015, the FASB approved a one year deferral that became effective through an ASU in August and changed the effective date to annual reporting periods beginning after December 15, 2017, including interim periods, with early adoption permitted, but not before the original effective date of December 15, 2016. The Company is currently assessing the impacts this guidance may have on the Consolidated Balance Sheets, Consolidated Statements of Operations, and disclosures including the ability to recognize revenue for certain contracts, and its accounting for contributions in aid of construction (CIAC). While management will continue to analyze the impact of this new standard and the related ASUs that clarify guidance in the standard, at this time, management does not believe adoption of the standard will have a significant impact on the Company's pattern of revenue recognition. The Company plans to adopt the guidance effective January 1, 2018. Simplifying the Presentation of Debt Issuance Costs In April 2015, the FASB issued new accounting guidance on accounting for debt issuance costs which changes the presentation of debt issuance costs in financial statements. This ASU requires an entity to present such costs in the balance sheet as a direct reduction from the related debt liability rather than as an asset. Amortization of the costs will continue to be reported as interest expense. This ASU is effective for annual reporting periods beginning after December 15, 2015. The guidance was adopted as of January 1, 2016 and has been applied retrospectively to all periods presented. The effect of the change on the December 31, 2015 balance sheet was the reclassification of $8.6 million from Regulatory assets to Long-term Debt. The reclassification had no material impact on the Company's financial condition, results of operations, or cash flows as a result of the adoption. Leases In February 2016, the FASB issued new accounting guidance for the recognition, measurement, presentation and disclosure of leasing arrangements. This ASU requires the recognition of lease assets and liabilities for those leases currently classified as operating leases while also refining the definition of a lease. In addition, lessees will be required to disclose key information about the amount, timing, and uncertainty of cash flows arising from leasing arrangements. This ASU is effective for the interim and annual reporting periods beginning January 1, 2019, although it can be early adopted, with a modified retrospective approach for leases that commenced prior to the date of adoption. The Company is currently evaluating the standard to determine the impact it will have on the financial statements. Stock Compensation In March 2016, the FASB issued new accounting guidance which is intended to simplify several aspects of accounting for share-based payment transactions, including the income tax consequences. This ASU is effective for annual periods beginning after December 15, 2016, and relevant interim periods. Early application is permitted. The Company does not have share-based compensation plans separate from the Company's parent; the Company is however allocated costs associated with the plans of the Company's parent. Pursuant to these plans, share based awards are settled via cash payments and are therefore not impacted by this standard. The Company does not anticipate adoption of the standard to have a significant impact on the financial statements. Other Recently Issued Standards Management believes that other recently issued standards, which are not yet effective, will not have a material impact on the Company's financial position, results of operations, or cash flows upon adoption.

Quarterly Financial Data (Unaud

Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2016
Quarterly Financial Information Disclosure [Abstract]
Quarterly Financial Data (Unaudited)	Quarterly Financial Data (Unaudited) Information in any one quarterly period is not indicative of annual results due to the seasonal variations common to the Company’s utility operations. Summarized quarterly financial data for 2016 and 2015 follows: (In millions) Q1 Q2 Q3 Q4 2016 Results of Operations: Operating revenues $ 423.4 $ 279.8 $ 291.3 $ 383.5 Operating income 106.8 52.2 64.0 93.5 Net income 61.1 26.3 34.9 51.3 2015 Results of Operations: Operating revenues $ 506.9 $ 276.5 $ 273.0 $ 338.1 Operating income 110.8 50.5 54.1 81.3 Net income 63.0 24.4 26.9 46.6

SCHEDULE II VALUATION AND QUALI

SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES	12 Months Ended
	Dec. 31, 2016
Valuation and Qualifying Accounts [Abstract]
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES	SCHEDULE II Vectren Utility Holdings, Inc. and Subsidiaries VALUATION AND QUALIFYING ACCOUNTS AND RESERVES Column A Column B Column C Column D Column E Additions Balance at Charged Charged Deductions Balance at Beginning to to Other from End of Description Of Year Expenses Accounts Reserves, Net Year (In millions) VALUATION AND QUALIFYING ACCOUNTS: Year 2016 – Accumulated provision for uncollectible accounts $ 3.0 $ 6.6 $ — $ 5.5 $ 4.1 Year 2015 – Accumulated provision for uncollectible accounts $ 3.9 $ 6.9 $ — $ 7.8 $ 3.0 Year 2014 – Accumulated provision for uncollectible accounts $ 5.0 $ 6.1 $ — $ 7.2 $ 3.9

Summary of Significant Accoun25

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
Principles of Consolidation	Principles of Consolidation The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries, after appropriate elimination of intercompany transactions.
Subsequent Events Review	Subsequent Events Review Management performs a review of subsequent events for any events occurring after the balance sheet date but prior to the date the financial statements are issued.
Cash and Cash Equivalents	Cash & Cash Equivalents Highly liquid investments with an original maturity of three months or less at the date of purchase are considered cash equivalents. Cash and cash equivalents are stated at cost plus accrued interest to approximate fair value.
Allowance for Uncollectible Accounts	Allowance for Uncollectible Accounts The Company maintains allowances for uncollectible accounts for estimated losses resulting from the inability of its customers to make required payments. The Company estimates the allowance for uncollectible accounts based on a variety of factors including the length of time receivables are past due, the financial health of its customers, unusual macroeconomic conditions, and historical experience. If the financial condition of its customers deteriorates or other circumstances occur that result in an impairment of customers’ ability to make payments, the Company records additional allowances as needed.
Inventories	Inventories In most circumstances, the Company’s inventory components are recorded using an average cost method; however, natural gas in storage at the Company’s Indiana utilities are recorded using the Last In – First Out (LIFO) method. Inventory related to the Company’s regulated operations is valued at historical cost consistent with ratemaking treatment. Materials and supplies are recorded as inventory when purchased and subsequently charged to expense or capitalized to plant when installed.
Property, Plant & Equipment	Property, Plant & Equipment Both the Company’s Utility Plant and Nonutility Plant is stated at historical cost, inclusive of financing costs and direct and indirect construction costs, less accumulated depreciation and when necessary, impairment charges. The cost of renewals and betterments that extend the useful life are capitalized. Maintenance and repairs, including the cost of removal of minor items of property and planned major maintenance projects, are charged to expense as incurred. Utility Plant & Related Depreciation Both the IURC and PUCO allow the Company’s utilities to capitalize financing costs associated with Utility Plant based on a computed interest cost and a designated cost of equity funds. These financing costs are commonly referred to as AFUDC and are capitalized for ratemaking purposes and for financial reporting purposes instead of amounts that would otherwise be capitalized when acquiring nonutility plant. The Company reports both the debt and equity components of AFUDC in Other – net in the Consolidated Statements of Income . When property that represents a retirement unit is replaced or removed, the remaining historical value of such property is charged to Utility Plant , with an offsetting charge to Accumulated depreciation , resulting in no gain or loss. Costs to dismantle and remove retired property are recovered through the depreciation rates as determined by the IURC and PUCO. The Company’s portion of jointly owned Utility Plant , along with that plant’s related operating expenses, is presented in these financial statements in proportion to the ownership percentage. Nonutility Plant & Related Depreciation The depreciation of Nonutility Plant is charged against income over its estimated useful life, using the straight-line method of depreciation. When nonutility property is retired, or otherwise disposed of, the asset and accumulated depreciation are removed, and the resulting gain or loss is reflected in income, typically impacting operating expenses. Impairment Reviews Property, plant and equipment along with other long-lived assets are reviewed as facts and circumstances indicate the carrying amount may be impaired. This impairment review involves the comparison of an asset’s (or group of assets’) carrying value to the estimated future cash flows the asset (or asset group) is expected to generate over a remaining life. If this evaluation were to conclude the carrying value is impaired, an impairment charge would be recorded based on the difference between the carrying amount and its fair value (less costs to sell for assets to be disposed of by sale) as a charge to operations or discontinued operations.
Goodwill	Goodwill Goodwill recorded on the Consolidated Balance Sheets results from business acquisitions and is based on a fair value allocation of the businesses’ purchase price at the time of acquisition. Goodwill is charged to expense only when it is impaired. The Company tests its goodwill for impairment at an operating segment level because the components within the segments are similar. These tests are performed at least annually and at the beginning of each year. Impairment reviews consist of a comparison of fair value to the carrying amount. If the fair value is less than the carrying amount, an impairment loss is recognized in operations. No goodwill impairments have been recorded during the periods presented.
Regulation	Regulation Retail public utility operations affecting Indiana customers are subject to regulation by the IURC, and retail public utility operations affecting Ohio customers are subject to regulation by the PUCO. The Company’s accounting policies give recognition to the ratemaking and accounting practices authorized by these agencies. Refundable or Recoverable Gas Costs & Cost of Fuel & Purchased Power All metered gas rates in Indiana contain a gas cost adjustment clause that allows the Company to charge for changes in the cost of purchased gas. Metered electric rates contain a fuel adjustment clause that allows for adjustment in charges for electric energy to reflect changes in the cost of fuel. The net energy cost of purchased power, subject to a variable benchmark based on NYMEX natural gas prices, is also recovered through regulatory proceedings. The Company records any under-or-over-recovery resulting from gas and fuel adjustment clauses each month in revenues. A corresponding asset or liability is recorded until the under-or-over-recovery is billed or refunded to utility customers. The cost of gas sold is charged to operating expense as delivered to customers, and the cost of fuel and purchased power for electric generation is charged to operating expense when consumed. Regulatory Assets & Liabilities Regulatory assets represent certain incurred costs, which will result in probable future cash recoveries from customers through the ratemaking process. Regulatory liabilities represent probable expenditures by the Company for removal costs or future reductions in revenues associated with amounts to be credited to customers through the ratemaking process. The Company continually assesses the recoverability of costs recognized as regulatory assets and liabilities and the ability to recognize new regulatory assets and liabilities associated with its regulated utility operations. Given the current regulatory environment in its jurisdictions, the Company believes such accounting is appropriate. The Company collects an estimated cost of removal of its utility plant through depreciation rates established in regulatory proceedings. The Company records amounts expensed in advance of payments as a Regulatory liability because the liability does not meet the threshold of an asset retirement obligation.
Asset Retirement Obligations	Asset Retirement Obligations A portion of removal costs related to interim retirements of gas utility pipeline and utility poles, certain asbestos-related issues, and reclamation activities meet the definition of an asset retirement obligation (ARO). The Company records the fair value of a liability for a legal ARO in the period in which it is incurred. When the liability is initially recorded, the Company capitalizes a cost by increasing the carrying amount of the related long-lived asset. The liability is accreted, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, the Company settles the obligation for its recorded amount or incurs a gain or loss. To the extent regulation is involved, regulatory assets and liabilities result when accretion and amortization is adjusted to match rates established by regulators and any gain or loss is subject to deferral.
Energy Contracts & Derivatives	Energy Contracts & Derivatives The Company will periodically execute derivative contracts in the normal course of operations while buying and selling commodities to be used in operations, optimizing its generation assets, and managing risk. A derivative is recognized on the balance sheet as an asset or liability measured at its fair market value and the change in the derivative's fair market value is recognized currently in earnings unless specific hedge criteria are met. When an energy contract that is a derivative is designated and documented as a normal purchase or normal sale (NPNS), it is exempt from mark-to-market accounting. Most energy contracts executed by the Company are subject to the NPNS exclusion or are not considered derivatives. Such energy contracts include Real Time and Day Ahead purchase and sale contracts with the MISO, natural gas purchases, and wind farm and other electric generating contracts. When the Company engages in energy contracts and financial contracts that are derivatives and are not subject to the NPNS or other exclusions, such contracts are recorded at market value as current or noncurrent assets or liabilities depending on their value and when the contracts are expected to be settled. Contracts and any associated collateral with counter-parties subject to master netting arrangements are presented net in the Consolidated Balance Sheets . The offset resulting from carrying the derivative at fair value on the balance sheet is charged to earnings unless it qualifies as a hedge or is subject to regulatory accounting treatment. When hedge accounting is appropriate, the Company assesses and documents hedging relationships between the derivative contract and underlying risks as well as its risk management objectives and anticipated effectiveness. When the hedging relationship is highly effective, derivatives are designated as hedges. The market value of the effective portion of the hedge is marked to market in Accumulated other comprehensive income for cash flow hedges. Ineffective portions of hedging arrangements are marked to market through earnings. For fair value hedges, both the derivative and the underlying hedged item are marked to market through earnings. The offset to contracts affected by regulatory accounting treatment are marked to market as a regulatory asset or liability. Market value for derivative contracts is determined using quoted market prices from independent sources. The Company rarely enters into contracts that have a significant impact to the financial statements where internal models are used to calculate fair value. As of and for the periods presented, related derivative activity is not material to these financial statements.
Revenues	Revenues Revenues are recorded as products and services are delivered to customers. To more closely match revenues and expenses, the Company records revenues for all gas and electricity delivered to customers but not billed at the end of an accounting period in Accrued unbilled revenues . Substantially all revenue sources are subject to unbillled accruals.
MISO Transactions	MISO Transactions With the IURC’s approval, the Company is a member of the MISO, a FERC approved regional transmission organization. The MISO serves the electrical transmission needs of much of the Midcontinent region and maintains operational control over the Company’s electric transmission facilities as well as other utilities in the region. The Company is an active participant in the MISO energy markets, bidding its owned generation into the Day Ahead and Real Time markets and procuring power for its retail customers at Locational Marginal Pricing (LMP) as determined by the MISO market. MISO-related purchase and sale transactions are recorded using settlement information provided by the MISO. These purchase and sale transactions are accounted for on a net hourly position. Net purchases in a single hour are recorded in Cost of fuel & purchased power and net sales in a single hour are recorded in Electric utility revenues . On occasion, prior period transactions are resettled outside the routine process due to a change in the MISO’s tariff or a material interpretation thereof. Expenses associated with resettlements are recorded once the resettlement is probable and the resettlement amount can be estimated. Revenues associated with resettlements are recognized when the amount is determinable and collectability is reasonably assured. The Company also receives transmission revenue that results from other members’ use of the Company’s transmission system. These revenues are also included in Electric utility revenues. Generally, these transmission revenues along with costs charged by the MISO are considered components of base rates and any variance from that included in base rates is recovered from / refunded to retail customers through tracking mechanisms.
Excise and Utility Receipts Taxes	Excise & Utility Receipts Taxes Excise taxes and a portion of utility receipts taxes are included in rates charged to customers. Accordingly, the Company records these taxes received as a component of operating revenues, which totaled $28.3 million in 2016 , $29.4 million in 2015 , and $32.3 million in 2014 . Expense associated with excise and utility receipts taxes are recorded as a component of Taxes other than income taxes .
Operating Segments	Operating Segments The Company's chief operating decision maker is the Chief Executive Officer. The Company uses net income calculated in accordance with generally accepted accounting principles as its most relevant performance measure. The Company’s operations consist of regulated operations and other operations that provide information technology and other support services to those regulated operations. The Company segregates its regulated operations between a Gas Utility Services operating segment and an Electric Utility Services operating segment.
Fair Value Measurements	Fair Value Measurements Certain assets and liabilities are valued and disclosed at fair value. Nonfinancial assets and liabilities include the initial measurement of an asset retirement obligation or the use of fair value in goodwill, intangible assets, and long-lived assets impairment tests. FASB guidance provides the framework for measuring fair value. That framework provides a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of the fair value hierarchy are described as follows: Level 1 Inputs to the valuation methodology are unadjusted quoted prices for identical assets or liabilities in active markets. Level 2 Inputs to the valuation methodology include · quoted prices for similar assets or liabilities in active markets; · quoted prices for identical or similar assets or liabilities in inactive markets; · inputs other than quoted prices that are observable for the asset or liability; · inputs that are derived principally from or corroborated by observable market data by correlation or other means If the asset or liability has a specified (contractual) term, the Level 2 input must be observable for substantially the full term of the asset or liability. Level 3 Inputs to the valuation methodology are unobservable and significant to the fair value measurement. The asset or liability’s fair value measurement level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement. Valuation techniques used maximize the use of observable inputs and minimize the use of unobservable inputs.
Earnings Per Share	Earnings Per Share Earnings per share are not presented as the Company's common stock is wholly owned by the Company's parent.
Other Significant Policies	Other Significant Policies Included elsewhere in these notes are significant accounting policies related to retirement plans and other postretirement benefits, intercompany allocations and income taxes (Note 5).

Utility & Nonutility Plant (Tab

Utility & Nonutility Plant (Tables)	12 Months Ended
	Dec. 31, 2016
Property, Plant and Equipment [Abstract]
Cost of Utility Plant, together with depreciation rates expressed as a percentage of original costs	The original cost of Utility Plant , together with depreciation rates expressed as a percentage of original cost, follows: At and For the Year Ended December 31, (In millions) 2016 2015 Original Cost Depreciation Rates as a Percent of Original Cost Original Cost Depreciation Rates as a Percent of Original Cost Gas utility plant $ 3,627.0 3.4 % $ 3,279.7 3.4 % Electric utility plant 2,799.1 3.4 % 2,695.8 3.3 % Common utility plant 56.3 3.2 % 55.0 3.2 % Construction work in progress 63.0 — 59.9 — Total original cost $ 6,545.4 $ 6,090.4
Nonutility Plant, net of accumulated depreciation and amortization	Nonutility Plant , net of accumulated depreciation and amortization follows: At December 31, (In millions) 2016 2015 Computer hardware & software $ 120.5 $ 107.6 Land & buildings 37.6 35.0 All other 6.7 7.1 Nonutility plant - net $ 164.8 $ 149.7

Regulatory Assets & Liabiliti27

Regulatory Assets & Liabilities (Tables)	12 Months Ended
	Dec. 31, 2016
Regulatory Assets and Liabilities Disclosure [Abstract]
Schedule of Regulatory Assets	Regulatory assets consist of the following: At December 31, (In millions) 2016 2015 Future amounts recoverable from ratepayers related to: Net deferred income taxes $ (17.1 ) $ (16.9 ) (17.1 ) (16.9 ) Amounts deferred for future recovery related to: Cost recovery riders & other 91.6 54.6 91.6 54.6 Amounts currently recovered in customer rates related to: Unamortized debt issue costs, reacquisition premiums & hedging proceeds 24.1 25.8 Indiana authorized trackers 64.2 42.6 Deferred coal costs 21.2 28.3 Ohio authorized trackers 22.2 17.6 Other base rate recoveries — 0.1 131.7 114.4 Total regulatory assets $ 206.2 $ 152.1

Transactions with Other Vectr28

Transactions with Other Vectren Companies and Affiliates (Tables)	12 Months Ended
	Dec. 31, 2016
Transactions with Other Vectren Companies and Affiliates [Abstract]
Components of income tax expense and utilization of investment tax credits	The components of income tax expense and amortization of investment tax credits follow: Year Ended December 31, (In millions) 2016 2015 2014 Current: Federal $ (1.4 ) $ (1.9 ) $ 16.6 State 4.2 4.2 10.9 Total current taxes 2.8 2.3 27.5 Deferred: Federal 93.5 81.7 57.8 State 3.7 4.6 (1.6 ) Total deferred taxes 97.2 86.3 56.2 Amortization of investment tax credits (0.5 ) (0.5 ) (0.5 ) Total income tax expense $ 99.5 $ 88.1 $ 83.2
Reconciliation of the federal statutory rate to the effective income tax rate	A reconciliation of the federal statutory rate to the effective income tax rate follows: Year Ended December 31, 2016 2015 2014 Statutory rate 35.0 % 35.0 % 35.0 % State and local taxes-net of federal benefit 2.6 2.8 3.3 Amortization of investment tax credit (0.2 ) (0.2 ) (0.2 ) Domestic production deduction (0.5 ) (0.9 ) (0.9 ) Research and development credit (0.8 ) (2.0 ) (0.3 ) All other - net 0.3 0.7 (1.0 ) Effective tax rate 36.4 % 35.4 % 35.9 %
Significant components of the net deferred tax liability (assets)	Significant components of the net deferred tax liability follow: At December 31, (In millions) 2016 2015 Noncurrent deferred tax liabilities (assets): Depreciation & cost recovery timing differences $ 821.6 $ 752.6 Regulatory assets recoverable through future rates 17.6 31.6 Alternative minimum tax carryforward (29.3 ) (34.5 ) Employee benefit obligations 10.2 7.2 Regulatory liabilities to be settled through future rates (15.9 ) (29.9 ) Deferred fuel costs 25.9 14.2 Other – net 24.4 17.2 Net noncurrent deferred tax liability $ 854.5 $ 758.4

Borrowing Arrangements (Tables)

Borrowing Arrangements (Tables)	12 Months Ended
	Dec. 31, 2016
Debt Disclosure [Abstract]
Short term borrowing arrangements	Following is certain information regarding these short-term borrowing arrangements: (In millions) 2016 2015 2014 Year End Balance Outstanding $ 194.4 $ 14.5 $ 156.4 Weighted Average Interest Rate 1.05 % 0.55 % 0.50 % Annual Average Balance Outstanding $ 59.8 $ 53.8 $ 35.6 Weighted Average Interest Rate 0.71 % 0.38 % 0.34 % Maximum Month End Balance Outstanding $ 194.4 $ 121.5 $ 156.4
Long term senior unsecured obligations and first mortgage bonds outstanding by subsidiary	Long-term senior unsecured obligations and first mortgage bonds outstanding by subsidiary follow: At December 31, (In millions) 2016 2015 Utility Holdings Fixed Rate Senior Unsecured Notes 2018, 5.75% 100.0 100.0 2020, 6.28% 100.0 100.0 2021, 4.67% 55.0 55.0 2023, 3.72% 150.0 150.0 2026, 5.02% 60.0 60.0 2028, 3.20% 45.0 45.0 2035, 6.10% 75.0 75.0 2035, 3.90% 25.0 25.0 2041, 5.99% 35.0 35.0 2042, 5.00% 100.0 100.0 2043, 4.25% 80.0 80.0 2045, 4.36% 135.0 135.0 2055, 4.51% 40.0 40.0 Total Utility Holdings 1,000.0 1,000.0 SIGECO First Mortgage Bonds 2016, 1986 Series, 8.875% — 13.0 2022, 2013 Series C, 1.95%, tax exempt 4.6 4.6 2024, 2013 Series D, 1.95%, tax exempt 22.5 22.5 2025, 2014 Series B, current adjustable rate 1.045%, tax-exempt 41.3 41.3 2029, 1999 Series, 6.72% 80.0 80.0 2037, 2013 Series E, 1.95%, tax exempt 22.0 22.0 2038, 2013 Series A, 4.00%, tax exempt 22.2 22.2 2043, 2013 Series B, 4.05%, tax exempt 39.6 39.6 2044, 2014 Series A, 4.00%, tax exempt 22.3 22.3 2055, 2015 Series Mt. Vernon, 2.375%, tax-exempt 23.0 23.0 2055, 2015 Series Warrick County, 2.375%, tax-exempt 15.2 15.2 Total SIGECO 292.7 305.7 Indiana Gas Fixed Rate Senior Unsecured Notes 2025, Series E, 6.53% 10.0 10.0 2027, Series E, 6.42% 5.0 5.0 2027, Series E, 6.68% 1.0 1.0 2027, Series F, 6.34% 20.0 20.0 2028, Series F, 6.36% 10.0 10.0 2028, Series F, 6.55% 20.0 20.0 2029, Series G, 7.08% 30.0 30.0 Total Indiana Gas 96.0 96.0 Total long-term debt outstanding 1,388.7 1,401.7 Current maturities of long-term debt (49.1 ) (13.0 ) Debt issuance costs (7.9 ) (8.6 ) Unamortized debt premium & discount - net (0.7 ) (0.9 ) Total long-term debt-net $ 1,331.0 $ 1,379.2

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2016
Fair Value Disclosures [Abstract]
Carrying value and estimated fair value of other financial instruments	The carrying values and estimated fair values using primarily Level 2 assumptions of the Company's other financial instruments follow: At December 31, 2016 2015 (In millions) Carrying Amount Est. Fair Value Carrying Amount Est. Fair Value Long-term debt $ 1,380.1 $ 1,495.3 $ 1,392.2 $ 1,495.0 Short-term borrowings 194.4 194.4 14.5 14.5 Cash & cash equivalents 9.4 9.4 6.2 6.2 Restricted cash 0.9 0.9 5.9 5.9

Segment Reporting (Tables)

Segment Reporting (Tables)	12 Months Ended
	Dec. 31, 2016
Segment Reporting [Abstract]
Schedule of Segment Reporting	Information related to the Company’s business segments is summarized below: Year Ended December 31, (In millions) 2016 2015 2014 Revenues Gas Utility Services $ 771.7 $ 792.6 $ 944.6 Electric Utility Services 605.8 601.6 624.8 Other Operations 42.2 40.7 38.3 Eliminations (41.9 ) (40.4 ) (38.0 ) Total revenues $ 1,377.8 $ 1,394.5 $ 1,569.7 Profitability Measure - Net Income Gas Utility Services $ 76.1 $ 64.4 $ 57.0 Electric Utility Services 84.7 82.6 79.7 Other Operations 12.8 13.9 11.7 Total net income $ 173.6 $ 160.9 $ 148.4 Amounts Included in Profitability Measures Depreciation & Amortization Gas Utility Services $ 108.1 $ 98.6 $ 93.3 Electric Utility Services 87.1 85.6 85.7 Other Operations 23.9 24.6 24.1 Total depreciation & amortization $ 219.1 $ 208.8 $ 203.1 Interest Expense Gas Utility Services $ 40.1 $ 35.8 $ 34.9 Electric Utility Services 27.0 27.8 29.0 Other Operations 2.6 2.7 2.7 Total interest expense $ 69.7 $ 66.3 $ 66.6 Income Taxes Gas Utility Services $ 47.1 $ 40.8 $ 35.7 Electric Utility Services 50.1 49.3 48.1 Other Operations 2.3 (2.0 ) (0.6 ) Total income taxes $ 99.5 $ 88.1 $ 83.2 Capital Expenditures Gas Utility Services $ 358.5 $ 291.2 $ 245.9 Electric Utility Services 106.4 87.6 92.4 Other Operations 39.0 25.7 22.8 Non-cash costs & changes in accruals (7.3 ) (5.3 ) (10.1 ) Total capital expenditures $ 496.6 $ 399.2 $ 351.0 At December 31, (In millions) 2016 2015 2014 Assets Gas Utility Services $ 3,091.0 $ 2,706.9 $ 2,604.6 Electric Utility Services 1,788.4 1,778.3 1,656.2 Other Operations, net of eliminations 161.5 107.5 148.5 Total assets $ 5,040.9 $ 4,592.7 $ 4,409.3

Additional Balance Sheet & Op32

Additional Balance Sheet & Operational Information (Tables)	12 Months Ended
	Dec. 31, 2016
Additional Balance Sheet and Operational Information [Abstract]
Summary of inventories	Inventories consist of the following: At December 31, (In millions) 2016 2015 Gas in storage – at LIFO cost $ 37.0 $ 40.5 Materials & supplies 38.1 38.4 Coal & oil for electric generation - at average cost 42.6 45.0 Other 1.3 1.4 Total inventories $ 119.0 $ 125.3
Summary of prepayments and other current assets	Prepayments & other current assets in the Consolidated Balance Sheets consist of the following: At December 31, (In millions) 2016 2015 Prepaid gas delivery service $ 26.4 $ 30.0 Prepaid taxes 8.0 3.9 Other prepayments & current assets 4.2 15.1 Total prepayments & other current assets $ 38.6 $ 49.0
Other utility and corporate investments in the consolidated balance sheets	Other investments in the Consolidated Balance Sheets consist of the following: At December 31, (In millions) 2016 2015 Cash surrender value of life insurance policies $ 20.4 $ 19.2 Restricted cash & other investments 0.9 0.9 Total other investments $ 21.3 $ 20.1
Summary of accrued liabilities	Accrued liabilities in the Consolidated Balance Sheets consist of the following: At December 31, (In millions) 2016 2015 Refunds to customers & customer deposits $ 49.4 $ 51.4 Accrued taxes 44.8 36.7 Accrued interest 16.4 16.3 Accrued salaries & other 29.5 24.0 Total accrued liabilities $ 140.1 $ 128.4
Asset retirement obligation	Asset retirement obligations included in Deferred credits and other liabilities in the Consolidated Balance Sheets roll forward as follows: (In millions) 2016 2015 Asset retirement obligation, January 1 $ 81.9 $ 54.6 Accretion 3.8 3.3 Liabilities incurred in current period — 24.2 Changes in estimates, net of cash payments 20.9 (0.2 ) Asset retirement obligation, December 31 $ 106.6 $ 81.9
Other, net in the consolidated statements of income	Other – net in the Consolidated Statements of Income consists of the following: Year Ended December 31, (In millions) 2016 2015 2014 AFUDC - borrowed funds $ 20.3 $ 16.3 $ 10.8 AFUDC - equity funds 2.2 2.6 3.2 Nonutility plant capitalized interest 1.0 0.4 0.6 Interest income 0.3 0.6 0.7 Other income 2.5 (1.2 ) 1.5 Total other – net $ 26.3 $ 18.7 $ 16.8
Supplemental cash flow information	Supplemental Cash Flow Information: Year Ended December 31, (In millions) 2016 2015 2014 Cash paid (received) for: Interest $ 69.6 $ 66.2 $ 66.7 Income taxes 6.7 (23.1 ) 63.2

Subsidiary Guarantor & Consol33

Subsidiary Guarantor & Consolidating Information (Tables)	12 Months Ended
	Dec. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Condensed Consolidating Statements of Income	Consolidating Statement of Income for the year ended December 31, 2016 (in millions): Subsidiary Guarantors Parent Company Reclassifications and Eliminations Consolidated OPERATING REVENUES Gas utility $ 771.7 $ — $ — $ 771.7 Electric utility 605.8 — — 605.8 Other — 42.2 (41.9 ) 0.3 Total operating revenues 1,377.5 42.2 (41.9 ) 1,377.8 OPERATING EXPENSES Cost of gas sold 266.7 — — 266.7 Cost of fuel & purchased power 183.6 — — 183.6 Other operating 374.0 — (40.4 ) 333.6 Depreciation & amortization 195.2 23.8 0.1 219.1 Taxes other than income taxes 56.8 1.5 — 58.3 Total operating expenses 1,076.3 25.3 (40.3 ) 1,061.3 OPERATING INCOME 301.2 16.9 (1.6 ) 316.5 OTHER INCOME (EXPENSE) Equity in earnings of consolidated companies — 160.8 (160.8 ) — Other – net 24.0 48.3 (46.0 ) 26.3 Total other income (expense) 24.0 209.1 (206.8 ) 26.3 Interest expense 67.2 50.1 (47.6 ) 69.7 INCOME BEFORE INCOME TAXES 258.0 175.9 (160.8 ) 273.1 Income taxes 97.2 2.3 — 99.5 NET INCOME $ 160.8 $ 173.6 $ (160.8 ) $ 173.6 Consolidating Statement of Income for the year ended December 31, 2015 (in millions): Subsidiary Guarantors Parent Company Reclassifications and Eliminations Consolidated OPERATING REVENUES Gas utility $ 792.6 $ — $ — $ 792.6 Electric utility 601.6 — — 601.6 Other — 40.7 (40.4 ) 0.3 Total operating revenues 1,394.2 40.7 (40.4 ) 1,394.5 OPERATING EXPENSES Cost of gas sold 305.4 — — 305.4 Cost of fuel & purchased power 187.5 — — 187.5 Other operating 376.9 — (37.8 ) 339.1 Depreciation & amortization 184.2 24.3 0.3 208.8 Taxes other than income taxes 55.2 1.8 0.1 57.1 Total operating expenses 1,109.2 26.1 (37.4 ) 1,097.9 OPERATING INCOME 285.0 14.6 (3.0 ) 296.6 OTHER INCOME (EXPENSE) Equity in earnings of consolidated companies — 147.0 (147.0 ) — Other – net 15.7 42.7 (39.7 ) 18.7 Total other income (expense) 15.7 189.7 (186.7 ) 18.7 Interest expense 63.7 45.3 (42.7 ) 66.3 INCOME BEFORE INCOME TAXES 237.0 159.0 (147.0 ) 249.0 Income taxes 90.0 (1.9 ) — 88.1 NET INCOME $ 147.0 $ 160.9 $ (147.0 ) $ 160.9 Consolidating Statement of Income for the year ended December 31, 2014 (in millions): Subsidiary Guarantors Parent Company Reclassifications and Eliminations Consolidated OPERATING REVENUES Gas utility $ 944.6 $ — $ — $ 944.6 Electric utility 624.8 — — 624.8 Other — 38.3 (38.0 ) 0.3 Total operating revenues 1,569.4 38.3 (38.0 ) 1,569.7 OPERATING EXPENSES Cost of gas sold 468.7 — — 468.7 Cost of fuel & purchased power 201.8 — — 201.8 Other operating 390.3 — (35.8 ) 354.5 Depreciation & amortization 179.1 23.5 0.5 203.1 Taxes other than income taxes 58.4 1.7 0.1 60.2 Total operating expenses 1,298.3 25.2 (35.2 ) 1,288.3 OPERATING INCOME 271.1 13.1 (2.8 ) 281.4 OTHER INCOME (EXPENSE) Equity in earnings of consolidated companies — 136.7 (136.7 ) — Other – net 13.3 43.2 (39.7 ) 16.8 Total other income (expense) 13.3 179.9 (176.4 ) 16.8 Interest expense 63.9 45.2 (42.5 ) 66.6 INCOME BEFORE INCOME TAXES 220.5 147.8 (136.7 ) 231.6 Income taxes 83.8 (0.6 ) — 83.2 NET INCOME $ 136.7 $ 148.4 $ (136.7 ) $ 148.4
Condensed Consolidating Balance Sheets	Consolidating Balance Sheet as of December 31, 2016 (in millions): ASSETS Subsidiary Parent Guarantors Company Eliminations Consolidated Current Assets Cash & cash equivalents $ 7.6 $ 1.8 $ — $ 9.4 Accounts receivable - less reserves 102.4 0.2 — 102.6 Intercompany receivables 17.5 157.1 (174.6 ) — Accrued unbilled revenues 112.0 — — 112.0 Inventories 119.0 — — 119.0 Recoverable fuel & natural gas costs 29.9 — — 29.9 Prepayments & other current assets 36.5 4.4 (2.3 ) 38.6 Total current assets 424.9 163.5 (176.9 ) 411.5 Utility Plant Original cost 6,545.4 — — 6,545.4 Less: accumulated depreciation & amortization 2,562.5 — — 2,562.5 Net utility plant 3,982.9 — — 3,982.9 Investments in consolidated subsidiaries — 1,577.2 (1,577.2 ) — Notes receivable from consolidated subsidiaries — 945.4 (945.4 ) — Investments in unconsolidated affiliates 0.2 — — 0.2 Other investments 20.9 0.4 — 21.3 Nonutility plant - net 1.7 163.1 — 164.8 Goodwill - net 205.0 — — 205.0 Regulatory assets 190.0 16.2 — 206.2 Other assets 53.9 3.7 (8.6 ) 49.0 TOTAL ASSETS $ 4,879.5 $ 2,869.5 $ (2,708.1 ) $ 5,040.9 LIABILITIES & SHAREHOLDER'S EQUITY Subsidiary Parent Guarantors Company Eliminations Consolidated Current Liabilities Accounts payable $ 194.6 $ 10.8 $ — $ 205.4 Intercompany payables 14.8 — (14.8 ) — Payables to other Vectren companies 25.4 — — 25.4 Accrued liabilities 126.0 16.4 (2.3 ) 140.1 Short-term borrowings — 194.4 — 194.4 Intercompany short-term borrowings 142.3 17.5 (159.8 ) — Current maturities of long-term debt 49.1 — — 49.1 Total current liabilities 552.2 239.1 (176.9 ) 614.4 Long-Term Debt Long-term debt - net of current maturities & debt subject to tender 335.2 995.8 — 1,331.0 Long-term debt due to VUHI 945.4 — (945.4 ) — Total long-term debt - net 1,280.6 995.8 (945.4 ) 1,331.0 Deferred Income Taxes & Other Liabilities Deferred income taxes 855.4 (0.9 ) — 854.5 Regulatory liabilities 452.4 1.3 — 453.7 Deferred credits & other liabilities 161.7 10.2 (8.6 ) 163.3 Total deferred credits & other liabilities 1,469.5 10.6 (8.6 ) 1,471.5 Common Shareholder's Equity Common stock (no par value) 844.4 831.2 (844.4 ) 831.2 Retained earnings 732.8 792.8 (732.8 ) 792.8 Total common shareholder's equity 1,577.2 1,624.0 (1,577.2 ) 1,624.0 TOTAL LIABILITIES & SHAREHOLDER'S EQUITY $ 4,879.5 $ 2,869.5 $ (2,708.1 ) $ 5,040.9 Consolidating Balance Sheet as of December 31, 2015 (in millions): ASSETS Subsidiary Parent Guarantors Company Eliminations Consolidated Current Assets Cash & cash equivalents $ 5.5 $ 0.7 $ — $ 6.2 Accounts receivable - less reserves 92.3 — — 92.3 Intercompany receivables 51.2 142.9 (194.1 ) — Accrued unbilled revenues 85.7 — — 85.7 Inventories 125.3 — — 125.3 Prepayments & other current assets 49.3 4.1 (4.4 ) 49.0 Total current assets 409.3 147.7 (198.5 ) 358.5 Utility Plant Original cost 6,090.4 — — 6,090.4 Less: accumulated depreciation & amortization 2,415.5 — — 2,415.5 Net utility plant 3,674.9 — — 3,674.9 Investments in consolidated subsidiaries — 1,467.0 (1,467.0 ) — Notes receivable from consolidated subsidiaries — 836.0 (836.0 ) — Investments in unconsolidated affiliates 0.2 — — 0.2 Other investments 19.7 0.4 — 20.1 Nonutility plant - net 1.7 148.0 — 149.7 Goodwill - net 205.0 — — 205.0 Regulatory assets 135.2 16.9 — 152.1 Other assets 39.6 1.3 (8.7 ) 32.2 TOTAL ASSETS $ 4,485.6 $ 2,617.3 $ (2,510.2 ) $ 4,592.7 LIABILITIES & SHAREHOLDER'S EQUITY Subsidiary Parent Guarantors Company Eliminations Consolidated Current Liabilities Accounts payable $ 161.1 $ 7.4 $ — $ 168.5 Intercompany payables 12.4 — (12.4 ) — Payables to other Vectren companies 25.7 — — 25.7 Accrued liabilities 120.2 12.6 (4.4 ) 128.4 Short-term borrowings — 14.5 — 14.5 Intercompany short-term borrowings 130.5 51.2 (181.7 ) — Current maturities of long-term debt 13.0 — — 13.0 Total current liabilities 462.9 85.7 (198.5 ) 350.1 Long-Term Debt Long-term debt - net of current maturities & debt subject to tender 383.9 995.3 — 1,379.2 Long-term debt due to VUHI 836.0 — (836.0 ) — Total long-term debt - net 1,219.9 995.3 (836.0 ) 1,379.2 Deferred Income Taxes & Other Liabilities Deferred income taxes 763.7 (5.3 ) — 758.4 Regulatory liabilities 432.5 1.4 — 433.9 Deferred credits & other liabilities 139.6 5.0 (8.7 ) 135.9 Total deferred credits & other liabilities 1,335.8 1.1 (8.7 ) 1,328.2 Common Shareholder's Equity Common stock (no par value) 813.1 799.9 (813.1 ) 799.9 Retained earnings 653.9 735.3 (653.9 ) 735.3 Total common shareholder's equity 1,467.0 1,535.2 (1,467.0 ) 1,535.2 TOTAL LIABILITIES & SHAREHOLDER'S EQUITY $ 4,485.6 $ 2,617.3 $ (2,510.2 ) $ 4,592.7
Condensed Consolidating Statements of Cash Flows	Consolidating Statement of Cash Flows for the year ended December 31, 2016 (in millions): Subsidiary Guarantors Parent Company Eliminations Consolidated NET CASH PROVIDED BY OPERATING ACTIVITIES $ 352.2 $ 45.2 $ — $ 397.4 CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from: Long-term debt, net of issuance costs 109.4 — (109.4 ) — Additional capital contribution from Parent 31.3 31.3 (31.3 ) 31.3 Requirements for: Dividends to parent (82.0 ) (116.1 ) 82.0 (116.1 ) Retirement of long-term debt (13.0 ) — — (13.0 ) Net change in intercompany short-term borrowings 11.9 (33.7 ) 21.8 — Net change in short-term borrowings — 179.9 — 179.9 Net cash used in financing activities 57.6 61.4 (36.9 ) 82.1 CASH FLOWS FROM INVESTING ACTIVITIES Proceeds from: Consolidated subsidiary distributions — 82.0 (82.0 ) — Other investing activities 15.3 — — 15.3 Requirements for: Capital expenditures, excluding AFUDC equity (461.7 ) (34.9 ) — (496.6 ) Consolidated subsidiary investments — (31.3 ) 31.3 — Changes in restricted cash 5.0 — — 5.0 Net change in long-term intercompany notes receivable — (109.4 ) 109.4 — Net change in short-term intercompany notes receivable 33.7 (11.9 ) (21.8 ) — Net cash used in investing activities (407.7 ) (105.5 ) 36.9 (476.3 ) Net change in cash & cash equivalents 2.1 1.1 — 3.2 Cash & cash equivalents at beginning of period 5.5 0.7 — 6.2 Cash & cash equivalents at end of period $ 7.6 $ 1.8 $ — $ 9.4 Consolidating Statement of Cash Flows for the year ended December 31, 2015 (in millions): Subsidiary Guarantors Parent Company Eliminations Consolidated NET CASH PROVIDED BY OPERATING ACTIVITIES $ 460.3 $ 32.6 $ — $ 492.9 CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from: Long-term debt, net of issuance costs 126.8 199.0 (89.5 ) 236.3 Additional capital contribution from Parent 6.2 6.2 (6.2 ) 6.2 Requirements for: Dividends to parent (103.2 ) (110.4 ) 103.2 (110.4 ) Retirement of long-term debt (20.0 ) (75.0 ) — (95.0 ) Net change in intercompany short-term borrowings (40.7 ) 51.2 (10.5 ) — Net change in short-term borrowings — (141.9 ) — (141.9 ) Net cash used in financing activities (30.9 ) (70.9 ) (3.0 ) (104.8 ) CASH FLOWS FROM INVESTING ACTIVITIES Proceeds from: Consolidated subsidiary distributions — 103.2 (103.2 ) — Other investing activities — 3.9 — 3.9 Requirements for: Capital expenditures, excluding AFUDC equity (373.7 ) (25.5 ) — (399.2 ) Consolidated subsidiary investments — (6.2 ) 6.2 — Changes in restricted cash (5.9 ) — — (5.9 ) Net change in long-term intercompany notes receivable — (89.5 ) 89.5 — Net change in short-term intercompany notes receivable (51.2 ) 40.7 10.5 — Net cash used in investing activities (430.8 ) 26.6 3.0 (401.2 ) Net change in cash & cash equivalents (1.4 ) (11.7 ) — (13.1 ) Cash & cash equivalents at beginning of period 6.9 12.4 — 19.3 Cash & cash equivalents at end of period $ 5.5 $ 0.7 $ — $ 6.2 Consolidating Statement of Cash Flows for the year ended December 31, 2014 (in millions): Subsidiary Guarantors Parent Company Eliminations Consolidated NET CASH PROVIDED BY OPERATING ACTIVITIES $ 274.4 $ 63.1 $ — $ 337.5 CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from: Long-term debt, net of issuance costs 186.6 — (124.2 ) 62.4 Additional capital contribution from Parent 6.0 6.0 (6.0 ) 6.0 Requirements for: Dividends to parent (101.6 ) (108.7 ) 101.6 (108.7 ) Retirement of long-term debt, including premiums paid (63.6 ) — — (63.6 ) Net change in intercompany short-term borrowings 23.9 (0.3 ) (23.6 ) — Net change in short-term borrowings — 127.8 — 127.8 Net cash used in financing activities 51.3 24.8 (52.2 ) 23.9 CASH FLOWS FROM INVESTING ACTIVITIES Proceeds from: Consolidated subsidiary distributions — 101.6 (101.6 ) — Other investing activities — 0.3 — 0.3 Requirements for: Capital expenditures, excluding AFUDC equity (327.3 ) (23.7 ) — (351.0 ) Consolidated subsidiary investments — (6.0 ) 6.0 — Net change in long-term intercompany notes receivable — (50.1 ) 50.1 — Net change in short-term intercompany notes receivable 0.3 (98.0 ) 97.7 — Net cash used in investing activities (327.0 ) (75.9 ) 52.2 (350.7 ) Net change in cash & cash equivalents (1.3 ) 12.0 — 10.7 Cash & cash equivalents at beginning of period 8.2 0.4 — 8.6 Cash & cash equivalents at end of period $ 6.9 $ 12.4 $ — $ 19.3

Quarterly Financial Data (Una34

Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2016
Quarterly Financial Information Disclosure [Abstract]
Summarized quarterly financial data	Summarized quarterly financial data for 2016 and 2015 follows: (In millions) Q1 Q2 Q3 Q4 2016 Results of Operations: Operating revenues $ 423.4 $ 279.8 $ 291.3 $ 383.5 Operating income 106.8 52.2 64.0 93.5 Net income 61.1 26.3 34.9 51.3 2015 Results of Operations: Operating revenues $ 506.9 $ 276.5 $ 273.0 $ 338.1 Operating income 110.8 50.5 54.1 81.3 Net income 63.0 24.4 26.9 46.6

Organization and Nature of Op35

Organization and Nature of Operations (Details) customer in Thousands	12 Months Ended
	Dec. 31, 2016customerpublic_utility
Public Utilities, General Disclosures [Line Items]
Operating utility companies | public_utility	3
Natural Gas Customers [Member] | Indiana Gas [Member] | Indiana [Member]
Public Utilities, General Disclosures [Line Items]
Approximate number of customers	587
Natural Gas Customers [Member] | SIGECO [Member] | Indiana [Member]
Public Utilities, General Disclosures [Line Items]
Approximate number of customers	111
Natural Gas Customers [Member] | Vectren Energy Delivery of Ohio [Member] | Ohio [Member]
Public Utilities, General Disclosures [Line Items]
Approximate number of customers	316
Electric Customers [Member] | SIGECO [Member] | Indiana [Member]
Public Utilities, General Disclosures [Line Items]
Approximate number of customers	144

Summary of Significant Accoun36

Summary of Significant Accounting Policies (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Accounting Policies [Abstract]
Goodwill impairments	$ 0	$ 0	$ 0
Excise taxes and a portion of utility receipts taxes	$ 28,300,000	$ 29,400,000	$ 32,300,000

Utility & Nonutility Plant (Det

Utility & Nonutility Plant (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)MW	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Utility & Nonutility Plant
Original cost	$ 6,545.4	$ 6,090.4
Cost of Non-Utility plant, net of accumulated depreciation and amortization	164.8	149.7
Utility Group [Member]
Utility & Nonutility Plant
Original cost	6,545.4	6,090.4
Utility Group [Member] | Gas Utility Plant [Member]
Utility & Nonutility Plant
Original cost	$ 3,627	$ 3,279.7
Depreciation Rates as a Percent of Original Cost (in hundredths)	3.40%	3.40%
Utility Group [Member] | Electric Utility Plant [Member]
Utility & Nonutility Plant
Original cost	$ 2,799.1	$ 2,695.8
Depreciation Rates as a Percent of Original Cost (in hundredths)	3.40%	3.30%
Utility Group [Member] | Common Utility Plant [Member]
Utility & Nonutility Plant
Original cost	$ 56.3	$ 55
Depreciation Rates as a Percent of Original Cost (in hundredths)	3.20%	3.20%
Utility Group [Member] | Construction Work in Progress [Member]
Utility & Nonutility Plant
Original cost	$ 63	$ 59.9
Depreciation Rates as a Percent of Original Cost (in hundredths)	0.00%	0.00%
Utility Group [Member] | Warrick Power Plant [Member]
Utility & Nonutility Plant
Size of Unit 4 Warrick Power Plant (in megawatts) | MW	300
Utility Group [Member] | SIGECO [Member]
Utility & Nonutility Plant
Southern Indiana Gas And Electric Company's Share Of Cost Of Unit 4	$ 190.4
Southern Indiana Gas And Electric Company's Share Of Accumulated Depreciation Of Unit 4	110.8
Nonutility Group [Member]
Utility & Nonutility Plant
Cost of Non-Utility plant, net of accumulated depreciation and amortization	164.8	$ 149.7
Nonutility plant accumulated depreciation and amortization	264.7	248
Capitalized interest on nonutility plant construction projects	1	0.4	$ 0.6
Nonutility Group [Member] | Computer Hardware & Software [Member]
Utility & Nonutility Plant
Cost of Non-Utility plant, net of accumulated depreciation and amortization	120.5	107.6
Nonutility Group [Member] | Land & Buildings [Member]
Utility & Nonutility Plant
Cost of Non-Utility plant, net of accumulated depreciation and amortization	37.6	35
Nonutility Group [Member] | All Other [Member]
Utility & Nonutility Plant
Cost of Non-Utility plant, net of accumulated depreciation and amortization	$ 6.7	$ 7.1

Regulatory Assets & Liabiliti38

Regulatory Assets & Liabilities (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Regulatory Liabilities [Abstract]
Regulatory liabilities	$ (453,700,000)	$ (433,900,000)
Regulatory assets	206,200,000	152,100,000
Regulatory assets currently being recovered in base rates	$ 24,000,000
Weighted average recovery period of regulatory assets currently being recovered (in years)	24 years
Amounts Deferred for Future Recovery [Member]
Regulatory Liabilities [Abstract]
Regulatory assets	$ 91,600,000	54,600,000
Amounts Deferred for Future Recovery [Member] | Cost Recovery Riders and Other [Member]
Regulatory Liabilities [Abstract]
Regulatory assets	91,600,000	54,600,000
Amounts Currently Recovered in Customer Rates [Member]
Regulatory Liabilities [Abstract]
Regulatory assets	131,700,000	114,400,000
Amounts Currently Recovered in Customer Rates [Member] | Unamortized Debt Issue Costs, Reaquisition Premiums and Hedging Proceeds [Member]
Regulatory Liabilities [Abstract]
Regulatory assets	24,100,000	25,800,000
Amounts Currently Recovered in Customer Rates [Member] | Indiana Authorized Trackers [Member]
Regulatory Liabilities [Abstract]
Regulatory assets	64,200,000	42,600,000
Amounts Currently Recovered in Customer Rates [Member] | Deferred Coal Costs [Member]
Regulatory Liabilities [Abstract]
Regulatory assets	21,200,000	28,300,000
Amounts Currently Recovered in Customer Rates [Member] | Ohio Authorized Trackers [Member]
Regulatory Liabilities [Abstract]
Regulatory assets	22,200,000	17,600,000
Amounts Currently Recovered in Customer Rates [Member] | Other Base Rate Recoveries [Member]
Regulatory Liabilities [Abstract]
Regulatory assets	0	100,000
Amounts Currently Recovered in Customer Rates [Member] | Demand Side Management Programs [Member]
Regulatory Liabilities [Abstract]
Regulatory asset amounts earning a return	0
Future Amounts Recoverable From Ratepayers [Member]
Regulatory Liabilities [Abstract]
Regulatory liabilities	(17,100,000)	(16,900,000)
Future Amounts Recoverable From Ratepayers [Member] | Deferred Income Tax Charge [Member]
Regulatory Liabilities [Abstract]
Regulatory liabilities	$ (17,100,000)	$ (16,900,000)

Transactions with Other Vectr39

Transactions with Other Vectren Companies and Affiliates (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)pension_plan	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Transactions with Other Vectren Companies and Affiliates [Line Items]
Company contributions	$ 15	$ 19.6	$ 0
Deferred credits & other liabilities	163.3	135.9
Deferred credits & other liabilities	42.3	35.7
Current:
Federal	(1.4)	(1.9)	16.6
State	4.2	4.2	10.9
Total current taxes	2.8	2.3	27.5
Deferred:
Federal	93.5	81.7	57.8
State	3.7	4.6	(1.6)
Total deferred taxes	97.2	86.3	56.2
Amortization of investment tax credits	(0.5)	(0.5)	(0.5)
Total income tax expense	$ 99.5	$ 88.1	$ 83.2
Reconciliation of the federal statutory rate to the effective income tax rate [Abstract]
Statutory rate	35.00%	35.00%	35.00%
State and local taxes-net of federal benefit	2.60%	2.80%	3.30%
Amortization of investment tax credit	(0.20%)	(0.20%)	(0.20%)
Domestic production deduction	(0.50%)	(0.90%)	(0.90%)
Research and development credit	(0.80%)	(2.00%)	(0.30%)
All other - net	0.30%	0.70%	(1.00%)
Effective tax rate	36.40%	35.40%	35.90%
Noncurrent deferred tax liabilities (assets) [Abstract]
Depreciation & cost recovery timing differences	$ 821.6	$ 752.6
Regulatory assets recoverable through future rates	17.6	31.6
Alternative minimum tax carryforward	(29.3)	(34.5)
Employee benefit obligations	10.2	7.2
Regulatory liabilities to be settled through future rates	(15.9)	(29.9)
Deferred fuel costs	25.9	14.2
Other – net	24.4	17.2
Net noncurrent deferred tax liability	854.5	758.4
Investment tax credits	1.6	2.1
Alternative minimum tax carryforward	29.3	34.5
Net liability for unrecognized tax benefits	$ 1.1	0.7
Defined Benefit Pension Plans [Member]
Transactions with Other Vectren Companies and Affiliates [Line Items]
Number of closed qualified defined benefit pension plans | pension_plan	3
Company contributions	$ 15	$ 19.6
Funded status as a percent	92.00%	90.00%
Net periodic benefit cost	$ 6.1	$ 7	$ 6.7
Deferred credits & other liabilities	12.2	12
Other Assets	40.9	30.3
Vectren Infrastructure Services Corporation [Member]
Transactions with Other Vectren Companies and Affiliates [Line Items]
Expenses from transactions with other Vectren companies and affiliates	117.8	109.5	94
Vectren Fuels Inc. [Member]
Transactions with Other Vectren Companies and Affiliates [Line Items]
Expenses from transactions with other Vectren companies and affiliates			98.6
Support Services & Purchases [Member]
Transactions with Other Vectren Companies and Affiliates [Line Items]
Corporate allocations	$ 57.6	$ 52.3	$ 57

Borrowing Arrangements Short-Te

Borrowing Arrangements Short-Term Borrowings (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Short-term borrowings [Abstract]
Short-term borrowing capacity	$ 350,000,000
Short term borrowings available	156,000,000
Letters of credit outstanding	0
Year end [Abstract]
Balance Outstanding, end of period	$ 194,400,000	$ 14,500,000	$ 156,400,000
Weighted Average Interest Rate, end of period (in hundredths)	1.05%	0.55%	0.50%
Annual Average [Abstract]
Balance Outstanding, annual average	$ 59,800,000	$ 53,800,000	$ 35,600,000
Weighted Average Interest Rate, annual average (in hundredths)	0.71%	0.38%	0.34%
Maximum Month End Balance Outstanding	$ 194,400,000	$ 121,500,000	$ 156,400,000
Vectren Utility Holdings Inc [Member] | Utility Group [Member]
Short-term borrowings [Abstract]
Letter of credit, within debt facility, maximum borrowing capacity	$ 100,000,000

Borrowing Arrangements - Long-t

Borrowing Arrangements - Long-term Debt (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015	Dec. 15, 2015	Sep. 09, 2015	Sep. 24, 2014
Debt Instrument [Line Items]
Total long term debt outstanding	$ 1,388.7	$ 1,401.7
Current maturities of long-term debt	(49.1)	(13)
Debt issuance costs	(7.9)	(8.6)
Unamortized debt premium & discount - net	(0.7)	(0.9)
Total long-term debt-net	1,331	1,379.2
Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member]
Debt Instrument [Line Items]
Total long term debt outstanding	1,000	1,000
Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2018, 5.75% [Member]
Debt Instrument [Line Items]
Total long term debt outstanding	$ 100	100
Fixed rate stated percentage (in hundredths)	5.75%
Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2020, 6.28% [Member]
Debt Instrument [Line Items]
Total long term debt outstanding	$ 100	100
Fixed rate stated percentage (in hundredths)	6.28%
Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2021, 4.67 [Member]
Debt Instrument [Line Items]
Total long term debt outstanding	$ 55	55
Fixed rate stated percentage (in hundredths)	4.67%
Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2023, 3.72% [Member]
Debt Instrument [Line Items]
Total long term debt outstanding	$ 150	150
Fixed rate stated percentage (in hundredths)	3.72%
Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2026, 5.02% [Member]
Debt Instrument [Line Items]
Total long term debt outstanding	$ 60	60
Fixed rate stated percentage (in hundredths)	5.02%
Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2028, 3.20% [Member]
Debt Instrument [Line Items]
Total long term debt outstanding	$ 45	45
Fixed rate stated percentage (in hundredths)	3.20%
Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2035, 6.10% [Member]
Debt Instrument [Line Items]
Total long term debt outstanding	$ 75	75
Fixed rate stated percentage (in hundredths)	6.10%
Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2035,3.90% [Member]
Debt Instrument [Line Items]
Total long term debt outstanding	$ 25	25
Fixed rate stated percentage (in hundredths)	3.90%		3.90%
Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2041, 5.99% [Member]
Debt Instrument [Line Items]
Total long term debt outstanding	$ 35	35
Fixed rate stated percentage (in hundredths)	5.99%
Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2042, 5.00% [Member]
Debt Instrument [Line Items]
Total long term debt outstanding	$ 100	100
Fixed rate stated percentage (in hundredths)	5.00%
Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2043, 4.25% [Member]
Debt Instrument [Line Items]
Total long term debt outstanding	$ 80	80
Fixed rate stated percentage (in hundredths)	4.25%
Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2045, 4.36% [Member]
Debt Instrument [Line Items]
Total long term debt outstanding	$ 135	135
Fixed rate stated percentage (in hundredths)	4.36%		4.36%
Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2055, 4.51% [Member]
Debt Instrument [Line Items]
Total long term debt outstanding	$ 40	40
Fixed rate stated percentage (in hundredths)	4.51%		4.51%
SIGECO [Member] | First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Total long term debt outstanding	$ 292.7	305.7
SIGECO [Member] | First Mortgage Bonds [Member] | 2016, 1986 Series, 8.875% [Member]
Debt Instrument [Line Items]
Total long term debt outstanding	0	$ 13
Fixed rate stated percentage (in hundredths)		8.875%
SIGECO [Member] | First Mortgage Bonds [Member] | 2022, 2013 Series C, 1.95% tax exempt [Member]
Debt Instrument [Line Items]
Total long term debt outstanding	$ 4.6	$ 4.6
Fixed rate stated percentage (in hundredths)	1.95%
SIGECO [Member] | First Mortgage Bonds [Member] | 2024, 2013 Series D, 1.95% tax exempt [Member]
Debt Instrument [Line Items]
Total long term debt outstanding	$ 22.5	22.5
Fixed rate stated percentage (in hundredths)	1.95%
SIGECO [Member] | First Mortgage Bonds [Member] | 2025, 2014 Series B, 1.045% Tax Exempt [Member]
Debt Instrument [Line Items]
Total long term debt outstanding	$ 41.3	41.3
Fixed rate stated percentage (in hundredths)	1.045%
SIGECO [Member] | First Mortgage Bonds [Member] | 2029, 1999 Senior Notes, 6.72% [Member]
Debt Instrument [Line Items]
Total long term debt outstanding	$ 80	80
Fixed rate stated percentage (in hundredths)	6.72%
SIGECO [Member] | First Mortgage Bonds [Member] | 2037, 2013 Series E 1.95% Tax Exempt [Member]
Debt Instrument [Line Items]
Total long term debt outstanding	$ 22	22
Fixed rate stated percentage (in hundredths)	1.95%
SIGECO [Member] | First Mortgage Bonds [Member] | 2038, 2013 Series A, 4.00% Tax Exempt [Member]
Debt Instrument [Line Items]
Total long term debt outstanding	$ 22.2	22.2
Fixed rate stated percentage (in hundredths)	4.00%
SIGECO [Member] | First Mortgage Bonds [Member] | 2043, 2013 Series B 4.05% Tax Exempt [Member]
Debt Instrument [Line Items]
Total long term debt outstanding	$ 39.6	39.6
Fixed rate stated percentage (in hundredths)	4.05%
SIGECO [Member] | First Mortgage Bonds [Member] | 2044, 2014 Series A 4.00% Tax Exempt [Member]
Debt Instrument [Line Items]
Total long term debt outstanding	$ 22.3	22.3
Fixed rate stated percentage (in hundredths)	4.00%				4.00%
SIGECO [Member] | First Mortgage Bonds [Member] | 2055, 2015 Series Mt. Vernon, 2.375%, tax-exempt
Debt Instrument [Line Items]
Total long term debt outstanding	$ 23	23
Fixed rate stated percentage (in hundredths)	2.375%			2.375%
SIGECO [Member] | First Mortgage Bonds [Member] | 2055, 2015 Series Warrick County, 2.375%, tax-exempt
Debt Instrument [Line Items]
Total long term debt outstanding	$ 15.2	15.2
Fixed rate stated percentage (in hundredths)	2.375%
Indiana Gas [Member] | Fixed Rate Senior Unsecured Notes [Member]
Debt Instrument [Line Items]
Total long term debt outstanding	$ 96	96
Indiana Gas [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2025, Series E, 6.53% [Member]
Debt Instrument [Line Items]
Total long term debt outstanding	$ 10	10
Fixed rate stated percentage (in hundredths)	6.53%
Indiana Gas [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2027, Series E, 6.42% [Member]
Debt Instrument [Line Items]
Total long term debt outstanding	$ 5	5
Fixed rate stated percentage (in hundredths)	6.42%
Indiana Gas [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2027, Series E, 6.68% [Member]
Debt Instrument [Line Items]
Total long term debt outstanding	$ 1	1
Fixed rate stated percentage (in hundredths)	6.68%
Indiana Gas [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2027, Series F, 6.34% [Member]
Debt Instrument [Line Items]
Total long term debt outstanding	$ 20	20
Fixed rate stated percentage (in hundredths)	6.34%
Indiana Gas [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2028, Series F, 6.36% [Member]
Debt Instrument [Line Items]
Total long term debt outstanding	$ 10	10
Fixed rate stated percentage (in hundredths)	6.36%
Indiana Gas [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2028, Series F, 6.55% [Member]
Debt Instrument [Line Items]
Total long term debt outstanding	$ 20	20
Fixed rate stated percentage (in hundredths)	6.55%
Indiana Gas [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2029, Series G, 7.08% [Member]
Debt Instrument [Line Items]
Total long term debt outstanding	$ 30	$ 30
Fixed rate stated percentage (in hundredths)	7.08%

Borrowing Arrangements (Details

Borrowing Arrangements (Details)	Jun. 01, 2016USD ($)	Dec. 29, 2015USD ($)	Dec. 21, 2015USD ($)	Dec. 01, 2015USD ($)	Mar. 15, 2015USD ($)	Sep. 24, 2014USD ($)series	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 15, 2015USD ($)	Sep. 09, 2015USD ($)series	Jun. 01, 1986USD ($)
Long term debt [Abstract]
Debt issuance costs							$ 7,900,000	$ 8,600,000
Maturities of long term debt [Abstract]
Debt maturing within 12 months following date of latest balance sheet							49,100,000
Debt maturing within two years following date of latest balance sheet							100,000,000
Debt maturing within three years following date of latest balance sheet							100,000,000
Debt maturing within five years following date of latest balance sheet							55,000,000
Debt maturing thereafter 5 years following date of the latest balance sheet							1,076,000,000
Debt maturing within four years following date of latest balance sheet							0
Debt guarantees [Abstract]
Long-term guarantees							996,000,000
Short-term debt guarantees							$ 194,000,000
Covenants [Abstract]
Debt to consolidated total capitalization - maximum ratio							65.00%
SIGECO [Member] | First Mortgage Bonds [Member]
Long term debt [Abstract]
Extinguishment of debt						$ 63,600,000
Debt Issuance Amount						$ 63,600,000				$ 38,200,000
Series of debt issued | series						2				2
Series of debt retired | series						3
Debt subject to mandatory tender							$ 87,300,000
Future long term debt sinking fund fund requirements and maturities [Abstract]
Annual sinking fund requirement fixed percentage (in hundredths)							1.00%
Utility plant remaining unfunded under mortgage indenture							$ 1,400,000,000
Gross utility plant balance subject to the mortgage indenture							$ 3,300,000,000
SIGECO [Member] | First Mortgage Bonds [Member] | 2016, 8.875% [Member]
Long term debt [Abstract]
Extinguishment of debt	$ 13,000,000
Fixed rate stated percentage (in hundredths)											8.875%
Debt Issuance Amount											$ 25,000,000
SIGECO [Member] | First Mortgage Bonds [Member] | 2055, 2015 Series Mt. Vernon, 2.375%, tax-exempt
Long term debt [Abstract]
Fixed rate stated percentage (in hundredths)							2.375%			2.375%
Debt Issuance Amount										$ 23,000,000
SIGECO [Member] | First Mortgage Bonds [Member] | 2055, 2015 Series Warrick County, 2.375%, tax-exempt
Long term debt [Abstract]
Fixed rate stated percentage (in hundredths)							2.375%
Debt Issuance Amount										$ 15,200,000
SIGECO [Member] | First Mortgage Bonds [Member] | 2044, 2014 Series A 4.00% Tax Exempt [Member]
Long term debt [Abstract]
Fixed rate stated percentage (in hundredths)						4.00%	4.00%
Debt Issuance Amount						$ 22,300,000
SIGECO [Member] | First Mortgage Bonds [Member] | 2025, Series 2014B, Variable Rate
Long term debt [Abstract]
Debt Issuance Amount						$ 41,300,000
Debt subject to mandatory tender							$ 41,300,000
SIGECO [Member] | First Mortgage Bonds [Member] | Bonds subject to mandatory tender in September 2017 [Member]
Long term debt [Abstract]
Debt subject to mandatory tender							49,100,000
SIGECO [Member] | First Mortgage Bonds [Member] | Bonds subject to mandatory tender in September 2020 [Member]
Long term debt [Abstract]
Debt subject to mandatory tender							$ 38,200,000
Indiana Gas [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2015, Series E, 7.15% [Member]
Long term debt [Abstract]
Extinguishment of debt					$ 5,000,000
Fixed rate stated percentage (in hundredths)					7.15%
Indiana Gas [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2015, Series E, 6.69% [Member]
Long term debt [Abstract]
Extinguishment of debt			$ 5,000,000
Fixed rate stated percentage (in hundredths)		6.69%
Indiana Gas [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2015, Series E1, 6.69% [Member]
Long term debt [Abstract]
Extinguishment of debt		$ 10,000,000
Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2035,3.90% [Member]
Long term debt [Abstract]
Fixed rate stated percentage (in hundredths)							3.90%		3.90%
Debt Issuance Amount									$ 25,000,000
Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2045, 4.36% [Member]
Long term debt [Abstract]
Fixed rate stated percentage (in hundredths)							4.36%		4.36%
Debt Issuance Amount									$ 135,000,000
Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2055, 4.51% [Member]
Long term debt [Abstract]
Fixed rate stated percentage (in hundredths)							4.51%		4.51%
Debt Issuance Amount									$ 40,000,000
Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2015, 5.45% [Member]
Long term debt [Abstract]
Extinguishment of debt				$ 75,000,000
Fixed rate stated percentage (in hundredths)				5.45%
Regulatory Assets [Member] | Accounting Standards Update 2015-03 [Member]
Long term debt [Abstract]
Debt issuance costs								(8,600,000)
Long-term Debt [Member] | Accounting Standards Update 2015-03 [Member]
Long term debt [Abstract]
Debt issuance costs								$ 8,600,000

Common Shareholder's Equity (De

Common Shareholder's Equity (Details) - USD ($) $ in Millions	12 Months Ended			36 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2016
Accumulated Other Comprehensive Income (Loss) [Line Items]
Additional capital contribution	$ 31.3	$ 6.2	$ 6
Common Shareholders Equity [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Additional capital contribution	25			$ 43.5
Parent Company [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Additional capital contribution	31.3	$ 6.2	$ 6
Parent Company [Member] | Common Shareholders Equity [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Proceeds from new share issues	$ 18.5

Commitments & Contingencies (De

Commitments & Contingencies (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Commitments [Abstract]
Future minimum operating lease payments due within one year of the balance sheet date	$ 0.8
Future minimum operating lease payments due within the second year of the balance sheet date	0.8
Future minimum operating lease payments due within the third year of the balance sheet date	0.6
Future minimum operating lease payments due within the fourth year of the balance sheet date	0.6
Future minimum operating lease payments due within the fifth year of the balance sheet date	0.6
Future minimum operating lease payments due after the fifth year of the balance sheet date	1.6
Total lease expense	1.1	$ 0.8	$ 1.5
Firm purchase commitments due within one year	4.4
Firm purchase commitments, due within two years	$ 1.5
Firm purchase commitment term one	5 years
Firm purchase commitment term two	20 years

Gas Rate and Regulatory Matte45

Gas Rate and Regulatory Matters (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Jan. 25, 2017	Mar. 31, 2016
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items]
Length of project plan required for recovery under new legislation	7 years
Other – net	$ 26,300,000	$ 18,700,000	$ 16,800,000
Indiana [Member] | Indiana Recovery and Deferral Mechanisms [Member]
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items]
Regulatory Assset balance associated with Vectren north and south programs	21,900,000	19,900,000
Indiana [Member] | Senate Bill 251 and 560 [Member]
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items]
Investment in infrastructure modernization project	80,000,000				$ 890,000,000
Capital expenditure increase	65,000,000
Project spend life to date	338,000,000
Regulatory assets related to return on investment, depreciation deferral, and other operating expenses	51,100,000	28,600,000
Ohio [Member] | Ohio Recovery and Deferral Mechanisms [Member]
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items]
Initial DRR Term	100,000,000
Amount of Capital Investment Expected Over Next Five Years Recoverable Under DRR	120,000,000
Cumulative gross plant investment made under Distribution Replacement Rider	259,600,000	204,000,000
Regulatory Asset associated with DRR deferrals of depreciation and post in-service carrying costs	24,400,000	18,200,000
Ohio [Member] | Ohio House Bill95 [Member]
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items]
Impact on Customer Bill Per Month	1.50
Other – net	41,900,000	$ 24,100,000
Indiana Gas [Member] | Indiana [Member] | Indiana Recovery and Deferral Mechanisms [Member]
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items]
Allowable capital expenditures under Vectren North Program	$ 20,000,000
Limitations of deferrals of debt-related post in service carrying costs	4 years
SIGECO [Member] | Indiana [Member] | Indiana Recovery and Deferral Mechanisms [Member]
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items]
Allowable capital expenditures under Vectren South program	$ 3,000,000
Limitations of deferrals of debt-related post in service carrying costs	3 years
Subsequent Event [Member] | Indiana [Member] | Senate Bill 251 and 560 [Member]
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items]
Investment in infrastructure modernization project				$ 950,000,000
Senate Bill 251 and 560 [Member] | Indiana [Member]
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items]
Capital expenditure increase	$ 60,000,000

Electric Rate and Regulatory 46

Electric Rate and Regulatory Matters (Details) $ in Millions

Feb. 23, 2017USD ($)

Mar. 23, 2016

Aug. 31, 2011

Dec. 31, 2016USD ($)MW

Dec. 31, 2015USD ($)

Dec. 31, 2014USD ($)

Feb. 22, 2017USD ($)MW

Sep. 28, 2016

Jun. 30, 2016

Oct. 29, 2015USD ($)

Jan. 06, 2015

Nov. 12, 2013

Public Utilities, General Disclosures [Line Items]

Length of project plan required for recovery under new legislation

7 years

Added rooftop solar generation | MW

4

Vectren South Electric Environmental Compliance Filing [Abstract]

Lower range of request for approval of capital investments on coal-fired generation units

$ 30

Upper range of request for approval of capital investments on coal-fired generation units

40

Estimated cost of equipment to comply with MATS

6.9

$ 30

Estimated cost of equipment required by the NOV

2.8

$ 40

Amount of deferred costs to date related to depreciation, property tax, and operating expenses under Senate Bill 29 and Senate Bill 251

30

Amount of deferred costs to date related to post in-service carrying costs under Senate Bill 29 and Senate Bill 251.

40

Vectren South Electric Demand Side Management Program Filing [Abstract]

Number of years in DSM plan

3 years

Electric revenue recognized associated with lost margin recovery

11.1

$ 10.1

$ 8.7

FERC Return On Equity Complaint [Abstract]

Current return on equity used in MISO transmission owners rates

12.38%

Reduced return on equity percentage sought by third party through joint complaint

9.15%

Incentive return granted on qualifying investments in NETO

10.32%

Percentage return approved by FERC on ROE complaint against NETO

9.70%

FERC authorized base ROE percentage for first refund period

0.50%

Investment in qualifying projects

157.7

Net investment in qualifying projects

$ 136.8

Electric Demand Side Management Filing [Member]

Vectren South Electric Demand Side Management Program Filing [Abstract]

Maximum period for recovery under energy efficiency program

4 years

Subsequent Event [Member]

Public Utilities, General Disclosures [Line Items]

Added universal solar generation | MW

4

Added battery storage resources | MW

1

Subsequent Event [Member] | Electric Modernization Program - SB 560 [Member]

Public Utilities, General Disclosures [Line Items]

Capital expenditures

$ 500

Length of project plan required for recovery under new legislation

7 years

Subsequent Event [Member] | Renewable Generation - SB 29 [Member]

Public Utilities, General Disclosures [Line Items]

Capital expenditures under project plan

$ 15

Environmental and Sustainabil47

Environmental and Sustainability Matters (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)lb / MWhagreementsiteMW	Dec. 31, 2015USD ($)	Oct. 29, 2015USD ($)	Dec. 31, 2014USD ($)
Site Contingency [Line Items]
Coal-fired generation | MW	1,000
Natural gas peaking units | MW	245
Landfill-gas-to-electricity facility | MW	3
Wind power | MW	80
Number of purchase agreements | agreement	2
Period of plan	20 years
Additional universal solar | MW	54
Expected additional capacity from newly constructed plant | MW	890
Coal Ash Waste Disposal, Ash Ponds and Water [Abstract]
Estimated capital expenditures to comply with Ash Pond and Coal Ash disposal regulations - lower range	$ 35
Estimated capital expenditures to comply with Ash Pond and Coal Ash disposal regulations - upper range	80
Asset retirement obligation	106.6	$ 81.9		$ 54.6
Estimated spend for ash pond dam reinforcement and other operational changes	17
Estimated capital expenditures to comply with Clean Water Act (Lower Range)	4
Estimated capital expenditures to comply with Clean Water Act (Upper Range)	8
Air Quality [Abstract]
Amount approved for capital investments on coal-fired generation units	70
Amount of capital investments to date in equipment for mercury control	30
Estimated cost of equipment to comply with MATS	6.9		$ 30
Estimated cost of equipment required by the NOV	$ 2.8		$ 40
Percentage of coal fired generating fleet currently being scrubbed for SO2 (in hundredths)	100.00%
Percentage of coal fired generating fleet currently controlled for NOx (in hundredths)	90.00%
Climate Changes [Abstract]
Vectren's share of Indiana's CO2 emissions historically (as a percent)				6.00%
Percent reduction of Vectren's CO2 emissions since 2005		31.00%
Long term contract for purchase of electric power generated by wind energy (in megawatts) | MW	80
Percentage of total electricity obtained by the supplier to meet the energy needs of its retail customers provided by clean energy sources (in hundredths)	4.00%
Vectren's emission rate (as measured in lbs CO2/MWh) prior to installation of new technology | lb / MWh	1,967
Vectren's emission rate (as measured in lbs CO2/MWh) after installation of new technology | lb / MWh	1,922
Percentage reduction of lbs CO2/MWh since 2005	3.00%
Manufactured Gas Plants
Site contingency, accrual, undiscounted amount	$ 44.2
Accrued costs included in Other Liabilities	$ 2.9	$ 3.3
Indiana Gas [Member]
Manufactured Gas Plants
Number of sites identified with potential remedial responsibility for entity (in number of sites) | site	26
Site contingency, accrual, undiscounted amount	$ 23.9
Environmental cost recognized, recover from insurance carriers credited to expense	$ 20.8
SIGECO [Member]
Manufactured Gas Plants
Number of sites identified with potential remedial responsibility for entity (in number of sites) | site	5
Site contingency, accrual, undiscounted amount	$ 20.3
Environmental cost recognized, recover from insurance carriers credited to expense	15.2
Insurance recoveries	15.8
Minimum [Member]
Coal Ash Waste Disposal, Ash Ponds and Water [Abstract]
Ash Pond and Coal Ash disposal exit costs revised anticipated cost	45
Maximum [Member]
Coal Ash Waste Disposal, Ash Ponds and Water [Abstract]
Ash Pond and Coal Ash disposal exit costs revised anticipated cost	100
Ash Ponds [Member] | SIGECO [Member]
Coal Ash Waste Disposal, Ash Ponds and Water [Abstract]
Asset retirement obligation	$ 40
OVEC [Member]
Site Contingency [Line Items]
Coal-fired generation | MW	32
Warrick Unit 4 [Member]
Site Contingency [Line Items]
Current electric capacity under joint operations | MW	300
Culley Unit 3 [Member]
Site Contingency [Line Items]
Current electric capacity under joint operations | MW	270
AB Brown Unit 1, AB Brown Unit 2 & Culley Unit 2 [Member]
Site Contingency [Line Items]
Current electric capacity under joint operations | MW	580

Fair Value Measurements (Detail

Fair Value Measurements (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	$ 1,380.1	$ 1,392.2
Short-term borrowings	194.4	14.5
Cash & cash equivalents	9.4	6.2
Restricted cash	0.9	5.9
Estimated Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	1,495.3	1,495
Short-term borrowings	194.4	14.5
Cash & cash equivalents	9.4	6.2
Restricted cash	$ 0.9	$ 5.9

Segment Reporting (Details)

Segment Reporting (Details) customer in Millions, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2016USD ($)customersegment	Sep. 30, 2016USD ($)	Jun. 30, 2016USD ($)	Mar. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Sep. 30, 2015USD ($)	Jun. 30, 2015USD ($)	Mar. 31, 2015USD ($)	Dec. 31, 2016USD ($)customersegment	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Segment Reporting Information [Line Items]
Portion of Indiana that is provided natural gas distribution and transportation services by the Gas Utility Services segment (in hundredths)	66.67%								66.67%
Number of customers (greater than) | customer	1								1
Number of operating segments in Utility group | segment	3								3
Revenues	$ 383.5	$ 291.3	$ 279.8	$ 423.4	$ 338.1	$ 273	$ 276.5	$ 506.9	$ 1,377.8	$ 1,394.5	$ 1,569.7
Net income (loss)	51.3	$ 34.9	$ 26.3	$ 61.1	46.6	$ 26.9	$ 24.4	$ 63	173.6	160.9	148.4
Amounts Included in Profitability Measures [Abstract]
Depreciation and Amortization									219.1	208.8	203.1
Interest expense									69.7	66.3	66.6
Income Taxes									99.5	88.1	83.2
Capital Expenditures									496.6	399.2	351
Non-cash costs & changes in accruals									(7.3)	(5.3)	(10.1)
Assets	5,040.9				4,592.7				5,040.9	4,592.7	4,409.3
Operating Segments [Member] | Gas Utility Services [Member]
Segment Reporting Information [Line Items]
Revenues									771.7	792.6	944.6
Net income (loss)									76.1	64.4	57
Amounts Included in Profitability Measures [Abstract]
Depreciation and Amortization									108.1	98.6	93.3
Interest expense									40.1	35.8	34.9
Income Taxes									47.1	40.8	35.7
Capital Expenditures									358.5	291.2	245.9
Assets	3,091				2,706.9				3,091	2,706.9	2,604.6
Operating Segments [Member] | Electric Utility Services [Member]
Segment Reporting Information [Line Items]
Revenues									605.8	601.6	624.8
Net income (loss)									84.7	82.6	79.7
Amounts Included in Profitability Measures [Abstract]
Depreciation and Amortization									87.1	85.6	85.7
Interest expense									27	27.8	29
Income Taxes									50.1	49.3	48.1
Capital Expenditures									106.4	87.6	92.4
Assets	1,788.4				1,778.3				1,788.4	1,778.3	1,656.2
Operating Segments [Member] | Other Operations [Member]
Segment Reporting Information [Line Items]
Revenues									42.2	40.7	38.3
Net income (loss)									12.8	13.9	11.7
Amounts Included in Profitability Measures [Abstract]
Depreciation and Amortization									23.9	24.6	24.1
Interest expense									2.6	2.7	2.7
Income Taxes									2.3	(2)	(0.6)
Capital Expenditures									39	25.7	22.8
Assets	$ 161.5				$ 107.5				161.5	107.5	148.5
Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues									$ (41.9)	$ (40.4)	$ (38)

Additional Balance Sheet & Op50

Additional Balance Sheet & Operational Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Inventory, Net [Abstract]
Gas in storage – at LIFO cost	$ 37	$ 40.5
Materials & supplies	38.1	38.4
Coal & oil for electric generation - at average cost	42.6	45
Other	1.3	1.4
Total inventories	119	125.3
Amount by which cost of replacing inventories carried at LIFO cost exceeded carrying value	1
Prepayments and other current assets [Abstract]
Prepaid gas delivery service	26.4	30
Prepaid taxes	8	3.9
Other prepayments & current assets	4.2	15.1
Total prepayments & other current assets	38.6	49
Other utility and corporate investments [Abstract]
Cash surrender value of life insurance policies	20.4	19.2
Restricted cash & other investments	0.9	0.9
Total other investments	21.3	20.1
Accrued liabilities [Abstract]
Refunds to customers & customer deposits	49.4	51.4
Accrued taxes	44.8	36.7
Accrued interest	16.4	16.3
Accrued salaries & other	29.5	24
Total accrued liabilities	140.1	128.4
Asset Retirement Obligation [Roll Forward]
Asset retirement obligation, beginning balance	81.9	54.6
Accretion	3.8	3.3
Liabilities incurred in current period	0	24.2
Changes in estimates, net of cash payments	20.9	(0.2)
Asset retirement obligation, ending balance	106.6	81.9	$ 54.6
Other - net in the consolidated statement of income [Abstract]
AFUDC - borrowed funds	20.3	16.3	10.8
AFUDC - equity funds	2.2	2.6	3.2
Nonutility plant capitalized interest	1	0.4	0.6
Interest income	0.3	0.6	0.7
Other income	2.5	(1.2)	1.5
Total other income (expense)	26.3	18.7	16.8
Cash paid (received) for [Abstract]
Interest	69.6	66.2	66.7
Income taxes	6.7	(23.1)	$ 63.2
Accruals related to utility and nonutility plant purchases [Abstract]
Accruals related to utility and nonutility plant purchases	$ 27.4	$ 18.1

Subsidiary Guarantor & Consol51

Subsidiary Guarantor & Consolidating Information Narrative (Details)	12 Months Ended
	Dec. 31, 2016USD ($)public_utility
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Operating utility companies | public_utility	3
Short-term borrowing capacity	$ 350,000,000
Line of credit facility, amount outstanding	194,000,000
Unsecured debt	$ 996,000,000

Subsidiary Guarantor & Consol52

Subsidiary Guarantor & Consolidating Information Income Statement (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
OPERATING REVENUES
Gas utility									$ 771.7	$ 792.6	$ 944.6
Electric utility									605.8	601.6	624.8
Other									0.3	0.3	0.3
Total operating revenues	$ 383.5	$ 291.3	$ 279.8	$ 423.4	$ 338.1	$ 273	$ 276.5	$ 506.9	1,377.8	1,394.5	1,569.7
OPERATING EXPENSES
Cost of gas sold									266.7	305.4	468.7
Cost of fuel & purchased power									183.6	187.5	201.8
Other operating									333.6	339.1	354.5
Depreciation & amortization									219.1	208.8	203.1
Taxes other than income taxes									58.3	57.1	60.2
Total operating expenses									1,061.3	1,097.9	1,288.3
OPERATING INCOME	93.5	64	52.2	106.8	81.3	54.1	50.5	110.8	316.5	296.6	281.4
OTHER INCOME (EXPENSE)
Equity in earnings of consolidated companies									0	0	0
Other – net									26.3	18.7	16.8
Total other income (expense)									26.3	18.7	16.8
Interest expense									69.7	66.3	66.6
INCOME BEFORE INCOME TAXES									273.1	249	231.6
Income taxes									99.5	88.1	83.2
NET INCOME	$ 51.3	$ 34.9	$ 26.3	$ 61.1	$ 46.6	$ 26.9	$ 24.4	$ 63	173.6	160.9	148.4
Reclassifications and Eliminations [Member]
OPERATING REVENUES
Gas utility									0	0	0
Electric utility									0	0	0
Other									(41.9)	(40.4)	(38)
Total operating revenues									(41.9)	(40.4)	(38)
OPERATING EXPENSES
Cost of gas sold									0	0	0
Cost of fuel & purchased power									0	0	0
Other operating									(40.4)	(37.8)	(35.8)
Depreciation & amortization									0.1	0.3	0.5
Taxes other than income taxes									0	0.1	0.1
Total operating expenses									(40.3)	(37.4)	(35.2)
OPERATING INCOME									(1.6)	(3)	(2.8)
OTHER INCOME (EXPENSE)
Equity in earnings of consolidated companies									(160.8)	(147)	(136.7)
Other – net									(46)	(39.7)	(39.7)
Total other income (expense)									(206.8)	(186.7)	(176.4)
Interest expense									(47.6)	(42.7)	(42.5)
INCOME BEFORE INCOME TAXES									(160.8)	(147)	(136.7)
Income taxes									0	0	0
NET INCOME									(160.8)	(147)	(136.7)
Subsidiary Guarantors [Member]
OPERATING REVENUES
Gas utility									771.7	792.6	944.6
Electric utility									605.8	601.6	624.8
Other									0	0	0
Total operating revenues									1,377.5	1,394.2	1,569.4
OPERATING EXPENSES
Cost of gas sold									266.7	305.4	468.7
Cost of fuel & purchased power									183.6	187.5	201.8
Other operating									374	376.9	390.3
Depreciation & amortization									195.2	184.2	179.1
Taxes other than income taxes									56.8	55.2	58.4
Total operating expenses									1,076.3	1,109.2	1,298.3
OPERATING INCOME									301.2	285	271.1
OTHER INCOME (EXPENSE)
Equity in earnings of consolidated companies									0	0	0
Other – net									24	15.7	13.3
Total other income (expense)									24	15.7	13.3
Interest expense									67.2	63.7	63.9
INCOME BEFORE INCOME TAXES									258	237	220.5
Income taxes									97.2	90	83.8
NET INCOME									160.8	147	136.7
Parent Company [Member]
OPERATING REVENUES
Gas utility									0	0	0
Electric utility									0	0	0
Other									42.2	40.7	38.3
Total operating revenues									42.2	40.7	38.3
OPERATING EXPENSES
Cost of gas sold									0	0	0
Cost of fuel & purchased power									0	0	0
Other operating									0	0	0
Depreciation & amortization									23.8	24.3	23.5
Taxes other than income taxes									1.5	1.8	1.7
Total operating expenses									25.3	26.1	25.2
OPERATING INCOME									16.9	14.6	13.1
OTHER INCOME (EXPENSE)
Equity in earnings of consolidated companies									160.8	147	136.7
Other – net									48.3	42.7	43.2
Total other income (expense)									209.1	189.7	179.9
Interest expense									50.1	45.3	45.2
INCOME BEFORE INCOME TAXES									175.9	159	147.8
Income taxes									2.3	(1.9)	(0.6)
NET INCOME									$ 173.6	$ 160.9	$ 148.4

Subsidiary Guarantor & Consol53

Subsidiary Guarantor & Consolidating Information Balance Sheet (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
ASSETS
Cash & cash equivalents	$ 9.4	$ 6.2	$ 19.3	$ 8.6
Accounts receivable - less reserves	102.6	92.3
Intercompany receivables	0	0
Accrued unbilled revenues	112	85.7
Inventories	119	125.3
Recoverable fuel & natural gas costs	29.9	0
Prepayments & other current assets	38.6	49
Total current assets	411.5	358.5
Original cost	6,545.4	6,090.4
Less: accumulated depreciation & amortization	2,562.5	2,415.5
Net utility plant	3,982.9	3,674.9
Investments in consolidated subsidiaries	0	0
Notes receivable from consolidated subsidiaries	0	0
Investments in unconsolidated affiliates	0.2	0.2
Other investments	21.3	20.1
Nonutility plant - net	164.8	149.7
Goodwill	205	205
Regulatory assets	206.2	152.1
Other assets	49	32.2
TOTAL ASSETS	5,040.9	4,592.7	4,409.3
LIABILITIES & SHAREHOLDER'S EQUITY
Accounts payable	205.4	168.5
Intercompany payables	0	0
Payables to other Vectren companies	25.4	25.7
Accrued liabilities	140.1	128.4
Short-term borrowings	194.4	14.5	156.4
Intercompany short-term borrowings	0	0
Current maturities of long-term debt	49.1	13
Total current liabilities	614.4	350.1
Long-Term Debt - Net of Current Maturities	1,331	1,379.2
Long-term debt due to VUHI	0	0
Total long-term debt - net	1,331	1,379.2
Deferred income taxes	854.5	758.4
Regulatory liabilities	453.7	433.9
Deferred credits & other liabilities	163.3	135.9
Total deferred credits & other liabilities	1,471.5	1,328.2
Common stock (no par value)	831.2	799.9
Retained earnings	792.8	735.3
Total common shareholder's equity	1,624	1,535.2
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	5,040.9	4,592.7
Eliminations [Member]
ASSETS
Cash & cash equivalents	0	0	0	0
Accounts receivable - less reserves	0	0
Intercompany receivables	(174.6)	(194.1)
Accrued unbilled revenues	0	0
Inventories	0	0
Recoverable fuel & natural gas costs	0
Prepayments & other current assets	(2.3)	(4.4)
Total current assets	(176.9)	(198.5)
Original cost	0	0
Less: accumulated depreciation & amortization	0	0
Net utility plant	0	0
Investments in consolidated subsidiaries	(1,577.2)	(1,467)
Notes receivable from consolidated subsidiaries	(945.4)	(836)
Investments in unconsolidated affiliates	0	0
Other investments	0	0
Nonutility plant - net	0	0
Goodwill	0	0
Regulatory assets	0	0
Other assets	(8.6)	(8.7)
TOTAL ASSETS	(2,708.1)	(2,510.2)
LIABILITIES & SHAREHOLDER'S EQUITY
Accounts payable	0	0
Intercompany payables	(14.8)	(12.4)
Payables to other Vectren companies	0	0
Accrued liabilities	(2.3)	(4.4)
Short-term borrowings	0	0
Intercompany short-term borrowings	(159.8)	(181.7)
Current maturities of long-term debt	0	0
Total current liabilities	(176.9)	(198.5)
Long-Term Debt - Net of Current Maturities	0	0
Long-term debt due to VUHI	(945.4)	(836)
Total long-term debt - net	(945.4)	(836)
Deferred income taxes	0	0
Regulatory liabilities	0	0
Deferred credits & other liabilities	(8.6)	(8.7)
Total deferred credits & other liabilities	(8.6)	(8.7)
Common stock (no par value)	(844.4)	(813.1)
Retained earnings	(732.8)	(653.9)
Total common shareholder's equity	(1,577.2)	(1,467)
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	(2,708.1)	(2,510.2)
Subsidiary Guarantors [Member]
ASSETS
Cash & cash equivalents	7.6	5.5	6.9	8.2
Accounts receivable - less reserves	102.4	92.3
Intercompany receivables	17.5	51.2
Accrued unbilled revenues	112	85.7
Inventories	119	125.3
Recoverable fuel & natural gas costs	29.9
Prepayments & other current assets	36.5	49.3
Total current assets	424.9	409.3
Original cost	6,545.4	6,090.4
Less: accumulated depreciation & amortization	2,562.5	2,415.5
Net utility plant	3,982.9	3,674.9
Investments in consolidated subsidiaries	0	0
Notes receivable from consolidated subsidiaries	0	0
Investments in unconsolidated affiliates	0.2	0.2
Other investments	20.9	19.7
Nonutility plant - net	1.7	1.7
Goodwill	205	205
Regulatory assets	190	135.2
Other assets	53.9	39.6
TOTAL ASSETS	4,879.5	4,485.6
LIABILITIES & SHAREHOLDER'S EQUITY
Accounts payable	194.6	161.1
Intercompany payables	14.8	12.4
Payables to other Vectren companies	25.4	25.7
Accrued liabilities	126	120.2
Short-term borrowings	0	0
Intercompany short-term borrowings	142.3	130.5
Current maturities of long-term debt	49.1	13
Total current liabilities	552.2	462.9
Long-Term Debt - Net of Current Maturities	335.2	383.9
Long-term debt due to VUHI	945.4	836
Total long-term debt - net	1,280.6	1,219.9
Deferred income taxes	855.4	763.7
Regulatory liabilities	452.4	432.5
Deferred credits & other liabilities	161.7	139.6
Total deferred credits & other liabilities	1,469.5	1,335.8
Common stock (no par value)	844.4	813.1
Retained earnings	732.8	653.9
Total common shareholder's equity	1,577.2	1,467
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	4,879.5	4,485.6
Parent Company [Member]
ASSETS
Cash & cash equivalents	1.8	0.7	$ 12.4	$ 0.4
Accounts receivable - less reserves	0.2	0
Intercompany receivables	157.1	142.9
Accrued unbilled revenues	0	0
Inventories	0	0
Recoverable fuel & natural gas costs	0
Prepayments & other current assets	4.4	4.1
Total current assets	163.5	147.7
Original cost	0	0
Less: accumulated depreciation & amortization	0	0
Net utility plant	0	0
Investments in consolidated subsidiaries	1,577.2	1,467
Notes receivable from consolidated subsidiaries	945.4	836
Investments in unconsolidated affiliates	0	0
Other investments	0.4	0.4
Nonutility plant - net	163.1	148
Goodwill	0	0
Regulatory assets	16.2	16.9
Other assets	3.7	1.3
TOTAL ASSETS	2,869.5	2,617.3
LIABILITIES & SHAREHOLDER'S EQUITY
Accounts payable	10.8	7.4
Intercompany payables	0	0
Payables to other Vectren companies	0	0
Accrued liabilities	16.4	12.6
Short-term borrowings	194.4	14.5
Intercompany short-term borrowings	17.5	51.2
Current maturities of long-term debt	0	0
Total current liabilities	239.1	85.7
Long-Term Debt - Net of Current Maturities	995.8	995.3
Long-term debt due to VUHI	0	0
Total long-term debt - net	995.8	995.3
Deferred income taxes	(0.9)	(5.3)
Regulatory liabilities	1.3	1.4
Deferred credits & other liabilities	10.2	5
Total deferred credits & other liabilities	10.6	1.1
Common stock (no par value)	831.2	799.9
Retained earnings	792.8	735.3
Total common shareholder's equity	1,624	1,535.2
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	$ 2,869.5	$ 2,617.3

Subsidiary Guarantor & Consol54

Subsidiary Guarantor & Consolidating Information Cash Flows (Details) - USD ($) $ in Millions	12 Months Ended			36 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2016
Condensed Cash Flow Statements, Captions [Line Items]
Net cash flows from operating activities	$ 397.4	$ 492.9	$ 337.5
CASH FLOWS FROM FINANCING ACTIVITIES
Long-term debt, net of issuance costs	0	236.3	62.4
Additional capital contribution from Parent	31.3	6.2	6
Dividends to parent	(116.1)	(110.4)	(108.7)
Retirement of long-term debt	(13)	(95)	(63.6)
Net change in intercompany short-term borrowings	0	0	0
Net change in short-term borrowings	179.9	(141.9)	127.8
Net cash used in financing activities	82.1	(104.8)	23.9
CASH FLOWS FROM INVESTING ACTIVITIES
Consolidated subsidiary distributions	0	0	0
Proceeds from other investing activities	15.3	3.9	0.3
Capital expenditures, excluding AFUDC equity	(496.6)	(399.2)	(351)
Requirements for consolidated subsidiary investments	0		0
Consolidated subsidiary investments		0
Changes in restricted cash	5	(5.9)	0
Net change in long term intercompany notes receivable	0	0	0
Net change in short term intercompany notes receivable	0	0	0
Net cash used in investing activities	(476.3)	(401.2)	(350.7)
Net change in cash & cash equivalents	3.2	(13.1)	10.7
Cash & cash equivalents at beginning of period	6.2	19.3	8.6	$ 8.6
Cash & cash equivalents at end of period	9.4	6.2	19.3	9.4
Eliminations [Member]
Condensed Cash Flow Statements, Captions [Line Items]
Net cash flows from operating activities	0	0	0
CASH FLOWS FROM FINANCING ACTIVITIES
Long-term debt, net of issuance costs	(109.4)	(89.5)	(124.2)
Additional capital contribution from Parent	(31.3)	(6.2)	(6)
Dividends to parent	82	103.2	101.6
Retirement of long-term debt	0	0	0
Net change in intercompany short-term borrowings	21.8	(10.5)	(23.6)
Net change in short-term borrowings	0	0	0
Net cash used in financing activities	(36.9)	(3)	(52.2)
CASH FLOWS FROM INVESTING ACTIVITIES
Consolidated subsidiary distributions	(82)	(103.2)	(101.6)
Proceeds from other investing activities	0	0	0
Capital expenditures, excluding AFUDC equity	0	0	0
Requirements for consolidated subsidiary investments	31.3		6
Consolidated subsidiary investments		6.2
Changes in restricted cash	0	0
Net change in long term intercompany notes receivable	109.4	89.5	50.1
Net change in short term intercompany notes receivable	(21.8)	10.5	97.7
Net cash used in investing activities	36.9	3	52.2
Net change in cash & cash equivalents	0	0	0
Cash & cash equivalents at beginning of period	0	0	0	0
Cash & cash equivalents at end of period	0	0	0	0
Subsidiary Guarantors [Member]
Condensed Cash Flow Statements, Captions [Line Items]
Net cash flows from operating activities	352.2	460.3	274.4
CASH FLOWS FROM FINANCING ACTIVITIES
Long-term debt, net of issuance costs	109.4	126.8	186.6
Additional capital contribution from Parent	31.3	6.2	6
Dividends to parent	(82)	(103.2)	(101.6)
Retirement of long-term debt	(13)	(20)	(63.6)
Net change in intercompany short-term borrowings	11.9	(40.7)	23.9
Net change in short-term borrowings	0	0	0
Net cash used in financing activities	57.6	(30.9)	51.3
CASH FLOWS FROM INVESTING ACTIVITIES
Consolidated subsidiary distributions	0	0	0
Proceeds from other investing activities	15.3	0	0
Capital expenditures, excluding AFUDC equity	(461.7)	(373.7)	(327.3)
Requirements for consolidated subsidiary investments	0		0
Consolidated subsidiary investments		0
Changes in restricted cash	5	(5.9)
Net change in long term intercompany notes receivable	0	0	0
Net change in short term intercompany notes receivable	33.7	(51.2)	0.3
Net cash used in investing activities	(407.7)	(430.8)	(327)
Net change in cash & cash equivalents	2.1	(1.4)	(1.3)
Cash & cash equivalents at beginning of period	5.5	6.9	8.2	8.2
Cash & cash equivalents at end of period	7.6	5.5	6.9	7.6
Parent Company [Member]
Condensed Cash Flow Statements, Captions [Line Items]
Net cash flows from operating activities	45.2	32.6	63.1
CASH FLOWS FROM FINANCING ACTIVITIES
Long-term debt, net of issuance costs	0	199	0
Additional capital contribution from Parent	31.3	6.2	6
Dividends to parent	(116.1)	(110.4)	(108.7)
Retirement of long-term debt	0	(75)	0
Net change in intercompany short-term borrowings	(33.7)	51.2	(0.3)
Net change in short-term borrowings	179.9	(141.9)	127.8
Net cash used in financing activities	61.4	(70.9)	24.8
CASH FLOWS FROM INVESTING ACTIVITIES
Consolidated subsidiary distributions	82	103.2	101.6
Proceeds from other investing activities	0	3.9	0.3
Capital expenditures, excluding AFUDC equity	(34.9)	(25.5)	(23.7)
Requirements for consolidated subsidiary investments	(31.3)		(6)
Consolidated subsidiary investments		(6.2)
Changes in restricted cash	0	0
Net change in long term intercompany notes receivable	(109.4)	(89.5)	(50.1)
Net change in short term intercompany notes receivable	(11.9)	40.7	(98)
Net cash used in investing activities	(105.5)	26.6	(75.9)
Net change in cash & cash equivalents	1.1	(11.7)	12
Cash & cash equivalents at beginning of period	0.7	12.4	0.4	0.4
Cash & cash equivalents at end of period	$ 1.8	$ 0.7	$ 12.4	$ 1.8

Impact of Recently Issued Acc55

Impact of Recently Issued Accounting Guidance (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Debt issuance costs	$ 7.9	$ 8.6
Regulatory Assets [Member] | Accounting Standards Update 2015-03 [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Debt issuance costs		(8.6)
Long-term Debt [Member] | Accounting Standards Update 2015-03 [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Debt issuance costs		$ 8.6

Quarterly Financial Data (Una56

Quarterly Financial Data (Unaudited) (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]
Operating revenues	$ 383.5	$ 291.3	$ 279.8	$ 423.4	$ 338.1	$ 273	$ 276.5	$ 506.9	$ 1,377.8	$ 1,394.5	$ 1,569.7
Operating income	93.5	64	52.2	106.8	81.3	54.1	50.5	110.8	316.5	296.6	281.4
Net income	$ 51.3	$ 34.9	$ 26.3	$ 61.1	$ 46.6	$ 26.9	$ 24.4	$ 63	$ 173.6	$ 160.9	$ 148.4

SCHEDULE II VALUATION AND QUA57

SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES (Details) - Accumulated Provision for Uncollectible Accounts [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Allowance for Doubtful Accounts Receivable [Roll Forward]
Balance, at beginning of year	$ 3	$ 3.9	$ 5
Additions charged to expenses	6.6	6.9	6.1
Additions charged to other accounts	0	0	0
Deductions from Reserves, Net	5.5	7.8	7.2
Balance, at end of period	$ 4.1	$ 3	$ 3.9