Document_And_Entity_Informatio
Document And Entity Information (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Jan. 30, 2015 | Jun. 30, 2014 | |
Entity Information [Line Items] | |||
Entity Registrant Name | VECTREN CORP | ||
Entity Central Index Key | 1096385 | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | No | ||
Entity Filer Category | Large Accelerated Filer | ||
Entity Public Float | $3,496,151,448 | ||
Entity Common Stock, Shares Outstanding | 82,593,724 | ||
Document Fiscal Year Focus | 2014 | ||
Document Fiscal Period Focus | FY | ||
Document Type | 10-K | ||
Amendment Flag | FALSE | ||
Document Period End Date | 31-Dec-14 | ||
Current Fiscal Year End Date | -19 |
Balance_Sheet
Balance Sheet (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Millions, unless otherwise specified | ||
Current Assets | ||
Cash and cash equivalents | $86.40 | $21.50 |
Accounts receivable - less reserves of $6.0 & $6.8, respectively | 196 | 259.2 |
Accrued unbilled revenues | 164.8 | 134.2 |
Inventories | 118.5 | 134.4 |
Recoverable fuel and natural gas costs | 9.8 | 5.5 |
Prepayments and other current assets | 110.9 | 75.6 |
Total current assets | 686.4 | 630.4 |
Utility Plant | ||
Original cost | 5,718.70 | 5,389.60 |
Less: accumulated depreciation and amortization | 2,279.70 | 2,165.30 |
Net utility plant | 3,439 | 3,224.30 |
Investments in unconsolidated affiliates | 23.4 | 24 |
Other utility and corporate investments | 37.2 | 38.1 |
Other nonutility investments | 33.6 | 33.8 |
Nonutility plant - net | 378 | 657.2 |
Goodwill | 289.9 | 262.3 |
Regulatory assets | 233.6 | 193.4 |
Other assets | 41.2 | 39.1 |
TOTAL ASSETS | 5,162.30 | 5,102.60 |
Current Liabilities | ||
Accounts payable | 248.9 | 227.2 |
Refundable fuel and natural gas costs | 2.5 | 2.6 |
Accrued liabilities | 184.9 | 182.1 |
Short-term borrowings | 156.4 | 68.6 |
Current maturities of long-term debt | 170 | 30 |
Total current liabilities | 762.7 | 510.5 |
Long-term Debt - Net of Current Maturities | 1,407.30 | 1,777.10 |
Deferred Income Taxes and Other Liabilities | ||
Deferred income taxes | 741.2 | 707.4 |
Regulatory liabilities | 410.3 | 387.3 |
Deferred credits and other liabilities | 234.2 | 166 |
Total deferred credits and other liabilities | 1,385.70 | 1,260.70 |
Commitments & Contingencies (Notes 7, 17-20) | ||
Common Shareholders' Equity | ||
Common stock (no par value) – issued & outstanding 82.6 & 82.4 shares, respectively | 715.7 | 709.3 |
Retained earnings | 892.2 | 845.7 |
Accumulated other comprehensive income/(loss) | -1.3 | -0.7 |
Total common shareholders' equity | 1,606.60 | 1,554.30 |
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY | $5,162.30 | $5,102.60 |
Income_Statement
Income Statement (USD $) | 12 Months Ended | ||
In Millions, except Per Share data, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
OPERATING REVENUES | |||
Gas utility | $944.60 | $810 | $738.10 |
Electric utility | 624.8 | 619.3 | 594.9 |
Nonutility | 1,042.30 | 1,061.90 | 899.8 |
Total operating revenues | 2,611.70 | 2,491.20 | 2,232.80 |
OPERATING EXPENSES | |||
Cost of gas sold | 468.7 | 358.1 | 301.3 |
Cost of fuel and purchased power | 201.8 | 202.9 | 192 |
Cost of nonutility revenues | 346.4 | 366.7 | 295.1 |
Other operating | 943.4 | 891.6 | 781 |
Depreciation and amortization | 273.4 | 277.8 | 254.6 |
Taxes other than income taxes | 63.5 | 60.5 | 56.3 |
Total operating expenses | 2,297.20 | 2,157.60 | 1,880.30 |
OPERATING INCOME | 314.5 | 333.6 | 352.5 |
OTHER INCOME (EXPENSE) | |||
Equity in earnings (losses) of unconsolidated affiliates | 0.5 | -59.7 | -23.3 |
Other income (expense) - net | 19.7 | 17.7 | 8.3 |
Total other income (expense) | 20.2 | -42 | -15 |
Interest expense | 86.7 | 87.9 | 96 |
INCOME BEFORE INCOME TAXES | 248 | 203.7 | 241.5 |
Income taxes | 81.1 | 67.1 | 82.5 |
Net income | $166.90 | $136.60 | $159 |
AVERAGE COMMON SHARES OUTSTANDING (in shares) | 82.5 | 82.3 | 82 |
DILUTED COMMON SHARES OUTSTANDING (in shares) | 82.5 | 82.4 | 82.1 |
EARNINGS PER SHARE OF COMMON STOCK: | |||
BASIC (in dollars per share) | $2.02 | $1.66 | $1.94 |
DILUTED (in dollars per share) | $2.02 | $1.66 | $1.94 |
Balance_Sheet_Parenthetical
Balance Sheet (Parenthetical) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Millions, unless otherwise specified | ||
Current Assets | ||
Reserves | $6 | $6.80 |
Common Shareholders' Equity | ||
Common stock Shares, Issued (in shares) | 82.6 | 82.4 |
Common stock, Shares Outstanding (in shares) | 82.6 | 82.4 |
CONSOLIDATED_CONDENSED_STATEME
CONSOLIDATED CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Net Income | $166.90 | $136.60 | $159 |
Other comprehensive income | -0.6 | 3.6 | 9 |
TOTAL COMPREHENSIVE INCOME | 166.3 | 140.2 | 168 |
AOCI of Unconsolidated Affiliates [Member] | |||
Net amount arising during the year before tax | 0 | 4.6 | 11.3 |
Income taxes | 0 | -1.8 | -4.6 |
Other comprehensive income | 0 | 2.8 | 6.7 |
Pensions and Other Benefits [Member] | |||
Amounts arising during the year before tax | -52.6 | 61.4 | -3.3 |
Reclassifications to periodic cost before tax | 3.4 | 9.1 | 7.1 |
Deferrals to regulatory assets | 48.2 | -69.1 | 0.2 |
Income taxes | 0.4 | -0.6 | -1.6 |
Other comprehensive income | -0.6 | 0.8 | 2.4 |
Cash Flow Hedges [Member] | |||
Reclassifications to net income before tax | 0 | 0 | -0.1 |
Other comprehensive income | $0 | $0 | ($0.10) |
Statement_of_Cash_Flows
Statement of Cash Flows (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
CASH FLOWS FROM OPERATING ACTIVITIES | |||
Net Income | $166.90 | $136.60 | $159 |
Adjustments to reconcile net income to cash from operating activities: | |||
Depreciation and amortization | 273.4 | 277.8 | 254.6 |
Deferred income taxes and investment tax credits | 37.9 | 43.3 | 84.3 |
Equity in (earnings) losses of unconsolidated affiliates | -0.5 | 59.7 | 23.3 |
Provision for uncollectible accounts | 7.3 | 6.8 | 8.2 |
Expense portion of pension and postretirement benefit cost | 6.6 | 9.9 | 8.7 |
Other non-cash expense - net | 5.8 | 5.8 | 9.8 |
Loss on Sale of Business | 41.8 | 0 | 0 |
Gain on Revaluation of Contingent Consideration | -14.8 | 0 | 0 |
Changes in working capital accounts: | |||
Accounts receivable & accrued unbilled revenues | 11.8 | 1.5 | -67.1 |
Inventories | -22.5 | 24.2 | 3.3 |
Recoverable/refundable fuel and natural gas costs | -4.4 | 22.4 | -12.9 |
Prepayments and other current assets | -35.2 | 12.8 | -5.1 |
Accounts payable, including to affiliated companies | 20.2 | 6.8 | -14.8 |
Accrued liabilities | 12.3 | -1.2 | 3.4 |
Unconsolidated affiliate dividends | 0 | 1.1 | 0.1 |
Employer contributions to pension and postretirement plans | -5.1 | -13.7 | -20.5 |
Changes in noncurrent assets | 0.1 | -2.1 | -35.3 |
Changes in noncurrent liabilities | -13.4 | -4.7 | -11.6 |
Net cash flows from operating activities | 488.2 | 587 | 387.4 |
Proceeds from: | |||
Long-term debt, net of issuance costs | 62.4 | 481.7 | 199.5 |
Dividend reinvestment plan and other common stock issuances | 6.1 | 6.9 | 7.2 |
Requirements for: | |||
Dividends on common stock | -120.4 | -117.3 | -115.3 |
Retirement of long-term debt | -293.6 | -338.9 | -62.7 |
Other financing activities | 0.1 | -2.1 | 0 |
Net change in short-term borrowings | 87.8 | -210.2 | -48.3 |
Net cash flows from financing activities | -257.6 | -179.9 | -19.6 |
Proceeds from: | |||
Sale of business | 311.2 | 0 | 0 |
Unconsolidated affiliate distributions | 1.1 | 0 | 0.2 |
Other collections | 8.4 | 5.6 | 9.9 |
Requirements for: | |||
Transaction Costs for Sale of Business | -9.5 | 0 | 0 |
Capital expenditures, excluding AFUDC equity | -448.3 | -393.4 | -365.8 |
Business acquisition | -28.6 | 0 | 0 |
Other investments | 0 | -17.3 | -1.2 |
Net cash flows from investing activities | -165.7 | -405.1 | -356.9 |
Net change in cash and cash equivalents | 64.9 | 2 | 10.9 |
Cash and cash equivalents at beginning of period | 21.5 | 19.5 | 8.6 |
Cash and cash equivalents at end of period | $86.40 | $21.50 | $19.50 |
Statement_of_Shareholders_Equi
Statement of Shareholders' Equity (USD $) | Total | Common Stock [Member] | Retained Earnings [Member] | Accumulated Other Comprehensive Income (Loss) [Member] |
In Millions, unless otherwise specified | ||||
Balance at beginning of period at Dec. 31, 2011 | $1,465.50 | $692.60 | $786.20 | ($13.30) |
Balance at beginning of period (in shares) at Dec. 31, 2011 | 81.9 | |||
Comprehensive income: | ||||
Net Income | 159 | 159 | ||
Other comprehensive income | 9 | 9 | ||
Common stock: | ||||
Issuance: option exercises and dividend reinvestment plan (in shares) | 0.3 | |||
Issuance: option exercised and dividend reinvestment plan | 7.2 | 7.2 | ||
Dividends ($1.405, $1.425, and $1.460 per share) | -115.3 | -115.3 | ||
Other | 0.7 | 0.7 | ||
Balance at end of period at Dec. 31, 2012 | 1,526.10 | 700.5 | 829.9 | -4.3 |
Balance at end of period (in shares) at Dec. 31, 2012 | 82.2 | |||
Comprehensive income: | ||||
Net Income | 136.6 | 136.6 | ||
Other comprehensive income | 3.6 | 3.6 | ||
Common stock: | ||||
Issuance: option exercises and dividend reinvestment plan (in shares) | 0.2 | |||
Issuance: option exercised and dividend reinvestment plan | 6.9 | 6.9 | ||
Dividends ($1.405, $1.425, and $1.460 per share) | -117.3 | -117.3 | ||
Other | -1.6 | 1.9 | -3.5 | |
Balance at end of period at Dec. 31, 2013 | 1,554.30 | 709.3 | 845.7 | -0.7 |
Balance at end of period (in shares) at Dec. 31, 2013 | 82.4 | 82.4 | ||
Comprehensive income: | ||||
Net Income | 166.9 | 166.9 | ||
Other comprehensive income | -0.6 | -0.6 | ||
Common stock: | ||||
Issuance: option exercises and dividend reinvestment plan (in shares) | 0.2 | |||
Issuance: option exercised and dividend reinvestment plan | 6.1 | 6.1 | ||
Dividends ($1.405, $1.425, and $1.460 per share) | -120.4 | -120.4 | ||
Other | 0.3 | 0.3 | ||
Balance at end of period at Dec. 31, 2014 | $1,606.60 | $715.70 | $892.20 | ($1.30) |
Balance at end of period (in shares) at Dec. 31, 2014 | 82.6 | 82.6 |
Statement_of_Shareholders_Equi1
Statement of Shareholders' Equity (Parenthetical) (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Statement of Stockholders' Equity [Abstract] | |||
Dividends (in dollars per share) | $1.46 | $1.43 | $1.41 |
Organization_and_Nature_of_Ope
Organization and Nature of Operations | 12 Months Ended |
Dec. 31, 2014 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Organization and Nature of Operations | Organization and Nature of Operations |
Vectren Corporation (the Company or Vectren), an Indiana corporation, is an energy holding company headquartered in Evansville, Indiana. The Company’s wholly owned subsidiary, Vectren Utility Holdings, Inc. (Utility Holdings or VUHI), serves as the intermediate holding company for three public utilities: Indiana Gas Company, Inc. (Indiana Gas), Southern Indiana Gas and Electric Company (SIGECO), and Vectren Energy Delivery of Ohio, Inc. (VEDO). Utility Holdings also has other assets that provide information technology and other services to the three utilities. Utility Holdings’ consolidated operations are collectively referred to as the Utility Group. Both Vectren and Utility Holdings are holding companies as defined by the Energy Policy Act of 2005 (Energy Act). Vectren was incorporated under the laws of Indiana on June 10, 1999. | |
Indiana Gas provides energy delivery services to approximately 575,000 natural gas customers located in central and southern Indiana. SIGECO provides energy delivery services to approximately 143,000 electric customers and over 110,000 gas customers located near Evansville in southwestern Indiana. SIGECO also owns and operates electric generation assets to serve its electric customers and optimizes those assets in the wholesale power market. Indiana Gas and SIGECO generally do business as Vectren Energy Delivery of Indiana. VEDO provides energy delivery services to approximately 313,000 natural gas customers located near Dayton in west central Ohio. | |
The Company, through Vectren Enterprises, Inc. (Enterprises), is involved in nonutility activities in two primary business areas: Infrastructure Services and Energy Services. Infrastructure Services provides underground pipeline construction and repair services. Energy Services provides energy performance contracting and sustainable infrastructure, such as renewables, distributed generation, and combined heat and power projects. Prior to August 29, 2014, the Company had activities in its Coal Mining business. Results in the financial statements include the results of Vectren Fuels, Inc. (Vectren Fuels) through the date of sale of August 29, 2014, when the Company exited the coal mining business through the sale of Vectren Fuels. Further, prior to June 18, 2013, the Company had activities in its Energy Marketing business. Energy Marketing marketed and supplied natural gas and provided energy management services through ProLiance Holdings, LLC (ProLiance or ProLiance Holdings). In June 2013, ProLiance exited the gas marketing business through the disposition of certain of the net assets of its energy marketing subsidiary, ProLiance Energy, LLC (ProLiance Energy). Other minor operating results of the remaining ProLiance investment are reflected in Other Businesses. Enterprises has other legacy businesses that have investments in energy-related opportunities and services, real estate, and a leveraged lease, among other investments. All of the above is collectively referred to as the Nonutility Group. Enterprises supports the Company's regulated utilities by providing infrastructure services. |
Summary_of_Significant_Account
Summary of Significant Accounting Policies | 12 Months Ended | |
Dec. 31, 2014 | ||
Accounting Policies [Abstract] | ||
Summary of Significant Accounting Policies | Summary of Significant Accounting Policies | |
In applying its accounting policies, the Company makes judgments, assumptions, and estimates that affect the amounts reported in these consolidated financial statements and related footnotes. Examples of transactions for which estimation techniques are used include valuing pension and postretirement benefit obligations, deferred tax obligations, unbilled revenue, uncollectible accounts, regulatory assets and liabilities, reclamation liabilities, and derivatives and other financial instruments. Estimates also impact the depreciation of utility and nonutility plant and the testing of goodwill and other assets for impairment. Recorded estimates are revised when better information becomes available or when actual amounts can be determined. Actual results could differ from current estimates. | ||
Principles of Consolidation | ||
The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries, after elimination of intercompany transactions. | ||
Subsequent Events Review | ||
Management performs a review of subsequent events for any events occurring after the balance sheet date but prior to the date the financial statements are issued. | ||
Cash & Cash Equivalents | ||
All highly liquid investments with an original maturity of three months or less at the date of purchase are considered cash equivalents. Cash and cash equivalents are stated at cost plus accrued interest to approximate fair value. | ||
Allowance for Uncollectible Accounts | ||
The Company maintains allowances for uncollectible accounts for estimated losses resulting from the inability of its customers to make required payments. The Company estimates the allowance for uncollectible accounts based on a variety of factors including the length of time receivables are past due, the financial health of its customers, unusual macroeconomic conditions, and historical experience. If the financial condition of its customers deteriorates or other circumstances occur that result in an impairment of customers’ ability to make payments, the Company records additional allowances as needed. | ||
Inventories | ||
In most circumstances, the Company’s inventory components are recorded using an average cost method; however, natural gas in storage at the Company’s Indiana utilities 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. Nonutility inventory is valued at the lower of cost or market. | ||
Property, Plant & Equipment | ||
Both the Company’s Utility Plant and Nonutility Plant is stated at historical cost, inclusive of financing costs and direct and indirect construction costs, less accumulated depreciation and when necessary, impairment charges. The cost of renewals and betterments that extend the useful life are capitalized. Maintenance and repairs, including the cost of removal of minor items of property and planned major maintenance projects, are charged to expense as incurred. | ||
Utility Plant & Related Depreciation | ||
Both the IURC and PUCO allow the Company’s utilities to capitalize financing costs associated with Utility Plant based on a computed interest cost and a designated cost of equity funds. These financing costs are commonly referred to as AFUDC and are capitalized for ratemaking purposes and for financial reporting purposes instead of amounts that would otherwise be capitalized when acquiring nonutility plant. The Company reports both the debt and equity components of AFUDC in Other – net in the Consolidated Statements of Income. | ||
When property that represents a retirement unit is replaced or removed, the remaining historical value of such property is charged to Utility plant, with an offsetting charge to Accumulated depreciation, resulting in no gain or loss. Costs to dismantle and remove retired property are recovered through the depreciation rates as determined by the IURC and PUCO. | ||
The Company’s portion of jointly owned Utility plant, along with that plant’s related operating expenses, is presented in these financial statements in proportion to the ownership percentage. | ||
Nonutility Plant & Related Depreciation | ||
The depreciation of Nonutility plant is charged against income over its estimated useful life, using the straight-line method of depreciation. When nonutility property is retired, or otherwise disposed of, the asset and accumulated depreciation are removed, and the resulting gain or loss is reflected in income, typically impacting operating expenses. | ||
Impairment Reviews | ||
Property, plant and equipment along with other long-lived assets are reviewed as facts and circumstances indicate that the carrying amount may be impaired. This impairment review involves the comparison of an asset’s (or group of assets’) carrying value to the estimated future cash flows the asset (or asset group) is expected to generate over a remaining life. If this evaluation were to conclude that the carrying value is impaired, an impairment charge would be recorded based on the difference between the carrying amount and its fair value (less costs to sell for assets to be disposed of by sale) as a charge to operations or discontinued operations. During the year, the Company determined that a certain Energy Services asset's carrying value exceeded its net realizable value and thus was written down to zero, resulting in an after tax charge of $0.7 million. | ||
Investments in Unconsolidated Affiliates | ||
Investments in unconsolidated affiliates where the Company has significant influence are accounted for using the equity method of accounting. The Company’s share of net income or loss from these investments is recorded in Equity in (losses) of unconsolidated affiliates. Dividends are recorded as a reduction of the carrying value of the investment when received. Investments in unconsolidated affiliates where the Company does not have significant influence are accounted for using the cost method of accounting. Dividends associated with cost method investments are recorded as Other income – net when received. Investments are reviewed as facts and circumstances indicate that the carrying amount may be impaired. This impairment review involves the comparison of an investment's fair value to its carrying value. Investments, when necessary, include adjustments for declines in value judged to be other than temporary. | ||
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 that test is performed at the beginning of each year. Impairment reviews consist of a comparison of fair value to the carrying amount. If the fair value is less than the carrying amount, an impairment loss is recognized in operations. No goodwill impairments have been recorded during the periods presented. | ||
Specific to Energy Services, the Company performed a detailed analysis related to the carrying value of goodwill and other intangible assets recorded upon Energy Systems Group's acquisition of the federal sector energy services unit of Chevron Energy Solutions from Chevron, USA (Federal Business Unit or FBU). A triggering event resulted from the failure to sign sufficient sales orders by the contractually determined earn-out date of December 31, 2014. The failure to achieve the earn-out resulted in the reversal of the contingent consideration liability and was considered a triggering event for goodwill and intangible asset testing at December 31, 2014. The Company performed a detailed discounted cash flow analysis of the Energy Services operating segment using various revenue scenarios to understand the effects of the event on its sales and earnings forecast. As of December 31, 2014, the analysis indicates that there is no impairment related to the goodwill or other intangible assets recorded upon the acquisition of the FBU. The estimates used in the forecast scenarios are highly subjective and may differ materially from actual results. | ||
Regulation | ||
Retail public utility operations affecting Indiana customers are subject to regulation by the IURC, and retail public utility operations affecting Ohio customers are subject to regulation by the PUCO. The Company’s accounting policies give recognition to the ratemaking and accounting practices authorized by these agencies. | ||
Refundable or Recoverable Gas Costs & Cost of Fuel & Purchased Power | ||
All metered gas rates in Indiana contain a gas cost adjustment clause that allows the Company to charge for changes in the cost of purchased gas. Metered electric rates contain a fuel adjustment clause that allows for adjustment in charges for electric energy to reflect changes in the cost of fuel. The net energy cost of purchased power, subject to a variable benchmark based on NYMEX natural gas prices, is also recovered through regulatory proceedings. The Company records any under-or-over-recovery resulting from gas and fuel adjustment clauses each month in revenues. A corresponding asset or liability is recorded until the under-or-over-recovery is billed or refunded to utility customers. The cost of gas sold is charged to operating expense as delivered to customers, and the cost of fuel and purchased power for electric generation is charged to operating expense when consumed. | ||
Regulatory Assets & Liabilities | ||
Regulatory assets represent probable future revenues associated with certain incurred costs, which will be recovered from customers through the ratemaking process. Regulatory liabilities represent probable expenditures by the Company for removal costs or future reductions in revenues associated with amounts that are to be credited to customers through the ratemaking process. The Company continually assesses the recoverability of costs recognized as regulatory assets and liabilities and the ability to recognize new regulatory assets and liabilities associated with its regulated utility operations. Given the current regulatory environment in its jurisdictions, the Company believes such accounting is appropriate. | ||
The Company collects an estimated cost of removal of its utility plant through depreciation rates established in regulatory proceedings. The Company records amounts expensed in advance of payments as a Regulatory liability because the liability does not meet the threshold of an asset retirement obligation. | ||
Postretirement Obligations & Costs | ||
The Company recognizes the funded status of its pension plans and postretirement plans on its balance sheet. The funded status of a defined benefit plan is its assets (if any) less its projected benefit obligation (PBO), which reflects service accrued to date and includes the impact of projected salary increases (for pay-related benefits). The funded status of a postretirement plan is its assets (if any) less its accumulated postretirement benefit obligation (APBO), which reflects accrued service to date. To the extent this obligation exceeds amounts previously recognized in the statement of income, the Company records a Regulatory asset for that portion related to its rate regulated utilities. To the extent that excess liability does not relate to a rate regulated utility, the offset is recorded as a reduction to equity in Accumulated other comprehensive income. | ||
The annual cost of all postretirement plans is recognized in operating expenses or capitalized to plant following the direct labor of current employees. Specific to pension plans, the Company uses the projected unit credit actuarial cost method to calculate service cost and the PBO. This method projects the present value of benefits at retirement and allocates that cost over the projected years of service. Annual service cost represents one year’s benefit accrual while the PBO represents benefits allocated to previously accrued service. For other postretirement plans, service cost is calculated by dividing the present value of a participant’s projected postretirement benefits into equal parts based upon the number of years between a participant’s hire date and first eligible retirement date. Annual service cost represents one year’s benefit accrual while the APBO represents benefit allocated to previously accrued service. To calculate the expected return on pension plan assets, the Company uses the plan assets’ market-related value and an expected long-term rate of return. For the majority of the Company’s pension plans, the fair market value of the assets at the balance sheet date is adjusted to a market-related value by recognizing the change in fair value experienced in a given year ratably over a five-year period. Interest cost represents the annual accretion of the PBO and APBO at the discount rate. Actuarial gains and losses outside of a corridor (equal to 10 percent of the greater of the benefit obligation and the market-related value of assets) are amortized over the expected future working lifetime of active participants (except for plans where almost all participants are inactive). Prior service costs related to plan changes are amortized over the expected future working lifetime (or to full eligibility date for postretirement plan other than pensions) of the active participants at the time of the amendment. | ||
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. | ||
Product Warranties, Performance Guarantees & Other Guarantees | ||
Liabilities and expenses associated with product warranties and performance guarantees are recognized based on historical experience at the time the associated revenue is recognized. Adjustments are made as changes become reasonably estimable. The Company does not recognize the fair value of an obligation at inception for these guarantees because they are guarantees of the Company’s own performance and/or product installations. | ||
While not significant at December 31, 2014 or 2013, the Company does recognize the fair value of an obligation at the inception of a guarantee in certain circumstances. These circumstances would include executing certain indemnification agreements and guaranteeing operating lease residual values, the performance of a third party, or the indebtedness of a third party. | ||
Energy Contracts & Derivatives | ||
The Company will periodically execute derivative contracts in the normal course of operations while buying and selling commodities to be used in operations, optimizing its generation assets, and managing risk. A derivative is recognized on the balance sheet as an asset or liability measured at its fair market value and the change in the derivative's fair market value is recognized currently in earnings unless specific hedge criteria are met. | ||
When an energy contract that is a derivative is designated and documented as a normal purchase or normal sale (NPNS), it is exempted from mark-to-market accounting. Most energy contracts executed by the Company are subject to the NPNS exclusion or are not considered derivatives. Such energy contracts include Real Time and Day Ahead purchase and sale contracts with the MISO, natural gas purchases, and wind farm and other electric generating contracts. | ||
When the Company engages in energy contracts and financial contracts that are derivatives and are not subject to the NPNS or other exclusions, such contracts are recorded at market value as current or noncurrent assets or liabilities depending on their value and on when the contracts are expected to be settled. Contracts and any associated collateral with counter-parties subject to master netting arrangements are presented net in the Consolidated Balance Sheets. The offset resulting from carrying the derivative at fair value on the balance sheet is charged to earnings unless it qualifies as a hedge or is subject to regulatory accounting treatment. When hedge accounting is appropriate, the Company assesses and documents hedging relationships between the derivative contract and underlying risks as well as its risk management objectives and anticipated effectiveness. When the hedging relationship is highly effective, derivatives are designated as hedges. The market value of the effective portion of the hedge is marked to market in Accumulated other comprehensive income for cash flow hedges. Ineffective portions of hedging arrangements are marked to market through earnings. For fair value hedges, both the derivative and the underlying hedged item are marked to market through earnings. The offset to contracts affected by regulatory accounting treatment are marked to market as a regulatory asset or liability. Market value for derivative contracts is determined using quoted market prices from independent sources. The Company rarely enters into contracts that have a significant impact to the financial statements where internal models are used to calculate fair value. As of and for the periods presented, related derivative activity is not material to these financial statements. | ||
Income Taxes | ||
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. | ||
Revenues | ||
Most revenues are recognized as products and services are delivered to customers. Some nonutility revenues are recognized using the percentage of completion method. The Company records revenues for services and goods delivered but not billed at the end of an accounting period in Accrued unbilled revenues. The goods and services delivered by the Company subject to unbilled revenue accruals include gas, electricity, energy services, and infrastructure services. | ||
MISO Transactions | ||
With the IURC’s approval, the Company is a member of the MISO, a FERC approved regional transmission organization. The MISO serves the electrical transmission needs of much of the Midcontinent region and maintains operational control over the Company’s electric transmission facilities as well as that of other utilities in the region. The Company is an active participant in the MISO energy markets, bidding its owned generation into the Day Ahead and Real Time markets and procuring power for its retail customers at Locational Marginal Pricing (LMP) as determined by the MISO market. | ||
MISO-related purchase and sale transactions are recorded using settlement information provided by MISO. These purchase and sale transactions are accounted for on a net hourly position. Net purchases in a single hour are recorded in Cost of fuel & purchased power and net sales in a single hour are recorded in Electric utility revenues. On occasion, prior period transactions are resettled outside the routine process due to a change in 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. | ||
Share-Based Compensation | ||
The Company grants share-based awards to certain employees and board members. Liability classified share-based compensation awards are re-measured at the end of each period based on their expected settlement date fair value. Equity classified share-based compensation awards are measured at the grant date, based on the fair value of the award. Expense associated with share-based awards is recognized over the requisite service period, which generally begins on the date the award is granted through the earlier of the date the award vests or the date the employee becomes retirement eligible. | ||
Excise & Utility Receipts Taxes | ||
Excise taxes and a portion of utility receipts taxes are included in rates charged to customers. Accordingly, the Company records these taxes received as a component of operating revenues, which totaled $32.3 million in 2014, $29.6 million in 2013, and $26.9 million in 2012. Expense associated with excise and utility receipts taxes are recorded as a component of Taxes other than income taxes. | ||
Operating Segments | ||
The Company’s chief operating decision maker is the Chief Executive Officer. The Company uses net income calculated in accordance with generally accepted accounting principles as its most relevant performance measure. The Company has three operating segments within its Utility Group, four operating segments in its Nonutility Group, and a Corporate and Other segment. | ||
Fair Value Measurements | ||
Certain assets and liabilities are valued and/or disclosed at fair value. Financial assets include securities held in trust by the Company’s pension plans. 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 that the Company has the ability to access. | |
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 need to maximize the use of observable inputs and minimize the use of unobservable inputs. |
Utility_Nonutility_Plant
Utility & Nonutility Plant | 12 Months Ended | ||||||||||||||
Dec. 31, 2014 | |||||||||||||||
Property, Plant and Equipment [Abstract] | |||||||||||||||
Utility and Nonutility Plant | Utility & Nonutility Plant | ||||||||||||||
The original cost of Utility plant, together with depreciation rates expressed as a percentage of original cost, follows: | |||||||||||||||
At December 31, | |||||||||||||||
(In millions) | 2014 | 2013 | |||||||||||||
Original Cost | Depreciation | Original Cost | Depreciation | ||||||||||||
Rates as a | Rates as a | ||||||||||||||
Percent of | Percent of | ||||||||||||||
Original Cost | Original Cost | ||||||||||||||
Gas utility plant | $ | 3,011.00 | 3.4 | % | $ | 2,762.20 | 3.5 | % | |||||||
Electric utility plant | 2,602.50 | 3.3 | % | 2,519.80 | 3.3 | % | |||||||||
Common utility plant | 54.3 | 3.2 | % | 53.4 | 3 | % | |||||||||
Construction work in progress | 50.9 | — | 54.2 | — | |||||||||||
Total original cost | $ | 5,718.70 | $ | 5,389.60 | |||||||||||
SIGECO and Alcoa Generating Corporation (AGC), a subsidiary of ALCOA, own the 300 MW Unit 4 at the Warrick Power Plant as tenants in common. SIGECO's share of the cost of this unit at December 31, 2014, is $188.0 million with accumulated depreciation totaling $93.5 million. AGC and SIGECO also share equally in the cost of operation and output of the unit. SIGECO's share of operating costs is included in Other operating expenses in the Consolidated Statements of Income. | |||||||||||||||
Nonutility plant, net of accumulated depreciation and amortization follows: | |||||||||||||||
At December 31, | |||||||||||||||
(In millions) | 2014 | 2013 | |||||||||||||
Coal mine development costs & equipment | $ | — | $ | 242 | |||||||||||
Computer hardware & software | 106.1 | 102.7 | |||||||||||||
Land & buildings | 72.1 | 129.3 | |||||||||||||
Vehicles & equipment | 182.7 | 165.2 | |||||||||||||
All other | 17.1 | 18 | |||||||||||||
Nonutility plant - net | $ | 378 | $ | 657.2 | |||||||||||
Nonutility plant is presented net of accumulated depreciation and amortization totaling $361.9 million and $541.7 million as of December 31, 2014 and 2013, respectively. For the years ended December 31, 2014, 2013, and 2012, the Company capitalized interest totaling $0.6 million, $0.5 million, and $1.8 million, respectively, on nonutility plant construction projects. |
Regulatory_Assets_Liabilities
Regulatory Assets & Liabilities | 12 Months Ended | ||||||||
Dec. 31, 2014 | |||||||||
Regulatory Assets and Liabilities Disclosure [Abstract] | |||||||||
Regulatory Assets and Liabilities | Regulatory Assets & Liabilities | ||||||||
Regulatory Assets | |||||||||
Regulatory assets consist of the following: | |||||||||
At December 31, | |||||||||
(In millions) | 2014 | 2013 | |||||||
Future amounts recoverable from ratepayers related to: | |||||||||
Benefit obligations (See Note 11) | $ | 105.3 | $ | 57.1 | |||||
Net deferred income taxes (See Note 10) | (14.8 | ) | (5.8 | ) | |||||
Asset retirement obligations & other | — | 2.4 | |||||||
90.5 | 53.7 | ||||||||
Amounts deferred for future recovery related to: | |||||||||
Deferred coal costs (See Note 19) | — | 42.4 | |||||||
Cost recovery riders & other | 33.3 | 18.6 | |||||||
33.3 | 61 | ||||||||
Amounts currently recovered in customer rates related to: | |||||||||
Unamortized debt issue costs & hedging proceeds | 33.5 | 34.6 | |||||||
Demand side management programs | 0.6 | 2.5 | |||||||
Indiana authorized trackers | 25.6 | 30.8 | |||||||
Deferred coal costs (See Note 19) | 35.3 | — | |||||||
Ohio authorized trackers | 12.7 | 7.9 | |||||||
Premiums paid to reacquire debt | 1.7 | 2.2 | |||||||
Other base rate recoveries | 0.4 | 0.7 | |||||||
109.8 | 78.7 | ||||||||
Total regulatory assets | $ | 233.6 | $ | 193.4 | |||||
Of the $109.8 million currently being recovered in customer rates, $0.6 million that is associated with demand side management programs is earning a return. The weighted average recovery period of regulatory assets currently being recovered in base rates, which totals $36 million, is 23 years. The remainder of the regulatory assets are being recovered timely through periodic recovery mechanisms. The Company has rate orders for all deferred costs not yet in rates and therefore believes that future recovery is probable. | |||||||||
Assets arising from benefit obligations represent the funded status of retirement plans less amounts previously recognized in the statement of income. The increase in 2014 of approximately $48 million is primarily a result of a decrease in discount rate and updated mortality assumptions used to value the projected benefit obligation. The Company records a Regulatory asset for that portion related to its rate regulated utilities. If the cost is ultimately recognized as a periodic cost, it will be recovered through rates charged to customers. See Note 11. | |||||||||
Regulatory Liabilities | |||||||||
At December 31, 2014 and 2013, the Company has approximately $410.3 million and $387.3 million, respectively, in Regulatory liabilities. Of these amounts, $373.5 million and $373.0 million relate to cost of removal obligations. The remaining amounts primarily relate to timing differences associated with asset retirement obligations and deferred financing costs. |
Federal_Business_Unit_Acquisit
Federal Business Unit Acquisition Federal Business Unit Acquisition | 12 Months Ended | |||
Dec. 31, 2014 | ||||
Business Combinations [Abstract] | ||||
Business Combination Disclosure [Text Block] | Federal Business Unit Acquisition | |||
On April 1, 2014, the Company, through its wholly owned subsidiary Energy Systems Group (ESG), purchased the federal sector energy services unit of Chevron Energy Solutions from Chevron USA, referred to hereafter as the Federal Business Unit (FBU). FBU performs under several long-term operations and maintenance contracts (O&M), and has a construction project sales funnel. Included in the acquisition are several Indefinite Delivery / Indefinite Quantity contracts with federal government entities including Energy Savings Performance Contracts (ESPC) with the US Department of Energy and US Army Corps of Engineers. Also included are long-term operation and maintenance and repair contracts with multiple Department of Defense installations. FBU is included in the Company’s nonutility Energy Services operating segment. | ||||
See further discussion of Company issued guarantees and a Vectren Enterprises’ indemnification associated with this acquisition in Note 17. | ||||
The acquisition purchase price was $42.1 million, which included contingent consideration to be paid if certain new order targets were met in 2014. Those new order targets were not met in 2014 and therefore the contingent consideration was not earned. As such, the contingent consideration liability as of December 31, 2014 of $14.8 million was reversed as operating income. The initial new order target at the end of 2014 was dependent on the signing of contracts with sufficient revenue to meet the threshold. A single contract was targeted that would have been sufficient to meet the threshold but the signing of that contract was delayed by the customer. That contract is expected to be signed in 2015. The failure to sign that targeted contract by the earn-out threshold date is viewed as timing only and not reflective of future sales opportunities. As a result, goodwill is not impaired at December 31, 2014. | ||||
The Company recognized the assets acquired and the liabilities assumed, measured at their fair values as of the date of acquisition. The following table summarizes the allocation of the purchase price to the fair value of the assets acquired and liabilities assumed as of April 1, 2014. | ||||
(In millions) | ||||
Adjusted Net Working Capital | $ | 2.2 | ||
Depreciable Fixed Assets | 0.4 | |||
Customer Relationships (Sales Funnel) | 7.1 | |||
ESPC Licenses | 6 | |||
Deferred Tax Asset | 0.8 | |||
Goodwill | 27.7 | |||
Total Assets acquired | 44.2 | |||
Less: Unfavorable Contract Liabilities Assumed | (2.1 | ) | ||
Total Purchase Consideration | 42.1 | |||
Level 3 market inputs, such as discounted cash flows and revenue growth rates were used to derive the preliminary fair values of the identifiable intangible assets. Identifiable intangible assets include long-term customer relationships and licenses. Goodwill arising from the purchase represents intangible value the Company expects to realize over time. This value includes but is not limited to: 1) expected customer growth beyond what is in the current sales funnel and 2) the experience of the acquired work force. The goodwill, which does not amortize pursuant to accounting guidance, is deductible over a 15-year period for purposes of computing current income tax expense, and will be included in the Energy Services operating segment. | ||||
Transaction costs associated with the acquisition and expensed by the Company totaled approximately $1.7 million, of which $0.8 million and $0.9 million are included in other operating expenses during the twelve months ended December 31, 2014 and 2013, respectively. For the period from April 1, 2014 through December 31, 2014, FBU contributed an immaterial amount of revenue and net loss to the Company's revenue and net income. | ||||
For the year ended December 2014 and 2013, unaudited proforma results of the combined companies, assuming the acquisition closed on January 1, 2013, would have added approximately $17.7 million and $27.6 million to consolidated revenues, respectively. For the periods presented, the impact to net income and earnings per share would have been de minimis. These proforma results may not be indicative of what actual results would have been if the acquisition had taken place on the proforma date or of future results. |
Sale_of_Vectren_Fuels_Inc
Sale of Vectren Fuels, Inc. | 12 Months Ended |
Dec. 31, 2014 | |
Discontinued Operations and Disposal Groups [Abstract] | |
Disposal Groups, Including Discontinued Operations, Disclosure [Text Block] | Sale of Vectren Fuels, Inc. |
On July 1, 2014, the Company announced that it had reached an agreement to sell its wholly owned coal mining subsidiary, Vectren Fuels, to Sunrise Coal, LLC (Sunrise Coal), an Indiana-based wholly owned subsidiary of Hallador Energy Company. Sunrise Coal owns and operates coal mines in the Illinois Basin. On August 29, 2014, the transaction closed. Total cash received was approximately $311 million, inclusive of a $15 million change in working capital from December 31, 2013, through closing. At June 30, 2014, the Company recorded an estimated loss on the transaction, including costs to sell, of approximately $32 million, or $20 million after tax. At December 31, 2014, the pre-tax loss of $32 million was reflected in the Consolidated Statement of Income as a $42 million charge to other operating expense, offset by $10 million in lower depreciation expense as depreciation ceased for the assets classified as held for sale at June 30, 2014. Results from Coal Mining for the year ended December 31, 2014, inclusive of the loss on sale, was a loss of $21.1 million, net of tax, compared to losses of $16.0 million and $3.5 million for the years ended December 31, 2013 and 2012, respectively. The assets were classified as held for sale, as the sale of Vectren Fuels did not meet the requirements under GAAP to qualify as discontinued operations since Vectren will have significant continuing cash flows related to the purchase of coal from the buyer of these mines. |
Investment_in_ProLiance_Holdin
Investment in ProLiance Holdings, LLC | 12 Months Ended | |||
Dec. 31, 2014 | ||||
Equity Method Investments and Joint Ventures [Abstract] | ||||
Investment in ProLiance Holdings, LLC | Investment in ProLiance Holdings, LLC | |||
The Company has an investment in ProLiance Holdings, LLC (ProLiance), an affiliate of the Company and Citizens Energy Group (Citizens). On June 18, 2013, ProLiance exited the natural gas marketing business through the disposition of certain of the net assets, along with the long-term pipeline and storage commitments, of its energy marketing business, ProLiance Energy, LLC (ProLiance Energy), to a subsidiary of Energy Transfer Partners, ETC Marketing, Ltd (ETC). Other minor operating results of the remaining ProLiance investments are reflected in Other Businesses. The Company's remaining investment in ProLiance relates primarily to an investment in LA Storage, LLC (LA Storage). Consistent with its ownership percentage, the Company is allocated 61 percent of ProLiance’s profits and losses; however, governance and voting rights remain at 50 percent for each member, and therefore, the Company accounts for its investment in ProLiance using the equity method of accounting. | ||||
As a result of ProLiance exiting the natural gas marketing business on June 18, 2013, the Company recorded its share of the loss on the disposition, termination of long-term pipeline and storage commitments, and related transaction and other costs totaling $43.6 million pre-tax, or $26.8 million net of tax, during the second quarter of 2013. At the time of sale, ProLiance Holdings funded an estimated equity shortfall at ProLiance Energy of $16.6 million. To fund this estimated shortfall, the Company issued a note to ProLiance Holdings for its 61 percent ownership share of the $16.6 million shortfall, or $10.1 million, which was utilized by ProLiance Holdings to invest additional equity in ProLiance Energy. This interest-bearing note is classified as Other nonutility investments in the Consolidated Balance Sheets. | ||||
The Company's remaining investment in ProLiance at December 31, 2014, shown at its 61 percent ownership share, is as follows and reflects that it relates primarily to ProLiance's investment in LA Storage, LLC (LA Storage) discussed below. | ||||
As of | ||||
December 31, | ||||
(In millions) | 2014 | |||
Cash | $ | 4.8 | ||
Investment in LA Storage | 21.6 | |||
Other midstream asset investment | 4.2 | |||
Total investment in ProLiance | $ | 30.6 | ||
Included in: | ||||
Investments in unconsolidated affiliates | 20.5 | |||
Other nonutility investments | 10.1 | |||
LA Storage, LLC Storage Asset Investment | ||||
ProLiance Transportation and Storage, LLC (PT&S), a subsidiary of ProLiance, and Sempra Energy International (SEI), a subsidiary of Sempra Energy (SE), through a joint venture, have a 100 percent interest in a development project for salt-cavern natural gas storage facilities known as LA Storage. PT&S is the minority member with a 25 percent interest, which it accounts for using the equity method. The project, which includes a pipeline system, is expected to include 17 Bcf of capacity, and has the potential for further expansion. This pipeline system is currently connected with several interstate pipelines, including the Cameron Interstate Pipeline operated by Sempra Pipelines & Storage, and will connect area liquefied natural gas regasification terminals to an interstate natural gas transmission system and storage facilities. | ||||
Approximately 12 Bcf of the storage, which comprises three of the four FERC certified caverns, is fully tested but additional work is required to connect the caverns to the pipeline system. The timing and extent of development of these caverns is dependent on market conditions, including pricing, need for storage capacity, and development of the liquefied natural gas market, among other factors. At December 31, 2014, ProLiance's investment in the joint venture was $35.4 million. | ||||
The joint venture received a demand for arbitration from Williams Midstream Natural Gas Liquids, Inc. (Williams) in February 2011 related to a sublease agreement. Williams alleges that the joint venture was negligent in its attempt to convert certain salt caverns to natural gas storage and seeks damages of $56.7 million. The joint venture intends to vigorously defend itself and has asserted counterclaims substantially in excess of the amounts asserted by Williams. As such, as of December 31, 2014, ProLiance has no material reserve recorded related to this matter and this litigation has not materially impacted ProLiance's results of operations or statement of financial position. | ||||
Transactions with ProLiance | ||||
Purchases from ProLiance for resale and for injections into storage for the years ended December 31, 2013, and 2012, totaled $200.5 million, and $274.5 million, respectively. The Company did not have any purchases from ProLiance for the year ended December 31, 2014. The Company purchases in 2013 and 2012 from ProLiance all occurred prior to June 18, 2013 when ProLiance exited the natural gas marketing business. |
Nonutility_Real_Estate_Other_L
Nonutility Real Estate & Other Legacy Holdings | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Nonutility Real Estate Other Legacy Holdings [Abstract] | |||||||||||||
Nonutility Real Estate and Other Legacy Holdings | Nonutility Real Estate & Other Legacy Holdings | ||||||||||||
Within the nonutility group, there are legacy investments involved in real estate, a leveraged lease, and other ventures. As of December 31, 2014 and 2013, total remaining legacy investments included in the Other Businesses portfolio total $25.0 million and $26.5 million, respectively. Further separation of that 2014 investment by type of investment follows: | |||||||||||||
December 31, 2014 | |||||||||||||
Value Included In | |||||||||||||
(In millions) | Carrying | Other Nonutility Investments | Investments in Unconsolidated Affiliates | ||||||||||
Value | |||||||||||||
Commercial real estate investment | $ | 8 | $ | 8 | $ | — | |||||||
Leveraged lease | 15.2 | 15.2 | — | ||||||||||
Other investments | 1.8 | 0.2 | 1.6 | ||||||||||
$ | 25 | $ | 23.4 | $ | 1.6 | ||||||||
Commercial Real Estate | |||||||||||||
The Company holds a real estate investment in an office building. The Company's exposure to loss is limited to its investment. | |||||||||||||
Leveraged Lease | |||||||||||||
At December 31, 2014, the Company has an investment in a leveraged lease. The original cost for the leased facility was $27.5 million and was partially financed by non-recourse debt provided by lenders who were granted an assignment of rentals due and a security interest in the leased property, which they accepted as their sole remedy in the event of default by the lessee. Such remaining debt was approximately $16.3 million at December 31, 2014. The book value of this leverage lease is $5.2 million at December 31, 2014, net of related deferred taxes of $10.0 million. |
Intangible_Assets
Intangible Assets | 12 Months Ended | ||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||
Goodwill and Intangible Assets Disclosure [Abstract] | |||||||||||||||||
Intangible Assets | Intangible Assets | ||||||||||||||||
Intangible assets, which are included in Other assets, consist of the following: | |||||||||||||||||
(In millions) | At December 31, | ||||||||||||||||
2014 | 2013 | ||||||||||||||||
Amortizing | Non-amortizing | Amortizing | Non-amortizing | ||||||||||||||
Customer-related assets | $ | 22.5 | $ | — | $ | 17.4 | $ | — | |||||||||
Market-related assets | 1.1 | 13 | 1.9 | 7 | |||||||||||||
Intangible assets, net | $ | 23.6 | $ | 13 | $ | 19.3 | $ | 7 | |||||||||
As of December 31, 2014, the weighted average remaining life for amortizing customer-related assets and all amortizing intangibles is 12 years. These amortizing intangible assets have no significant residual values. Intangible assets are presented net of accumulated amortization totaling $10.0 million for customer-related assets and $3.4 million for market-related assets at December 31, 2014 and $8.1 million for customer-related assets and $2.6 million for market-related assets at December 31, 2013. Annual amortization associated with intangible assets totaled $2.8 million in 2014, $2.3 million in 2013 and $2.6 million in 2012. Amortization should approximate (in millions) $3.0, $2.3, $2.1, $2.1, and $2.1 in 2015, 2016, 2017, 2018, and 2019, respectively. Intangible assets are primarily in the Nonutility Group. |
Income_Taxes
Income Taxes | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Income Tax Disclosure [Abstract] | |||||||||||||
Income Taxes | Income Taxes | ||||||||||||
A reconciliation of the federal statutory rate to the effective income tax rate follows: | |||||||||||||
Year Ended December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
Statutory rate: | 35 | % | 35 | % | 35 | % | |||||||
State & local taxes-net of federal benefit | 4.1 | 4.6 | 4 | ||||||||||
Amortization of investment tax credit | (0.3 | ) | (0.3 | ) | (0.3 | ) | |||||||
Depletion | (2.6 | ) | (1.5 | ) | (1.5 | ) | |||||||
Domestic production deduction | (1.1 | ) | — | — | |||||||||
Energy efficiency building deductions | (1.6 | ) | (3.8 | ) | (3.0 | ) | |||||||
Other tax credits | (0.2 | ) | (1.1 | ) | (0.1 | ) | |||||||
Adjustment of income tax accruals and all other-net | (0.6 | ) | 0.1 | 0.1 | |||||||||
Effective tax rate | 32.7 | % | 33 | % | 34.2 | % | |||||||
Significant components of the net deferred tax liability follow: | |||||||||||||
At December 31, | |||||||||||||
(In millions) | 2014 | 2013 | |||||||||||
Noncurrent deferred tax liabilities (assets): | |||||||||||||
Depreciation & cost recovery timing differences | $ | 757.9 | $ | 725.2 | |||||||||
Leveraged lease | 9.8 | 10.4 | |||||||||||
Regulatory assets recoverable through future rates | 29.2 | 22.8 | |||||||||||
Alternative minimum tax carryforward | (13.3 | ) | (23.5 | ) | |||||||||
Employee benefit obligations | (14.5 | ) | (6.7 | ) | |||||||||
Net operating loss & other carryforwards | (2.0 | ) | (1.2 | ) | |||||||||
Regulatory liabilities to be settled through future rates | (27.5 | ) | (18.7 | ) | |||||||||
Impairments | (5.6 | ) | (6.2 | ) | |||||||||
Other – net | 7.2 | 5.3 | |||||||||||
Net noncurrent deferred tax liability | 741.2 | 707.4 | |||||||||||
Current deferred tax liabilities (assets): | |||||||||||||
Deferred fuel costs-net | 22 | 22.9 | |||||||||||
Alternative minimum tax carryforward | (38.1 | ) | (33.7 | ) | |||||||||
Net operating loss & other carryforwards | — | (4.9 | ) | ||||||||||
Other – net | (0.2 | ) | 1.8 | ||||||||||
Net current deferred tax liability (asset) | (16.3 | ) | (13.9 | ) | |||||||||
Net deferred tax liability | $ | 724.9 | $ | 693.5 | |||||||||
At December 31, 2014 and 2013, investment tax credits totaling $4.7 million and $5.3 million respectively, are included in Deferred credits & other liabilities. At December 31, 2014, the Company has alternative minimum tax carryforwards which do not expire. In addition, the Company has $2.0 million in net operating loss and general business credit carryforwards, which will expire in 5 to 20 years. The net operating loss carryforward was reduced for the impacts of unrecognized tax benefits and a valuation allowance relating to state net operating loss carryforwards. At December 31, 2014 and 2013, the valuation allowance was $7.3 million and $3.6 million, respectively. | |||||||||||||
The components of income tax expense and utilization of investment tax credits follow: | |||||||||||||
Year Ended December 31, | |||||||||||||
(In millions) | 2014 | 2013 | 2012 | ||||||||||
Current: | |||||||||||||
Federal | $ | 24.7 | $ | 12.4 | $ | (8.2 | ) | ||||||
State | 18.5 | 11.4 | 6.4 | ||||||||||
Total current taxes | 43.2 | 23.8 | (1.8 | ) | |||||||||
Deferred: | |||||||||||||
Federal | 42.7 | 43.4 | 80.3 | ||||||||||
State | (4.2 | ) | 0.5 | 4.6 | |||||||||
Total deferred taxes | 38.5 | 43.9 | 84.9 | ||||||||||
Amortization of investment tax credits | (0.6 | ) | (0.6 | ) | (0.6 | ) | |||||||
Total income tax expense | $ | 81.1 | $ | 67.1 | $ | 82.5 | |||||||
Uncertain Tax Positions | |||||||||||||
Following is a roll forward of unrecognized tax benefits for the three years ended December 31, 2014: | |||||||||||||
(In millions) | 2014 | 2013 | 2012 | ||||||||||
Unrecognized tax benefits at January 1 | $ | 5.9 | $ | 4.8 | $ | 12.4 | |||||||
Gross increases - tax positions in prior periods | 0.2 | — | 0.2 | ||||||||||
Gross decreases - tax positions in prior periods | (4.8 | ) | (0.2 | ) | (9.4 | ) | |||||||
Gross increases - current period tax positions | — | 1.2 | 1.9 | ||||||||||
Settlements | — | — | (0.3 | ) | |||||||||
Lapse of statute of limitations | (0.2 | ) | 0.1 | — | |||||||||
Unrecognized tax benefits at December 31 | $ | 1.1 | $ | 5.9 | $ | 4.8 | |||||||
Of the change in unrecognized tax benefits during 2014, 2013, and 2012, almost none impacted the effective rate. The amount of unrecognized tax benefits, which if recognized, that would impact the effective tax rate was $0.8 million at December 31, 2014, and $0.7 million at each of December 31, 2013 and 2012. | |||||||||||||
The Company recognized income related to a reversal of interest expense previously accrued and net of penalties totaling approximately $0.1 million in 2014, $0.1 million in 2013, and $0.7 million in 2012. The Company had approximately $0.4 million and $0.5 million for the payment of interest and penalties accrued as of December 31, 2014 and 2013, respectively. | |||||||||||||
The net liability on the Consolidated Balance Sheet for unrecognized tax benefits inclusive of interest, penalties and net of secondary impacts which are a component of the Deferred income taxes and are benefits, totaled $1.1 million and $3.8 million, respectively, at December 31, 2014 and 2013. | |||||||||||||
The Company believes that a minor decrease in unrecognized tax benefits may be realized by the end of 2015 as a result of a lapse of the statute of limitations. | |||||||||||||
The Company and/or certain of its subsidiaries file income tax returns in the U.S. federal jurisdiction and various states. The Internal Revenue Service (IRS) has concluded examinations of the Company's U.S. federal income tax returns for tax years through December 31, 2008. The IRS is currently examining the 2009-2012 federal income tax returns as part of a routine review by the Joint Committee of Taxation. The State of Indiana, the Company's primary state tax jurisdiction, has conducted examinations of state income tax returns for tax years through December 31, 2008. The statutes of limitations for assessment of federal income tax and Indiana income tax have expired with respect to tax years through 2008. | |||||||||||||
Final Federal Income Tax Regulations | |||||||||||||
In September 2013, the IRS released final tangible property regulations regarding the deduction and capitalization of expenditures related to tangible property. The final regulations are generally effective for tax years beginning on or after January 1, 2014, and will be adopted on the 2014 federal income tax return. The IRS has been working with the utility industry to provide industry specific guidance concerning the deductibility and capitalization of expenditures related to tangible property. The IRS has indicated that it expects to issue updated or new guidance with respect to electric and natural gas transmission and distribution assets during 2015. The Company continues to evaluate the impact adoption of the regulations and industry guidance will have on its consolidated financial statements. As of this date, the Company does not expect the adoption of the regulations to have a material impact on its consolidated financial statements. | |||||||||||||
Indiana Senate Bill 1 | |||||||||||||
In March 2014, Indiana Senate Bill 1 was signed into law. This legislation phases in a 1.6 percent rate reduction to the Indiana Adjusted Gross Income Tax Rate for corporations over a six year period. Pursuant to this legislation, the tax rate will be lowered by 0.25 percent each year for the first five years and 0.35 percent in year six beginning on July 1, 2016 to the final rate of 4.9 percent effective July 1, 2021. Pursuant to FASB guidance, the Company accounted for the effect of the change in tax law on its deferred taxes in the first quarter of 2014, the period of enactment. The impact was not material to results of operations. |
Retirement_Plans_Other_Postret
Retirement Plans & Other Postretirement Benefits | 12 Months Ended | ||||||||||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||||||||||
Compensation and Retirement Disclosure [Abstract] | |||||||||||||||||||||||||
Retirement Plans and Other Postretirement Benefits | Retirement Plans & Other Postretirement Benefits | ||||||||||||||||||||||||
At December 31, 2014, the Company maintains three qualified defined benefit pension plans, a nonqualified supplemental executive retirement plan (SERP), and a postretirement benefit plan. The defined benefit pension plans and postretirement benefit plan, which cover eligible full-time regular employees, are primarily noncontributory. The postretirement health care and life insurance plans are a combination of self-insured and fully insured plans. The qualified pension plans and the SERP are aggregated under the heading “Pension Benefits.” The postretirement benefit plan is presented under the heading “Other Benefits.” | |||||||||||||||||||||||||
Net Periodic Benefit Costs | |||||||||||||||||||||||||
A summary of the components of net periodic benefit cost for the three years ended December 31, 2014 follows: | |||||||||||||||||||||||||
Pension Benefits | Other Benefits | ||||||||||||||||||||||||
(In millions) | 2014 | 2013 | 2012 | 2014 | 2013 | 2012 | |||||||||||||||||||
Service cost | $ | 7.4 | $ | 8.6 | $ | 7.7 | $ | 0.4 | $ | 0.5 | $ | 0.5 | |||||||||||||
Interest cost | 15.5 | 14.7 | 15.5 | 2.3 | 2 | 2.8 | |||||||||||||||||||
Expected return on plan assets | (22.7 | ) | (22.1 | ) | (21.2 | ) | — | — | — | ||||||||||||||||
Amortization of prior service cost (benefit) | 1 | 1.5 | 1.6 | (3.0 | ) | (3.2 | ) | (2.5 | ) | ||||||||||||||||
Amortization of actuarial loss | 5 | 10.1 | 6.8 | 0.4 | 0.7 | 0.7 | |||||||||||||||||||
Amortization of transitional obligation | — | — | — | — | — | 0.5 | |||||||||||||||||||
Settlement charge | 3.1 | 1.3 | — | — | — | — | |||||||||||||||||||
Net periodic benefit cost | $ | 9.3 | $ | 14.1 | $ | 10.4 | $ | 0.1 | $ | — | $ | 2 | |||||||||||||
A portion of the net periodic benefit cost disclosed in the table above is capitalized as Utility plant. Costs capitalized in 2014, 2013, and 2012 are estimated at $2.8 million, $4.2 million, and $3.7 million, respectively. | |||||||||||||||||||||||||
The Company increased the discount rate used to measure periodic cost from 4.03 percent in 2013 to 4.74 percent in 2014 due to higher benchmark interest rates that approximated the expected duration of the Company’s benefit obligations as of that valuation date. For fiscal year 2015, the weighted average discount rate assumption will decrease to 4.05 percent for the defined benefit pension plans, based on decreased benchmark interest rates. | |||||||||||||||||||||||||
The weighted averages of significant assumptions used to determine net periodic benefit costs follow: | |||||||||||||||||||||||||
Pension Benefits | Other Benefits | ||||||||||||||||||||||||
2014 | 2013 | 2012 | 2014 | 2013 | 2012 | ||||||||||||||||||||
Discount rate | 4.74 | % | 4.03 | % | 4.82 | % | 4.66 | % | 3.91 | % | 4.75 | % | |||||||||||||
Rate of compensation increase | 3.5 | % | 3.5 | % | 3.5 | % | N/A | N/A | N/A | ||||||||||||||||
Expected return on plan assets | 7.75 | % | 7.75 | % | 7.75 | % | N/A | N/A | N/A | ||||||||||||||||
Expected increase in Consumer Price Index | N/A | N/A | N/A | 2.75 | % | 2.75 | % | 2.75 | % | ||||||||||||||||
Health care cost trend rate assumptions do not have a material effect on the service and interest cost components of benefit costs. The Company’s plans limit its exposure to increases in health care costs to annual changes in the Consumer Price Index (CPI). Any increase in health care costs in excess of the CPI increase is the responsibility of the plan participants. | |||||||||||||||||||||||||
Benefit Obligations | |||||||||||||||||||||||||
A reconciliation of the Company’s benefit obligations at December 31, 2014 and 2013 follows: | |||||||||||||||||||||||||
Pension Benefits | Other Benefits | ||||||||||||||||||||||||
(In millions) | 2014 | 2013 | 2014 | 2013 | |||||||||||||||||||||
Benefit obligation, beginning of period | $ | 338.4 | $ | 377.3 | $ | 51.3 | $ | 54.4 | |||||||||||||||||
Service cost – benefits earned during the period | 7.4 | 8.6 | 0.4 | 0.5 | |||||||||||||||||||||
Interest cost on projected benefit obligation | 15.5 | 14.7 | 2.3 | 2 | |||||||||||||||||||||
Plan participants' contributions | — | — | 0.9 | 0.8 | |||||||||||||||||||||
Plan amendments | — | — | — | (0.2 | ) | ||||||||||||||||||||
Actuarial loss (gain) | 48.5 | (32.7 | ) | 3.2 | (2.4 | ) | |||||||||||||||||||
Settlement loss | 1.7 | 1.5 | — | — | |||||||||||||||||||||
Medicare subsidy receipts | — | — | — | — | |||||||||||||||||||||
Benefit payments | (25.3 | ) | (22.8 | ) | (4.8 | ) | (3.8 | ) | |||||||||||||||||
Settlement payments | (14.3 | ) | (8.2 | ) | — | — | |||||||||||||||||||
Benefit obligation, end of period | $ | 371.9 | $ | 338.4 | $ | 53.3 | $ | 51.3 | |||||||||||||||||
The accumulated benefit obligation for all defined benefit pension plans was $356.4 million and $321.9 million at December 31, 2014 and 2013, respectively. | |||||||||||||||||||||||||
Mortality Assumption Changes | |||||||||||||||||||||||||
In October 2014, the Society of Actuaries (SOA) released updated mortality estimates that reflect increased life expectancy. The Company updated its mortality assumptions to incorporate this increase in life expectancy. Accordingly, the Company updated its base mortality assumption to the SOA 2014 table as well as updated its projected mortality improvement. These changes are reflected in the Company's benefit obligation as of December 31, 2014. | |||||||||||||||||||||||||
Other Material Assumptions | |||||||||||||||||||||||||
The benefit obligation as of December 31, 2014 and 2013 was calculated using the following weighted average assumptions: | |||||||||||||||||||||||||
Pension Benefits | Other Benefits | ||||||||||||||||||||||||
2014 | 2013 | 2014 | 2013 | ||||||||||||||||||||||
Discount rate | 4.05 | % | 4.74 | % | 3.95 | % | 4.66 | % | |||||||||||||||||
Rate of compensation increase | 3.5 | % | 3.5 | % | N/A | N/A | |||||||||||||||||||
Expected increase in Consumer Price Index | N/A | N/A | 2.5 | % | 2.75 | % | |||||||||||||||||||
To calculate the 2014 ending postretirement benefit obligation, medical claims costs in 2015 were assumed to be 6.5 percent higher than those incurred in 2014. That trend was assumed to reach its ultimate trending increase of 5 percent by 2018 and remain level thereafter. A one-percentage point change in assumed health care cost trend rates would have changed the benefit obligation by approximately $0.3 million. The increase in the pension benefit obligation in 2014 is primarily due to a decrease in the discount rate used to measure the obligation at year end and, to a lesser extent, the updated mortality assumption. | |||||||||||||||||||||||||
Plan Assets | |||||||||||||||||||||||||
A reconciliation of the Company’s plan assets at December 31, 2014 and 2013 follows: | |||||||||||||||||||||||||
Pension Benefits | Other Benefits | ||||||||||||||||||||||||
(In millions) | 2014 | 2013 | 2014 | 2013 | |||||||||||||||||||||
Plan assets at fair value, beginning of period | $ | 323.9 | $ | 295.7 | $ | — | $ | — | |||||||||||||||||
Actual return on plan assets | 20.1 | 48.4 | — | — | |||||||||||||||||||||
Employer contributions | 1.2 | 10.8 | 3.9 | 3 | |||||||||||||||||||||
Plan participants' contributions | — | — | 0.9 | 0.8 | |||||||||||||||||||||
Benefit payments | (25.3 | ) | (22.8 | ) | (4.8 | ) | (3.8 | ) | |||||||||||||||||
Settlement payments | (14.3 | ) | (8.2 | ) | — | — | |||||||||||||||||||
Fair value of plan assets, end of period | $ | 305.6 | $ | 323.9 | $ | — | $ | — | |||||||||||||||||
The Company’s overall investment strategy for its retirement plan trusts is to maintain investments in a diversified portfolio, comprised of primarily equity and fixed income investments, which are further diversified among various asset classes. The diversification is designed to minimize the risk of large losses while maximizing total return within reasonable and prudent levels of risk. The investment objectives specify a targeted investment allocation for the pension plans of 60 percent equities, 35 percent debt, and 5 percent for other investments, including real estate. Both the equity and debt securities have a blend of domestic and international exposures. Objectives do not target a specific return by asset class. The portfolios’ return is monitored in total. Following is a description of the valuation methodologies used for trust assets measured at fair value. | |||||||||||||||||||||||||
Mutual Funds | |||||||||||||||||||||||||
The fair values of mutual funds are derived from quoted market prices or net asset values as these instruments have active markets (Level 1 inputs). | |||||||||||||||||||||||||
Common Collective Trust Funds (CTF’s) | |||||||||||||||||||||||||
The Company’s plans have investments in trust funds similar to mutual funds in that they are created by pooling of funds from investors into a common trust and such funds are managed by a third party investment manager. These trust funds typically give investors a wider range of investment options through this pooling of funds than that generally available to investors on an individual basis. However, unlike mutual funds, these trusts are not publicly traded in an active market. The fair values of these trusts are derived from Level 2 market inputs based on a daily calculated unit value as determined by the issuer. This daily calculated value is based on the fair market value of the underlying investments. These funds are primarily comprised of investments in equity and fixed income securities which represent approximately 56 percent and 37 percent, respectively, of their fair value as of December 31, 2014 and approximately 53 percent and 42 percent, respectively, as of December 31, 2013. Equity securities within these funds are primarily valued using quoted market prices as these instruments have active markets. From time to time, less liquid equity securities are valued using Level 2 inputs, such as bid prices or a closing price, as determined in good faith by the investment manager. Fixed income securities are valued at the last available bid prices quoted by an independent pricing service. When valuations are not readily available, fixed income securities are valued using primarily other Level 2 inputs as determined in good faith by the investment manager. | |||||||||||||||||||||||||
The fair value of these funds totals $155.6 million at December 31, 2014 and $161.7 million at December 31, 2013. In relation to these investments, there are no unfunded commitments. Also, the Plan can exchange shares with minimal restrictions, however, certain events may exist where share exchanges are restricted for up to 31 days. | |||||||||||||||||||||||||
Guaranteed Annuity Contract | |||||||||||||||||||||||||
One of the Company’s pension plans is party to a group annuity contract with John Hancock Life Insurance Company (John Hancock). At December 31, 2014 and 2013, the estimate of undiscounted funds necessary to satisfy John Hancock’s remaining obligation was $3.8 million and $3.7 million, respectively. If funds retained by John Hancock are not sufficient to satisfy retirement payments due to these retirees, the shortfall must be funded by the Company. The composite investment return, net of manager fees and other charges for the years ended December 31, 2014 and 2013 was 4.12 percent and 4.75 percent, respectively. The Company values this illiquid investment using long-term interest rate and mortality assumptions, among others, and is therefore considered a Level 3 investment. There is no unfunded commitment related to this investment. | |||||||||||||||||||||||||
The fair values of the Company’s pension and other retirement plan assets at December 31, 2014 and December 31, 2013 by asset category and by fair value hierarchy are as follows: | |||||||||||||||||||||||||
As of December 31, 2014 | |||||||||||||||||||||||||
(In millions) | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||||||
Domestic equities & equity funds | $ | 62.8 | $ | 87.3 | $ | — | $ | 150.1 | |||||||||||||||||
International equities & equity funds | 38.4 | — | — | 38.4 | |||||||||||||||||||||
Domestic bonds & bond funds | 38.8 | 47.1 | — | 85.9 | |||||||||||||||||||||
Inflation protected security fund | — | 11.1 | — | 11.1 | |||||||||||||||||||||
Real estate, commodities & other | 5.8 | 10.1 | 4.2 | 20.1 | |||||||||||||||||||||
Total plan investments | $ | 145.8 | $ | 155.6 | $ | 4.2 | $ | 305.6 | |||||||||||||||||
As of December 31, 2013 | |||||||||||||||||||||||||
(In millions) | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||||||
Domestic equities & equity funds | $ | 69.6 | $ | 85.6 | $ | — | $ | 155.2 | |||||||||||||||||
International equities & equity funds | 41.9 | — | — | 41.9 | |||||||||||||||||||||
Domestic bonds & bond funds | 40.4 | 55.4 | — | 95.8 | |||||||||||||||||||||
Inflation protected security fund | — | 12.1 | — | 12.1 | |||||||||||||||||||||
Real estate, commodities & other | 6.2 | 8.6 | 4.1 | 18.9 | |||||||||||||||||||||
Total plan investments | $ | 158.1 | $ | 161.7 | $ | 4.1 | $ | 323.9 | |||||||||||||||||
A roll forward of the fair value of the guaranteed annuity contract calculated using Level 3 valuation assumptions follows: | |||||||||||||||||||||||||
(In millions) | 2014 | 2013 | |||||||||||||||||||||||
Fair value, beginning of year | $ | 4.1 | $ | 3.9 | |||||||||||||||||||||
Unrealized gains related to | 0.1 | 0.2 | |||||||||||||||||||||||
investments still held at reporting date | |||||||||||||||||||||||||
Purchases, sales and settlements, net | — | — | |||||||||||||||||||||||
Fair value, end of year | $ | 4.2 | $ | 4.1 | |||||||||||||||||||||
Funded Status | |||||||||||||||||||||||||
The funded status of the plans as of December 31, 2014 and 2013 follows: | |||||||||||||||||||||||||
Pension Benefits | Other Benefits | ||||||||||||||||||||||||
(In millions) | 2014 | 2013 | 2014 | 2013 | |||||||||||||||||||||
Qualified Plans | |||||||||||||||||||||||||
Benefit obligation, end of period | $ | (351.7 | ) | $ | (321.0 | ) | $ | (53.3 | ) | $ | (51.4 | ) | |||||||||||||
Fair value of plan assets, end of period | 305.6 | 323.9 | — | — | |||||||||||||||||||||
Funded Status of Qualified Plans, end of period | (46.1 | ) | 2.9 | (53.3 | ) | (51.4 | ) | ||||||||||||||||||
Benefit obligation of SERP Plan, end of period | (20.2 | ) | (17.5 | ) | — | — | |||||||||||||||||||
Total funded status, end of period | $ | (66.3 | ) | $ | (14.6 | ) | $ | (53.3 | ) | $ | (51.4 | ) | |||||||||||||
Accrued liabilities | $ | 1.2 | $ | 1 | $ | 4.6 | $ | 4.9 | |||||||||||||||||
Deferred credits & other liabilities | $ | 65.1 | $ | 20.1 | $ | 48.7 | $ | 46.4 | |||||||||||||||||
Other Assets | $ | — | $ | 6.5 | $ | — | $ | — | |||||||||||||||||
Expected Cash Flows | |||||||||||||||||||||||||
In 2015, the Company anticipates making $20 million in contributions to its qualified pension plans. In addition, the Company expects to make payments totaling approximately $1.2 million directly to SERP participants and approximately $3.5 million directly to those participating in the postretirement plan. | |||||||||||||||||||||||||
Estimated retiree pension benefit payments, including the SERP, projected to be required during the years following 2014 are approximately (in millions) $24.7 in 2015, $25.7 in 2016, $36.1 in 2017, $26.7 in 2018, $27.8 in 2019, and $143.8 in years 2020-2024. Expected benefit payments projected to be required for postretirement benefits during the years following 2014 (in millions) are approximately $4.6 in 2015, $4.7 in 2016, $4.8 in 2017, $5.1 in 2018, $5.4 in 2019, and $28.8 in years 2020-2024. | |||||||||||||||||||||||||
Prior Service Cost, Actuarial Gains and Losses, and Transition Obligation Effects | |||||||||||||||||||||||||
Following is a roll forward of prior service cost, actuarial gains and losses, and transition obligations. | |||||||||||||||||||||||||
Pensions | Other Benefits | ||||||||||||||||||||||||
(In millions) | Prior | Net | Prior | Net | Transition Obligation | ||||||||||||||||||||
Service | Gain | Service | Gain | ||||||||||||||||||||||
Cost | or Loss | Cost | or Loss | ||||||||||||||||||||||
Balance at January 1, 2012 | $ | 5.4 | $ | 116.6 | $ | (1.2 | ) | $ | 9.1 | $ | 2.7 | ||||||||||||||
Amounts arising during the period | 0.7 | 26.4 | (24.4 | ) | 2.8 | (2.2 | ) | ||||||||||||||||||
Reclassification to benefit costs | (1.6 | ) | (6.8 | ) | 2.5 | (0.7 | ) | (0.5 | ) | ||||||||||||||||
Balance at December 31, 2012 | $ | 4.5 | $ | 136.2 | $ | (23.1 | ) | $ | 11.2 | $ | — | ||||||||||||||
Amounts arising during the period | — | (58.8 | ) | (0.2 | ) | (2.4 | ) | — | |||||||||||||||||
Reclassification to benefit costs | (1.5 | ) | (10.1 | ) | 3.2 | (0.7 | ) | — | |||||||||||||||||
Balance at December 31, 2013 | $ | 3 | $ | 67.3 | $ | (20.1 | ) | $ | 8.1 | $ | — | ||||||||||||||
Amounts arising during the period | — | 49.4 | — | 3.2 | — | ||||||||||||||||||||
Reclassification to benefit costs | (1.0 | ) | (5.0 | ) | 3 | (0.4 | ) | — | |||||||||||||||||
Balance at December 31, 2014 | $ | 2 | $ | 111.7 | $ | (17.1 | ) | $ | 10.9 | $ | — | ||||||||||||||
Following is a reconciliation of the amounts in Accumulated other comprehensive income (AOCI) and Regulatory assets related to retirement plan obligations at December 31, 2014 and 2013. | |||||||||||||||||||||||||
(In millions) | 2014 | 2013 | |||||||||||||||||||||||
Pensions | Other Benefits | Pensions | Other Benefits | ||||||||||||||||||||||
Prior service cost | $ | 2 | $ | (17.1 | ) | $ | 3 | $ | (20.1 | ) | |||||||||||||||
Unamortized actuarial gain/(loss) | 111.7 | 10.9 | 67.3 | 8.1 | |||||||||||||||||||||
Transition obligation | — | — | — | — | |||||||||||||||||||||
113.7 | (6.2 | ) | 70.3 | (12.0 | ) | ||||||||||||||||||||
Less: Regulatory asset deferral | (111.4 | ) | 6.1 | (68.9 | ) | 11.8 | |||||||||||||||||||
AOCI before taxes | $ | 2.3 | $ | (0.1 | ) | $ | 1.4 | $ | (0.2 | ) | |||||||||||||||
Related to pension plans, $1.0 million of prior service cost and $8.5 million of actuarial gain/loss is expected to be amortized to cost in 2015. Related to other benefits, $0.7 million of actuarial gain/loss is expected to be amortized to periodic cost in 2015, and $3.0 million of prior service cost is expected to reduce costs in 2015. | |||||||||||||||||||||||||
Multiemployer Benefit Plan | |||||||||||||||||||||||||
The Company, through its Infrastructure Services operating segment, participates in several industry wide multiemployer pension plans for its union employees which provide for monthly benefits based on length of service. The risks of participating in multiemployer pension plans are different from the risks of participating in single-employer pension plans in the following respects: 1) assets contributed to the multiemployer plan by one employer may be used to provide benefits to employees of other participating employers, 2) if a participating employer stops contributing to the plan, the unfunded obligations of the plan allocable to such withdrawing employer may be borne by the remaining participating employers, and 3) if the Company stops participating in some of its multiemployer pension plans, the Company may be required to pay those plans an amount based on its allocable share of the underfunded status of the plan, referred to as a withdrawal liability. | |||||||||||||||||||||||||
Expense is recognized as payments are accrued for work performed or when withdrawal liabilities are probable and estimable. Expense associated with multiemployer plans was $32.4 million, $33.2 million and $27.6 million for the years ended December 31, 2014, 2013, and 2012, respectively. During 2014, the Company made contributions to these multiemployer plans on behalf of employees that participate in approximately 250 local unions. Contracts with these unions are negotiated with trade agreements through two primary contractor associations. These trade agreements have varying expiration dates ranging from 2015 through 2017. The average contribution related to these local unions was less than $0.2 million, and the largest contribution was $4.1 million. Multiple unions can contribute to a single multiemployer plan. The Company made contributions to at least 50 plans in 2014, four of which are considered significant plans based on, among other things, the amount of the contributions, the number of employees participating in the plan, and the funded status of the plan. | |||||||||||||||||||||||||
The Company's participation in the significant plans is outlined in the following table. The Employer Identification Number (EIN) / Pension Plan Number column provides the EIN and three digit pension plan numbers. The most recent Pension Protection Act Zone Status available in 2014 and 2013 is for the plan year end at January 31, 2014 and 2013 for the Central Pension Fund, December 31, 2013 and 2012 for the Pipeline Industry Benefit Fund, May 31, 2014 and 2013 for the Indiana Laborers Pension Fund, and December 31, 2013 and 2012 for the Minnesota Laborers Pension Fund, respectively. Generally, plans in the red zone are less than 65 percent funded, plans in the yellow zone are less than 80 percent funded and plans in the green zone are at least 80 percent funded. The FIP/RP Status Pending / Implemented column indicates plans for which a funding improvement plan ("FIP") or rehabilitation plan ("RP") is either pending or has been implemented. The multiemployer contributions listed in the table below are the Company's multiemployer contributions made in 2014, 2013, and 2012. | |||||||||||||||||||||||||
(In millions) | |||||||||||||||||||||||||
Pension Protection Act Zone Status | Multiemployer Contributions | ||||||||||||||||||||||||
Pension Fund | EIN/Pension Plan Number | 2014 | 2013 | FIP/RP Status Pending/Implemented | 2014 | 2013 | 2012 | Surcharge Imposed | |||||||||||||||||
Central Pension Fund | 36-6052390-001 | Green | Green | No | $7.70 | $8.50 | $4.00 | No | |||||||||||||||||
Pipeline Industry Benefit Fund | 73-0742835-001 | Green | Green | No | 5.1 | 5.3 | 3.9 | No | |||||||||||||||||
Indiana Laborers Pension Fund (1) | 35-6027150-001 | Yellow | Yellow | Implemented | 3.5 | 2.4 | 3.2 | No | |||||||||||||||||
Minnesota Laborers Pension Fund | 41-6159599-001 | Green | Green | No | 2.2 | 2.8 | 2 | No | |||||||||||||||||
Other | 13.9 | 14.2 | 14.5 | ||||||||||||||||||||||
Total Contributions | $32.40 | $33.20 | $27.60 | ||||||||||||||||||||||
(1) Federal law requires pension plans in endangered status to adopt a funding improvement plan aimed at restoring the financial health of the plan. In December 2014, the Multiemployer Pension Reform Act of 2014 was passed and permanently extended the Pension Protection Act of 2006 multiemployer plan critical and endangered status funding rules, among other things including providing a provision for a plan sponsor to suspend or reduce benefit payments to preserve plans in critical and declining status. Since the Indiana Laborers Pension Fund became endangered as of June 1, 2008, a funding improvement plan was previously set in place to begin June 1, 2009. The funding improvement plan requires that the plan's funded percentage improve at least thirty-three percent of the way to 100 percent over a ten-year period. The target for this plan under the law is a funded percentage of 78 percent by 2019. The plan must also meet the federal minimum funding requirements during this 10-year period. If the Plan is in endangered or critical status for the plan year ended May 31, 2015, separate notification of the status has or will be provided. | |||||||||||||||||||||||||
While not considered significant to the Company, there are eight plans in red zone status receiving Company contributions. There are also four other plans where Company contributions exceed 5 percent of each plan's total contributions and one of these plans was considered significant to the Company. | |||||||||||||||||||||||||
Defined Contribution Plan | |||||||||||||||||||||||||
The Company also has defined contribution retirement savings plans that are qualified under sections 401(a) and 401(k) of the Internal Revenue Code and include an option to invest in Vectren common stock, among other alternatives. During 2014, 2013 and 2012, the Company made contributions to these plans of $9.1 million, $7.5 million, and $6.7 million, respectively. |
Borrowing_Arrangements
Borrowing Arrangements | 12 Months Ended | ||||||||||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||||||||||
Debt Disclosure [Abstract] | |||||||||||||||||||||||||
Borrowing Arrangements | Borrowing Arrangements | ||||||||||||||||||||||||
Long-Term Debt | |||||||||||||||||||||||||
Long-term senior unsecured obligations and first mortgage bonds outstanding by subsidiary follow: | |||||||||||||||||||||||||
At December 31, | |||||||||||||||||||||||||
(In millions) | 2014 | 2013 | |||||||||||||||||||||||
Utility Holdings | |||||||||||||||||||||||||
Fixed Rate Senior Unsecured Notes | |||||||||||||||||||||||||
2015, 5.45% | 75 | 75 | |||||||||||||||||||||||
2018, 5.75% | 100 | 100 | |||||||||||||||||||||||
2020, 6.28% | 100 | 100 | |||||||||||||||||||||||
2021, 4.67% | 55 | 55 | |||||||||||||||||||||||
2023, 3.72% | 150 | 150 | |||||||||||||||||||||||
2026, 5.02% | 60 | 60 | |||||||||||||||||||||||
2028, 3.20% | 45 | 45 | |||||||||||||||||||||||
2035, 6.10% | 75 | 75 | |||||||||||||||||||||||
2041, 5.99% | 35 | 35 | |||||||||||||||||||||||
2042, 5.00% | 100 | 100 | |||||||||||||||||||||||
2043, 4.25% | 80 | 80 | |||||||||||||||||||||||
Total Utility Holdings | 875 | 875 | |||||||||||||||||||||||
Indiana Gas | |||||||||||||||||||||||||
Fixed Rate Senior Unsecured Notes | |||||||||||||||||||||||||
2015, Series E, 7.15% | 5 | 5 | |||||||||||||||||||||||
2015, Series E, 6.69% | 5 | 5 | |||||||||||||||||||||||
2015, Series E, 6.69% | 10 | 10 | |||||||||||||||||||||||
2025, Series E, 6.53% | 10 | 10 | |||||||||||||||||||||||
2027, Series E, 6.42% | 5 | 5 | |||||||||||||||||||||||
2027, Series E, 6.68% | 1 | 1 | |||||||||||||||||||||||
2027, Series F, 6.34% | 20 | 20 | |||||||||||||||||||||||
2028, Series F, 6.36% | 10 | 10 | |||||||||||||||||||||||
2028, Series F, 6.55% | 20 | 20 | |||||||||||||||||||||||
2029, Series G, 7.08% | 30 | 30 | |||||||||||||||||||||||
Total Indiana Gas | 116 | 116 | |||||||||||||||||||||||
SIGECO | |||||||||||||||||||||||||
First Mortgage Bonds | |||||||||||||||||||||||||
2015, 1985 Pollution Control Series A, current adjustable rate 0.05%, tax-exempt, | |||||||||||||||||||||||||
2013 weighted average: 0.10% | — | 9.8 | |||||||||||||||||||||||
2016, 1986 Series, 8.875% | 13 | 13 | |||||||||||||||||||||||
2022, 2013 Series C, 1.95%, tax-exempt | 4.6 | 4.6 | |||||||||||||||||||||||
2024, 2013 Series D, 1.95%, tax-exempt | 22.5 | 22.5 | |||||||||||||||||||||||
2025, 1998 Pollution Control Series A, current adjustable rate 0.05%, tax-exempt, | |||||||||||||||||||||||||
2013 weighted average: 0.10% | — | 31.5 | |||||||||||||||||||||||
2025, 2014 Series B, current adjustable rate 0.722%, tax-exempt | 41.3 | — | |||||||||||||||||||||||
2029, 1999 Series, 6.72% | 80 | 80 | |||||||||||||||||||||||
2037, 2013 Series E, 1.95%, tax-exempt | 22 | 22 | |||||||||||||||||||||||
2038, 2013 Series A, 4.0%, tax-exempt | 22.2 | 22.2 | |||||||||||||||||||||||
2040, 2009 Environmental Improvement Series, 5.40%, tax-exempt | — | 22.3 | |||||||||||||||||||||||
2043, 2013 Series B, 4.05%, tax-exempt | 39.6 | 39.6 | |||||||||||||||||||||||
2044, 2014 Series A, 4.00% tax-exempt | 22.3 | — | |||||||||||||||||||||||
Total SIGECO | 267.5 | 267.5 | |||||||||||||||||||||||
At December 31, | |||||||||||||||||||||||||
(In millions) | 2014 | 2013 | |||||||||||||||||||||||
Vectren Capital Corp. | |||||||||||||||||||||||||
Fixed Rate Senior Unsecured Notes | |||||||||||||||||||||||||
2014, 6.37% | — | 30 | |||||||||||||||||||||||
2015, 5.31% | 75 | 75 | |||||||||||||||||||||||
2016, 6.92% | 60 | 60 | |||||||||||||||||||||||
2017, 3.48% | 75 | 75 | |||||||||||||||||||||||
2019, 7.30% | 60 | 60 | |||||||||||||||||||||||
2025, 4.53% | 50 | 50 | |||||||||||||||||||||||
Variable Rate Term Loans | |||||||||||||||||||||||||
2015 | — | 100 | |||||||||||||||||||||||
2016 | — | 100 | |||||||||||||||||||||||
Total Vectren Capital Corp. | 320 | 550 | |||||||||||||||||||||||
Total long-term debt outstanding | 1,578.50 | 1,808.50 | |||||||||||||||||||||||
Current maturities of long-term debt | (170.0 | ) | (30.0 | ) | |||||||||||||||||||||
Unamortized debt premium & discount - net | (1.2 | ) | (1.4 | ) | |||||||||||||||||||||
Total long-term debt-net | $ | 1,407.30 | $ | 1,777.10 | |||||||||||||||||||||
Vectren Capital Unsecured Note Retirement | |||||||||||||||||||||||||
On March 11, 2014, a $30 million Vectren Capital senior unsecured note matured. The Series A note, which was part of a private placement Note Purchase Agreement entered into on March 11, 2009, carried a fixed interest rate of 6.37 percent. The repayment of debt was funded from the Company's short-term credit facility. | |||||||||||||||||||||||||
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. | |||||||||||||||||||||||||
Sale of Vectren Fuels Proceeds | |||||||||||||||||||||||||
On August 29, 2014, the Company closed on a transaction to sell its wholly owned coal mining subsidiary, Vectren Fuels, to Sunrise Coal. The proceeds received, net of transaction costs and estimated tax payments, totaled $285 million and were used to retire $200 million in outstanding Vectren Capital bank term loans and pay down outstanding short-term debt. | |||||||||||||||||||||||||
Vectren Capital 2013 Term Loan | |||||||||||||||||||||||||
On August 6, 2013, Vectren Capital entered into a $100 million three-year term loan agreement. Loans under the term loan agreement bore interest at either a Eurodollar rate or base rate plus an additional margin which was based on the Company's credit rating. Interest periods were variable and could have ranged from seven days to six months. The proceeds from this debt transaction were used to repay short-term borrowings outstanding under Vectren Capital's credit facility. The loan agreement was guaranteed by Vectren Corporation and included customary representations, warranties, and covenants, including a leverage covenant consistent with leverage covenants contained in other Vectren Capital borrowing arrangements. The Company received net proceeds of approximately $100.0 million in August 2013 and repaid the loan in August of 2014. | |||||||||||||||||||||||||
SIGECO 2013 Debt Refund and Reissuance | |||||||||||||||||||||||||
During the second quarter of 2013, approximately $111 million of SIGECO's tax-exempt long-term debt was redeemed at par plus accrued interest. Approximately $62 million of tax-exempt long-term debt was reissued on April 26, 2013 at interest rates that are fixed to maturity, receiving proceeds, net of issuance costs, of approximately $60 million. The terms are $22.2 million at 4.00 percent per annum due 2038, and $39.6 million at 4.05 percent per annum due 2043. | |||||||||||||||||||||||||
The remaining approximately $49 million of the called debt was remarketed on August 13, 2013. The remarketed tax-exempt debt has a fixed interest rate of 1.95 percent per annum until September 13, 2017. SIGECO closed on this remarketing and received net proceeds of $48.3 million on August 28, 2013. | |||||||||||||||||||||||||
Utility Holdings 2013 Debt Call and Reissuance | |||||||||||||||||||||||||
On April 1, 2013, VUHI exercised a call option at par on Utility Holdings' $121.6 million 6.25 percent senior unsecured notes due in 2039. This debt was refinanced on June 5, 2013, with proceeds from a private placement note purchase agreement entered into on December 20, 2012 with a delayed draw feature. It provides for the following tranches of notes: (i) $45 million, 3.20 percent senior guaranteed notes, due June 5, 2028 and (ii) $80 million, 4.25 percent senior guaranteed notes, due June 5, 2043. Total proceeds received from these notes, net of issuance costs, were $44.8 million and $79.6 million, respectively. The notes are unconditionally guaranteed by Indiana Gas, SIGECO and VEDO. | |||||||||||||||||||||||||
On August 22, 2013, VUHI entered into a private placement note purchase agreement with a delayed draw feature, pursuant to which institutional investors agreed to purchase $150 million of senior guaranteed notes with a fixed interest rate of 3.72 percent per annum, due December 5, 2023. The notes were unconditionally guaranteed by Indiana Gas, SIGECO, and VEDO. On December 5, 2013, the Company received net proceeds of $149.1 million from the issuance of the senior guaranteed notes, which were used to refinance $100 million of 5.25 percent senior notes that matured August 1, 2013, for capital expenditures, and for general corporate purposes. | |||||||||||||||||||||||||
Vectren Capital 2012 Term Loan | |||||||||||||||||||||||||
On November 1, 2012, Vectren Capital entered into a $100 million three year term loan agreement. Loans under the term loan agreement bore interest at either a Eurodollar rate or base rate plus an additional margin which was based on the Company's credit rating. Interest periods were variable and could have ranged from seven days to six months. The proceeds from this debt transaction were used to repay short-term borrowings outstanding under Vectren Capital's credit facility. The loan agreement was guaranteed by Vectren Corporation and included customary representations, warranties and covenants, including a leverage covenant consistent with leverage covenants contained in other Vectren Capital borrowing arrangements. The Company received net proceeds of approximately $100 million in November 2012 and repaid the loan in August 2014. | |||||||||||||||||||||||||
Utility Holdings 2012 Debt Transactions | |||||||||||||||||||||||||
On February 1, 2012, Utility Holdings issued $100 million of senior unsecured notes at an interest rate of 5.00 percent per annum and with a maturity date of February 3, 2042. The notes were sold to various institutional investors pursuant to a private placement note purchase agreement executed in November 2011 with a delayed draw feature. These senior notes are unsecured and jointly and severally guaranteed by Utility Holdings’ regulated utility subsidiaries, SIGECO, Indiana Gas, and VEDO. The proceeds from the sale of the notes, net of issuance costs, totaled approximately $99.5 million. These notes have no sinking fund requirements and interest payments are due semi-annually. These notes contain customary representations, warranties and covenants, including a leverage covenant consistent with leverage covenants contained in other Utility Holdings’ borrowing arrangements. | |||||||||||||||||||||||||
Mandatory Tenders | |||||||||||||||||||||||||
At December 31, 2014, certain series of SIGECO bonds, aggregating $49.1 million, currently bear interest at fixed rates and are subject to mandatory tender in September 2017. Additionally, SIGECO Bond Series 2014B, in the amount of $41.3 million, with a variable interest rate that is reset monthly, is subject to mandatory tender in September 2019. | |||||||||||||||||||||||||
Future Long-Term Debt Sinking Fund Requirements and Maturities | |||||||||||||||||||||||||
The annual sinking fund requirement of SIGECO's first mortgage bonds is 1 percent of the greatest amount of bonds outstanding under the Mortgage Indenture. This requirement may be satisfied by certification to the Trustee of unfunded property additions in the prescribed amount as provided in the Mortgage Indenture. SIGECO intends to meet the 2014 sinking fund requirement by this means and, accordingly, the sinking fund requirement for 2014 is excluded from Current liabilities in the Consolidated Balance Sheets. At December 31, 2014, $1.3 billion of SIGECO's utility plant remained unfunded under SIGECO's Mortgage Indenture. SIGECO’s gross utility plant balance subject to the Mortgage Indenture approximated $3.0 billion at December 31, 2014. | |||||||||||||||||||||||||
Consolidated maturities of long-term debt during the five years following 2014 (in millions) are $170.0 in 2015, $73.0 in 2016, $75.0 in 2017, $100.0 in 2018, $60.0 in 2019, and $1,099.3 thereafter. | |||||||||||||||||||||||||
Debt Guarantees | |||||||||||||||||||||||||
Vectren Corporation guarantees Vectren Capital’s long-term debt, including current maturities, and short-term debt, which totaled $320 million and $0 million, respectively, at December 31, 2014. Utility Holdings’ currently outstanding long-term and short-term debt is jointly and severally guaranteed by Indiana Gas, SIGECO, and VEDO. Utility Holdings’ long-term debt and short-term debt outstanding at December 31, 2014, totaled $875 million and $156 million, respectively. | |||||||||||||||||||||||||
Covenants | |||||||||||||||||||||||||
Both long-term and short-term borrowing arrangements contain customary default provisions; restrictions on liens, sale-leaseback transactions, mergers or consolidations, and sales of assets; and restrictions on leverage, among other restrictions. Multiple debt agreements contain a covenant that the ratio of consolidated total debt to consolidated total capitalization will not exceed 65 percent. As of December 31, 2014 the Company was in compliance with all financial covenants. | |||||||||||||||||||||||||
Short-Term Borrowings | |||||||||||||||||||||||||
At December 31, 2014, the Company has $600 million of short-term borrowing capacity, including $350 million for the Utility Group and $250 million for the wholly owned Nonutility Group and corporate operations. As reduced by borrowings currently outstanding, approximately $194 million was available for the Utility Group operations and approximately $250 million was available for the wholly owned Nonutility Group and corporate operations. On October 31, 2014, Vectren Capital’s and Utility Holdings’ short-term credit facilities, totaling $600 million in borrowing capacity, were amended to extend their maturity until October 31, 2019. These facilities are used to supplement working capital needs and also to fund capital investments and debt redemptions until financed on a long-term basis. | |||||||||||||||||||||||||
Following is certain information regarding these short-term borrowing arrangements. | |||||||||||||||||||||||||
Utility Group Borrowings | Nonutility Group Borrowings | ||||||||||||||||||||||||
(In millions) | 2014 | 2013 | 2012 | 2014 | 2013 | 2012 | |||||||||||||||||||
As of Year End | |||||||||||||||||||||||||
Balance Outstanding | $ | 156.4 | $ | 28.6 | $ | 116.7 | $ | — | $ | 40 | $ | 162.1 | |||||||||||||
Weighted Average Interest Rate | 0.5 | % | 0.29 | % | 0.4 | % | N/A | 1.27 | % | 1.35 | % | ||||||||||||||
Annual Average | |||||||||||||||||||||||||
Balance Outstanding | $ | 35.6 | $ | 119.6 | $ | 77.6 | $ | 34.5 | $ | 119.3 | $ | 151.5 | |||||||||||||
Weighted Average Interest Rate | 0.34 | % | 0.34 | % | 0.47 | % | 1.29 | % | 1.35 | % | 1.44 | % | |||||||||||||
Maximum Month End Balance Outstanding | $ | 156.4 | $ | 176.1 | $ | 214.2 | $ | 76.3 | $ | 173.8 | $ | 216.1 | |||||||||||||
Throughout 2014, 2013, and 2012, the Company has placed commercial paper without any significant issues and did not borrow from Utility Holdings' backup credit facility in any of the periods presented. |
Common_Shareholders_Equity
Common Shareholder's Equity | 12 Months Ended |
Dec. 31, 2014 | |
Stockholders' Equity Note [Abstract] | |
Common Shareholder's Equity | Common Shareholders’ Equity |
Authorized, Reserved Common and Preferred Shares | |
At December 31, 2014 and 2013, the Company was authorized to issue 480 million shares of common stock and 20 million shares of preferred stock. Of the authorized common shares, approximately 5.3 million shares at December 31, 2014 and 5.8 million shares at December 31, 2013 were reserved by the board of directors for issuance through the Company’s share-based compensation plans, benefit plans, and dividend reinvestment plan. At December 31, 2014 and 2013, there were 392.2 million and 391.7 million, respectively, of authorized shares of common stock and all authorized shares of preferred stock, available for a variety of general corporate purposes, including future public offerings to raise additional capital and for facilitating acquisitions. |
Earnings_Per_Share
Earnings Per Share | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Earnings Per Share [Abstract] | |||||||||||||
Earnings Per Share | Earnings Per Share | ||||||||||||
The Company uses the two class method to calculate earnings per share (EPS). The two class method is an earnings allocation formula that treats a participating security as having rights to earnings that otherwise would have been available to common shareholders. Under the two class method, earnings for a period are allocated between common shareholders and participating security holders based on their respective rights to receive dividends as if all undistributed book earnings for the period were distributed. | |||||||||||||
Basic EPS is computed by dividing net income attributable to only the common shareholders by the weighted-average number of common shares outstanding for the period. Diluted EPS includes the impact of stock options and other equity based instruments to the extent the effect is dilutive. | |||||||||||||
The following table illustrates the basic and dilutive EPS calculations for the three years ended December 31, 2014: | |||||||||||||
Year Ended December 31, | |||||||||||||
(In millions, except per share data) | 2014 | 2013 | 2012 | ||||||||||
Numerator: | |||||||||||||
Numerator for basic EPS | $ | 166.9 | $ | 136.6 | $ | 159 | |||||||
Add back earnings attributable to participating securities | — | — | — | ||||||||||
Reported net income (Numerator for Diluted EPS) | $ | 166.9 | $ | 136.6 | $ | 159 | |||||||
Denominator: | |||||||||||||
Weighted average common shares outstanding (Basic EPS) | 82.5 | 82.3 | 82 | ||||||||||
Conversion of share based compensation arrangements | 0 | 0.1 | 0.1 | ||||||||||
Adjusted weighted average shares outstanding and | |||||||||||||
assumed conversions outstanding (Diluted EPS) | 82.5 | 82.4 | 82.1 | ||||||||||
Basic earnings per share | $ | 2.02 | $ | 1.66 | $ | 1.94 | |||||||
Diluted earnings per share | $ | 2.02 | $ | 1.66 | $ | 1.94 | |||||||
For the years ended December 31, 2014 , 2013, and 2012, all options and equity based instruments were dilutive. |
Accumulated_Other_Comprehensiv
Accumulated Other Comprehensive Income | 12 Months Ended | ||||||||||||||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||||||||||||||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract] | |||||||||||||||||||||||||||||
Accumulated Other Comprehensive Income | Accumulated Other Comprehensive Income | ||||||||||||||||||||||||||||
A summary of the components of and changes in Accumulated other comprehensive income for the past three years follows: | |||||||||||||||||||||||||||||
2012 | 2013 | 2014 | |||||||||||||||||||||||||||
Beginning | Changes | End | Changes | End | Changes | End | |||||||||||||||||||||||
of Year | During | of Year | During | of Year | During | of Year | |||||||||||||||||||||||
(In millions) | Balance | Year | Balance | Year | Balance | Year | Balance | ||||||||||||||||||||||
Unconsolidated affiliates | $ | (15.9 | ) | $ | 11.3 | $ | (4.6 | ) | $ | 4.6 | $ | — | $ | — | $ | — | |||||||||||||
Pension & other benefit costs | (6.6 | ) | 4 | (2.6 | ) | 1.4 | (1.2 | ) | (1.0 | ) | (2.2 | ) | |||||||||||||||||
Cash flow hedges | 0.1 | (0.1 | ) | — | — | — | — | — | |||||||||||||||||||||
Deferred income taxes | 9.1 | (6.2 | ) | 2.9 | (2.4 | ) | 0.5 | 0.4 | 0.9 | ||||||||||||||||||||
Accumulated other comprehensive income (loss) | $ | (13.3 | ) | $ | 9 | $ | (4.3 | ) | $ | 3.6 | $ | (0.7 | ) | $ | (0.6 | ) | $ | (1.3 | ) | ||||||||||
Accumulated other comprehensive income arising from unconsolidated affiliates was previously primarily the Company’s portion of ProLiance Holdings, LLC’s accumulated comprehensive income related to use of cash flow hedges. (See Note 7 for more information on ProLiance.) |
ShareBased_Compensation_Deferr
Share-Based Compensation & Deferred Compensation Arrangements | 12 Months Ended | |||||||||||||
Dec. 31, 2014 | ||||||||||||||
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | ||||||||||||||
Share-Based Compensation and Deferred Compensation Arrangements | Share-Based Compensation & Deferred Compensation Arrangements | |||||||||||||
The Company has share-based compensation programs to encourage Company officers, key non-officer employees, and non-employee directors to remain with the Company and to more closely align their interests with those of the Company’s shareholders. Under these programs, the Company has in the past issued stock options and both performance-based and time-based awards. All share-based compensation programs are shareholder approved. Currently, awards issued to officers of the Company, which comprise a substantial majority of the awards issued, are performance-based, are generally settled in cash, and dividends that accrue are also subject to performance measures. In addition, the Company maintains a deferred compensation plan for executives and non-employee directors where participants can invest earned compensation and vested share-based awards in phantom Company stock units, among other options. Certain vesting grants provide for accelerated vesting if there is a change in control or upon the participant’s retirement. | ||||||||||||||
Following is a reconciliation of the total cost associated with share-based awards recognized in the Company’s financial statements to its after tax effect on net income: | ||||||||||||||
Year Ended December 31, | ||||||||||||||
(In millions) | 2014 | 2013 | 2012 | |||||||||||
Total cost of share-based compensation | $ | 25.2 | $ | 14.8 | $ | 6.3 | ||||||||
Less capitalized cost | 5.3 | 2.8 | 1.2 | |||||||||||
Total in other operating expense | 19.9 | 12 | 5.1 | |||||||||||
Less income tax benefit in earnings | 7.9 | 4.8 | 2.1 | |||||||||||
After tax effect of share-based compensation | $ | 12 | $ | 7.2 | $ | 3 | ||||||||
Performance Based Awards & Other Awards | ||||||||||||||
The vesting of awards issued to Company officers and certain non-officer employees is contingent upon meeting total return and return on equity performance objectives. Historically, grants to Company officers and certain non-officer employees generally vested at the end of a four-year period, with performance measured at the end of the third year. Grants issued to Company officers and certain non-officer employees in 2015 and beyond will generally vest at the end of a three-year period, with performance continuing to be measured at the end of the third year. Based on performance objectives, the number of awards could double or could be entirely forfeited. | ||||||||||||||
A limited number of awards for non-officer employees are time-vested awards and vest ratably over a three or five-year period. In addition, non-employee directors receive a portion of their fees in share based awards. These awards to non-employee directors are not performance based and generally vest over one year. Because Company officers and non-employee directors have the choice of settling awards in cash or deferring their receipt into a deferred compensation plan (where the value is eventually withdrawn in cash), these awards are accounted for as liability awards at their settlement date fair value. Share awards to certain non-officer employees must be settled in shares and are therefore accounted for in equity at their grant date fair value. | ||||||||||||||
A summary of the status of awards separated between those accounted for as liabilities and equity as of December 31, 2014, and changes during the year ended December 31, 2014, follows: | ||||||||||||||
Equity Awards | ||||||||||||||
Wtd. Avg. | ||||||||||||||
Grant Date | Liability Awards | |||||||||||||
Units | Fair value | Units | Fair value | |||||||||||
Awards at January 1, 2014 | 79,957 | $ | 29.12 | 731,251 | ||||||||||
Granted | 5,910 | 31.24 | 331,344 | |||||||||||
Vested | -51,594 | 28.36 | -347,031 | |||||||||||
Forfeited | — | — | -22,405 | |||||||||||
Awards at December 31, 2014 | 34,273 | $ | 30.55 | 693,159 | $ | 46.23 | ||||||||
As of December 31, 2014, there was $16.5 million of total unrecognized compensation cost associated with outstanding grants. That cost is expected to be recognized over a weighted-average period of 1.9 years. The total fair value of shares vested for liability awards during the years ended December 31, 2014, 2013, and 2012, was $15.1 million, $5.7 million, and $4.4 million, respectively. The total fair value of equity awards vesting during the year ended December 31, 2014, 2013, and 2012 was $0.9 million, $0.4 million, $0.1 million, respectively. | ||||||||||||||
Stock Option Plans | ||||||||||||||
In the past, option awards were granted to executives and other key employees with an exercise price equal to the market price of the Company’s stock at the date of grant; those option awards generally required three years of continuous service and have 10-year contractual terms. These awards generally vested on a pro-rata basis over three years. The last option grant occurred in 2005, and the Company has no plans to issue options in the future. All compensation cost has been recognized. | ||||||||||||||
The total intrinsic value of options exercised during the year ended December 31, 2014 , 2013, and 2012 was $0.1 million, $3.8 million, and $0.1 million respectively and the actual tax benefit realized for tax deductions from these option exercises was approximately $0.2 million, $1.5 million, and $0.1 million in 2014, 2013, and 2012, respectively. As of December 31, 2014, there are 946 exercisable shares remaining. | ||||||||||||||
Deferred Compensation Plans | ||||||||||||||
The Company has nonqualified deferred compensation plans, which permit eligible executives and non-employee directors to defer portions of their compensation and vested share-based compensation. A record keeping account is established for each participant, and the participant chooses from a variety of measurement funds for the deemed investment of their accounts. The measurement funds are similar to the funds in the Company's defined contribution plan and include an investment in phantom stock units of the Company. The account balance fluctuates with the investment returns on those funds. At December 31, 2014 and 2013, the liability associated with these plans totaled $31.2 million and $26.1 million, respectively. Other than $1.4 million and $1.6 million which are classified in Accrued liabilities at December 31, 2014 and 2013, respectively, the liability is included in Deferred credits & other liabilities. The impact of these plans on Other operating expenses was expense of $5.0 million in 2014, $4.0 million in 2013 and $1.7 million in 2012. The amount recorded in earnings related to the investment activities in Vectren phantom stock associated with these plans during the years ended December 31, 2014, 2013, and 2012, was a cost of $4.0 million, $2.6 million and $0.6 million, respectively. | ||||||||||||||
The Company has certain investments currently funded primarily through corporate-owned life insurance policies. These investments, which are consolidated, are available to pay deferred compensation benefits. These investments are also subject to the claims of the Company's creditors. The cash surrender value of these policies included in Other corporate & utility investments on the Consolidated Balance Sheets were $32.3 million and $32.9 million at December 31, 2014 and 2013, respectively. Earnings from those investments, which are recorded in Other income-net, were earnings of $2.8 million in 2014, $4.8 million in 2013, and $1.8 million in 2012. |
Commitments_and_Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2014 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Commitments & Contingencies |
Commitments | |
Future minimum lease payments required under operating leases that have initial or remaining noncancelable lease terms in excess of one year during the five years following 2014 and thereafter (in millions) are $8.2 in 2015, $5.6 in 2016, $3.2 in 2017, $2.0 in 2018, $1.6 in 2019, and $3.6 thereafter. Total lease expense (in millions) was $13.2 in 2014, $9.9 in 2013, and $8.5 in 2012. | |
The Company’s regulated utilities have both firm and non-firm commitments to purchase natural gas, electricity, and coal as well as certain transportation and storage rights and certain contracts are firm commitments under five and ten-year arrangements. Costs arising from these commitments, while significant, are pass-through costs, generally collected dollar-for-dollar from retail customers through regulator-approved cost recovery mechanisms. | |
Corporate Guarantees | |
The Company issues parent level guarantees to certain vendors and customers of its wholly owned subsidiaries and unconsolidated affiliates. These guarantees do not represent incremental consolidated obligations; rather, they represent parental guarantees of subsidiary and unconsolidated affiliate obligations in order to allow those subsidiaries and affiliates the flexibility to conduct business without posting other forms of collateral. At December 31, 2014, parent level guarantees, excluding guarantees of obligations of the federal business unit acquired from Chevron USA on April 1, 2014, as further described below, support a maximum of $25 million of Energy System Group's (ESG) performance contracting commitments and warranty obligations and $35 million of other project guarantees. | |
On April 1, 2014, ESG acquired the federal sector energy services unit of CES, from Chevron USA. Pursuant to the agreement, the acquisition includes a provision whereby Vectren Enterprises, Inc., the wholly owned holding company for the Company's nonutility investments, provided CES with an indemnification for potential claims against the seller that could arise related to the performance of work undertaken by ESG. | |
The acquisition also includes ESG guarantees of performance under certain assumed contracts. The guarantees include energy savings that are used to satisfy project financing. The Company guarantees ESG's performance under these energy savings guarantees. The total maximum amount of the energy savings guarantees is approximately $140 million and will only be called upon in the event energy savings established under the existing contracts executed by CES are not achieved. Further, an energy facility operated by ESG and managed by Keenan Ft. Detrick Energy, LLC (Keenan), is governed by an operations agreement. All payment obligations to Keenan under this agreement are also guaranteed by the Company. The Vectren Enterprises, Inc. provision providing indemnification to CES and the Company guarantee of the Keenan Ft. Detrick Energy operations agreement with Keenan as discussed above, do not state a maximum guarantee. Due to the nature of work performed under these contracts, the Company cannot estimate a maximum potential amount of future payments. | |
In addition, the Company has approximately $17 million of other guarantees outstanding supporting other consolidated subsidiary operations, of which $11 million represents letters of credit supporting other nonutility operations. | |
While there can be no assurance that neither the Vectren Enterprises, Inc.'s indemnification nor the Company guarantee provisions will be called upon, the Company believes that the likelihood of a material amount being triggered under any of these provisions is remote. | |
Performance Guarantees & Product Warranties | |
In the normal course of business, wholly owned subsidiaries, including ESG, issue performance bonds or other forms of assurance that commit them to timely install infrastructure, operate facilities, pay vendors or subcontractors, and/or support warranty obligations. Based on a history of meeting performance obligations and installed products operating effectively, no significant liability or cost has been recognized for the periods presented. | |
Specific to ESG, in its role as a general contractor in the performance contracting industry, at December 31, 2014, there are 50 open surety bonds supporting future performance. The average face amount of these obligations is $6.9 million, and the largest obligation has a face amount of $57.3 million. The maximum exposure from these obligations is limited by the level of work already completed and guarantees issued to ESG by various subcontractors. At December 31, 2014, approximately 42 percent of work was completed on projects with open surety bonds. A significant portion of these open surety bonds will be released within one year. In instances where ESG operates facilities, project guarantees extend over a longer period. In addition to its performance obligations, ESG also warrants the functionality of certain installed infrastructure generally for one year and the associated energy savings over a specified number of years. The Company has no accruals for these warranty and energy obligations as of December 31, 2014. | |
Legal & Regulatory Proceedings | |
The Company is party to various legal proceedings, audits, and reviews by taxing authorities and other government agencies arising in the normal course of business. In the opinion of management, there are no legal proceedings or other regulatory reviews or audits pending against the Company that are likely to have a material adverse effect on its financial position, results of operations or cash flows. |
Gas_Rate_Regulatory_Matters
Gas Rate & Regulatory Matters | 12 Months Ended |
Dec. 31, 2014 | |
Public Utilities, General Disclosures [Abstract] | |
Gas Rate and Regulatory Matters | Gas Rate & Regulatory Matters |
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement | |
The Company monitors and maintains its natural gas distribution system to ensure that natural gas is delivered in a safe and efficient manner. The Company's natural gas utilities are currently engaged in programs to replace bare steel and cast iron infrastructure and other activities in both Indiana and Ohio to mitigate risk, improve the system, and comply with applicable regulations, many of which are a result of federal pipeline safety requirements. Laws in both Indiana and Ohio were passed that provide utilities the opportunity to timely recover costs of federally mandated projects and other infrastructure improvement projects outside of a base rate proceeding. | |
In April 2011, Indiana Senate Bill 251 (Senate Bill 251) was signed into Indiana law. The law provides a framework to recover 80 percent of federally mandated costs through a periodic rate adjustment mechanism outside of a general rate case. Such costs include a return on the federally mandated capital investment, along with recovery of depreciation and other operating costs associated with these mandates. The remaining 20 percent of those costs is deferred for future recovery in the utility's next general rate case. | |
In April 2013, Indiana Senate Bill 560 (Senate Bill 560) was signed into Indiana law. This legislation supplements Senate Bill 251 described above, and provides for cost recovery outside of a base rate proceeding for projects that either improve electric and gas system reliability and safety or are economic development projects that provide rural areas with access to gas service. Provisions of the legislation require that, among other things, requests for recovery include a seven-year project plan. Once the plan is approved by the IURC, 80 percent of such costs are eligible for current recovery using a periodic rate adjustment mechanism. Recoverable costs include a return on and of the investment, as well as property taxes and operating expenses. The remaining 20 percent of project costs is deferred and recovered in the utility’s next general rate case, which must be filed before the expiration of the seven year plan. The adjustment mechanism is capped at an annual increase in retail revenues of no more than two percent. | |
In June 2011, Ohio House Bill 95 (House Bill 95) was signed into law. Outside of a base rate proceeding, this legislation permits a natural gas utility to apply for recovery of much of its capital expenditure program. By allowing for the deferral of costs, such as depreciation, property taxes, and debt-related post in service carrying costs until recovery is approved by the Ohio Commission. | |
Indiana Recovery and Deferral Mechanisms | |
The Company's Indiana natural gas utilities received Orders in 2008 and 2007 associated with the most recent base rate cases. These Orders authorized the deferral of financial impacts associated with bare steel and cast iron replacement activities. The Orders provide for the deferral of depreciation and post in service carrying costs on qualifying projects totaling $20 million annually at Indiana Gas and $3 million annually at SIGECO. The debt-related post-in-service carrying costs are recognized in the Consolidated Statements of Income currently. The recording of post-in-service carrying costs and depreciation deferral is limited by individual qualifying project to three years after being placed into service at SIGECO and four years after being placed into service at Indiana Gas. At December 31, 2014 and 2013, the Company has regulatory assets totaling $16.4 million and $12.1 million, respectively, associated with the deferral of depreciation and debt-related post-in-service carrying cost activities. Beginning in 2014, all bare steel and cast iron replacement activities are now part of the Company’s seven-year capital investment plan filed pursuant to Senate Bill 251, discussed further below. | |
Requests for Recovery Under Indiana Regulatory Mechanisms | |
On August 27, 2014, the Commission issued an Order approving the Company’s seven-year capital infrastructure replacement and improvement plan, beginning in 2014, and the proposed accounting authority and recovery, pursuant to Senate Bill 251 and 560. As provided in the two laws, the Order approved semi-annual filings for rate recovery of 100 percent of the costs, inclusive of return, related to these capital investments and operating expenses associated with pipeline safety rules, with 80 percent of the costs recovered currently via an approved tracking mechanism and 20 percent of the costs deferred and recovered in the Company’s next base rate proceeding. In addition, the Order established guidelines to update the seven-year capital investment plan annually, with detailed estimates provided for the upcoming calendar year. Finally, the Order approved the Company’s proposal to recover eligible costs via a fixed monthly charge per residential customer. On September 26, 2014, the Indiana Office of Utility Consumer Counselor (OUCC) filed a Notice of Appeal with the Indiana Court of Appeals in response to the IURC's Order. On January 28, 2015, the OUCC filed its appellate brief raising an issue regarding the treatment of retired assets within the recovery mechanism. An appeal was also filed in response to the IURC's Order in Northern Indiana Public Service Company's (NIPSCO) Senate Bill 560 electric infrastructure proceeding, pertaining to certain issues regarding the Commission's authority to approve NIPSCO's infrastructure plan. The outcome of neither appeal and the implications to the Company’s Order, if any, cannot be determined. | |
On January 14, 2015, the Commission issued an Order approving the Company’s initial request for recovery of the revenue requirement associated with capital investment and applicable operating costs through June 30, 2014 as part of its approved seven-year plan. As the next step of the recovery process, as outlined in the legislation, this Order initiates the rates and charges necessary to begin cash recovery of 80 percent of the revenue requirement, with the remaining 20 percent deferred for recovery in the Company's next rate cases. Also, consistent with the guidelines set forth in the original August 2014 Order, the Commission approved the Company’s update to its seven-year plan, to reflect changes to project prioritization as a result of both additional risk modeling and cost increases. The updated plan reflects capital expenditures of approximately $900 million, an increase of $35 million from the previous plan and is inclusive of an estimated $30 million of economic development related expenditures, over the seven-year period beginning in 2014. The plan also includes approximately $15 million of annual operating costs associated with pipeline safety rules. | |
Ohio Recovery and Deferral Mechanisms | |
The PUCO Order approving the Company's 2009 base rate case in the Ohio service territory authorized a distribution replacement rider (DRR). The DRR's primary purpose is recovery of investments in utility plant and related operating expenses associated with replacing bare steel and cast iron pipelines and certain other infrastructure. This rider is updated annually for qualifying capital expenditures and allows for a return to be earned on those capital expenditures based on the rate of return approved in the 2009 base rate case. In addition, deferral of depreciation and the ability to accrue debt-related post-in-service carrying costs is also allowed until the related capital expenditures are included in the DRR. The Order also initially established a prospective bill impact evaluation on the annual deferrals. To date, the Company has made capital investments under this rider totaling $150.5 million. Regulatory assets associated with post-in-service carrying costs and depreciation deferrals were $13.1 million and $9.3 million at December 31, 2014 and December 31, 2013, respectively. Due to the expiration of the initial five-year term for the DRR in early 2014, the Company filed a request in August 2013 to extend and expand the DRR. On February 19, 2014, the PUCO issued an Order approving a Stipulation entered into by the PUCO Staff and the Company which provided for the extension of the DRR for the recovery of costs incurred through 2017 and expanded the types of investment covered by the DRR to include recovery of other infrastructure investments. The Order limits the resulting DRR fixed charge per month for residential and small general service customers to specific graduated levels over the next five years. The Company's five-year capital expenditure plan related to these infrastructure investments for calendar years 2013 through 2017 totals approximately $200 million, subject to the graduated caps on the fixed DRR monthly charge applicable to residential and small general service customers approved in the Order. In addition, the Order approved the Company's commitment that the DRR can only be further extended as part of a base rate case. On May 1, 2014, the Company filed its annual request to adjust the DRR for recovery of costs incurred through December 31, 2013. On August 27, 2014 the PUCO issued an Order approving the Company’s revised DRR rates and charges, effective September 1, 2014. | |
Given the extension of the DRR through 2017 as discussed above and the continued ability to defer other capital expenses under House Bill 95, it is anticipated that the Company will file a general rate case for the inclusion in rate base of the above costs near the expiration of the DRR. As such, the bill impact limits discussed below are not expected to be reached given the Company's capital expenditure plan during the remaining three-year time frame. | |
The PUCO has also issued Orders approving the Company's filings under Ohio House Bill 95. These Orders approve deferral of the Company’s Ohio capital expenditure program for items not covered by the DRR as well as expenditures necessary to comply with PUCO rules, regulations, orders, and system expansion to some new customers. Ohio House Bill 95 Orders also have established a prospective bill impact evaluation on the cumulative deferrals, limiting the total deferrals at a level which would equal $1.50 per residential and small general service customer per month. As of December 31, 2014, the Company's deferrals have not reached this bill impact cap. In addition, the Orders approved the Company's proposal that subsequent requests for accounting authority will be filed annually in April. The Company submitted its most recent annual filing on April 30, 2014, which covers the Company’s capital expenditure program through calendar year 2014. During 2014 and 2013, these approved capital expenditure programs under House Bill 95 generated Other income associated with the debt-related post-in-service carrying costs totaling $3.9 million and $2.2 million, respectively. Deferral of depreciation and property tax expenses related to these programs in 2014 and 2013 totaled $3.1 million and $1.7 million, respectively. | |
Other Regulatory Matters | |
Indiana Gas GCA Cost Recovery Issue | |
On July 1, 2014, Indiana Gas filed its recurring quarterly Gas Cost Adjustment (GCA) mechanism, which included recovery of gas cost variances incurred for the period January through March 2014. In August 2014, the OUCC filed testimony opposing the recovery of approximately $3.9 million of natural gas commodity purchases incurred during this period on the basis that a gas cost incentive calculation had not been properly performed. The calculation at issue is performed by the Company's supply administrator. In the winter period at issue, a pipeline force majeure event caused the gas to be priced at a location that was impacted by the extreme winter temperatures. After further review, the OUCC has modified its position in testimony filed on November 5, 2014, and now suggests a reduced disallowance of $3 million. The Commission has moved this specific issue to a sub-docket proceeding, and based on the procedural schedule, an order is expected later in 2015. The Company believes that the costs are either recoverable in its GCA, or that if the incentive mechanism calculation is found to create a credit due to customers, any such outcome would be funded by its supply administrator. The administrator has intervened and filed testimony in the proceeding. | |
Indiana Gas & SIGECO Gas Decoupling Extension Filing | |
On August 18, 2011, the IURC issued an Order granting the extension of the current decoupling mechanism in place at both Indiana gas companies and recovery of new conservation program costs through December 2015. The Order provides that the companies must submit an extension proposal no later than March 1, 2015. The Companies have reached an agreement in principle with the OUCC to extend the decoupling mechanism through 2020. The final settlement will be filed for approval by the Commission by March 1, 2015. |
Electric_Rate_and_Regulatory_M
Electric Rate and Regulatory Matters Electric Rate and Regulatory Matters | 12 Months Ended |
Dec. 31, 2014 | |
Public Utilities, General Disclosures [Abstract] | |
Electric Rate and Regulatory Matters | Electric Rate & Regulatory Matters |
SIGECO Electric Environmental Compliance Filing | |
On January 28, 2015, the IURC issued an Order approving the Company’s request for approval of capital investments on its coal-fired generation units to comply with new EPA mandates related to mercury and air toxin standards effective in 2015 and to address an outstanding Notice of Violation (NOV) from the EPA. The total investment is estimated to be between $80 and $90 million, roughly half of which will be made to control mercury in both air and water emissions, and the remaining investment will be made to address the issues raised in the NOV proceeding on the increase in sulfur trioxide emissions. Although the Company and the Commission acknowledge that these investments are recoverable as clean coal technology under Senate Bill 29 and federal mandated investment under Senate Bill 251, the Order approves the Company’s request for deferred accounting treatment in lieu of timely recovery to avoid immediate customer bill impacts. The accounting treatment, includes the deferral of depreciation and property tax expense related to these investments, accrual of post-in-service carrying costs, and deferral of incremental operating expenses related to compliance with these standards. The initial phase of the projects went into service in 2014, with the remaining investment expected to occur in 2015 and 2016. | |
Coal Procurement Procedures | |
Entering 2014, SIGECO had in place staggered term coal contracts with Vectren Fuels and one other supplier to provide supply for its generating units. During 2014, SIGECO entered into separate negotiations with Vectren Fuels and Sunrise Coal to modify its existing contracts as well as enter into new long-term contracts in order to secure its supply of coal with specifications that support its compliance with the Mercury and Air Toxins Rule. Subsequent to the sale of Vectren Fuels to Sunrise Coal in August 2014, all such contracts have been assigned to Sunrise Coal. Those contracts were submitted to the IURC for review as part of the 2014 annual sub docket proceeding. In December 2014, the Commission determined that the terms of the coal contracts are reasonable. The annual sub docket proceeding is no longer required. | |
On December 5, 2011 within the quarterly FAC filing, SIGECO submitted a joint proposal with the OUCC to reduce its fuel costs billed to customers by accelerating into 2012 the impact of lower cost coal under new term contracts effective after 2012. The cost difference was deferred to a regulatory asset and is being recovered over a 6 year period without interest beginning in 2014. The IURC approved this proposal on January 25, 2012, with the reduction to customer’s rates effective February 1, 2012. The total balance deferred for recovery through the Company’s FAC, which began February 2014, was $42.4 million, of which $35.3 million remains as of December 31, 2014. | |
SIGECO Electric Demand Side Management (DSM) Program Filing | |
On August 31, 2011 the IURC issued an Order approving an initial three year DSM plan in the SIGECO electric service territory that complied with the IURC’s energy saving targets. Consistent with the Company’s proposal, the Order approved, among other items, the following: 1) recovery of costs associated with implementing the DSM Plan; 2) the recovery of a performance incentive mechanism based on measured savings related to certain DSM programs; 3) lost margin recovery associated with the implementation of DSM programs for large customers; and 4) deferral of lost margin up to $3 million in 2012 and $1 million in 2011 associated with small customer DSM programs for subsequent recovery under a tracking mechanism to be proposed by the Company. On June 20, 2012, the IURC issued an Order approving a small customer lost margin recovery mechanism, inclusive of all previous deferrals. This mechanism is an alternative to the electric decoupling proposal that was denied by the IURC in the Company's last base rate proceeding. For the twelve months ended December 31, 2014 and December 31, 2013, the Company recognized Electric utility revenue of $8.7 million and $5.0 million, respectively, associated with this approved lost margin recovery mechanism. | |
On March 28, 2014, Senate Bill 340 was signed into law. This legislation ended electric DSM programs on December 31, 2014 that have been conducted to meet the energy savings requirements established in the Commission's December 2009 Order. The legislation also allows for industrial customers to opt out of participating in energy efficiency programs. As of January 1, 2015, approximately 80 percent of the Company’s eligible industrial load has opted out of participation in the applicable energy efficiency programs. Indiana's governor has requested that the Commission make new recommendations for energy efficiency programs to be proposed for 2015 and beyond, and has also asked the legislature to consider further legislation requiring some level of utility sponsored energy efficiency programs. The Company filed a request for Commission approval of a new portfolio of DSM programs on May 29, 2014 to be offered in 2015. On October 15, 2014, the Commission issued an Order approving a Settlement between the OUCC and the Company regarding the new portfolio of DSM programs effective January 2015. | |
FERC Return on Equity (ROE) Complaint | |
On November 12, 2013, certain parties representing a group of industrial customers filed a joint complaint with the FERC under Section 206 of the Federal Power Act against MISO and various MISO transmission owners, including SIGECO. The joint parties seek to reduce the 12.38 percent return on equity used in the MISO transmission owners’ rates, including SIGECO’s formula transmission rates, to 9.15 percent, and to set a capital structure in which the equity component does not exceed 50 percent. The MISO transmission owners filed their response to the complaint on January 6, 2014, opposing any change to the return. As of December 31, 2014, the Company had invested approximately $157.7 million in qualifying projects. The net plant balance for these projects totaled $143.6 million at December 31, 2014. | |
This joint complaint is similar to a complaint against the New England Transmission Owners (NETO) filed in September 2011, which requested that the 11.14 percent incentive return granted on qualifying investments in NETO be lowered. On October 16, 2014, the FERC issued an Order in the NETO case approving a 10.57 percent return on equity and a methodology set out in its June 19, 2014 decision. | |
In addition to the NETO ruling, the FERC acknowledged that the pending complaint raised against the MISO transmission owners is reasonable, and ordered the initiation of a formal settlement discussion, mediated by a FERC appointed judge, in November 2014. As of January 2015, a settlement was not reached, and the case will move to a formal evidentiary hearing before the FERC. A procedural schedule was set on January 22, 2015, which will define a targeted date of final resolution from the FERC. An initial decision is expected later in 2015, but the timing of the final order from the FERC is unknown at this time. The Company has established a reserve pending the outcome of this complaint. | |
On January 6, 2015, the FERC approved a MISO transmission owner joint request for an adder to the approved ROE. Under FERC regulations, transmission owners that are part of a Regional Transmission Organization (RTO) such as MISO are authorized to earn an incentive of 50 basis points above the FERC approved ROE. The FERC deferred the implementation of this adder until the pending complaint is resolved. Once the FERC sets a new ROE in the complaint case, this adder will be applied to that ROE, with retroactive billing to occur back to January 7, 2015. |
Environmental_Matters
Environmental Matters | 12 Months Ended |
Dec. 31, 2014 | |
Environmental Matters Disclosure [Abstract] | |
Environmental Matters | Environmental Matters |
Indiana Senate Bill 251 | |
Indiana Senate Bill 251 is also applicable to federal environmental mandates impacting SIGECO electric operations. The Company continues with its ongoing evaluation of the impact Senate Bill 251 may have on its operations, including applicability of the stricter regulations the EPA is currently considering involving air quality, fly ash disposal, cooling tower intake facilities, waste water discharges, and greenhouse gases. These issues are further discussed below. | |
Air Quality | |
Cross-State Air Pollution Rule | |
In July 2011, the EPA finalized the Cross-State Air Pollution Rule (CSAPR). CSAPR was the EPA’s response to the US Court of Appeals for the District of Columbia’s (the Court) remand of the Clean Air Interstate Rule (CAIR). CAIR was originally established in 2005 as an allowance cap and trade program that required reductions from coal-burning power plants for NOX emissions beginning January 1, 2009 and SO2 emissions beginning January 1, 2010, with a second phase of reductions in 2015. In an effort to address the Court’s finding that CAIR did not adequately ensure attainment of pollutants in certain downwind states due to unlimited trading of SO2 and NOX allowances, CSAPR reduced the ability of facilities to meet emission reduction targets through allowance trading. CSAPR reductions were to be achieved with initial step reductions beginning January 1, 2012, and final compliance to be achieved in 2014. After a series of legal challenges, the United States Supreme Court upheld CSAPR in April 2014, and the EPA finalized a new deadline schedule for entities that must comply, with CSAPR’s first phase caps starting in 2015 and 2016, and the second phase in 2017. The Company is in full compliance with all requirements of CSAPR. | |
Mercury and Air Toxics (MATS) Rule | |
On December 21, 2011, the EPA finalized the utility MATS Rule. The MATS Rule sets emission limits for hazardous air pollutants for existing and new coal-fired power plants and identifies the following broad categories of hazardous air pollutants: mercury, non-mercury hazardous air pollutants (primarily arsenic, chromium, cobalt, and selenium), and acid gases (hydrogen cyanide, hydrogen chloride, and hydrogen fluoride). The rule imposes mercury emission limits for two sub-categories of coal and proposed surrogate limits for non-mercury and acid gas hazardous air pollutants. Reductions are to be achieved within three years of publication of the final rule in the Federal Register (April 2015). The EPA did not grant blanket compliance extensions but asserted that states have broad authority to grant one year extensions for individual electric generating units where potential reliability impacts have been demonstrated. Legal challenges to the MATS Rule continue. In July, a coalition of twenty-one states, including Indiana, filed a petition for certiorari with the U.S. Supreme Court seeking review of the decision of the appellate court. On November 25, 2014, the U.S. Supreme Court agreed to hear the case, with a decision expected later in 2015. | |
Notice of Violation for A.B. Brown Power Plant | |
The Company received a notice of violation (NOV) from the EPA in November 2011 pertaining to its A.B. Brown generating station. The NOV asserts that when the facility was equipped with Selective Catalytic Reduction (SCR) systems, the correct permits were not obtained or the best available control technology to control incidental sulfuric acid mist was not installed. The Company reached a settlement in principle with the EPA to resolve the NOV. That settlement was contemplated in the plan filed and approved by the IURC on January 28, 2015 in the SIGECO Electric Environmental Compliance Filing. | |
Information Request | |
SIGECO and Alcoa Generating Corporation (AGC), a subsidiary of ALCOA, own a 300 MW Unit 4 at the Warrick Power Plant as tenants in common. AGC and SIGECO also share equally in the cost of operation and output of the unit. In January 2013, AGC received an information request from the EPA under Section 114 of the Clean Air Act for historical operational information on the Warrick Power Plant. In April 2013, ALCOA filed a timely response to the information request. | |
Ozone NAAQS | |
On November 26, 2014, the U.S. EPA proposed to tighten the current National Ambient Air Quality Standard (NAAQS) for ozone from the current standard of 75 parts per billion (ppb) to a level with the range of 65 to 70 ppb. The EPA has stated that it intends to finalize the rule by October 2015. Upon finalization, the EPA will then determine whether a particular region is in attainment with the new standard. While it is possible that counties in southwest Indiana could be declared in non-attainment with the new standard, and thus may have an effect on future economic development activities in the Company's service territory, the Company does not anticipate any significant compliance cost impacts from the determination given its previous investment in SCR technology for NOx control on its units. | |
Water | |
Section 316(b) of the Clean Water Act requires that generating facilities use the “best technology available” (BTA) to minimize adverse environmental impacts on a body of water. More specifically, Section 316(b) is concerned with impingement and entrainment of aquatic species in once-through cooling water intake structures used at electric generating facilities. A final rule was issued by the EPA on May 19, 2014. The final rule does not mandate cooling water tower retrofits but requires a state level case by case assessment of BTA for each facility. The final rule lists seven presumptive technologies which would qualify as BTA. These technologies range from intake screen modifications to cooling water tower retrofits. Ecological and technology assessment studies must be completed prior to determining BTA for the Company’s facilities. To comply, the Company believes that capital investments will likely be in the range of $4 million to $8 million. Costs for compliance with these final regulations should qualify as federally mandated regulatory requirements and be recoverable under Indiana Senate Bill 251 referenced above. | |
Under the Clean Water Act, the EPA sets technology-based guidelines for water discharges from new and existing facilities. The EPA is currently in the process of revising the existing steam electric effluent limitation guidelines that set the technology-based water discharge limits for the electric power industry. The EPA is focusing its rulemaking on wastewater generated primarily by pollution control equipment necessitated by the comprehensive air regulations. The EPA released proposed rules on April 19, 2013 however the rule is not yet finalized. At this time, it is not possible to estimate what potential costs may be required to meet these new water discharge limits, however costs for compliance with these regulations should qualify as federally mandated regulatory requirements and be recoverable under Senate Bill 251 referenced above. | |
Conclusions Regarding Air and Water Regulations | |
To comply with Indiana’s implementation plan of the Clean Air Act, the Company obtained authority from the IURC to invest in clean coal technology. Using this authorization, the Company invested approximately $411 million starting in 2001 with the last equipment being placed into service on January 1, 2010. The pollution control equipment included SCR systems, fabric filters, and an SO2 scrubber at its generating facility that is jointly owned with AGC. SCR technology is the most effective method of reducing NOX emissions where high removal efficiencies are required and fabric filters control particulate matter emissions. The unamortized portion of the $411 million clean coal technology investment was included in rate base for purposes of determining SIGECO’s electric base rates approved in the latest base rate order obtained April 27, 2011. SIGECO’s coal-fired generating fleet is 100 percent scrubbed for SO2 and 90 percent controlled for NOX. | |
Utilization of the Company’s NOX and SO2 allowances can be impacted as regulations are revised and implemented. Most of these allowances were granted to the Company at zero cost; therefore, any reduction in carrying value that could result from future changes in regulations would be immaterial. | |
As noted previously, on January 28, 2015, the IURC issued an Order approving the Company’s request for approval of capital investments on its coal-fired generation units to comply with new EPA mandates related to mercury and air toxin standards effective in 2015 and to address an outstanding Notice of Violation (NOV) from the EPA. The total investment is estimated to be between $80 and $90 million, roughly half of which will be made to control mercury in both air and water emissions, and the remaining investment will be made to address the issues raised in the NOV proceeding on the increase in sulfur trioxide emissions. | |
Coal Ash Waste Disposal & Ash Ponds | |
In June 2010, the EPA issued proposed regulations affecting the management and disposal of coal combustion products, such as ash generated by the Company’s coal-fired power plants. The proposed rules more stringently regulate these byproducts and would likely increase the cost of operating or expanding existing ash ponds and the development of new ash ponds. The alternatives include regulating coal combustion by-products that are not being beneficially reused as hazardous waste. The EPA did not offer a preferred alternative, but took public comment on multiple alternative regulations. | |
In December 2014 the U.S. EPA released its final coal ash rule which regulates ash as non-hazardous material under Subtitle D of the Resource Conservation and Recovery Act (RCRA). At this time the final rule has not been published in the Federal Register and as such is not yet effective. Under the final rule the Company will be required to commence an enhanced groundwater monitoring program to determine whether its existing ash ponds must be closed or retrofitted with liners. The final rule allows beneficial reuse of ash and the Company will continue to beneficially reuse a majority of its ash. Legislation is currently being considered by Congress that would provide for enforcement of the federal program by states in lieu of citizen suits. | |
The Company originally estimated capital expenditures to comply with the alternatives in the proposal could be as much as $30 million, and such expenditures could exceed $100 million if the most stringent of the alternatives was selected. As the less stringent Subtitle D program was selected by U.S. EPA in the final rule, the Company expects capital expenditures to comply in the lower end of this range. Annual compliance costs could increase only slightly or be impacted by as much as $5 million. Costs for compliance with these regulations should qualify as federally mandated regulatory requirements and be recoverable under Senate Bill 251 referenced above. | |
Climate Change | |
In April 2007, the US Supreme Court determined that greenhouse gases (GHG's) meet the definition of "air pollutant" under the Clean Air Act and ordered the EPA to determine whether GHG emissions cause or contribute to air pollution that may reasonably be anticipated to endanger public health or welfare. The endangerment finding was finalized in December 2009, concluding that carbon emissions pose an endangerment to public health and the environment. | |
The EPA has finalized two sets of GHG regulations that apply to the Company’s generating facilities. In 2009, the EPA finalized a mandatory GHG emissions registry which requires the reporting of emissions. The EPA has also finalized a revision to the Prevention of Significant Deterioration (PSD) and Title V permitting rules which would require facilities that emit 75,000 tons or more of GHG's a year to obtain a PSD permit for new construction or a significant modification of an existing facility. The EPA's PSD and Title V permitting rules for GHG's were upheld by the US Court of Appeals for the District of Columbia, and in June 2014 the US Supreme Court upheld the regulations with respect to applicability to major sources such as coal-fired power plants that are required to hold PSD construction and Title V air operating permits for other criteria pollutants. | |
While the Company has no plans to invest in new coal-fired generation, there is also a rule making and related legal challenge involving new source performance standards for new construction. This rulemaking must be finalized and withstand legal scrutiny in order for the EPA to implement its proposed new source performance standards for existing units discussed below. | |
In July 2013, the President announced a Climate Action Plan, which calls on the EPA to finalize the rule for new construction expeditiously and by June 2015 finalize, New Source Performance Standards (NSPS) for GHG's for existing electric generating units which would apply to the Company's power plants. States must have their implementation plans to the EPA no later than June 2016. On June 2, 2014, the EPA proposed its rule for states to regulate CO2 emissions from existing electric generating units. The rule, when final, will require states to adopt plans that reduce CO2 emissions by 30 percent from 2005 levels by 2030. The EPA provided an extended time frame for public commentary to December 1, 2014. The proposal sets state-specific CO2 emission rate-based CO2 goals (measured in lb CO2/MWh) and guidelines for the development, submission and implementation of state plans to achieve the state goals. These state-specific goals are calculated based upon 2012 average emission rates aggregated for all fossil fuel-based units in the state. For Indiana, the proposal uses a 2012 emission rate of 1,923 lb CO2/MWh, and sets an interim goal of 1,607 lb CO2/MWh and a final emission goal of 1,531 lb CO2/MWh that must be met by 2030. Under this proposal, these CO2 emission rate goals do not apply directly to individual units, or generating systems. They instead are state goals. As such, the state must establish a framework that will guide how compliance will be met on a statewide basis. The state’s interim or “phase in” goal of 1,607 lb CO2/MWh must be met as averaged over a ten-year period (2020 - 2029) with progress toward this goal to be demonstrated for every two rolling calendar years starting in 2020, with the first report due in 2022. | |
Under the proposal all states have unique goals based upon each state’s mix of electric generating assets. The EPA is proposing a 20 percent reduction in Indiana’s total CO2 emission rate compared to 2012. At 20 percent Indiana’s CO2 emission rate reduction requirement is tied with West Virginia as the 9th lowest reduction requirement. This is due in part to the EPA’s attempt to recognize the existing generating resource mix in the state and take into account each state’s ability to cost effectively lower its CO2 emission rate through a portfolio approach including energy efficiency and renewables, improving power plant heat rates, and dispatching lower emitting fuel sources. Each state’s goals were set by taking 2012 emissions data and applying four “building blocks” of emission rate improvements that the EPA asserts can be achieved by that state. These four building blocks constitute the EPA’s determination of “Best System of Emission Reductions that has been adequately demonstrated,” which defines the EPA’s authority under § 111(d) for existing sources. When applied to each state, the portfolio approach leads to significant differences in requirements across state lines. With the exception of building block number 1 (heat rate improvement of 6 percent), other building blocks are tailored to individual states based upon each state’s existing generating mix and what the EPA concluded a state could reasonably accomplish to reduce its CO2 emission rate. The Company timely filed comments to the Clean Power Plan proposal on December 1, 2014. The State of Indiana also filed public comments, asking that the proposal be withdrawn. Despite having just been recently proposed and not expected to be finalized until summer of 2015, legal challenges to the EPA's proposal have begun. On July 31, 2014, litigation was filed by the state of Indiana and other parties challenging the rules which may delay the timing of approval of the various state plans. That litigation has been set for argument before the U.S. Court of Appeals for the D.C. circuit in April of 2015, with a decision expected later in the summer. | |
With respect to the state of Indiana, the four building blocks that support Indiana’s goal are as follows: | |
(1) Heat rate (HR) improvements of 6 percent (this is consistently applied to all states). | |
(2) Increasing the dispatch of existing natural gas baseload generation sources to 70 percent. | |
(3) Renewable energy portfolio requirements of 5 percent (interim) and 7 percent (final). | |
(4) Energy efficiency / DSM that results in reductions of 1.5 percent annually starting in 2020, ending at a sustained 11 percent by 2030. | |
Under the proposal, Indiana may choose to implement a program based upon an annual average emission rate target or convert that target rate to a comparable CO2 emission cap. Indiana is the 5th largest carbon emitter in the nation in tons of CO2 produced from electric generation. In 2013, Indiana’s electric utilities generated 105.6 million tons of CO2. The Company’s share of that total was 6.3 million, or less than 6 percent. Since 2005, the Company’s emissions of CO2 have declined 23 percent (on a tonnage basis). These reductions have come from the retirement of FB Culley Unit 1, expiration of municipal contracts, electric conservation and the addition of renewable generation and the installation of more efficient dense pack turbine technology. With respect to renewable generation, in 2008 and 2009, the Company executed long-term purchase power commitments for a total of 80 MW of wind energy. The Company currently has approximately 4 percent of its electricity being provided by clean energy sources due to the long-term wind contracts and landfill gas investment. With respect to CO2 emission rate, since 2005 the Company has lowered its CO2 emission rate (as measured in lbs CO2/MWh) from 1967 lbs CO2/MWh to 1922 lbs CO2/MWh, for a reduction of 3 percent. The Company’s CO2 emission rate of 1922 lbs/MWh is basically the same as the State’s average CO2 emission rate of 1923 lb CO2/MWh. | |
Impact of Legislative Actions & Other Initiatives is Unknown | |
If the regulations referenced above are finalized by the EPA, or if legislation requiring reductions in CO2 and other GHG's or legislation mandating a renewable energy portfolio standard is adopted, such regulation could substantially affect both the costs and operating characteristics of the Company’s fossil fuel generating plants and natural gas distribution businesses. At this time and in the absence of final legislation or rulemaking, compliance costs and other effects associated with reductions in GHG emissions or obtaining renewable energy sources remain uncertain. The Company has gathered preliminary estimates of the costs to control GHG emissions. A preliminary investigation demonstrated costs to comply would be significant, first with regard to operating expenses and later for capital expenditures as technology becomes available to control GHG emissions. However, these compliance cost estimates were based on highly uncertain assumptions, including allowance prices if a cap and trade approach were employed, and energy efficiency targets. As the EPA moves toward finalization of the NSPS for existing sources and the State of Indiana begins formulation of its state implementation plan, the Company will continue to remain engaged with the state to develop a plan for compliance and have more information to enable it to better assess potential compliance costs with a final regulation. Costs to purchase allowances that cap GHG emissions or expenditures made to control emissions or lower carbon emission rates should be considered a federally mandated cost of providing electricity, and as such, the Company believes such costs and expenditures should be recoverable from customers through Senate Bill 251 as referenced above or Senate Bill 29, which was used by the Company to recover its initial pollution control investments. | |
Manufactured Gas Plants | |
In the past, the Company operated facilities to manufacture natural gas. Given the availability of natural gas transported by pipelines, these facilities have not been operated for many years. Under current environmental laws and regulations, those that owned or operated these facilities may now be required to take remedial action if certain contaminants are found above the regulatory thresholds. | |
In the Indiana Gas service territory, the existence, location, and certain general characteristics of 26 gas manufacturing and storage sites have been identified for which the Company may have some remedial responsibility. A remedial investigation/feasibility study (RI/FS) was completed at one of the sites under an agreed order between Indiana Gas and the IDEM, and a Record of Decision was issued by the IDEM in January 2000. The remaining sites have been submitted to the IDEM's Voluntary Remediation Program (VRP). The Company has identified its involvement in five manufactured gas plant sites in SIGECO’s service territory, all of which are currently enrolled in the IDEM’s VRP. The Company is currently conducting some level of remedial activities, including groundwater monitoring at certain sites. | |
The Company has accrued the estimated costs for further investigation, remediation, groundwater monitoring, and related costs for the sites. While the total costs that may be incurred in connection with addressing these sites cannot be determined at this time, the Company has recorded cumulative costs that it has incurred or reasonably expects to incur totaling approximately $43.4 million ($23.2 million at Indiana Gas and $20.2 million at SIGECO). The estimated accrued costs are limited to the Company’s share of the remediation efforts and are therefore net of exposures of other potentially responsible parties (PRP). | |
With respect to insurance coverage, Indiana Gas has received approximately $20.8 million from all known insurance carriers under insurance policies in effect when these plants were in operation. Likewise, SIGECO has settlement agreements with all known insurance carriers and has received to date approximately $14.3 million of the expected $15.8 million in insurance recoveries. | |
The costs the Company expects to incur are estimated by management using assumptions based on actual costs incurred, the timing of expected future payments, and inflation factors, among others. While the Company’s utilities have recorded all costs which they presently expect to incur in connection with activities at these sites, it is possible that future events may require remedial activities which are not presently foreseen and those costs may not be subject to PRP or insurance recovery. As of December 31, 2014 and 2013, approximately $3.6 million and $5.7 million, respectively, of accrued, but not yet spent, costs are included in Other Liabilities related to the Indiana Gas and SIGECO sites. |
Fair_Value_Measurements
Fair Value Measurements | 12 Months Ended | ||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||
Fair Value Disclosures [Abstract] | |||||||||||||||||
Fair Value Measurements | Fair Value Measurements | ||||||||||||||||
The carrying values and estimated fair values using primarily Level 2 assumptions of the Company's other financial instruments follow: | |||||||||||||||||
At December 31, | |||||||||||||||||
2014 | 2013 | ||||||||||||||||
(In millions) | Carrying | Est. Fair | Carrying | Est. Fair | |||||||||||||
Amount | Value | Amount | Value | ||||||||||||||
Long-term debt | $ | 1,577.30 | $ | 1,754.50 | $ | 1,807.10 | $ | 1,895.20 | |||||||||
Short-term borrowings & notes payable | 156.4 | 156.4 | 68.6 | 68.6 | |||||||||||||
Cash & cash equivalents | 86.4 | 86.4 | 21.5 | 21.5 | |||||||||||||
For the balance sheets presented, 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 long-term debt are generally recovered in customer rates over the life of the refunding issue or over a 15-year period. Accordingly, any reacquisition would not be expected to have a material effect on the Company's results of operations. | |||||||||||||||||
Because of the nature of certain other investments and lack of a readily available market, it is not practical to estimate the fair value of these financial instruments at specific dates without considerable effort and cost. At December 31, 2014 and 2013, the fair value for these financial instruments was not estimated. The carrying value of these investments at December 31, 2014 and 2013 was approximately $10.4 million. |
Segment_Reporting
Segment Reporting | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Segment Reporting [Abstract] | |||||||||||||
Segment Reporting | Segment Reporting | ||||||||||||
The Company segregates its operations into three groups: 1) Utility Group, 2) Nonutility Group, and 3) Corporate and Other. | |||||||||||||
The Utility Group is comprised of Vectren Utility Holdings, Inc.’s operations, which consist of the Company’s regulated operations and other operations that provide information technology and other support services to those regulated operations. The Company segregates its regulated operations between a Gas Utility Services operating segment and an Electric Utility Services operating segment. The Gas Utility Services segment provides natural gas distribution and transportation services to nearly two-thirds of Indiana and to west central Ohio. The Electric Utility Services segment provides electric distribution services primarily to southwestern Indiana, and includes the Company’s power generating and wholesale power operations. Regulated operations supply natural gas and/or electricity to over one million customers. In total, the Utility Group is comprised of three operating segments: Gas Utility Services, Electric Utility Services, and Other operations. | |||||||||||||
The Nonutility Group has historically reported five operating segments: Infrastructure Services, Energy Services, Coal Mining, Energy Marketing, and Other Businesses. Results in the Coal Mining segment include the results and loss on sale of Vectren Fuels through August 29, 2014 when it exited the coal mining business through the sale of Vectren Fuels (see Note 6 for more details of this transaction). Additionally, ProLiance exited the energy marketing business in 2013. In its 2014 periodic reports, the Company reports the Energy Marketing segment information for 2013 and 2012, which is inclusive of the Company's share of the loss from operations and its share of the loss on sale as recorded by ProLiance Energy in 2013. Remaining assets in Energy Marketing relate to the investment in ProLiance Holdings, LLC as described in Note 7. | |||||||||||||
Corporate and Other includes unallocated corporate expenses such as advertising and charitable contributions, among other activities, that benefit the Company’s other operating segments. Net income is the measure of profitability used by management for all operations. Information related to the Company’s business segments is summarized as follows: | |||||||||||||
Year Ended December 31, | |||||||||||||
(In millions) | 2014 | 2013 | 2012 | ||||||||||
Revenues | |||||||||||||
Utility Group | |||||||||||||
Gas Utility Services | $ | 944.6 | $ | 810 | $ | 738.1 | |||||||
Electric Utility Services | 624.8 | 619.3 | 594.9 | ||||||||||
Other Operations | 38.3 | 38.1 | 40.1 | ||||||||||
Eliminations | (38.0 | ) | (37.8 | ) | (39.5 | ) | |||||||
Total Utility Group | 1,569.70 | 1,429.60 | 1,333.60 | ||||||||||
Nonutility Group | |||||||||||||
Infrastructure Services | 779 | 783.5 | 663.6 | ||||||||||
Energy Services | 129.8 | 91.3 | 117.7 | ||||||||||
Coal Mining | 234.3 | 292.8 | 235.8 | ||||||||||
Other Businesses | — | — | 0.5 | ||||||||||
Total Nonutility Group | 1,143.10 | 1,167.60 | 1,017.60 | ||||||||||
Eliminations, net of Corporate & Other Revenues | (101.1 | ) | (106.0 | ) | (118.4 | ) | |||||||
Consolidated Revenues | $ | 2,611.70 | $ | 2,491.20 | $ | 2,232.80 | |||||||
Profitability Measures - Net Income | |||||||||||||
Utility Group Net Income | |||||||||||||
Gas Utility Services | $ | 57 | $ | 55.7 | $ | 60 | |||||||
Electric Utility Services | 79.7 | 75.8 | 68 | ||||||||||
Other Operations | 11.7 | 10.3 | 10 | ||||||||||
Total Utility Group Net Income | 148.4 | 141.8 | 138 | ||||||||||
Nonutility Group Net Income (Loss) | |||||||||||||
Infrastructure Services | 43.1 | 49 | 40.5 | ||||||||||
Energy Services | (3.2 | ) | 1 | 5.7 | |||||||||
Coal Mining | (21.1 | ) | (16.0 | ) | (3.5 | ) | |||||||
Energy Marketing | — | (37.5 | ) | (17.6 | ) | ||||||||
Other Businesses | (0.8 | ) | (1.0 | ) | (3.4 | ) | |||||||
Total Nonutility Group Net Income (Loss) | 18 | (4.5 | ) | 21.7 | |||||||||
Corporate & Other Net Loss | 0.5 | (0.7 | ) | (0.7 | ) | ||||||||
Consolidated Net Income | $ | 166.9 | $ | 136.6 | $ | 159 | |||||||
Year Ended December 31, | |||||||||||||
(In millions) | 2014 | 2013 | 2012 | ||||||||||
Amounts Included in Profitability Measures | |||||||||||||
Depreciation & Amortization | |||||||||||||
Utility Group | |||||||||||||
Gas Utility Services | $ | 93.3 | $ | 90.5 | $ | 85.4 | |||||||
Electric Utility Services | 85.7 | 84 | 81.3 | ||||||||||
Other Operations | 24.1 | 21.9 | 23.3 | ||||||||||
Total Utility Group | 203.1 | 196.4 | 190 | ||||||||||
Nonutility Group | |||||||||||||
Infrastructure Services | 36.2 | 28.8 | 20.7 | ||||||||||
Energy Services | 3.9 | 1.7 | 1.9 | ||||||||||
Coal Mining | 29.9 | 50.8 | 41.8 | ||||||||||
Other Businesses | 0.3 | 0.1 | 0.2 | ||||||||||
Total Nonutility Group | 70.3 | 81.4 | 64.6 | ||||||||||
Consolidated Depreciation & Amortization | $ | 273.4 | $ | 277.8 | $ | 254.6 | |||||||
Interest Expense | |||||||||||||
Utility Group | |||||||||||||
Gas Utility Services | $ | 34.9 | $ | 30.6 | $ | 31.8 | |||||||
Electric Utility Services | 29 | 29.2 | 33.8 | ||||||||||
Other Operations | 2.7 | 5.2 | 5.9 | ||||||||||
Total Utility Group | 66.6 | 65 | 71.5 | ||||||||||
Nonutility Group | |||||||||||||
Infrastructure Services | 11.1 | 10.1 | 7.5 | ||||||||||
Energy Services | 1.3 | 0.6 | 0.4 | ||||||||||
Coal Mining | 7.5 | 9.8 | 11.5 | ||||||||||
Energy Marketing | — | 2.2 | 4.8 | ||||||||||
Other Businesses | 0.9 | 0.5 | 0.7 | ||||||||||
Total Nonutility Group | 20.8 | 23.2 | 24.9 | ||||||||||
Corporate & Other | (0.7 | ) | (0.3 | ) | (0.4 | ) | |||||||
Consolidated Interest Expense | $ | 86.7 | $ | 87.9 | $ | 96 | |||||||
Income Taxes | |||||||||||||
Utility Group | |||||||||||||
Gas Utility Services | $ | 35.7 | $ | 36.6 | $ | 39.1 | |||||||
Electric Utility Services | 48.1 | 48.3 | 46.4 | ||||||||||
Other Operations | (0.6 | ) | 0.4 | (0.2 | ) | ||||||||
Total Utility Group | 83.2 | 85.3 | 85.3 | ||||||||||
Nonutility Group | |||||||||||||
Infrastructure Services | 28.9 | 34.3 | 29.6 | ||||||||||
Energy Services | (7.8 | ) | (11.9 | ) | (9.0 | ) | |||||||
Coal Mining | (21.8 | ) | (14.6 | ) | (8.6 | ) | |||||||
Energy Marketing | — | (23.3 | ) | (11.7 | ) | ||||||||
Other Businesses | (0.3 | ) | (1.6 | ) | (2.0 | ) | |||||||
Total Nonutility Group | (1.0 | ) | (17.1 | ) | (1.7 | ) | |||||||
Corporate & Other | (1.1 | ) | (1.1 | ) | (1.1 | ) | |||||||
Consolidated Income Taxes | $ | 81.1 | $ | 67.1 | $ | 82.5 | |||||||
Year Ended December 31, | |||||||||||||
(In millions) | 2014 | 2013 | 2012 | ||||||||||
Capital Expenditures | |||||||||||||
Utility Group | |||||||||||||
Gas Utility Services | $ | 245.9 | $ | 150.5 | $ | 128.8 | |||||||
Electric Utility Services | 92.4 | 100 | 108.8 | ||||||||||
Other Operations | 23.3 | 25.8 | 16.2 | ||||||||||
Non-cash costs & changes in accruals | (10.9 | ) | (15.2 | ) | (7.8 | ) | |||||||
Total Utility Group | 350.7 | 261.1 | 246 | ||||||||||
Nonutility Group | |||||||||||||
Infrastructure Services | 54.1 | 79.2 | 53.7 | ||||||||||
Energy Services | 1.6 | 6.9 | 2.3 | ||||||||||
Coal Mining | 41.9 | 46.2 | 63.8 | ||||||||||
Total Nonutility Group | 97.6 | 132.3 | 119.8 | ||||||||||
Consolidated Capital Expenditures | $ | 448.3 | $ | 393.4 | $ | 365.8 | |||||||
At December 31, | |||||||||||||
(In millions) | 2014 | 2013 | |||||||||||
Assets | |||||||||||||
Utility Group | |||||||||||||
Gas Utility Services | $ | 2,605.10 | $ | 2,287.90 | |||||||||
Electric Utility Services | 1,659.30 | 1,679.00 | |||||||||||
Other Operations, net of eliminations | 163.7 | 173.9 | |||||||||||
Total Utility Group | 4,428.10 | 4,140.80 | |||||||||||
Nonutility Group | |||||||||||||
Infrastructure Services | 541.6 | 465.8 | |||||||||||
Energy Services | 87.1 | 63 | |||||||||||
Coal Mining | — | 433 | |||||||||||
Energy Marketing | 30.6 | 33.9 | |||||||||||
Other Businesses, net of eliminations and reclassifications | 89.2 | 34.9 | |||||||||||
Total Nonutility Group | 748.5 | 1,030.60 | |||||||||||
Corporate & Other | 658.1 | 828.1 | |||||||||||
Eliminations | (672.4 | ) | (896.9 | ) | |||||||||
Consolidated Assets | $ | 5,162.30 | $ | 5,102.60 | |||||||||
Additional_Balance_Sheet_Opera
Additional Balance Sheet & Operational Information | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Additional Balance Sheet and Operational Information [Abstract] | |||||||||||||
Additional Balance Sheet and Operational Information | Additional Balance Sheet & Operational Information | ||||||||||||
Inventories consist of the following: | |||||||||||||
At December 31, | |||||||||||||
(In millions) | 2014 | 2013 | |||||||||||
Gas in storage – at LIFO cost | $ | 40.5 | $ | 33.2 | |||||||||
Coal & oil for electric generation - at average cost | 33.8 | 16.5 | |||||||||||
Materials & supplies | 42.5 | 57.3 | |||||||||||
Nonutility coal - at LIFO cost | — | 26.2 | |||||||||||
Other | 1.7 | 1.2 | |||||||||||
Total inventories | $ | 118.5 | $ | 134.4 | |||||||||
Based on the average cost of gas purchased during December, the cost of replacing inventories carried at LIFO cost exceeded that carrying value at December 31, 2014 by approximately $3.0 million. Based on the average cost of gas purchase and coal produced during December, the cost of replacing inventories carried at LIFO cost exceeded that carrying value at December 31, 2013 by $8.5 million. | |||||||||||||
Prepayments & other current assets consist of the following: | |||||||||||||
At December 31, | |||||||||||||
(In millions) | 2014 | 2013 | |||||||||||
Prepaid gas delivery service | $ | 40.7 | $ | 32.9 | |||||||||
Deferred income taxes | 16.3 | 13.9 | |||||||||||
Prepaid taxes | 37.5 | 11.2 | |||||||||||
Other prepayments & current assets | 16.4 | 17.6 | |||||||||||
Total prepayments & other current assets | $ | 110.9 | $ | 75.6 | |||||||||
Investments in unconsolidated affiliates consist of the following: | |||||||||||||
At December 31, | |||||||||||||
(In millions) | 2014 | 2013 | |||||||||||
ProLiance Holdings, LLC | $ | 20.5 | $ | 20.8 | |||||||||
Other nonutility partnerships & corporations | 2.7 | 3 | |||||||||||
Other utility investments | 0.2 | 0.2 | |||||||||||
Total investments in unconsolidated affiliates | $ | 23.4 | $ | 24 | |||||||||
Other utility & corporate investments consist of the following: | |||||||||||||
At December 31, | |||||||||||||
(In millions) | 2014 | 2013 | |||||||||||
Cash surrender value of life insurance policies | $ | 32.3 | $ | 32.9 | |||||||||
Municipal bond | 3.1 | 3.4 | |||||||||||
Restricted cash & other investments | 1.8 | 1.8 | |||||||||||
Other utility & corporate investments | $ | 37.2 | $ | 38.1 | |||||||||
Goodwill by operating segment follows: | |||||||||||||
At December 31, | |||||||||||||
(In millions) | 2014 | 2013 | |||||||||||
Utility Group | |||||||||||||
Gas Utility Services | $ | 205 | $ | 205 | |||||||||
Nonutility Group | |||||||||||||
Infrastructure Services | 55.2 | 55.2 | |||||||||||
Energy Services | 29.7 | 2.1 | |||||||||||
Consolidated goodwill | $ | 289.9 | $ | 262.3 | |||||||||
Accrued liabilities consist of the following: | |||||||||||||
At December 31, | |||||||||||||
(In millions) | 2014 | 2013 | |||||||||||
Refunds to customers & customer deposits | $ | 51.3 | $ | 50.2 | |||||||||
Accrued taxes | 35.8 | 36.2 | |||||||||||
Accrued interest | 19.1 | 20 | |||||||||||
Deferred compensation & post-retirement benefits | 7.3 | 7.5 | |||||||||||
Accrued salaries & other | 71.4 | 68.2 | |||||||||||
Total accrued liabilities | $ | 184.9 | $ | 182.1 | |||||||||
Asset retirement obligations included in Deferred credits and other liabilities in the Consolidated Balance Sheets roll forward as follows: | |||||||||||||
(In millions) | 2014 | 2013 | |||||||||||
Asset retirement obligation, January 1 | $ | 41.3 | $ | 37.7 | |||||||||
Accretion | 1.7 | 2.2 | |||||||||||
Changes in estimates, net of cash payments | 23.8 | 1.4 | |||||||||||
Vectren Fuels Retirement Obligation | (11.8 | ) | — | ||||||||||
Asset retirement obligation, December 31 | 55 | 41.3 | |||||||||||
Equity in earnings (losses) of unconsolidated affiliates consists of the following: | |||||||||||||
Year Ended December 31, | |||||||||||||
(In millions) | 2014 | 2013 | 2012 | ||||||||||
ProLiance Holdings, LLC | $ | (0.3 | ) | $ | (57.7 | ) | $ | (22.7 | ) | ||||
Other | 0.8 | (2.0 | ) | (0.6 | ) | ||||||||
Total equity in earnings (losses) of unconsolidated affiliates | $ | 0.5 | $ | (59.7 | ) | $ | (23.3 | ) | |||||
Other income (expense) – net consists of the following: | |||||||||||||
Year Ended December 31, | |||||||||||||
(In millions) | 2014 | 2013 | 2012 | ||||||||||
AFUDC – borrowed funds | $ | 11.4 | $ | 5.9 | $ | 4.6 | |||||||
AFUDC – equity funds | 3.2 | 0.8 | 0.4 | ||||||||||
Nonutility plant capitalized interest | — | 0.5 | 1.8 | ||||||||||
Interest income, net | 1.1 | 1.1 | 1.1 | ||||||||||
Other nonutility investment impairment charges | (1.0 | ) | — | (2.7 | ) | ||||||||
Cash surrender value of life insurance policies | 2.8 | 4.8 | 1.8 | ||||||||||
All other income | 2.2 | 4.6 | 1.3 | ||||||||||
Total other income (expense) – net | $ | 19.7 | $ | 17.7 | $ | 8.3 | |||||||
Supplemental Cash Flow Information: | |||||||||||||
Year Ended December 31, | |||||||||||||
(In millions) | 2014 | 2013 | 2012 | ||||||||||
Cash paid (received) for: | |||||||||||||
Interest | $ | 87.5 | $ | 91 | $ | 94.6 | |||||||
Income taxes | 69.4 | 6.8 | 21.8 | ||||||||||
As of December 31, 2014 and 2013, the Company has accruals related to utility and nonutility plant purchases totaling approximately $20.2 million and $19.4 million, respectively. |
Impact_of_Recently_Issued_Acco
Impact of Recently Issued Accounting Guidance | 12 Months Ended |
Dec. 31, 2014 | |
New Accounting Pronouncements and Changes in Accounting Principles [Abstract] | |
Recently Issued Accounting Standards | Impact of Recently Issued Accounting Guidance |
Revenue Recognition Guidance | |
In May 2014, the FASB issued new accounting guidance to clarify the principles for recognizing revenue and to develop a common revenue standard for GAAP and IFRS. The amendments in this guidance state that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This new guidance requires improved disclosures to help users of financial statements better understand the nature, amount, timing, and uncertainty of revenue that is recognized. For a public entity, the guidance is effective for annual reporting periods beginning after December 15, 2016, with early adoption not permitted. An entity should apply the amendments in this update retrospectively to each prior reporting period presented or retrospectively with the cumulative effect of initially applying this update recognized at the date of initial application. The Company is currently evaluating the standard to understand the overall impact it will have on the financial statements. | |
Financial Reporting of Discontinued Operations | |
In April 2014, the FASB issued new accounting guidance on reporting discontinued operations and disclosures of disposals of a company or entity. The guidance changes the criteria for reporting discontinued operations and provides for enhanced disclosures in this area. Under the new guidance, only disposals representing a strategic shift in operations should be presented as discontinued operations. Those strategic shifts should have a major effect on the organization's operations and financial results. Additionally, the new guidance requires expanded disclosures about discontinued operations to provide more information about the assets, liabilities, income, and expenses of discontinued operations. The new guidance also requires disclosure of the pre-tax income attributable to a disposal of a significant part of an organization that does not qualify for discontinued operations reporting. This guidance is effective for fiscal years beginning on or after December 15, 2014, with early adoption permitted. The Company did not early adopt this guidance in accounting for the sale of its Coal Mining assets. The Company is currently evaluating the impact of this guidance, if any. | |
Accounting for Stock Compensation | |
In June 2014, the FASB issued new accounting guidance on accounting for share-based payments when the terms of an award provide that a performance target could be achieved after the requisite service period. These amendments provide explicit guidance on whether to treat a performance target that could be achieved after the requisite service period as a performance condition that affects vesting or as a non-vesting condition that affects the grant-date fair value of an award. This guidance is effective for annual periods and interim periods within those periods beginning after December 15, 2015, with early adoption permitted. The Company’s current practice for accounting for stock compensation follows the prescribed manner as suggested by the update. Adoption of this guidance will not have a material impact on the Company’s financial statements. | |
Financial Reporting of Going Concern | |
In August 2014, the FASB issued new accounting guidance with respect to reporting on an entity's ability to continue as a going concern. This new guidance requires management to assess an entity's ability to continue as a going concern by incorporating and expanding upon certain principles that are currently in U.S. auditing standards, which requires disclosure surrounding what constitutes substantial doubt for the entity, including disclosure of management's plans to mitigate and alleviate substantial doubt. This guidance is effective for annual periods beginning after December 15, 2016, and for annual and interim periods thereafter, with early application permitted. Adoption of this guidance will not have a material impact on the Company’s financial statements. |
Quarterly_Financial_Data_Unaud
Quarterly Financial Data (Unaudited) | 12 Months Ended | ||||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||||
Quarterly Financial Information Disclosure [Abstract] | |||||||||||||||||||
Quarterly Financial Data (Unaudited) | Quarterly Financial Data (Unaudited) | ||||||||||||||||||
Information in any one quarterly period is not indicative of annual results due to the seasonal variations common to the Company’s utility operations. Note that at June 30, 2014, the Company recorded an estimated loss on the transaction related to the Vectren Fuels sale to Sunrise Coal, including costs to sell, of approximately $32 million, or $20 million after tax. At June 18, 2013, the Company recorded its share of the loss related to ProLiance exiting the natural gas marketing business on the disposition, termination of long term pipeline and storage commitments, and related transaction and other costs totaling $43.6 million pre-tax, or $26.8 million net of tax. Summarized quarterly financial data for 2014 and 2013 follows: | |||||||||||||||||||
(In millions, except per share amounts) | Q1 | Q2 | Q3 | Q4 | |||||||||||||||
2014 | |||||||||||||||||||
Operating revenues | $ | 796.8 | $ | 542.5 | $ | 595.6 | $ | 676.8 | |||||||||||
Operating income | 99 | 33.9 | 84.5 | 97.1 | |||||||||||||||
Net income (loss) | 51.2 | 11.9 | 47.3 | 56.5 | |||||||||||||||
Earnings (loss) per share: | |||||||||||||||||||
Basic | $ | 0.62 | $ | 0.14 | $ | 0.57 | $ | 0.68 | |||||||||||
Diluted | 0.62 | 0.14 | 0.57 | 0.68 | |||||||||||||||
2013 | |||||||||||||||||||
Operating revenues | $ | 700.6 | $ | 531 | $ | 579.6 | $ | 680 | |||||||||||
Operating income | 106.8 | 57.9 | 83.3 | 85.6 | |||||||||||||||
Net income (loss) | 49.8 | (5.8 | ) | 42.8 | 49.8 | ||||||||||||||
Earnings (loss) per share: | |||||||||||||||||||
Basic | $ | 0.61 | $ | (0.07 | ) | $ | 0.52 | $ | 0.6 | ||||||||||
Diluted | 0.61 | (0.07 | ) | 0.52 | 0.6 | ||||||||||||||
SCHEDULE_II_VALUATION_AND_QUAL
SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES | 12 Months Ended | ||||||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||||||
Valuation and Qualifying Accounts [Abstract] | |||||||||||||||||||||
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES | SCHEDULE II | ||||||||||||||||||||
Vectren Corporation and Subsidiaries | |||||||||||||||||||||
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES | |||||||||||||||||||||
Column A | Column B | Column C | Column D | Column E | |||||||||||||||||
Additions | |||||||||||||||||||||
Balance at | Charged | Charged | Deductions | Balance at | |||||||||||||||||
Beginning | to | to Other | from | End of | |||||||||||||||||
Description | of Year | Expenses | Accounts | Reserves, Net | Year | ||||||||||||||||
(In millions) | |||||||||||||||||||||
VALUATION AND QUALIFYING ACCOUNTS: | |||||||||||||||||||||
Year 2014 – Accumulated provision for | |||||||||||||||||||||
uncollectible accounts | $ | 6.8 | $ | 7.3 | $ | — | $ | 8.1 | $ | 6 | |||||||||||
Year 2013 – Accumulated provision for | |||||||||||||||||||||
uncollectible accounts | $ | 6.8 | $ | 6.8 | $ | — | $ | 6.8 | $ | 6.8 | |||||||||||
Year 2012 – Accumulated provision for | |||||||||||||||||||||
uncollectible accounts | $ | 6.7 | $ | 8.2 | $ | — | $ | 8.1 | $ | 6.8 | |||||||||||
Year 2014 – Reserve for impaired | |||||||||||||||||||||
notes receivable | $ | 0.6 | $ | — | $ | — | $ | 0.6 | $ | — | |||||||||||
Year 2013 – Reserve for impaired | |||||||||||||||||||||
notes receivable | $ | 0.6 | $ | — | $ | — | $ | — | $ | 0.6 | |||||||||||
Year 2012 – Reserve for impaired | |||||||||||||||||||||
notes receivable | $ | 15.7 | $ | 0.5 | $ | — | $ | 15.6 | $ | 0.6 | |||||||||||
OTHER RESERVES: | |||||||||||||||||||||
Year 2014 - Restructuring costs | $ | 0.2 | $ | — | $ | — | $ | 0.2 | $ | — | |||||||||||
Year 2013 – Restructuring costs | $ | 0.3 | $ | — | $ | — | $ | 0.1 | $ | 0.2 | |||||||||||
Year 2012 – Restructuring costs | $ | 0.4 | $ | — | $ | — | $ | 0.1 | $ | 0.3 | |||||||||||
Summary_of_Significant_Account1
Summary of Significant Accounting Policies (Policies) | 12 Months Ended | |
Dec. 31, 2014 | ||
Accounting Policies [Abstract] | ||
Principles of Consolidation | Principles of Consolidation | |
The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries, after elimination of intercompany transactions. | ||
Subsequent Events Review | Subsequent Events Review | |
Management performs a review of subsequent events for any events occurring after the balance sheet date but prior to the date the financial statements are issued. | ||
Cash and Cash Equivalents | Cash & Cash Equivalents | |
All highly liquid investments with an original maturity of three months or less at the date of purchase are considered cash equivalents. Cash and cash equivalents are stated at cost plus accrued interest to approximate fair value. | ||
Allowance for Uncollectible Accounts | Allowance for Uncollectible Accounts | |
The Company maintains allowances for uncollectible accounts for estimated losses resulting from the inability of its customers to make required payments. The Company estimates the allowance for uncollectible accounts based on a variety of factors including the length of time receivables are past due, the financial health of its customers, unusual macroeconomic conditions, and historical experience. If the financial condition of its customers deteriorates or other circumstances occur that result in an impairment of customers’ ability to make payments, the Company records additional allowances as needed. | ||
Inventories | Inventories | |
In most circumstances, the Company’s inventory components are recorded using an average cost method; however, natural gas in storage at the Company’s Indiana utilities 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. Nonutility inventory is valued at the lower of cost or market. | ||
Property, Plant and Equipment | Property, Plant & Equipment | |
Both the Company’s Utility Plant and Nonutility Plant is stated at historical cost, inclusive of financing costs and direct and indirect construction costs, less accumulated depreciation and when necessary, impairment charges. The cost of renewals and betterments that extend the useful life are capitalized. Maintenance and repairs, including the cost of removal of minor items of property and planned major maintenance projects, are charged to expense as incurred. | ||
Utility Plant & Related Depreciation | ||
Both the IURC and PUCO allow the Company’s utilities to capitalize financing costs associated with Utility Plant based on a computed interest cost and a designated cost of equity funds. These financing costs are commonly referred to as AFUDC and are capitalized for ratemaking purposes and for financial reporting purposes instead of amounts that would otherwise be capitalized when acquiring nonutility plant. The Company reports both the debt and equity components of AFUDC in Other – net in the Consolidated Statements of Income. | ||
When property that represents a retirement unit is replaced or removed, the remaining historical value of such property is charged to Utility plant, with an offsetting charge to Accumulated depreciation, resulting in no gain or loss. Costs to dismantle and remove retired property are recovered through the depreciation rates as determined by the IURC and PUCO. | ||
The Company’s portion of jointly owned Utility plant, along with that plant’s related operating expenses, is presented in these financial statements in proportion to the ownership percentage. | ||
Nonutility Plant & Related Depreciation | ||
The depreciation of Nonutility plant is charged against income over its estimated useful life, using the straight-line method of depreciation. When nonutility property is retired, or otherwise disposed of, the asset and accumulated depreciation are removed, and the resulting gain or loss is reflected in income, typically impacting operating expenses. | ||
Impairment Reviews | ||
Property, plant and equipment along with other long-lived assets are reviewed as facts and circumstances indicate that the carrying amount may be impaired. This impairment review involves the comparison of an asset’s (or group of assets’) carrying value to the estimated future cash flows the asset (or asset group) is expected to generate over a remaining life. If this evaluation were to conclude that the carrying value is impaired, an impairment charge would be recorded based on the difference between the carrying amount and its fair value (less costs to sell for assets to be disposed of by sale) as a charge to operations or discontinued operations. During the year, the Company determined that a certain Energy Services asset's carrying value exceeded its net realizable value and thus was written down to zero, resulting in an after tax charge of $0.7 million. | ||
Investments in Unconsolidated Affiliates | Investments in Unconsolidated Affiliates | |
Investments in unconsolidated affiliates where the Company has significant influence are accounted for using the equity method of accounting. The Company’s share of net income or loss from these investments is recorded in Equity in (losses) of unconsolidated affiliates. Dividends are recorded as a reduction of the carrying value of the investment when received. Investments in unconsolidated affiliates where the Company does not have significant influence are accounted for using the cost method of accounting. Dividends associated with cost method investments are recorded as Other income – net when received. Investments are reviewed as facts and circumstances indicate that the carrying amount may be impaired. This impairment review involves the comparison of an investment's fair value to its carrying value. Investments, when necessary, include adjustments for declines in value judged to be other than temporary. | ||
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 that test is performed at the beginning of each year. Impairment reviews consist of a comparison of fair value to the carrying amount. If the fair value is less than the carrying amount, an impairment loss is recognized in operations. No goodwill impairments have been recorded during the periods presented. | ||
Specific to Energy Services, the Company performed a detailed analysis related to the carrying value of goodwill and other intangible assets recorded upon Energy Systems Group's acquisition of the federal sector energy services unit of Chevron Energy Solutions from Chevron, USA (Federal Business Unit or FBU). A triggering event resulted from the failure to sign sufficient sales orders by the contractually determined earn-out date of December 31, 2014. The failure to achieve the earn-out resulted in the reversal of the contingent consideration liability and was considered a triggering event for goodwill and intangible asset testing at December 31, 2014. The Company performed a detailed discounted cash flow analysis of the Energy Services operating segment using various revenue scenarios to understand the effects of the event on its sales and earnings forecast. As of December 31, 2014, the analysis indicates that there is no impairment related to the goodwill or other intangible assets recorded upon the acquisition of the FBU. The estimates used in the forecast scenarios are highly subjective and may differ materially from actual results. | ||
Regulation | Regulation | |
Retail public utility operations affecting Indiana customers are subject to regulation by the IURC, and retail public utility operations affecting Ohio customers are subject to regulation by the PUCO. The Company’s accounting policies give recognition to the ratemaking and accounting practices authorized by these agencies. | ||
Refundable or Recoverable Gas Costs & Cost of Fuel & Purchased Power | ||
All metered gas rates in Indiana contain a gas cost adjustment clause that allows the Company to charge for changes in the cost of purchased gas. Metered electric rates contain a fuel adjustment clause that allows for adjustment in charges for electric energy to reflect changes in the cost of fuel. The net energy cost of purchased power, subject to a variable benchmark based on NYMEX natural gas prices, is also recovered through regulatory proceedings. The Company records any under-or-over-recovery resulting from gas and fuel adjustment clauses each month in revenues. A corresponding asset or liability is recorded until the under-or-over-recovery is billed or refunded to utility customers. The cost of gas sold is charged to operating expense as delivered to customers, and the cost of fuel and purchased power for electric generation is charged to operating expense when consumed. | ||
Regulatory Assets & Liabilities | ||
Regulatory assets represent probable future revenues associated with certain incurred costs, which will be recovered from customers through the ratemaking process. Regulatory liabilities represent probable expenditures by the Company for removal costs or future reductions in revenues associated with amounts that are to be credited to customers through the ratemaking process. The Company continually assesses the recoverability of costs recognized as regulatory assets and liabilities and the ability to recognize new regulatory assets and liabilities associated with its regulated utility operations. Given the current regulatory environment in its jurisdictions, the Company believes such accounting is appropriate. | ||
The Company collects an estimated cost of removal of its utility plant through depreciation rates established in regulatory proceedings. The Company records amounts expensed in advance of payments as a Regulatory liability because the liability does not meet the threshold of an asset retirement obligation. | ||
Postretirement Obligations and Costs | Postretirement Obligations & Costs | |
The Company recognizes the funded status of its pension plans and postretirement plans on its balance sheet. The funded status of a defined benefit plan is its assets (if any) less its projected benefit obligation (PBO), which reflects service accrued to date and includes the impact of projected salary increases (for pay-related benefits). The funded status of a postretirement plan is its assets (if any) less its accumulated postretirement benefit obligation (APBO), which reflects accrued service to date. To the extent this obligation exceeds amounts previously recognized in the statement of income, the Company records a Regulatory asset for that portion related to its rate regulated utilities. To the extent that excess liability does not relate to a rate regulated utility, the offset is recorded as a reduction to equity in Accumulated other comprehensive income. | ||
The annual cost of all postretirement plans is recognized in operating expenses or capitalized to plant following the direct labor of current employees. Specific to pension plans, the Company uses the projected unit credit actuarial cost method to calculate service cost and the PBO. This method projects the present value of benefits at retirement and allocates that cost over the projected years of service. Annual service cost represents one year’s benefit accrual while the PBO represents benefits allocated to previously accrued service. For other postretirement plans, service cost is calculated by dividing the present value of a participant’s projected postretirement benefits into equal parts based upon the number of years between a participant’s hire date and first eligible retirement date. Annual service cost represents one year’s benefit accrual while the APBO represents benefit allocated to previously accrued service. To calculate the expected return on pension plan assets, the Company uses the plan assets’ market-related value and an expected long-term rate of return. For the majority of the Company’s pension plans, the fair market value of the assets at the balance sheet date is adjusted to a market-related value by recognizing the change in fair value experienced in a given year ratably over a five-year period. Interest cost represents the annual accretion of the PBO and APBO at the discount rate. Actuarial gains and losses outside of a corridor (equal to 10 percent of the greater of the benefit obligation and the market-related value of assets) are amortized over the expected future working lifetime of active participants (except for plans where almost all participants are inactive). Prior service costs related to plan changes are amortized over the expected future working lifetime (or to full eligibility date for postretirement plan other than pensions) of the active participants at the time of the amendment. | ||
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. | ||
Product Warranties, Performance Guarantees and Other Guarantees | Product Warranties, Performance Guarantees & Other Guarantees | |
Liabilities and expenses associated with product warranties and performance guarantees are recognized based on historical experience at the time the associated revenue is recognized. Adjustments are made as changes become reasonably estimable. The Company does not recognize the fair value of an obligation at inception for these guarantees because they are guarantees of the Company’s own performance and/or product installations. | ||
While not significant at December 31, 2014 or 2013, the Company does recognize the fair value of an obligation at the inception of a guarantee in certain circumstances. These circumstances would include executing certain indemnification agreements and guaranteeing operating lease residual values, the performance of a third party, or the indebtedness of a third party. | ||
Energy Contracts and Derivatives | Energy Contracts & Derivatives | |
The Company will periodically execute derivative contracts in the normal course of operations while buying and selling commodities to be used in operations, optimizing its generation assets, and managing risk. A derivative is recognized on the balance sheet as an asset or liability measured at its fair market value and the change in the derivative's fair market value is recognized currently in earnings unless specific hedge criteria are met. | ||
When an energy contract that is a derivative is designated and documented as a normal purchase or normal sale (NPNS), it is exempted from mark-to-market accounting. Most energy contracts executed by the Company are subject to the NPNS exclusion or are not considered derivatives. Such energy contracts include Real Time and Day Ahead purchase and sale contracts with the MISO, natural gas purchases, and wind farm and other electric generating contracts. | ||
When the Company engages in energy contracts and financial contracts that are derivatives and are not subject to the NPNS or other exclusions, such contracts are recorded at market value as current or noncurrent assets or liabilities depending on their value and on when the contracts are expected to be settled. Contracts and any associated collateral with counter-parties subject to master netting arrangements are presented net in the Consolidated Balance Sheets. The offset resulting from carrying the derivative at fair value on the balance sheet is charged to earnings unless it qualifies as a hedge or is subject to regulatory accounting treatment. When hedge accounting is appropriate, the Company assesses and documents hedging relationships between the derivative contract and underlying risks as well as its risk management objectives and anticipated effectiveness. When the hedging relationship is highly effective, derivatives are designated as hedges. The market value of the effective portion of the hedge is marked to market in Accumulated other comprehensive income for cash flow hedges. Ineffective portions of hedging arrangements are marked to market through earnings. For fair value hedges, both the derivative and the underlying hedged item are marked to market through earnings. The offset to contracts affected by regulatory accounting treatment are marked to market as a regulatory asset or liability. Market value for derivative contracts is determined using quoted market prices from independent sources. The Company rarely enters into contracts that have a significant impact to the financial statements where internal models are used to calculate fair value. As of and for the periods presented, related derivative activity is not material to these financial statements. | ||
Income Taxes | Income Taxes | |
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. | ||
Revenues | Revenues | |
Most revenues are recognized as products and services are delivered to customers. Some nonutility revenues are recognized using the percentage of completion method. The Company records revenues for services and goods delivered but not billed at the end of an accounting period in Accrued unbilled revenues. The goods and services delivered by the Company subject to unbilled revenue accruals include gas, electricity, energy services, and infrastructure services. | ||
MISO Transactions | MISO Transactions | |
With the IURC’s approval, the Company is a member of the MISO, a FERC approved regional transmission organization. The MISO serves the electrical transmission needs of much of the Midcontinent region and maintains operational control over the Company’s electric transmission facilities as well as that of other utilities in the region. The Company is an active participant in the MISO energy markets, bidding its owned generation into the Day Ahead and Real Time markets and procuring power for its retail customers at Locational Marginal Pricing (LMP) as determined by the MISO market. | ||
MISO-related purchase and sale transactions are recorded using settlement information provided by MISO. These purchase and sale transactions are accounted for on a net hourly position. Net purchases in a single hour are recorded in Cost of fuel & purchased power and net sales in a single hour are recorded in Electric utility revenues. On occasion, prior period transactions are resettled outside the routine process due to a change in 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. | ||
Share-Based Compensation | Share-Based Compensation | |
The Company grants share-based awards to certain employees and board members. Liability classified share-based compensation awards are re-measured at the end of each period based on their expected settlement date fair value. Equity classified share-based compensation awards are measured at the grant date, based on the fair value of the award. Expense associated with share-based awards is recognized over the requisite service period, which generally begins on the date the award is granted through the earlier of the date the award vests or the date the employee becomes retirement eligible. | ||
Excise and Utility Receipts Taxes | Excise & Utility Receipts Taxes | |
Excise taxes and a portion of utility receipts taxes are included in rates charged to customers. Accordingly, the Company records these taxes received as a component of operating revenues, which totaled $32.3 million in 2014, $29.6 million in 2013, and $26.9 million in 2012. Expense associated with excise and utility receipts taxes are recorded as a component of Taxes other than income taxes. | ||
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 has three operating segments within its Utility Group, four operating segments in its Nonutility Group, and a Corporate and Other segment. | ||
Fair Value Measurements | Fair Value Measurements | |
Certain assets and liabilities are valued and/or disclosed at fair value. Financial assets include securities held in trust by the Company’s pension plans. 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 that the Company has the ability to access. | |
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 need to maximize the use of observable inputs and minimize the use of unobservable inputs. |
Utility_Nonutility_Plant_Table
Utility & Nonutility Plant (Tables) | 12 Months Ended | ||||||||||||||
Dec. 31, 2014 | |||||||||||||||
Property, Plant and Equipment [Abstract] | |||||||||||||||
Cost of Utility Plant, together with depreciation rates expressed as a percentage of original costs | The original cost of Utility plant, together with depreciation rates expressed as a percentage of original cost, follows: | ||||||||||||||
At December 31, | |||||||||||||||
(In millions) | 2014 | 2013 | |||||||||||||
Original Cost | Depreciation | Original Cost | Depreciation | ||||||||||||
Rates as a | Rates as a | ||||||||||||||
Percent of | Percent of | ||||||||||||||
Original Cost | Original Cost | ||||||||||||||
Gas utility plant | $ | 3,011.00 | 3.4 | % | $ | 2,762.20 | 3.5 | % | |||||||
Electric utility plant | 2,602.50 | 3.3 | % | 2,519.80 | 3.3 | % | |||||||||
Common utility plant | 54.3 | 3.2 | % | 53.4 | 3 | % | |||||||||
Construction work in progress | 50.9 | — | 54.2 | — | |||||||||||
Total original cost | $ | 5,718.70 | $ | 5,389.60 | |||||||||||
Nonutility Plant, Net of Depreciation and Amortization | Nonutility plant, net of accumulated depreciation and amortization follows: | ||||||||||||||
At December 31, | |||||||||||||||
(In millions) | 2014 | 2013 | |||||||||||||
Coal mine development costs & equipment | $ | — | $ | 242 | |||||||||||
Computer hardware & software | 106.1 | 102.7 | |||||||||||||
Land & buildings | 72.1 | 129.3 | |||||||||||||
Vehicles & equipment | 182.7 | 165.2 | |||||||||||||
All other | 17.1 | 18 | |||||||||||||
Nonutility plant - net | $ | 378 | $ | 657.2 | |||||||||||
Regulatory_Assets_Liabilities_
Regulatory Assets & Liabilities (Tables) | 12 Months Ended | ||||||||
Dec. 31, 2014 | |||||||||
Regulatory Assets and Liabilities Disclosure [Abstract] | |||||||||
Schedule of Regulatory Assets | Regulatory assets consist of the following: | ||||||||
At December 31, | |||||||||
(In millions) | 2014 | 2013 | |||||||
Future amounts recoverable from ratepayers related to: | |||||||||
Benefit obligations (See Note 11) | $ | 105.3 | $ | 57.1 | |||||
Net deferred income taxes (See Note 10) | (14.8 | ) | (5.8 | ) | |||||
Asset retirement obligations & other | — | 2.4 | |||||||
90.5 | 53.7 | ||||||||
Amounts deferred for future recovery related to: | |||||||||
Deferred coal costs (See Note 19) | — | 42.4 | |||||||
Cost recovery riders & other | 33.3 | 18.6 | |||||||
33.3 | 61 | ||||||||
Amounts currently recovered in customer rates related to: | |||||||||
Unamortized debt issue costs & hedging proceeds | 33.5 | 34.6 | |||||||
Demand side management programs | 0.6 | 2.5 | |||||||
Indiana authorized trackers | 25.6 | 30.8 | |||||||
Deferred coal costs (See Note 19) | 35.3 | — | |||||||
Ohio authorized trackers | 12.7 | 7.9 | |||||||
Premiums paid to reacquire debt | 1.7 | 2.2 | |||||||
Other base rate recoveries | 0.4 | 0.7 | |||||||
109.8 | 78.7 | ||||||||
Total regulatory assets | $ | 233.6 | $ | 193.4 | |||||
Federal_Business_Unit_Acquisit1
Federal Business Unit Acquisition Federal Business Unit Acquisition (Tables) | 12 Months Ended | |||
Dec. 31, 2014 | ||||
Business Combinations [Abstract] | ||||
Schedule of Business Acquisitions, by Acquisition [Table Text Block] | The following table summarizes the allocation of the purchase price to the fair value of the assets acquired and liabilities assumed as of April 1, 2014. | |||
(In millions) | ||||
Adjusted Net Working Capital | $ | 2.2 | ||
Depreciable Fixed Assets | 0.4 | |||
Customer Relationships (Sales Funnel) | 7.1 | |||
ESPC Licenses | 6 | |||
Deferred Tax Asset | 0.8 | |||
Goodwill | 27.7 | |||
Total Assets acquired | 44.2 | |||
Less: Unfavorable Contract Liabilities Assumed | (2.1 | ) | ||
Total Purchase Consideration | 42.1 | |||
Investment_in_ProLiance_Holdin1
Investment in ProLiance Holdings, LLC (Tables) | 12 Months Ended | |||
Dec. 31, 2014 | ||||
Equity Method Investments and Joint Ventures [Abstract] | ||||
Summarized Financial Information of Equity Investment [Table Text Block] | The Company's remaining investment in ProLiance at December 31, 2014, shown at its 61 percent ownership share, is as follows and reflects that it relates primarily to ProLiance's investment in LA Storage, LLC (LA Storage) discussed below. | |||
As of | ||||
December 31, | ||||
(In millions) | 2014 | |||
Cash | $ | 4.8 | ||
Investment in LA Storage | 21.6 | |||
Other midstream asset investment | 4.2 | |||
Total investment in ProLiance | $ | 30.6 | ||
Included in: | ||||
Investments in unconsolidated affiliates | 20.5 | |||
Other nonutility investments | 10.1 | |||
Nonutility_Real_Estate_Other_L1
Nonutility Real Estate & Other Legacy Holdings (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Nonutility Real Estate Other Legacy Holdings [Abstract] | |||||||||||||
Investment by type of investment | Further separation of that 2014 investment by type of investment follows: | ||||||||||||
December 31, 2014 | |||||||||||||
Value Included In | |||||||||||||
(In millions) | Carrying | Other Nonutility Investments | Investments in Unconsolidated Affiliates | ||||||||||
Value | |||||||||||||
Commercial real estate investment | $ | 8 | $ | 8 | $ | — | |||||||
Leveraged lease | 15.2 | 15.2 | — | ||||||||||
Other investments | 1.8 | 0.2 | 1.6 | ||||||||||
$ | 25 | $ | 23.4 | $ | 1.6 | ||||||||
Intangible_Assets_Tables
Intangible Assets (Tables) | 12 Months Ended | ||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||
Goodwill and Intangible Assets Disclosure [Abstract] | |||||||||||||||||
Intangible Assets | Intangible assets, which are included in Other assets, consist of the following: | ||||||||||||||||
(In millions) | At December 31, | ||||||||||||||||
2014 | 2013 | ||||||||||||||||
Amortizing | Non-amortizing | Amortizing | Non-amortizing | ||||||||||||||
Customer-related assets | $ | 22.5 | $ | — | $ | 17.4 | $ | — | |||||||||
Market-related assets | 1.1 | 13 | 1.9 | 7 | |||||||||||||
Intangible assets, net | $ | 23.6 | $ | 13 | $ | 19.3 | $ | 7 | |||||||||
Income_Taxes_Tables
Income Taxes (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Income Tax Disclosure [Abstract] | |||||||||||||
Reconciliation of the federal statutory rate to the effective income tax rate | A reconciliation of the federal statutory rate to the effective income tax rate follows: | ||||||||||||
Year Ended December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
Statutory rate: | 35 | % | 35 | % | 35 | % | |||||||
State & local taxes-net of federal benefit | 4.1 | 4.6 | 4 | ||||||||||
Amortization of investment tax credit | (0.3 | ) | (0.3 | ) | (0.3 | ) | |||||||
Depletion | (2.6 | ) | (1.5 | ) | (1.5 | ) | |||||||
Domestic production deduction | (1.1 | ) | — | — | |||||||||
Energy efficiency building deductions | (1.6 | ) | (3.8 | ) | (3.0 | ) | |||||||
Other tax credits | (0.2 | ) | (1.1 | ) | (0.1 | ) | |||||||
Adjustment of income tax accruals and all other-net | (0.6 | ) | 0.1 | 0.1 | |||||||||
Effective tax rate | 32.7 | % | 33 | % | 34.2 | % | |||||||
Significant components of the net deferred tax liability (assets) | Significant components of the net deferred tax liability follow: | ||||||||||||
At December 31, | |||||||||||||
(In millions) | 2014 | 2013 | |||||||||||
Noncurrent deferred tax liabilities (assets): | |||||||||||||
Depreciation & cost recovery timing differences | $ | 757.9 | $ | 725.2 | |||||||||
Leveraged lease | 9.8 | 10.4 | |||||||||||
Regulatory assets recoverable through future rates | 29.2 | 22.8 | |||||||||||
Alternative minimum tax carryforward | (13.3 | ) | (23.5 | ) | |||||||||
Employee benefit obligations | (14.5 | ) | (6.7 | ) | |||||||||
Net operating loss & other carryforwards | (2.0 | ) | (1.2 | ) | |||||||||
Regulatory liabilities to be settled through future rates | (27.5 | ) | (18.7 | ) | |||||||||
Impairments | (5.6 | ) | (6.2 | ) | |||||||||
Other – net | 7.2 | 5.3 | |||||||||||
Net noncurrent deferred tax liability | 741.2 | 707.4 | |||||||||||
Current deferred tax liabilities (assets): | |||||||||||||
Deferred fuel costs-net | 22 | 22.9 | |||||||||||
Alternative minimum tax carryforward | (38.1 | ) | (33.7 | ) | |||||||||
Net operating loss & other carryforwards | — | (4.9 | ) | ||||||||||
Other – net | (0.2 | ) | 1.8 | ||||||||||
Net current deferred tax liability (asset) | (16.3 | ) | (13.9 | ) | |||||||||
Net deferred tax liability | $ | 724.9 | $ | 693.5 | |||||||||
Components of income tax expense and utilization of investment tax credits | The components of income tax expense and utilization of investment tax credits follow: | ||||||||||||
Year Ended December 31, | |||||||||||||
(In millions) | 2014 | 2013 | 2012 | ||||||||||
Current: | |||||||||||||
Federal | $ | 24.7 | $ | 12.4 | $ | (8.2 | ) | ||||||
State | 18.5 | 11.4 | 6.4 | ||||||||||
Total current taxes | 43.2 | 23.8 | (1.8 | ) | |||||||||
Deferred: | |||||||||||||
Federal | 42.7 | 43.4 | 80.3 | ||||||||||
State | (4.2 | ) | 0.5 | 4.6 | |||||||||
Total deferred taxes | 38.5 | 43.9 | 84.9 | ||||||||||
Amortization of investment tax credits | (0.6 | ) | (0.6 | ) | (0.6 | ) | |||||||
Total income tax expense | $ | 81.1 | $ | 67.1 | $ | 82.5 | |||||||
Roll forward of unrecognized tax benefits | Following is a roll forward of unrecognized tax benefits for the three years ended December 31, 2014: | ||||||||||||
(In millions) | 2014 | 2013 | 2012 | ||||||||||
Unrecognized tax benefits at January 1 | $ | 5.9 | $ | 4.8 | $ | 12.4 | |||||||
Gross increases - tax positions in prior periods | 0.2 | — | 0.2 | ||||||||||
Gross decreases - tax positions in prior periods | (4.8 | ) | (0.2 | ) | (9.4 | ) | |||||||
Gross increases - current period tax positions | — | 1.2 | 1.9 | ||||||||||
Settlements | — | — | (0.3 | ) | |||||||||
Lapse of statute of limitations | (0.2 | ) | 0.1 | — | |||||||||
Unrecognized tax benefits at December 31 | $ | 1.1 | $ | 5.9 | $ | 4.8 | |||||||
Retirement_Plans_Other_Postret1
Retirement Plans & Other Postretirement Benefits (Tables) | 12 Months Ended | ||||||||||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||||||||||
Compensation and Retirement Disclosure [Abstract] | |||||||||||||||||||||||||
Summary of components of net periodic benefit cost | A summary of the components of net periodic benefit cost for the three years ended December 31, 2014 follows: | ||||||||||||||||||||||||
Pension Benefits | Other Benefits | ||||||||||||||||||||||||
(In millions) | 2014 | 2013 | 2012 | 2014 | 2013 | 2012 | |||||||||||||||||||
Service cost | $ | 7.4 | $ | 8.6 | $ | 7.7 | $ | 0.4 | $ | 0.5 | $ | 0.5 | |||||||||||||
Interest cost | 15.5 | 14.7 | 15.5 | 2.3 | 2 | 2.8 | |||||||||||||||||||
Expected return on plan assets | (22.7 | ) | (22.1 | ) | (21.2 | ) | — | — | — | ||||||||||||||||
Amortization of prior service cost (benefit) | 1 | 1.5 | 1.6 | (3.0 | ) | (3.2 | ) | (2.5 | ) | ||||||||||||||||
Amortization of actuarial loss | 5 | 10.1 | 6.8 | 0.4 | 0.7 | 0.7 | |||||||||||||||||||
Amortization of transitional obligation | — | — | — | — | — | 0.5 | |||||||||||||||||||
Settlement charge | 3.1 | 1.3 | — | — | — | — | |||||||||||||||||||
Net periodic benefit cost | $ | 9.3 | $ | 14.1 | $ | 10.4 | $ | 0.1 | $ | — | $ | 2 | |||||||||||||
Schedule of assumptions used | The weighted averages of significant assumptions used to determine net periodic benefit costs follow: | ||||||||||||||||||||||||
Pension Benefits | Other Benefits | ||||||||||||||||||||||||
2014 | 2013 | 2012 | 2014 | 2013 | 2012 | ||||||||||||||||||||
Discount rate | 4.74 | % | 4.03 | % | 4.82 | % | 4.66 | % | 3.91 | % | 4.75 | % | |||||||||||||
Rate of compensation increase | 3.5 | % | 3.5 | % | 3.5 | % | N/A | N/A | N/A | ||||||||||||||||
Expected return on plan assets | 7.75 | % | 7.75 | % | 7.75 | % | N/A | N/A | N/A | ||||||||||||||||
Expected increase in Consumer Price Index | N/A | N/A | N/A | 2.75 | % | 2.75 | % | 2.75 | % | ||||||||||||||||
The benefit obligation as of December 31, 2014 and 2013 was calculated using the following weighted average assumptions: | |||||||||||||||||||||||||
Pension Benefits | Other Benefits | ||||||||||||||||||||||||
2014 | 2013 | 2014 | 2013 | ||||||||||||||||||||||
Discount rate | 4.05 | % | 4.74 | % | 3.95 | % | 4.66 | % | |||||||||||||||||
Rate of compensation increase | 3.5 | % | 3.5 | % | N/A | N/A | |||||||||||||||||||
Expected increase in Consumer Price Index | N/A | N/A | 2.5 | % | 2.75 | % | |||||||||||||||||||
Schedule of changes in projected benefit obligations | A reconciliation of the Company’s benefit obligations at December 31, 2014 and 2013 follows: | ||||||||||||||||||||||||
Pension Benefits | Other Benefits | ||||||||||||||||||||||||
(In millions) | 2014 | 2013 | 2014 | 2013 | |||||||||||||||||||||
Benefit obligation, beginning of period | $ | 338.4 | $ | 377.3 | $ | 51.3 | $ | 54.4 | |||||||||||||||||
Service cost – benefits earned during the period | 7.4 | 8.6 | 0.4 | 0.5 | |||||||||||||||||||||
Interest cost on projected benefit obligation | 15.5 | 14.7 | 2.3 | 2 | |||||||||||||||||||||
Plan participants' contributions | — | — | 0.9 | 0.8 | |||||||||||||||||||||
Plan amendments | — | — | — | (0.2 | ) | ||||||||||||||||||||
Actuarial loss (gain) | 48.5 | (32.7 | ) | 3.2 | (2.4 | ) | |||||||||||||||||||
Settlement loss | 1.7 | 1.5 | — | — | |||||||||||||||||||||
Medicare subsidy receipts | — | — | — | — | |||||||||||||||||||||
Benefit payments | (25.3 | ) | (22.8 | ) | (4.8 | ) | (3.8 | ) | |||||||||||||||||
Settlement payments | (14.3 | ) | (8.2 | ) | — | — | |||||||||||||||||||
Benefit obligation, end of period | $ | 371.9 | $ | 338.4 | $ | 53.3 | $ | 51.3 | |||||||||||||||||
Schedule of changes in fair value of plan assets | A reconciliation of the Company’s plan assets at December 31, 2014 and 2013 follows: | ||||||||||||||||||||||||
Pension Benefits | Other Benefits | ||||||||||||||||||||||||
(In millions) | 2014 | 2013 | 2014 | 2013 | |||||||||||||||||||||
Plan assets at fair value, beginning of period | $ | 323.9 | $ | 295.7 | $ | — | $ | — | |||||||||||||||||
Actual return on plan assets | 20.1 | 48.4 | — | — | |||||||||||||||||||||
Employer contributions | 1.2 | 10.8 | 3.9 | 3 | |||||||||||||||||||||
Plan participants' contributions | — | — | 0.9 | 0.8 | |||||||||||||||||||||
Benefit payments | (25.3 | ) | (22.8 | ) | (4.8 | ) | (3.8 | ) | |||||||||||||||||
Settlement payments | (14.3 | ) | (8.2 | ) | — | — | |||||||||||||||||||
Fair value of plan assets, end of period | $ | 305.6 | $ | 323.9 | $ | — | $ | — | |||||||||||||||||
Fair values of pension and other retirement plan assets by category and fair value hierarchy | The fair values of the Company’s pension and other retirement plan assets at December 31, 2014 and December 31, 2013 by asset category and by fair value hierarchy are as follows: | ||||||||||||||||||||||||
As of December 31, 2014 | |||||||||||||||||||||||||
(In millions) | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||||||
Domestic equities & equity funds | $ | 62.8 | $ | 87.3 | $ | — | $ | 150.1 | |||||||||||||||||
International equities & equity funds | 38.4 | — | — | 38.4 | |||||||||||||||||||||
Domestic bonds & bond funds | 38.8 | 47.1 | — | 85.9 | |||||||||||||||||||||
Inflation protected security fund | — | 11.1 | — | 11.1 | |||||||||||||||||||||
Real estate, commodities & other | 5.8 | 10.1 | 4.2 | 20.1 | |||||||||||||||||||||
Total plan investments | $ | 145.8 | $ | 155.6 | $ | 4.2 | $ | 305.6 | |||||||||||||||||
As of December 31, 2013 | |||||||||||||||||||||||||
(In millions) | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||||||
Domestic equities & equity funds | $ | 69.6 | $ | 85.6 | $ | — | $ | 155.2 | |||||||||||||||||
International equities & equity funds | 41.9 | — | — | 41.9 | |||||||||||||||||||||
Domestic bonds & bond funds | 40.4 | 55.4 | — | 95.8 | |||||||||||||||||||||
Inflation protected security fund | — | 12.1 | — | 12.1 | |||||||||||||||||||||
Real estate, commodities & other | 6.2 | 8.6 | 4.1 | 18.9 | |||||||||||||||||||||
Total plan investments | $ | 158.1 | $ | 161.7 | $ | 4.1 | $ | 323.9 | |||||||||||||||||
Schedule of effect of significant unobservable inputs, changes in plan assets | A roll forward of the fair value of the guaranteed annuity contract calculated using Level 3 valuation assumptions follows: | ||||||||||||||||||||||||
(In millions) | 2014 | 2013 | |||||||||||||||||||||||
Fair value, beginning of year | $ | 4.1 | $ | 3.9 | |||||||||||||||||||||
Unrealized gains related to | 0.1 | 0.2 | |||||||||||||||||||||||
investments still held at reporting date | |||||||||||||||||||||||||
Purchases, sales and settlements, net | — | — | |||||||||||||||||||||||
Fair value, end of year | $ | 4.2 | $ | 4.1 | |||||||||||||||||||||
Schedule of net funded status of plans | The funded status of the plans as of December 31, 2014 and 2013 follows: | ||||||||||||||||||||||||
Pension Benefits | Other Benefits | ||||||||||||||||||||||||
(In millions) | 2014 | 2013 | 2014 | 2013 | |||||||||||||||||||||
Qualified Plans | |||||||||||||||||||||||||
Benefit obligation, end of period | $ | (351.7 | ) | $ | (321.0 | ) | $ | (53.3 | ) | $ | (51.4 | ) | |||||||||||||
Fair value of plan assets, end of period | 305.6 | 323.9 | — | — | |||||||||||||||||||||
Funded Status of Qualified Plans, end of period | (46.1 | ) | 2.9 | (53.3 | ) | (51.4 | ) | ||||||||||||||||||
Benefit obligation of SERP Plan, end of period | (20.2 | ) | (17.5 | ) | — | — | |||||||||||||||||||
Total funded status, end of period | $ | (66.3 | ) | $ | (14.6 | ) | $ | (53.3 | ) | $ | (51.4 | ) | |||||||||||||
Accrued liabilities | $ | 1.2 | $ | 1 | $ | 4.6 | $ | 4.9 | |||||||||||||||||
Deferred credits & other liabilities | $ | 65.1 | $ | 20.1 | $ | 48.7 | $ | 46.4 | |||||||||||||||||
Other Assets | $ | — | $ | 6.5 | $ | — | $ | — | |||||||||||||||||
Schedule of net periodic benefit cost not yet recognized | Following is a roll forward of prior service cost, actuarial gains and losses, and transition obligations. | ||||||||||||||||||||||||
Pensions | Other Benefits | ||||||||||||||||||||||||
(In millions) | Prior | Net | Prior | Net | Transition Obligation | ||||||||||||||||||||
Service | Gain | Service | Gain | ||||||||||||||||||||||
Cost | or Loss | Cost | or Loss | ||||||||||||||||||||||
Balance at January 1, 2012 | $ | 5.4 | $ | 116.6 | $ | (1.2 | ) | $ | 9.1 | $ | 2.7 | ||||||||||||||
Amounts arising during the period | 0.7 | 26.4 | (24.4 | ) | 2.8 | (2.2 | ) | ||||||||||||||||||
Reclassification to benefit costs | (1.6 | ) | (6.8 | ) | 2.5 | (0.7 | ) | (0.5 | ) | ||||||||||||||||
Balance at December 31, 2012 | $ | 4.5 | $ | 136.2 | $ | (23.1 | ) | $ | 11.2 | $ | — | ||||||||||||||
Amounts arising during the period | — | (58.8 | ) | (0.2 | ) | (2.4 | ) | — | |||||||||||||||||
Reclassification to benefit costs | (1.5 | ) | (10.1 | ) | 3.2 | (0.7 | ) | — | |||||||||||||||||
Balance at December 31, 2013 | $ | 3 | $ | 67.3 | $ | (20.1 | ) | $ | 8.1 | $ | — | ||||||||||||||
Amounts arising during the period | — | 49.4 | — | 3.2 | — | ||||||||||||||||||||
Reclassification to benefit costs | (1.0 | ) | (5.0 | ) | 3 | (0.4 | ) | — | |||||||||||||||||
Balance at December 31, 2014 | $ | 2 | $ | 111.7 | $ | (17.1 | ) | $ | 10.9 | $ | — | ||||||||||||||
Reconciliation of the amounts in Accumulated other comprehensive income (AOCI) and Regulatory assets related to retirement plan obligations | Following is a reconciliation of the amounts in Accumulated other comprehensive income (AOCI) and Regulatory assets related to retirement plan obligations at December 31, 2014 and 2013. | ||||||||||||||||||||||||
(In millions) | 2014 | 2013 | |||||||||||||||||||||||
Pensions | Other Benefits | Pensions | Other Benefits | ||||||||||||||||||||||
Prior service cost | $ | 2 | $ | (17.1 | ) | $ | 3 | $ | (20.1 | ) | |||||||||||||||
Unamortized actuarial gain/(loss) | 111.7 | 10.9 | 67.3 | 8.1 | |||||||||||||||||||||
Transition obligation | — | — | — | — | |||||||||||||||||||||
113.7 | (6.2 | ) | 70.3 | (12.0 | ) | ||||||||||||||||||||
Less: Regulatory asset deferral | (111.4 | ) | 6.1 | (68.9 | ) | 11.8 | |||||||||||||||||||
AOCI before taxes | $ | 2.3 | $ | (0.1 | ) | $ | 1.4 | $ | (0.2 | ) | |||||||||||||||
Schedule of Multiemployer Contributions In Current Year [Table Text Block] | The multiemployer contributions listed in the table below are the Company's multiemployer contributions made in 2014, 2013, and 2012. | ||||||||||||||||||||||||
(In millions) | |||||||||||||||||||||||||
Pension Protection Act Zone Status | Multiemployer Contributions | ||||||||||||||||||||||||
Pension Fund | EIN/Pension Plan Number | 2014 | 2013 | FIP/RP Status Pending/Implemented | 2014 | 2013 | 2012 | Surcharge Imposed | |||||||||||||||||
Central Pension Fund | 36-6052390-001 | Green | Green | No | $7.70 | $8.50 | $4.00 | No | |||||||||||||||||
Pipeline Industry Benefit Fund | 73-0742835-001 | Green | Green | No | 5.1 | 5.3 | 3.9 | No | |||||||||||||||||
Indiana Laborers Pension Fund (1) | 35-6027150-001 | Yellow | Yellow | Implemented | 3.5 | 2.4 | 3.2 | No | |||||||||||||||||
Minnesota Laborers Pension Fund | 41-6159599-001 | Green | Green | No | 2.2 | 2.8 | 2 | No | |||||||||||||||||
Other | 13.9 | 14.2 | 14.5 | ||||||||||||||||||||||
Total Contributions | $32.40 | $33.20 | $27.60 |
Borrowing_Arrangements_Tables
Borrowing Arrangements (Tables) | 12 Months Ended | ||||||||||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||||||||||
Debt Disclosure [Abstract] | |||||||||||||||||||||||||
Short term borrowing arrangements | Following is certain information regarding these short-term borrowing arrangements. | ||||||||||||||||||||||||
Utility Group Borrowings | Nonutility Group Borrowings | ||||||||||||||||||||||||
(In millions) | 2014 | 2013 | 2012 | 2014 | 2013 | 2012 | |||||||||||||||||||
As of Year End | |||||||||||||||||||||||||
Balance Outstanding | $ | 156.4 | $ | 28.6 | $ | 116.7 | $ | — | $ | 40 | $ | 162.1 | |||||||||||||
Weighted Average Interest Rate | 0.5 | % | 0.29 | % | 0.4 | % | N/A | 1.27 | % | 1.35 | % | ||||||||||||||
Annual Average | |||||||||||||||||||||||||
Balance Outstanding | $ | 35.6 | $ | 119.6 | $ | 77.6 | $ | 34.5 | $ | 119.3 | $ | 151.5 | |||||||||||||
Weighted Average Interest Rate | 0.34 | % | 0.34 | % | 0.47 | % | 1.29 | % | 1.35 | % | 1.44 | % | |||||||||||||
Maximum Month End Balance Outstanding | $ | 156.4 | $ | 176.1 | $ | 214.2 | $ | 76.3 | $ | 173.8 | $ | 216.1 | |||||||||||||
Long term senior unsecured obligations and first mortgage bonds outstanding by subsidiary | Long-term senior unsecured obligations and first mortgage bonds outstanding by subsidiary follow: | ||||||||||||||||||||||||
At December 31, | |||||||||||||||||||||||||
(In millions) | 2014 | 2013 | |||||||||||||||||||||||
Utility Holdings | |||||||||||||||||||||||||
Fixed Rate Senior Unsecured Notes | |||||||||||||||||||||||||
2015, 5.45% | 75 | 75 | |||||||||||||||||||||||
2018, 5.75% | 100 | 100 | |||||||||||||||||||||||
2020, 6.28% | 100 | 100 | |||||||||||||||||||||||
2021, 4.67% | 55 | 55 | |||||||||||||||||||||||
2023, 3.72% | 150 | 150 | |||||||||||||||||||||||
2026, 5.02% | 60 | 60 | |||||||||||||||||||||||
2028, 3.20% | 45 | 45 | |||||||||||||||||||||||
2035, 6.10% | 75 | 75 | |||||||||||||||||||||||
2041, 5.99% | 35 | 35 | |||||||||||||||||||||||
2042, 5.00% | 100 | 100 | |||||||||||||||||||||||
2043, 4.25% | 80 | 80 | |||||||||||||||||||||||
Total Utility Holdings | 875 | 875 | |||||||||||||||||||||||
Indiana Gas | |||||||||||||||||||||||||
Fixed Rate Senior Unsecured Notes | |||||||||||||||||||||||||
2015, Series E, 7.15% | 5 | 5 | |||||||||||||||||||||||
2015, Series E, 6.69% | 5 | 5 | |||||||||||||||||||||||
2015, Series E, 6.69% | 10 | 10 | |||||||||||||||||||||||
2025, Series E, 6.53% | 10 | 10 | |||||||||||||||||||||||
2027, Series E, 6.42% | 5 | 5 | |||||||||||||||||||||||
2027, Series E, 6.68% | 1 | 1 | |||||||||||||||||||||||
2027, Series F, 6.34% | 20 | 20 | |||||||||||||||||||||||
2028, Series F, 6.36% | 10 | 10 | |||||||||||||||||||||||
2028, Series F, 6.55% | 20 | 20 | |||||||||||||||||||||||
2029, Series G, 7.08% | 30 | 30 | |||||||||||||||||||||||
Total Indiana Gas | 116 | 116 | |||||||||||||||||||||||
SIGECO | |||||||||||||||||||||||||
First Mortgage Bonds | |||||||||||||||||||||||||
2015, 1985 Pollution Control Series A, current adjustable rate 0.05%, tax-exempt, | |||||||||||||||||||||||||
2013 weighted average: 0.10% | — | 9.8 | |||||||||||||||||||||||
2016, 1986 Series, 8.875% | 13 | 13 | |||||||||||||||||||||||
2022, 2013 Series C, 1.95%, tax-exempt | 4.6 | 4.6 | |||||||||||||||||||||||
2024, 2013 Series D, 1.95%, tax-exempt | 22.5 | 22.5 | |||||||||||||||||||||||
2025, 1998 Pollution Control Series A, current adjustable rate 0.05%, tax-exempt, | |||||||||||||||||||||||||
2013 weighted average: 0.10% | — | 31.5 | |||||||||||||||||||||||
2025, 2014 Series B, current adjustable rate 0.722%, tax-exempt | 41.3 | — | |||||||||||||||||||||||
2029, 1999 Series, 6.72% | 80 | 80 | |||||||||||||||||||||||
2037, 2013 Series E, 1.95%, tax-exempt | 22 | 22 | |||||||||||||||||||||||
2038, 2013 Series A, 4.0%, tax-exempt | 22.2 | 22.2 | |||||||||||||||||||||||
2040, 2009 Environmental Improvement Series, 5.40%, tax-exempt | — | 22.3 | |||||||||||||||||||||||
2043, 2013 Series B, 4.05%, tax-exempt | 39.6 | 39.6 | |||||||||||||||||||||||
2044, 2014 Series A, 4.00% tax-exempt | 22.3 | — | |||||||||||||||||||||||
Total SIGECO | 267.5 | 267.5 | |||||||||||||||||||||||
At December 31, | |||||||||||||||||||||||||
(In millions) | 2014 | 2013 | |||||||||||||||||||||||
Vectren Capital Corp. | |||||||||||||||||||||||||
Fixed Rate Senior Unsecured Notes | |||||||||||||||||||||||||
2014, 6.37% | — | 30 | |||||||||||||||||||||||
2015, 5.31% | 75 | 75 | |||||||||||||||||||||||
2016, 6.92% | 60 | 60 | |||||||||||||||||||||||
2017, 3.48% | 75 | 75 | |||||||||||||||||||||||
2019, 7.30% | 60 | 60 | |||||||||||||||||||||||
2025, 4.53% | 50 | 50 | |||||||||||||||||||||||
Variable Rate Term Loans | |||||||||||||||||||||||||
2015 | — | 100 | |||||||||||||||||||||||
2016 | — | 100 | |||||||||||||||||||||||
Total Vectren Capital Corp. | 320 | 550 | |||||||||||||||||||||||
Total long-term debt outstanding | 1,578.50 | 1,808.50 | |||||||||||||||||||||||
Current maturities of long-term debt | (170.0 | ) | (30.0 | ) | |||||||||||||||||||||
Unamortized debt premium & discount - net | (1.2 | ) | (1.4 | ) | |||||||||||||||||||||
Total long-term debt-net | $ | 1,407.30 | $ | 1,777.10 | |||||||||||||||||||||
Earnings_Per_Share_Tables
Earnings Per Share (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Earnings Per Share [Abstract] | |||||||||||||
Basic and dilutive earnings per share calculation | The following table illustrates the basic and dilutive EPS calculations for the three years ended December 31, 2014: | ||||||||||||
Year Ended December 31, | |||||||||||||
(In millions, except per share data) | 2014 | 2013 | 2012 | ||||||||||
Numerator: | |||||||||||||
Numerator for basic EPS | $ | 166.9 | $ | 136.6 | $ | 159 | |||||||
Add back earnings attributable to participating securities | — | — | — | ||||||||||
Reported net income (Numerator for Diluted EPS) | $ | 166.9 | $ | 136.6 | $ | 159 | |||||||
Denominator: | |||||||||||||
Weighted average common shares outstanding (Basic EPS) | 82.5 | 82.3 | 82 | ||||||||||
Conversion of share based compensation arrangements | 0 | 0.1 | 0.1 | ||||||||||
Adjusted weighted average shares outstanding and | |||||||||||||
assumed conversions outstanding (Diluted EPS) | 82.5 | 82.4 | 82.1 | ||||||||||
Basic earnings per share | $ | 2.02 | $ | 1.66 | $ | 1.94 | |||||||
Diluted earnings per share | $ | 2.02 | $ | 1.66 | $ | 1.94 | |||||||
Accumulated_Other_Comprehensiv1
Accumulated Other Comprehensive Income (Tables) | 12 Months Ended | ||||||||||||||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||||||||||||||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract] | |||||||||||||||||||||||||||||
Components and changes in accumulated other comprehensive income | A summary of the components of and changes in Accumulated other comprehensive income for the past three years follows: | ||||||||||||||||||||||||||||
2012 | 2013 | 2014 | |||||||||||||||||||||||||||
Beginning | Changes | End | Changes | End | Changes | End | |||||||||||||||||||||||
of Year | During | of Year | During | of Year | During | of Year | |||||||||||||||||||||||
(In millions) | Balance | Year | Balance | Year | Balance | Year | Balance | ||||||||||||||||||||||
Unconsolidated affiliates | $ | (15.9 | ) | $ | 11.3 | $ | (4.6 | ) | $ | 4.6 | $ | — | $ | — | $ | — | |||||||||||||
Pension & other benefit costs | (6.6 | ) | 4 | (2.6 | ) | 1.4 | (1.2 | ) | (1.0 | ) | (2.2 | ) | |||||||||||||||||
Cash flow hedges | 0.1 | (0.1 | ) | — | — | — | — | — | |||||||||||||||||||||
Deferred income taxes | 9.1 | (6.2 | ) | 2.9 | (2.4 | ) | 0.5 | 0.4 | 0.9 | ||||||||||||||||||||
Accumulated other comprehensive income (loss) | $ | (13.3 | ) | $ | 9 | $ | (4.3 | ) | $ | 3.6 | $ | (0.7 | ) | $ | (0.6 | ) | $ | (1.3 | ) | ||||||||||
ShareBased_Compensation_Deferr1
Share-Based Compensation & Deferred Compensation Arrangements (Tables) | 12 Months Ended | |||||||||||||
Dec. 31, 2014 | ||||||||||||||
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | ||||||||||||||
Reconciliation of total cost of share-based awards to the after tax effect on net income | Following is a reconciliation of the total cost associated with share-based awards recognized in the Company’s financial statements to its after tax effect on net income: | |||||||||||||
Year Ended December 31, | ||||||||||||||
(In millions) | 2014 | 2013 | 2012 | |||||||||||
Total cost of share-based compensation | $ | 25.2 | $ | 14.8 | $ | 6.3 | ||||||||
Less capitalized cost | 5.3 | 2.8 | 1.2 | |||||||||||
Total in other operating expense | 19.9 | 12 | 5.1 | |||||||||||
Less income tax benefit in earnings | 7.9 | 4.8 | 2.1 | |||||||||||
After tax effect of share-based compensation | $ | 12 | $ | 7.2 | $ | 3 | ||||||||
Performance based units outstanding | A summary of the status of awards separated between those accounted for as liabilities and equity as of December 31, 2014, and changes during the year ended December 31, 2014, follows: | |||||||||||||
Equity Awards | ||||||||||||||
Wtd. Avg. | ||||||||||||||
Grant Date | Liability Awards | |||||||||||||
Units | Fair value | Units | Fair value | |||||||||||
Awards at January 1, 2014 | 79,957 | $ | 29.12 | 731,251 | ||||||||||
Granted | 5,910 | 31.24 | 331,344 | |||||||||||
Vested | -51,594 | 28.36 | -347,031 | |||||||||||
Forfeited | — | — | -22,405 | |||||||||||
Awards at December 31, 2014 | 34,273 | $ | 30.55 | 693,159 | $ | 46.23 | ||||||||
Status of stock option awards and changes during the period |
Fair_Value_Measurements_Tables
Fair Value Measurements (Tables) | 12 Months Ended | ||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||
Fair Value Disclosures [Abstract] | |||||||||||||||||
Carrying value and estimated fair value of other financial instruments | The carrying values and estimated fair values using primarily Level 2 assumptions of the Company's other financial instruments follow: | ||||||||||||||||
At December 31, | |||||||||||||||||
2014 | 2013 | ||||||||||||||||
(In millions) | Carrying | Est. Fair | Carrying | Est. Fair | |||||||||||||
Amount | Value | Amount | Value | ||||||||||||||
Long-term debt | $ | 1,577.30 | $ | 1,754.50 | $ | 1,807.10 | $ | 1,895.20 | |||||||||
Short-term borrowings & notes payable | 156.4 | 156.4 | 68.6 | 68.6 | |||||||||||||
Cash & cash equivalents | 86.4 | 86.4 | 21.5 | 21.5 | |||||||||||||
Segment_Reporting_Tables
Segment Reporting (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Segment Reporting [Abstract] | |||||||||||||
Schedule of Segment Reporting Information, by Segment [Table Text Block] | Corporate and Other includes unallocated corporate expenses such as advertising and charitable contributions, among other activities, that benefit the Company’s other operating segments. Net income is the measure of profitability used by management for all operations. Information related to the Company’s business segments is summarized as follows: | ||||||||||||
Year Ended December 31, | |||||||||||||
(In millions) | 2014 | 2013 | 2012 | ||||||||||
Revenues | |||||||||||||
Utility Group | |||||||||||||
Gas Utility Services | $ | 944.6 | $ | 810 | $ | 738.1 | |||||||
Electric Utility Services | 624.8 | 619.3 | 594.9 | ||||||||||
Other Operations | 38.3 | 38.1 | 40.1 | ||||||||||
Eliminations | (38.0 | ) | (37.8 | ) | (39.5 | ) | |||||||
Total Utility Group | 1,569.70 | 1,429.60 | 1,333.60 | ||||||||||
Nonutility Group | |||||||||||||
Infrastructure Services | 779 | 783.5 | 663.6 | ||||||||||
Energy Services | 129.8 | 91.3 | 117.7 | ||||||||||
Coal Mining | 234.3 | 292.8 | 235.8 | ||||||||||
Other Businesses | — | — | 0.5 | ||||||||||
Total Nonutility Group | 1,143.10 | 1,167.60 | 1,017.60 | ||||||||||
Eliminations, net of Corporate & Other Revenues | (101.1 | ) | (106.0 | ) | (118.4 | ) | |||||||
Consolidated Revenues | $ | 2,611.70 | $ | 2,491.20 | $ | 2,232.80 | |||||||
Profitability Measures - Net Income | |||||||||||||
Utility Group Net Income | |||||||||||||
Gas Utility Services | $ | 57 | $ | 55.7 | $ | 60 | |||||||
Electric Utility Services | 79.7 | 75.8 | 68 | ||||||||||
Other Operations | 11.7 | 10.3 | 10 | ||||||||||
Total Utility Group Net Income | 148.4 | 141.8 | 138 | ||||||||||
Nonutility Group Net Income (Loss) | |||||||||||||
Infrastructure Services | 43.1 | 49 | 40.5 | ||||||||||
Energy Services | (3.2 | ) | 1 | 5.7 | |||||||||
Coal Mining | (21.1 | ) | (16.0 | ) | (3.5 | ) | |||||||
Energy Marketing | — | (37.5 | ) | (17.6 | ) | ||||||||
Other Businesses | (0.8 | ) | (1.0 | ) | (3.4 | ) | |||||||
Total Nonutility Group Net Income (Loss) | 18 | (4.5 | ) | 21.7 | |||||||||
Corporate & Other Net Loss | 0.5 | (0.7 | ) | (0.7 | ) | ||||||||
Consolidated Net Income | $ | 166.9 | $ | 136.6 | $ | 159 | |||||||
Year Ended December 31, | |||||||||||||
(In millions) | 2014 | 2013 | 2012 | ||||||||||
Amounts Included in Profitability Measures | |||||||||||||
Depreciation & Amortization | |||||||||||||
Utility Group | |||||||||||||
Gas Utility Services | $ | 93.3 | $ | 90.5 | $ | 85.4 | |||||||
Electric Utility Services | 85.7 | 84 | 81.3 | ||||||||||
Other Operations | 24.1 | 21.9 | 23.3 | ||||||||||
Total Utility Group | 203.1 | 196.4 | 190 | ||||||||||
Nonutility Group | |||||||||||||
Infrastructure Services | 36.2 | 28.8 | 20.7 | ||||||||||
Energy Services | 3.9 | 1.7 | 1.9 | ||||||||||
Coal Mining | 29.9 | 50.8 | 41.8 | ||||||||||
Other Businesses | 0.3 | 0.1 | 0.2 | ||||||||||
Total Nonutility Group | 70.3 | 81.4 | 64.6 | ||||||||||
Consolidated Depreciation & Amortization | $ | 273.4 | $ | 277.8 | $ | 254.6 | |||||||
Interest Expense | |||||||||||||
Utility Group | |||||||||||||
Gas Utility Services | $ | 34.9 | $ | 30.6 | $ | 31.8 | |||||||
Electric Utility Services | 29 | 29.2 | 33.8 | ||||||||||
Other Operations | 2.7 | 5.2 | 5.9 | ||||||||||
Total Utility Group | 66.6 | 65 | 71.5 | ||||||||||
Nonutility Group | |||||||||||||
Infrastructure Services | 11.1 | 10.1 | 7.5 | ||||||||||
Energy Services | 1.3 | 0.6 | 0.4 | ||||||||||
Coal Mining | 7.5 | 9.8 | 11.5 | ||||||||||
Energy Marketing | — | 2.2 | 4.8 | ||||||||||
Other Businesses | 0.9 | 0.5 | 0.7 | ||||||||||
Total Nonutility Group | 20.8 | 23.2 | 24.9 | ||||||||||
Corporate & Other | (0.7 | ) | (0.3 | ) | (0.4 | ) | |||||||
Consolidated Interest Expense | $ | 86.7 | $ | 87.9 | $ | 96 | |||||||
Income Taxes | |||||||||||||
Utility Group | |||||||||||||
Gas Utility Services | $ | 35.7 | $ | 36.6 | $ | 39.1 | |||||||
Electric Utility Services | 48.1 | 48.3 | 46.4 | ||||||||||
Other Operations | (0.6 | ) | 0.4 | (0.2 | ) | ||||||||
Total Utility Group | 83.2 | 85.3 | 85.3 | ||||||||||
Nonutility Group | |||||||||||||
Infrastructure Services | 28.9 | 34.3 | 29.6 | ||||||||||
Energy Services | (7.8 | ) | (11.9 | ) | (9.0 | ) | |||||||
Coal Mining | (21.8 | ) | (14.6 | ) | (8.6 | ) | |||||||
Energy Marketing | — | (23.3 | ) | (11.7 | ) | ||||||||
Other Businesses | (0.3 | ) | (1.6 | ) | (2.0 | ) | |||||||
Total Nonutility Group | (1.0 | ) | (17.1 | ) | (1.7 | ) | |||||||
Corporate & Other | (1.1 | ) | (1.1 | ) | (1.1 | ) | |||||||
Consolidated Income Taxes | $ | 81.1 | $ | 67.1 | $ | 82.5 | |||||||
Year Ended December 31, | |||||||||||||
(In millions) | 2014 | 2013 | 2012 | ||||||||||
Capital Expenditures | |||||||||||||
Utility Group | |||||||||||||
Gas Utility Services | $ | 245.9 | $ | 150.5 | $ | 128.8 | |||||||
Electric Utility Services | 92.4 | 100 | 108.8 | ||||||||||
Other Operations | 23.3 | 25.8 | 16.2 | ||||||||||
Non-cash costs & changes in accruals | (10.9 | ) | (15.2 | ) | (7.8 | ) | |||||||
Total Utility Group | 350.7 | 261.1 | 246 | ||||||||||
Nonutility Group | |||||||||||||
Infrastructure Services | 54.1 | 79.2 | 53.7 | ||||||||||
Energy Services | 1.6 | 6.9 | 2.3 | ||||||||||
Coal Mining | 41.9 | 46.2 | 63.8 | ||||||||||
Total Nonutility Group | 97.6 | 132.3 | 119.8 | ||||||||||
Consolidated Capital Expenditures | $ | 448.3 | $ | 393.4 | $ | 365.8 | |||||||
At December 31, | |||||||||||||
(In millions) | 2014 | 2013 | |||||||||||
Assets | |||||||||||||
Utility Group | |||||||||||||
Gas Utility Services | $ | 2,605.10 | $ | 2,287.90 | |||||||||
Electric Utility Services | 1,659.30 | 1,679.00 | |||||||||||
Other Operations, net of eliminations | 163.7 | 173.9 | |||||||||||
Total Utility Group | 4,428.10 | 4,140.80 | |||||||||||
Nonutility Group | |||||||||||||
Infrastructure Services | 541.6 | 465.8 | |||||||||||
Energy Services | 87.1 | 63 | |||||||||||
Coal Mining | — | 433 | |||||||||||
Energy Marketing | 30.6 | 33.9 | |||||||||||
Other Businesses, net of eliminations and reclassifications | 89.2 | 34.9 | |||||||||||
Total Nonutility Group | 748.5 | 1,030.60 | |||||||||||
Corporate & Other | 658.1 | 828.1 | |||||||||||
Eliminations | (672.4 | ) | (896.9 | ) | |||||||||
Consolidated Assets | $ | 5,162.30 | $ | 5,102.60 | |||||||||
Additional_Balance_Sheet_Opera1
Additional Balance Sheet & Operational Information (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Additional Balance Sheet and Operational Information [Abstract] | |||||||||||||
Summary of inventories | Inventories consist of the following: | ||||||||||||
At December 31, | |||||||||||||
(In millions) | 2014 | 2013 | |||||||||||
Gas in storage – at LIFO cost | $ | 40.5 | $ | 33.2 | |||||||||
Coal & oil for electric generation - at average cost | 33.8 | 16.5 | |||||||||||
Materials & supplies | 42.5 | 57.3 | |||||||||||
Nonutility coal - at LIFO cost | — | 26.2 | |||||||||||
Other | 1.7 | 1.2 | |||||||||||
Total inventories | $ | 118.5 | $ | 134.4 | |||||||||
Summary of prepayments and other current assets | Prepayments & other current assets consist of the following: | ||||||||||||
At December 31, | |||||||||||||
(In millions) | 2014 | 2013 | |||||||||||
Prepaid gas delivery service | $ | 40.7 | $ | 32.9 | |||||||||
Deferred income taxes | 16.3 | 13.9 | |||||||||||
Prepaid taxes | 37.5 | 11.2 | |||||||||||
Other prepayments & current assets | 16.4 | 17.6 | |||||||||||
Total prepayments & other current assets | $ | 110.9 | $ | 75.6 | |||||||||
Schedule of investments in unconsolidated affiliates | Investments in unconsolidated affiliates consist of the following: | ||||||||||||
At December 31, | |||||||||||||
(In millions) | 2014 | 2013 | |||||||||||
ProLiance Holdings, LLC | $ | 20.5 | $ | 20.8 | |||||||||
Other nonutility partnerships & corporations | 2.7 | 3 | |||||||||||
Other utility investments | 0.2 | 0.2 | |||||||||||
Total investments in unconsolidated affiliates | $ | 23.4 | $ | 24 | |||||||||
Other utility and corporate investments in the consolidated balance sheets | Other utility & corporate investments consist of the following: | ||||||||||||
At December 31, | |||||||||||||
(In millions) | 2014 | 2013 | |||||||||||
Cash surrender value of life insurance policies | $ | 32.3 | $ | 32.9 | |||||||||
Municipal bond | 3.1 | 3.4 | |||||||||||
Restricted cash & other investments | 1.8 | 1.8 | |||||||||||
Other utility & corporate investments | $ | 37.2 | $ | 38.1 | |||||||||
Goodwill by operating segment | Goodwill by operating segment follows: | ||||||||||||
At December 31, | |||||||||||||
(In millions) | 2014 | 2013 | |||||||||||
Utility Group | |||||||||||||
Gas Utility Services | $ | 205 | $ | 205 | |||||||||
Nonutility Group | |||||||||||||
Infrastructure Services | 55.2 | 55.2 | |||||||||||
Energy Services | 29.7 | 2.1 | |||||||||||
Consolidated goodwill | $ | 289.9 | $ | 262.3 | |||||||||
Accrued Liabilities | Accrued liabilities consist of the following: | ||||||||||||
At December 31, | |||||||||||||
(In millions) | 2014 | 2013 | |||||||||||
Refunds to customers & customer deposits | $ | 51.3 | $ | 50.2 | |||||||||
Accrued taxes | 35.8 | 36.2 | |||||||||||
Accrued interest | 19.1 | 20 | |||||||||||
Deferred compensation & post-retirement benefits | 7.3 | 7.5 | |||||||||||
Accrued salaries & other | 71.4 | 68.2 | |||||||||||
Total accrued liabilities | $ | 184.9 | $ | 182.1 | |||||||||
Asset retirement obligation | Asset retirement obligations included in Deferred credits and other liabilities in the Consolidated Balance Sheets roll forward as follows: | ||||||||||||
(In millions) | 2014 | 2013 | |||||||||||
Asset retirement obligation, January 1 | $ | 41.3 | $ | 37.7 | |||||||||
Accretion | 1.7 | 2.2 | |||||||||||
Changes in estimates, net of cash payments | 23.8 | 1.4 | |||||||||||
Vectren Fuels Retirement Obligation | (11.8 | ) | — | ||||||||||
Asset retirement obligation, December 31 | 55 | 41.3 | |||||||||||
Equity in earnings (losses) of unconsolidated affiliates | Equity in earnings (losses) of unconsolidated affiliates consists of the following: | ||||||||||||
Year Ended December 31, | |||||||||||||
(In millions) | 2014 | 2013 | 2012 | ||||||||||
ProLiance Holdings, LLC | $ | (0.3 | ) | $ | (57.7 | ) | $ | (22.7 | ) | ||||
Other | 0.8 | (2.0 | ) | (0.6 | ) | ||||||||
Total equity in earnings (losses) of unconsolidated affiliates | $ | 0.5 | $ | (59.7 | ) | $ | (23.3 | ) | |||||
Other, net in the consolidated statements of income | Other income (expense) – net consists of the following: | ||||||||||||
Year Ended December 31, | |||||||||||||
(In millions) | 2014 | 2013 | 2012 | ||||||||||
AFUDC – borrowed funds | $ | 11.4 | $ | 5.9 | $ | 4.6 | |||||||
AFUDC – equity funds | 3.2 | 0.8 | 0.4 | ||||||||||
Nonutility plant capitalized interest | — | 0.5 | 1.8 | ||||||||||
Interest income, net | 1.1 | 1.1 | 1.1 | ||||||||||
Other nonutility investment impairment charges | (1.0 | ) | — | (2.7 | ) | ||||||||
Cash surrender value of life insurance policies | 2.8 | 4.8 | 1.8 | ||||||||||
All other income | 2.2 | 4.6 | 1.3 | ||||||||||
Total other income (expense) – net | $ | 19.7 | $ | 17.7 | $ | 8.3 | |||||||
Supplemental cash flow information | Supplemental Cash Flow Information: | ||||||||||||
Year Ended December 31, | |||||||||||||
(In millions) | 2014 | 2013 | 2012 | ||||||||||
Cash paid (received) for: | |||||||||||||
Interest | $ | 87.5 | $ | 91 | $ | 94.6 | |||||||
Income taxes | 69.4 | 6.8 | 21.8 | ||||||||||
Quarterly_Financial_Data_Unaud1
Quarterly Financial Data (Unaudited) (Tables) | 12 Months Ended | ||||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||||
Quarterly Financial Information Disclosure [Abstract] | |||||||||||||||||||
Summarized quarterly financial data | Information in any one quarterly period is not indicative of annual results due to the seasonal variations common to the Company’s utility operations. Note that at June 30, 2014, the Company recorded an estimated loss on the transaction related to the Vectren Fuels sale to Sunrise Coal, including costs to sell, of approximately $32 million, or $20 million after tax. At June 18, 2013, the Company recorded its share of the loss related to ProLiance exiting the natural gas marketing business on the disposition, termination of long term pipeline and storage commitments, and related transaction and other costs totaling $43.6 million pre-tax, or $26.8 million net of tax. Summarized quarterly financial data for 2014 and 2013 follows: | ||||||||||||||||||
(In millions, except per share amounts) | Q1 | Q2 | Q3 | Q4 | |||||||||||||||
2014 | |||||||||||||||||||
Operating revenues | $ | 796.8 | $ | 542.5 | $ | 595.6 | $ | 676.8 | |||||||||||
Operating income | 99 | 33.9 | 84.5 | 97.1 | |||||||||||||||
Net income (loss) | 51.2 | 11.9 | 47.3 | 56.5 | |||||||||||||||
Earnings (loss) per share: | |||||||||||||||||||
Basic | $ | 0.62 | $ | 0.14 | $ | 0.57 | $ | 0.68 | |||||||||||
Diluted | 0.62 | 0.14 | 0.57 | 0.68 | |||||||||||||||
2013 | |||||||||||||||||||
Operating revenues | $ | 700.6 | $ | 531 | $ | 579.6 | $ | 680 | |||||||||||
Operating income | 106.8 | 57.9 | 83.3 | 85.6 | |||||||||||||||
Net income (loss) | 49.8 | (5.8 | ) | 42.8 | 49.8 | ||||||||||||||
Earnings (loss) per share: | |||||||||||||||||||
Basic | $ | 0.61 | $ | (0.07 | ) | $ | 0.52 | $ | 0.6 | ||||||||||
Diluted | 0.61 | (0.07 | ) | 0.52 | 0.6 | ||||||||||||||
Organization_and_Nature_of_Ope1
Organization and Nature of Operations (Details) | 12 Months Ended |
Dec. 31, 2014 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Number of public utility subsidiaries owned by wholly owned subsidiary, Vectren Utility Holdings, Inc. (in number of subsidiaries) | 3 |
Estimated number of natural gas customers located in central and southern Indiana serviced by Indiana Gas Company (in number of customers) | 575,000 |
Estimated number of electric customers located near Evansville in southwestern Indiana serviced by Southern Indiana Gas and Electric Company (in number of customers) | 143,000 |
Estimated number of natural gas customers located near Evansville in southwestern Indiana serviced by Southern Indiana Gas and Electric Company (in number of customers) | 110,000 |
Estimated number of natural gas customers located near Dayton in west central Ohio serviced by the Ohio operations (in number of customers) | 313,000 |
Summary_of_Significant_Account2
Summary of Significant Accounting Policies (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Accounting Policies [Abstract] | |||
Energy Service's Asset Impairment Charge | $0.70 | ||
Excise taxes and a portion of utility receipts taxes | $32.30 | $29.60 | $26.90 |
Number of operating segments in Utility group | 3 | ||
Number of operating segments in Nonutility group | 4 |
Utility_Nonutility_Plant_Detai
Utility & Nonutility Plant (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Utility & Nonutility Plant | |||
Original Cost | $5,718.70 | $5,389.60 | |
Cost of Non-Utility plant, net of depreciation and amortization | 378 | 657.2 | |
Utility Group [Member] | |||
Utility & Nonutility Plant | |||
Original Cost | 5,718.70 | 5,389.60 | |
Utility Group [Member] | Warrick Power Plant [Member] | |||
Utility & Nonutility Plant | |||
Size of Unit 4 Warrick Power Plant (in megawatts) | 300 | ||
Utility Group [Member] | Gas Utility Plant [Member] | |||
Utility & Nonutility Plant | |||
Original Cost | 3,011 | 2,762.20 | |
Depreciation Rates as a Percent of Original Cost (in hundredths) | 3.40% | 3.50% | |
Utility Group [Member] | Electric Utility Plant [Member] | |||
Utility & Nonutility Plant | |||
Original Cost | 2,602.50 | 2,519.80 | |
Depreciation Rates as a Percent of Original Cost (in hundredths) | 3.30% | 3.30% | |
Utility Group [Member] | Common Utility Plant [Member] | |||
Utility & Nonutility Plant | |||
Original Cost | 54.3 | 53.4 | |
Depreciation Rates as a Percent of Original Cost (in hundredths) | 3.20% | 3.00% | |
Utility Group [Member] | Construction Work in Progress [Member] | |||
Utility & Nonutility Plant | |||
Original Cost | 50.9 | 54.2 | |
Depreciation Rates as a Percent of Original Cost (in hundredths) | 0.00% | 0.00% | |
Utility Group [Member] | SIGECO [Member] | |||
Utility & Nonutility Plant | |||
Southern Indiana Gas And Electric Company's Share Of Cost Of Unit 4 | 188 | ||
Southern Indiana Gas And Electric Company's Share Of Accumulated Depreciation Of Unit 4 | 93.5 | ||
Nonutility Group [Member] | |||
Utility & Nonutility Plant | |||
Cost of Non-Utility plant, net of depreciation and amortization | 378 | 657.2 | |
Nonutility plant accumulated depreciation and amortization | 361.9 | 541.7 | |
Capitalized interest on nonutility plant construction projects | 0.6 | 0.5 | 1.8 |
Nonutility Group [Member] | Coal Mine Development Costs and Equipment [Member] | |||
Utility & Nonutility Plant | |||
Cost of Non-Utility plant, net of depreciation and amortization | 0 | 242 | |
Nonutility Group [Member] | Computer Hardware and Software [Member] | |||
Utility & Nonutility Plant | |||
Cost of Non-Utility plant, net of depreciation and amortization | 106.1 | 102.7 | |
Nonutility Group [Member] | Land and Buildings [Member] | |||
Utility & Nonutility Plant | |||
Cost of Non-Utility plant, net of depreciation and amortization | 72.1 | 129.3 | |
Nonutility Group [Member] | Vehicles and Equipment [Member] | |||
Utility & Nonutility Plant | |||
Cost of Non-Utility plant, net of depreciation and amortization | 182.7 | 165.2 | |
Nonutility Group [Member] | All Other [Member] | |||
Utility & Nonutility Plant | |||
Cost of Non-Utility plant, net of depreciation and amortization | $17.10 | $18 |
Regulatory_Assets_Liabilities_1
Regulatory Assets & Liabilities (Details) (USD $) | 12 Months Ended | |
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 |
Regulatory Assets [Line Items] | ||
Regulatory assets | $233.60 | $193.40 |
Regulatory Assets Currently Being Recovered in Base Rates | 36 | |
Weighted average recovery period of regulatory assets currently being recovered (in years) | 23 | |
Defined Benefit Plan, increase in benefit obligation recoverable from ratepayers | 48 | |
Regulatory Liabilities [Abstract] | ||
Regulatory liabilities | 410.3 | 387.3 |
Asset Retirement Obligations and Other [Member] | ||
Regulatory Liabilities [Abstract] | ||
Regulatory liabilities | 373.5 | 373 |
Future Amounts Recoverable From Ratepayers [Member] | ||
Regulatory Assets [Line Items] | ||
Regulatory assets | 90.5 | 53.7 |
Future Amounts Recoverable From Ratepayers [Member] | Benefit Obligations [Member] | ||
Regulatory Assets [Line Items] | ||
Regulatory assets | 105.3 | 57.1 |
Future Amounts Recoverable From Ratepayers [Member] | Deferred Income Taxes [Member] | ||
Regulatory Assets [Line Items] | ||
Regulatory assets | -14.8 | -5.8 |
Future Amounts Recoverable From Ratepayers [Member] | Asset Retirement Obligations and Other [Member] | ||
Regulatory Assets [Line Items] | ||
Regulatory assets | 0 | 2.4 |
Amounts Deferred for Future Recovery [Member] | ||
Regulatory Assets [Line Items] | ||
Regulatory assets | 33.3 | 61 |
Amounts Deferred for Future Recovery [Member] | Deferred Coal Costs [Member] | ||
Regulatory Assets [Line Items] | ||
Regulatory assets | 0 | 42.4 |
Amounts Deferred for Future Recovery [Member] | Cost Recovery Riders Other [Member] | ||
Regulatory Assets [Line Items] | ||
Regulatory assets | 33.3 | 18.6 |
Amounts Currently Recovered in Customer Rates [Member] | ||
Regulatory Assets [Line Items] | ||
Regulatory assets | 109.8 | 78.7 |
Amounts Currently Recovered in Customer Rates [Member] | Deferred Coal Costs [Member] | ||
Regulatory Assets [Line Items] | ||
Regulatory assets | 35.3 | 0 |
Amounts Currently Recovered in Customer Rates [Member] | Unamortized Debt Issue Costs and Hedging Proceeds [Member] | ||
Regulatory Assets [Line Items] | ||
Regulatory assets | 33.5 | 34.6 |
Amounts Currently Recovered in Customer Rates [Member] | Demand Side Management Programs [Member] | ||
Regulatory Assets [Line Items] | ||
Regulatory assets | 0.6 | 2.5 |
Amounts Currently Recovered in Customer Rates [Member] | Indiana Authorized Trackers [Member] | ||
Regulatory Assets [Line Items] | ||
Regulatory assets | 25.6 | 30.8 |
Amounts Currently Recovered in Customer Rates [Member] | Ohio Authorized Trackers [Member] | ||
Regulatory Assets [Line Items] | ||
Regulatory assets | 12.7 | 7.9 |
Amounts Currently Recovered in Customer Rates [Member] | Premiums Paid to Reaquire Debt [Member] | ||
Regulatory Assets [Line Items] | ||
Regulatory assets | 1.7 | 2.2 |
Amounts Currently Recovered in Customer Rates [Member] | Other Base Rate Recoveries [Member] | ||
Regulatory Assets [Line Items] | ||
Regulatory assets | $0.40 | $0.70 |
Federal_Business_Unit_Acquisit2
Federal Business Unit Acquisition Federal Business Unit Acquisition (Details) (USD $) | 0 Months Ended | 12 Months Ended | ||
In Millions, unless otherwise specified | Apr. 01, 2014 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Business Acquisition [Line Items] | ||||
Effective Date of Acquisition | 1-Apr-14 | |||
Goodwill deductibility period for income tax purposes | 15 years | |||
Amount of Transaction Costs in Other Cost and Expense, Operating | $943.40 | $891.60 | $781 | |
Federal Business Unit [Member] | ||||
Business Acquisition [Line Items] | ||||
Business Combination, Liabilities Arising from Contingencies, Amount Recognized | 14.8 | |||
Adjusted net working capital | 2.2 | |||
Depreciable fixed assets | 0.4 | |||
Customer Relationships (Sales Funnel) | 7.1 | |||
ESPC Licenses | 6 | |||
Deferred Tax Asset | 0.8 | |||
Goodwill | 27.7 | |||
Total assets acquired | 44.2 | |||
Less: Unfavorable Contract Liabilities Assumed | -2.1 | |||
Total Purchase Consideration | 42.1 | |||
Transaction Costs | 1.7 | |||
Amount of Transaction Costs in Other Cost and Expense, Operating | 0.8 | 0.9 | ||
Pro Forma Revenue | $17.70 | $27.60 |
Sale_of_Vectren_Fuels_Inc_Deta
Sale of Vectren Fuels, Inc. (Details) (USD $) | 3 Months Ended | 12 Months Ended | |||||||||
In Millions, unless otherwise specified | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||||||||
Cash received at closing | $311.20 | $0 | $0 | ||||||||
Net income (loss) | 56.5 | 47.3 | 11.9 | 51.2 | 49.8 | 42.8 | -5.8 | 49.8 | 166.9 | 136.6 | 159 |
Vectren Fuels, Inc. [Member] | |||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||||||||
Cash received at closing | 311 | ||||||||||
Change in working capital | 15 | ||||||||||
Disposal Group, Including Discontinued Operation, Gross Profit (Loss) | -32 | ||||||||||
Loss on disposal, after tax | -20 | ||||||||||
Disposal Group, Including Discontinued Operation, Other Expense | 42 | ||||||||||
Disposal Group, Including Discontinued Operation, Depreciation and Amortization | 10 | ||||||||||
Net income (loss) | $21.10 | $16 | $3.50 |
Investment_in_ProLiance_Holdin2
Investment in ProLiance Holdings, LLC (Details) (USD $) | 12 Months Ended | 3 Months Ended | 12 Months Ended | |
In Millions, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Jun. 30, 2013 | Dec. 31, 2014 |
Schedule of Equity Method Investments [Line Items] | ||||
Other nonutility investments | $33.80 | $33.60 | ||
Equity method investment, investment in equity method investee's subsidiary (ProLiance Energy) | 4.8 | |||
Equity method investment, investment in storage assets and cash from sale of storage assets | 21.6 | |||
Equity method investment, minority interest in joint venture, investor's portion of interest | 4.2 | |||
Equity method investment, gross investment in equity method investee | 30.6 | |||
Purchases from ProLiance for resale and for injections into storage | 200.5 | 274.5 | ||
ProLiance Holdings, LLC [Member] | ||||
Schedule of Equity Method Investments [Line Items] | ||||
Equity method investee funding of equity shortfall of ProLiance Energy | 16.6 | |||
ProLiance Holdings, LLC [Member] | Vectren Corp [Member] | ||||
Schedule of Equity Method Investments [Line Items] | ||||
Equity method investment, ownership percentage (in hundredths) | 61.00% | |||
Equity Method Investment Governance and Voting Right Percentage | 50.00% | |||
Equity method investment, loss on sale of ProLiance Energy, before tax | 43.6 | |||
Equity method investment, loss on sale of ProLiance Energy, after tax | 26.8 | |||
Other nonutility investments | 10.1 | |||
LA Storage [Member] | ProLiance Holdings, LLC [Member] | ||||
Schedule of Equity Method Investments [Line Items] | ||||
Equity method investment, ownership percentage (in hundredths) | 25.00% | |||
Combined Joint Venture Ownership Percentage | 100.00% | |||
Equity Method Investment, Aggregate Cost | 35.4 | |||
Sublease Agreement [Member] | LA Storage [Member] | ||||
Schedule of Equity Method Investments [Line Items] | ||||
Loss contingency, gross damages sought from a party that entered into a sub-lease agreement with a party that is an investment of an equity method investee. | $56.70 |
Nonutility_Real_Estate_Other_L2
Nonutility Real Estate & Other Legacy Holdings (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Millions, unless otherwise specified | ||
Investments by type [Abstract] | ||
Other nonutility investments | $33.60 | $33.80 |
Investments in unconsolidated affiliates | 23.4 | 24 |
ProLiance Holdings, LLC [Member] | ||
Investments by type [Abstract] | ||
Investments in unconsolidated affiliates | 20.5 | 20.8 |
Nonutility Group [Member] | ||
Investments by type [Abstract] | ||
Total carrying value by type of investment | 25 | 26.5 |
Other nonutility investments | 23.4 | |
Investments in unconsolidated affiliates | 1.6 | |
Commercial Real Estate Investments [Member] | Nonutility Group [Member] | ||
Investments by type [Abstract] | ||
Total carrying value by type of investment | 8 | |
Other nonutility investments | 8 | |
Investments in unconsolidated affiliates | 0 | |
Leveraged Leases [Member] | Nonutility Group [Member] | ||
Investments by type [Abstract] | ||
Total carrying value by type of investment | 15.2 | |
Other nonutility investments | 15.2 | |
Investments in unconsolidated affiliates | 0 | |
Leveraged Leases | ||
Total equipment and facilities cost | 27.5 | |
Rentals due under the leases and a security interest in the leased property | 16.3 | |
Book value of leveraged lease | 5.2 | |
Leveraged Lease Deferred Taxes | 10 | |
Other Investments [Member] | Nonutility Group [Member] | ||
Investments by type [Abstract] | ||
Total carrying value by type of investment | 1.8 | |
Other nonutility investments | 0.2 | |
Investments in unconsolidated affiliates | $1.60 |
Intangible_Assets_Details
Intangible Assets (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Schedule of intangible assets, excluding goodwill [Line Items] | |||
Amortizing | $23.60 | $19.30 | |
Non-amortizing | 13 | 7 | |
Weighted average remaining life for amortizing customer-related assets and all amortizing intangibles (in years) | 12 years | ||
Amortization expense | 2.8 | 2.3 | 2.6 |
Amortization expense - year one | 3 | ||
Amortization expense - year two | 2.3 | ||
Amortization expense - year three | 2.1 | ||
Amortization expense - year four | 2.1 | ||
Amortization expense - year five | 2.1 | ||
Customer Related Assets [Member] | |||
Schedule of intangible assets, excluding goodwill [Line Items] | |||
Amortizing | 22.5 | 17.4 | |
Non-amortizing | 0 | 0 | |
Accumulated amortization | 10 | 8.1 | |
Market Related Assets [Member] | |||
Schedule of intangible assets, excluding goodwill [Line Items] | |||
Amortizing | 1.1 | 1.9 | |
Non-amortizing | 13 | 7 | |
Accumulated amortization | $3.40 | $2.60 |
Income_Taxes_Details
Income Taxes (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Reconciliation of the federal statutory rate to the effective income tax rate [Abstract] | |||
Statutory rate: (in hundredths) | 35.00% | 35.00% | 35.00% |
State and local taxes-net of federal benefit (in hundredths) | 4.10% | 4.60% | 4.00% |
Amortization of investment tax credit (in hundredths) | -0.30% | -0.30% | -0.30% |
Depletion (in hundredths) | -2.60% | -1.50% | -1.50% |
Domestic production deduction | -1.10% | 0.00% | 0.00% |
Energy efficiency building deductions | -1.60% | -3.80% | -3.00% |
Other tax credits (in hundredths) | -0.20% | -1.10% | -0.10% |
Adjustment of income tax accruals and all other-net (in hundredths) | -0.60% | 0.10% | 0.10% |
Effective tax rate (in hundredths) | 32.70% | 33.00% | 34.20% |
Noncurrent deferred tax liabilities (assets) [Abstract] | |||
Depreciation and cost recovery timing differences | $757.90 | $725.20 | |
Leveraged lease | 9.8 | 10.4 | |
Regulatory assets recoverable through future rates | 29.2 | 22.8 | |
Alternative minimum tax carryforward | -13.3 | -23.5 | |
Employee benefit obligations | -14.5 | -6.7 | |
Net operating loss and other carryforwards | -2 | -1.2 | |
Regulatory liabilities to be settled through future rates | -27.5 | -18.7 | |
Impairments | -5.6 | -6.2 | |
Other - net | 7.2 | 5.3 | |
Net noncurrent deferred tax liability | 741.2 | 707.4 | |
Deferred Tax Assets Liabilities Current Abstract | |||
Deferred fuel costs-net | 22 | 22.9 | |
Alternative minimum tax carryforward | -38.1 | -33.7 | |
Net operating loss and other carryforwards | 0 | -4.9 | |
Other - net | -0.2 | 1.8 | |
Net current deferred tax liability (asset) | -16.3 | -13.9 | |
Net deferred tax liability | 724.9 | 693.5 | |
Investment tax credits | 4.7 | 5.3 | |
Remaining life of NOL's and business credit carryforwards (in years) | 5 to 20 years | ||
Operating Loss Carryforwards, Valuation Allowance | 7.3 | 3.6 | |
Current: [Abstract] | |||
Federal | 24.7 | 12.4 | -8.2 |
State | 18.5 | 11.4 | 6.4 |
Total current taxes | 43.2 | 23.8 | -1.8 |
Deferred: [Abstract] | |||
Federal | 42.7 | 43.4 | 80.3 |
State | -4.2 | 0.5 | 4.6 |
Total deferred taxes | 38.5 | 43.9 | 84.9 |
Amortization of investment tax credits | -0.6 | -0.6 | -0.6 |
Total income tax expense | 81.1 | 67.1 | 82.5 |
Uncertain tax positions [Roll Forward] | |||
Unrecognized tax benefits at beginning of period | 5.9 | 4.8 | 12.4 |
Gross increases - tax positions in prior periods | 0.2 | 0 | 0.2 |
Gross decreases - tax positions in prior periods | -4.8 | -0.2 | -9.4 |
Gross increases - current period tax positions | 0 | 1.2 | 1.9 |
Settlements | 0 | 0 | -0.3 |
Lapse of statute of limitations | -0.2 | 0.1 | 0 |
Unrecognized tax benefits at end of period | 1.1 | 5.9 | 4.8 |
Uncertain tax positions [Abstract] | |||
Amount of unrecognized tax benefits, which if recognized, that would impact the effective tax rate | 0.8 | 0.7 | 0.7 |
Interest and penalties | 0.1 | 0.1 | 0.7 |
Payment of interest and penalties accrued | 0.4 | 0.5 | |
Net liability for unrecognized tax benefits inclusive of interest, penalties and net of secondary impacts which are a component of the deferred income taxes and are benefits | $1.10 | $3.80 |
Retirement_Plans_Other_Postret2
Retirement Plans & Other Postretirement Benefits (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Net periodic benefit costs [Abstract] | |||
Portion of benefit costs capitalized as Utility plant | $2.80 | $4.20 | $3.70 |
Plan Assets [Roll Forward] | |||
Plan assets at fair value, beginning of period [Roll Forward] | 323.9 | ||
Fair value of plan assets, end of period | 305.6 | 323.9 | |
Fair Value of guaranteed annuity contract [Roll Forward] | |||
Guaranteed Annuity Contract - estimate of undiscounted funds necessary to satisfy John Hancock's remaining obligation | 3.8 | 3.7 | |
Guaranteed Annuity Contract - percent of composite investment return, net of manger fees and other charges (in hundredths) | 4.12% | 4.75% | |
Fair value, beginning of year | 4.1 | 3.9 | |
Unrealized gains related to investments still held at reporting date | 0.1 | 0.2 | |
Purchases, sales and settlements, net | 0 | 0 | |
Fair value, end of year | 4.2 | 4.1 | |
Qualified Plans | |||
Fair value of plan assets, end of period | 305.6 | 323.9 | |
Payments expected to be made to SERP participants in the next fiscal year | 1.2 | ||
Reconciliation of amounts in Accumulated other comprehensive income and Regulatory assets | |||
Less: Regulatory asset deferral | 233.6 | 193.4 | |
Multiemployer Benefit Plan [Abstract] | |||
Number of unions the Company contributed to on behalf of employees | 250 | ||
Average contributions to each union | 0.2 | ||
Largest union multiemployer plan contribution | 4.1 | ||
Expense for the Multiemployer Benefit plan | 32.4 | 33.2 | 27.6 |
Defined Contribution Plan [Abstract] | |||
Contributions to Defined Contribution Plan | 9.1 | 7.5 | 6.7 |
Central Pension Fund [Member] | |||
Multiemployer Benefit Plan [Abstract] | |||
Expense for the Multiemployer Benefit plan | 7.7 | 8.5 | 4 |
Pipeline Industry Benefit Fund [Member] | |||
Multiemployer Benefit Plan [Abstract] | |||
Expense for the Multiemployer Benefit plan | 5.1 | 5.3 | 3.9 |
Indiana Laborers Pension Fund [Member] | |||
Multiemployer Benefit Plan [Abstract] | |||
Expense for the Multiemployer Benefit plan | 3.5 | 2.4 | 3.2 |
Minnesota Laborers Pension Fund [Member] | |||
Multiemployer Benefit Plan [Abstract] | |||
Expense for the Multiemployer Benefit plan | 2.2 | 2.8 | 2 |
Other Pension Funds [Member] | |||
Multiemployer Benefit Plan [Abstract] | |||
Expense for the Multiemployer Benefit plan | 13.9 | 14.2 | 14.5 |
Domestic equities and equity funds [Member] | |||
Plan Assets [Roll Forward] | |||
Fair value of plan assets, end of period | 150.1 | 155.2 | |
Qualified Plans | |||
Fair value of plan assets, end of period | 150.1 | 155.2 | |
International equities and equity funds [Member] | |||
Plan Assets [Roll Forward] | |||
Fair value of plan assets, end of period | 38.4 | 41.9 | |
Qualified Plans | |||
Fair value of plan assets, end of period | 38.4 | 41.9 | |
Domestic bonds and bond funds [Member] | |||
Plan Assets [Roll Forward] | |||
Fair value of plan assets, end of period | 85.9 | 95.8 | |
Qualified Plans | |||
Fair value of plan assets, end of period | 85.9 | 95.8 | |
Inflation protected security fund [Member] | |||
Plan Assets [Roll Forward] | |||
Fair value of plan assets, end of period | 11.1 | 12.1 | |
Qualified Plans | |||
Fair value of plan assets, end of period | 11.1 | 12.1 | |
Real estate, commodities and other [Member] | |||
Plan Assets [Roll Forward] | |||
Fair value of plan assets, end of period | 20.1 | 18.9 | |
Qualified Plans | |||
Fair value of plan assets, end of period | 20.1 | 18.9 | |
Fair Value, Inputs, Level 1 [Member] | |||
Plan Assets [Roll Forward] | |||
Fair value of plan assets, end of period | 145.8 | 158.1 | |
Qualified Plans | |||
Fair value of plan assets, end of period | 145.8 | 158.1 | |
Fair Value, Inputs, Level 1 [Member] | Domestic equities and equity funds [Member] | |||
Plan Assets [Roll Forward] | |||
Fair value of plan assets, end of period | 62.8 | 69.6 | |
Qualified Plans | |||
Fair value of plan assets, end of period | 62.8 | 69.6 | |
Fair Value, Inputs, Level 1 [Member] | International equities and equity funds [Member] | |||
Plan Assets [Roll Forward] | |||
Fair value of plan assets, end of period | 38.4 | 41.9 | |
Qualified Plans | |||
Fair value of plan assets, end of period | 38.4 | 41.9 | |
Fair Value, Inputs, Level 1 [Member] | Domestic bonds and bond funds [Member] | |||
Plan Assets [Roll Forward] | |||
Fair value of plan assets, end of period | 38.8 | 40.4 | |
Qualified Plans | |||
Fair value of plan assets, end of period | 38.8 | 40.4 | |
Fair Value, Inputs, Level 1 [Member] | Inflation protected security fund [Member] | |||
Plan Assets [Roll Forward] | |||
Fair value of plan assets, end of period | 0 | 0 | |
Qualified Plans | |||
Fair value of plan assets, end of period | 0 | 0 | |
Fair Value, Inputs, Level 1 [Member] | Real estate, commodities and other [Member] | |||
Plan Assets [Roll Forward] | |||
Fair value of plan assets, end of period | 5.8 | 6.2 | |
Qualified Plans | |||
Fair value of plan assets, end of period | 5.8 | 6.2 | |
Fair Value, Inputs, Level 2 [Member] | |||
Plan Assets [Roll Forward] | |||
Fair value of plan assets, end of period | 155.6 | 161.7 | |
Common Collective Trust Funds [Abstract] | |||
Portion of Common Collective Trust Funds comprised of equity funds (in hundredths) | 56.00% | 53.00% | |
Portion of Common Collective Trust Funds comprised of fixed income funds (in hundredths) | 37.00% | 42.00% | |
Fair value of Common Collective Trust Funds | 155.6 | 161.7 | |
Maximum number of days restriction for exchange of shares in Common Collective Trust Funds (in days) | 31 | ||
Qualified Plans | |||
Fair value of plan assets, end of period | 155.6 | 161.7 | |
Fair Value, Inputs, Level 2 [Member] | Domestic equities and equity funds [Member] | |||
Plan Assets [Roll Forward] | |||
Fair value of plan assets, end of period | 87.3 | 85.6 | |
Qualified Plans | |||
Fair value of plan assets, end of period | 87.3 | 85.6 | |
Fair Value, Inputs, Level 2 [Member] | International equities and equity funds [Member] | |||
Plan Assets [Roll Forward] | |||
Fair value of plan assets, end of period | 0 | 0 | |
Qualified Plans | |||
Fair value of plan assets, end of period | 0 | 0 | |
Fair Value, Inputs, Level 2 [Member] | Domestic bonds and bond funds [Member] | |||
Plan Assets [Roll Forward] | |||
Fair value of plan assets, end of period | 47.1 | 55.4 | |
Qualified Plans | |||
Fair value of plan assets, end of period | 47.1 | 55.4 | |
Fair Value, Inputs, Level 2 [Member] | Inflation protected security fund [Member] | |||
Plan Assets [Roll Forward] | |||
Fair value of plan assets, end of period | 11.1 | 12.1 | |
Qualified Plans | |||
Fair value of plan assets, end of period | 11.1 | 12.1 | |
Fair Value, Inputs, Level 2 [Member] | Real estate, commodities and other [Member] | |||
Plan Assets [Roll Forward] | |||
Fair value of plan assets, end of period | 10.1 | 8.6 | |
Qualified Plans | |||
Fair value of plan assets, end of period | 10.1 | 8.6 | |
Fair Value, Inputs, Level 3 [Member] | |||
Plan Assets [Roll Forward] | |||
Fair value of plan assets, end of period | 4.2 | 4.1 | |
Qualified Plans | |||
Fair value of plan assets, end of period | 4.2 | 4.1 | |
Fair Value, Inputs, Level 3 [Member] | Domestic equities and equity funds [Member] | |||
Plan Assets [Roll Forward] | |||
Fair value of plan assets, end of period | 0 | 0 | |
Qualified Plans | |||
Fair value of plan assets, end of period | 0 | 0 | |
Fair Value, Inputs, Level 3 [Member] | International equities and equity funds [Member] | |||
Plan Assets [Roll Forward] | |||
Fair value of plan assets, end of period | 0 | 0 | |
Qualified Plans | |||
Fair value of plan assets, end of period | 0 | 0 | |
Fair Value, Inputs, Level 3 [Member] | Domestic bonds and bond funds [Member] | |||
Plan Assets [Roll Forward] | |||
Fair value of plan assets, end of period | 0 | 0 | |
Qualified Plans | |||
Fair value of plan assets, end of period | 0 | 0 | |
Fair Value, Inputs, Level 3 [Member] | Inflation protected security fund [Member] | |||
Plan Assets [Roll Forward] | |||
Fair value of plan assets, end of period | 0 | 0 | |
Qualified Plans | |||
Fair value of plan assets, end of period | 0 | 0 | |
Fair Value, Inputs, Level 3 [Member] | Real estate, commodities and other [Member] | |||
Plan Assets [Roll Forward] | |||
Fair value of plan assets, end of period | 4.2 | 4.1 | |
Qualified Plans | |||
Fair value of plan assets, end of period | 4.2 | 4.1 | |
Other Pension Plans, Defined Benefit [Member] | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Number of qualified defined benefit pension plans | 3 | ||
Net periodic benefit costs [Abstract] | |||
Service cost | 7.4 | 8.6 | 7.7 |
Interest cost | 15.5 | 14.7 | 15.5 |
Expected return on plan assets | -22.7 | -22.1 | -21.2 |
Amortization of prior service cost (benefit) | 1 | 1.5 | 1.6 |
Amortization of actuarial loss (gain) | 5 | 10.1 | 6.8 |
Amortization of transitional obligation | 0 | 0 | 0 |
Settlement (credit) charge | 3.1 | 1.3 | 0 |
Net periodic benefit cost | 9.3 | 14.1 | 10.4 |
Discount Rate (in hundredths) | 4.74% | 4.03% | 4.82% |
Rate of compensation increase (in hundredths) | 3.50% | 3.50% | 3.50% |
Expected return on plan assets (in hundredths) | 7.75% | 7.75% | 7.75% |
Assumptions used to calculate benefit obligations [Abstract] | |||
Discount rate (in hundredths) | 4.05% | 4.74% | |
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Rate of Compensation Increase | 3.50% | 3.50% | |
Benefit Obligation [Roll Forward] | |||
Benefit obligation, beginning of period | 338.4 | 377.3 | |
Service cost - benefits earned during the period | 7.4 | 8.6 | 7.7 |
Interest cost on projected benefit obligation | 15.5 | 14.7 | 15.5 |
Plan participants' contributions | 0 | 0 | |
Plan amendments | 0 | 0 | |
Actuarial loss (gain) | 48.5 | -32.7 | |
Settlement loss | 1.7 | 1.5 | |
Medicare subsidy receipts | 0 | 0 | |
Benefit payments | -25.3 | -22.8 | |
Settlement payments | -14.3 | -8.2 | |
Benefit obligation, end of period | 371.9 | 338.4 | 377.3 |
Accumulated benefit obligation for all defined benefit pension plans | 356.4 | 321.9 | |
Plan Assets [Roll Forward] | |||
Plan assets at fair value, beginning of period [Roll Forward] | 323.9 | 295.7 | |
Actual return on plan assets | 20.1 | 48.4 | |
Employer contributions | 1.2 | 10.8 | |
Plan participants' contributions | 0 | 0 | |
Benefit payments | -25.3 | -22.8 | |
Settlement payments | -14.3 | -8.2 | |
Fair value of plan assets, end of period | 305.6 | 323.9 | 295.7 |
Qualified Plans | |||
Benefit obligation, end of period | -351.7 | -321 | |
Fair value of plan assets, end of period | 305.6 | 323.9 | 295.7 |
Funded Status of Qualified Plans, end of period | -46.1 | 2.9 | |
Benefit obligation of SERP Plan, end of period | -20.2 | -17.5 | |
Total funded status, end of period | -66.3 | -14.6 | |
Accrued liabilities | 1.2 | 1 | |
Deferred credits and other liabilities | 65.1 | 20.1 | |
Other Assets | 0 | 6.5 | |
Contributions expected to be made to pension plan trusts in the next fiscal year | 20 | ||
Estimated future benefit payments [Abstract] | |||
Expected future benefit payments, year one | 24.7 | ||
Expected future benefit payments, year two | 25.7 | ||
Expected future benefit payments, year three | 36.1 | ||
Expected future benefit payments, year four | 26.7 | ||
Expected future benefit payments, year five | 27.8 | ||
Expected future benefit payments, years six through ten | 143.8 | ||
Prior service costs [Roll Forward] | |||
Balance, beginning of year | 3 | 4.5 | 5.4 |
Amounts arising during the period | 0 | 0 | 0.7 |
Reclassification to benefit costs | -1 | -1.5 | -1.6 |
Balance, end of year | 2 | 3 | 4.5 |
Net gain or loss [Roll Forward] | |||
Balance, beginning of year | 67.3 | 136.2 | 116.6 |
Amounts arising during the period | 49.4 | -58.8 | 26.4 |
Reclassification to benefit costs | -5 | -10.1 | -6.8 |
Balance, end of year | 111.7 | 67.3 | 136.2 |
Transition obligation [Roll Forward] | |||
Balance, beginning of year | 0 | ||
Balance, end of year | 0 | 0 | |
Reconciliation of amounts in Accumulated other comprehensive income and Regulatory assets | |||
Prior service cost | 2 | 3 | 4.5 |
Unamortized actuarial gain/(loss) | 111.7 | 67.3 | 136.2 |
Transition obligation | 0 | 0 | |
Sub total | 113.7 | 70.3 | |
Less: Regulatory asset deferral | -111.4 | -68.9 | |
AOCI before taxes | 2.3 | 1.4 | |
Amounts that will be amortized from Accumulated Other Comprehensive Income (Loss) in next year [Abstract] | |||
Prior service cost expected to be amortized in next year | 1 | ||
Actuarial gain/loss expected to be amortized in next year | 8.5 | ||
Other Pension Plans, Defined Benefit [Member] | Equity Securities [Member] | |||
Plan Assets [Roll Forward] | |||
Target percentage of investments in equity instruments (in hundredths) | 60.00% | ||
Other Pension Plans, Defined Benefit [Member] | Debt Securities [Member] | |||
Plan Assets [Roll Forward] | |||
Target percentage of investments in equity instruments (in hundredths) | 35.00% | ||
Other Pension Plans, Defined Benefit [Member] | Real estate, commodities and other [Member] | |||
Plan Assets [Roll Forward] | |||
Target percentage of investments in equity instruments (in hundredths) | 5.00% | ||
Other Postretirement Benefit Plans, Defined Benefit [Member] | |||
Net periodic benefit costs [Abstract] | |||
Service cost | 0.4 | 0.5 | 0.5 |
Interest cost | 2.3 | 2 | 2.8 |
Expected return on plan assets | 0 | 0 | 0 |
Amortization of prior service cost (benefit) | -3 | -3.2 | -2.5 |
Amortization of actuarial loss (gain) | 0.4 | 0.7 | 0.7 |
Amortization of transitional obligation | 0 | 0 | 0.5 |
Settlement (credit) charge | 0 | 0 | 0 |
Net periodic benefit cost | 0.1 | 0 | 2 |
Discount Rate (in hundredths) | 4.66% | 3.91% | 4.75% |
Expected increase in Consumer Price Index (in hundredths) | 2.75% | 2.75% | 2.75% |
Assumptions used to calculate benefit obligations [Abstract] | |||
Discount rate (in hundredths) | 3.95% | 4.66% | |
Expected increase in Consumer Price Index (in hundredths) | 2.50% | 2.75% | |
Benefit Obligation [Roll Forward] | |||
Benefit obligation, beginning of period | 51.3 | 54.4 | |
Service cost - benefits earned during the period | 0.4 | 0.5 | 0.5 |
Interest cost on projected benefit obligation | 2.3 | 2 | 2.8 |
Plan participants' contributions | 0.9 | 0.8 | |
Plan amendments | 0 | -0.2 | |
Actuarial loss (gain) | 3.2 | -2.4 | |
Settlement loss | 0 | 0 | |
Medicare subsidy receipts | 0 | 0 | |
Benefit payments | -4.8 | -3.8 | |
Settlement payments | 0 | 0 | |
Benefit obligation, end of period | 53.3 | 51.3 | 54.4 |
Assumption of percentage increase in medical claims cost for next fiscal year (in hundredths) | 6.50% | ||
Ultimate trending increase of medical claims cost (in hundredths) | 5.00% | ||
Year that rate reaches ultimate trend rate | 2018 | ||
Dollar impact of a one-percentage point change in assumed health care cost trend rates | 0.3 | ||
Plan Assets [Roll Forward] | |||
Plan assets at fair value, beginning of period [Roll Forward] | 0 | 0 | |
Actual return on plan assets | 0 | 0 | |
Employer contributions | 3.9 | 3 | |
Plan participants' contributions | 0.9 | 0.8 | |
Benefit payments | -4.8 | -3.8 | |
Settlement payments | 0 | 0 | |
Fair value of plan assets, end of period | 0 | 0 | 0 |
Qualified Plans | |||
Benefit obligation, end of period | -53.3 | -51.4 | |
Fair value of plan assets, end of period | 0 | 0 | 0 |
Funded Status of Qualified Plans, end of period | -53.3 | -51.4 | |
Benefit obligation of SERP Plan, end of period | 0 | 0 | |
Total funded status, end of period | -53.3 | -51.4 | |
Accrued liabilities | 4.6 | 4.9 | |
Deferred credits and other liabilities | 48.7 | 46.4 | |
Other Assets | 0 | 0 | |
Other postretirement benefit payments to be made during the next fiscal year | 3.5 | ||
Estimated future benefit payments [Abstract] | |||
Expected future benefit payments, year one | 4.6 | ||
Expected future benefit payments, year two | 4.7 | ||
Expected future benefit payments, year three | 4.8 | ||
Expected future benefit payments, year four | 5.1 | ||
Expected future benefit payments, year five | 5.4 | ||
Expected future benefit payments, years six through ten | 28.8 | ||
Prior service costs [Roll Forward] | |||
Balance, beginning of year | -20.1 | -23.1 | -1.2 |
Amounts arising during the period | 0 | -0.2 | -24.4 |
Reclassification to benefit costs | 3 | 3.2 | 2.5 |
Balance, end of year | -17.1 | -20.1 | -23.1 |
Net gain or loss [Roll Forward] | |||
Balance, beginning of year | 8.1 | 11.2 | 9.1 |
Amounts arising during the period | 3.2 | -2.4 | 2.8 |
Reclassification to benefit costs | -0.4 | -0.7 | -0.7 |
Balance, end of year | 10.9 | 8.1 | 11.2 |
Transition obligation [Roll Forward] | |||
Balance, beginning of year | 0 | 0 | 2.7 |
Amounts arising during the period | 0 | 0 | -2.2 |
Reclassification to benefit costs | 0 | 0 | -0.5 |
Balance, end of year | 0 | 0 | 0 |
Reconciliation of amounts in Accumulated other comprehensive income and Regulatory assets | |||
Prior service cost | -17.1 | -20.1 | -23.1 |
Unamortized actuarial gain/(loss) | 10.9 | 8.1 | 11.2 |
Transition obligation | 0 | 0 | 0 |
Sub total | -6.2 | -12 | |
Less: Regulatory asset deferral | 6.1 | 11.8 | |
AOCI before taxes | -0.1 | -0.2 | |
Amounts that will be amortized from Accumulated Other Comprehensive Income (Loss) in next year [Abstract] | |||
Prior service cost expected to be amortized in next year | 3 | ||
Actuarial gain/loss expected to be amortized in next year | $0.70 | ||
Multi-employer Pension Plan [Member] | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Number of qualified defined benefit pension plans | 50 | ||
Multiemployer Benefit Plan [Abstract] | |||
Defined benefit plan, number of significant plans | 4 | ||
Required percentage improvement of plans in funding improvement plans | 33.00% | ||
Number of years in period of funding improvement plan | 10 | ||
Target funding percentage at the end of funding improvement time period | 78.00% | ||
Number of plans in red zone status receiving company contributions | 8 | ||
Number of plans in red zone status considered significant by the Company | 1 | ||
Number of plans whereby company contributions exceed 5% of plan balance | 4 | ||
Percentage threshold by which plan contributions are considered significant | 5.00% |
Borrowing_Arrangements_Details
Borrowing Arrangements (Details) (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2012 | Dec. 31, 2013 | |
Long term debt [Abstract] | |||
Total long term debt outstanding | $1,578,500,000 | $1,808,500,000 | |
Current maturities of long-term debt | -170,000,000 | -30,000,000 | |
Unamortized debt premium and discount - net | -1,200,000 | -1,400,000 | |
Long-term debt - net of current maturities and debt subject to tender | 1,407,300,000 | 1,777,100,000 | |
Maturities of long term debt [Abstract] | |||
Debt maturing within 12 months following date of latest balance sheet | 170,000,000 | ||
Debt maturing within two years following date of latest balance sheet | 73,000,000 | ||
Debt maturing within three years following date of latest balance sheet | 75,000,000 | ||
Debt maturing within four years following date of latest balance sheet | 100,000,000 | ||
Debt maturing within five years following date of latest balance sheet | 60,000,000 | ||
Debt maturing thereafter 5 years following date of the latest balance sheet | 1,099,300,000 | ||
Covenants [Abstract] | |||
Ratio of consolidated total debt to consolidated total capitalization, maximum ( in hundredths) | not exceed 65 percent | ||
Fixed Rate Senior Unsecured Notes [Member] | 2042, 5.00% [Member] | |||
Long term debt [Abstract] | |||
Debt Issuance | 100,000,000 | ||
Proceeds from debt issuance | 99,500,000 | ||
Fixed rate stated percentage (in hundredths) | 5.00% | ||
Maturity date | 3-Feb-42 | ||
Debt Instrument Issuance Date | 1-Feb-12 | ||
Utility Holdings [Member] | |||
Debt guarantees [Abstract] | |||
Long-term guarantees | 875,000,000 | ||
Short-term debt guarantees | 156,000,000 | ||
Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member] | |||
Long term debt [Abstract] | |||
Total long term debt outstanding | 875,000,000 | 875,000,000 | |
Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2015, 5.45% [Member] | |||
Long term debt [Abstract] | |||
Total long term debt outstanding | 75,000,000 | 75,000,000 | |
Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2018, 5.75% [Member] | |||
Long term debt [Abstract] | |||
Total long term debt outstanding | 100,000,000 | 100,000,000 | |
Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2020, 6.28% [Member] | |||
Long term debt [Abstract] | |||
Total long term debt outstanding | 100,000,000 | 100,000,000 | |
Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2021, 4.67 [Member] | |||
Long term debt [Abstract] | |||
Total long term debt outstanding | 55,000,000 | 55,000,000 | |
Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2023, 3.72% [Member] | |||
Long term debt [Abstract] | |||
Fixed rate stated percentage (in hundredths) | 3.72% | ||
Total long term debt outstanding | 150,000,000 | 150,000,000 | |
Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member] | Fixed Rate Senior Unsecured Notes 2013525 [Member] | |||
Long term debt [Abstract] | |||
Debt Issuance | 100,000,000 | ||
Fixed rate stated percentage (in hundredths) | 5.25% | ||
Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2026, 5.02% [Member] | |||
Long term debt [Abstract] | |||
Total long term debt outstanding | 60,000,000 | 60,000,000 | |
Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2028, 3.20% [Member] | |||
Long term debt [Abstract] | |||
Fixed rate stated percentage (in hundredths) | 3.20% | ||
Total long term debt outstanding | 45,000,000 | 45,000,000 | |
Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2035, 6.10% [Member] | |||
Long term debt [Abstract] | |||
Total long term debt outstanding | 75,000,000 | 75,000,000 | |
Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2041, 5.99% [Member] | |||
Long term debt [Abstract] | |||
Total long term debt outstanding | 35,000,000 | 35,000,000 | |
Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2042, 5.00% [Member] | |||
Long term debt [Abstract] | |||
Total long term debt outstanding | 100,000,000 | 100,000,000 | |
Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2043, 4.25% [Member] | |||
Long term debt [Abstract] | |||
Fixed rate stated percentage (in hundredths) | 4.25% | ||
Total long term debt outstanding | 80,000,000 | 80,000,000 | |
Indiana Gas [Member] | Fixed Rate Senior Unsecured Notes [Member] | |||
Long term debt [Abstract] | |||
Total long term debt outstanding | 116,000,000 | 116,000,000 | |
Indiana Gas [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2015, Series E, 7.15% [Member] | |||
Long term debt [Abstract] | |||
Total long term debt outstanding | 5,000,000 | 5,000,000 | |
Indiana Gas [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2015, Series E, 6.69% [Member] | |||
Long term debt [Abstract] | |||
Total long term debt outstanding | 5,000,000 | 5,000,000 | |
Indiana Gas [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2015, Series E1, 6.69% [Member] | |||
Long term debt [Abstract] | |||
Total long term debt outstanding | 10,000,000 | 10,000,000 | |
Indiana Gas [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2025, Series E, 6.53% [Member] | |||
Long term debt [Abstract] | |||
Total long term debt outstanding | 10,000,000 | 10,000,000 | |
Indiana Gas [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2027, Series E, 6.42% [Member] | |||
Long term debt [Abstract] | |||
Total long term debt outstanding | 5,000,000 | 5,000,000 | |
Indiana Gas [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2027, Series E, 6.68% [Member] | |||
Long term debt [Abstract] | |||
Total long term debt outstanding | 1,000,000 | 1,000,000 | |
Indiana Gas [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2027, Series F, 6.34% [Member] | |||
Long term debt [Abstract] | |||
Total long term debt outstanding | 20,000,000 | 20,000,000 | |
Indiana Gas [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2028, Series F, 6.36% [Member] | |||
Long term debt [Abstract] | |||
Total long term debt outstanding | 10,000,000 | 10,000,000 | |
Indiana Gas [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2028, Series F, 6.55% [Member] | |||
Long term debt [Abstract] | |||
Total long term debt outstanding | 20,000,000 | 20,000,000 | |
Indiana Gas [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2029, Series G, 7.08% [Member] | |||
Long term debt [Abstract] | |||
Total long term debt outstanding | 30,000,000 | 30,000,000 | |
SIGECO [Member] | First Mortgage Bonds [Member] | |||
Long term debt [Abstract] | |||
Proceeds from debt issuance | 60,000,000 | ||
SIGECO [Member] | First Mortgage Bonds [Member] | Tax Exempt Debt, 1.95 Percent [Member] | |||
Long term debt [Abstract] | |||
Proceeds from debt issuance | 48,300,000 | ||
Fixed rate stated percentage (in hundredths) | 1.95% | ||
Amount of debt to be re-marketed | 49,000,000 | ||
Debt re-market date | 13-Aug-13 | ||
SIGECO [Member] | Mortgages [Member] | |||
Long term debt [Abstract] | |||
Total long term debt outstanding | 267,500,000 | 267,500,000 | |
Future long term debt sinking fund fund requirements and maturities [Abstract] | |||
Annual sinking fund requirement fixed percentage (in hundredths) | 1.00% | ||
Utility plant remaining unfunded under mortgage indenture | 1,300,000,000 | ||
Gross utility plant balance subject to the mortgage indenture | 3,000,000,000 | ||
SIGECO [Member] | Mortgages [Member] | 2015, 1985 Pollution Control Series A, current adjustable rate 0.05%, tax exempt, 2013 weighted average: 0.10% | |||
Long term debt [Abstract] | |||
Total long term debt outstanding | 0 | 9,800,000 | |
SIGECO [Member] | Mortgages [Member] | 2016, 1986 Series, 8.875% [Member] | |||
Long term debt [Abstract] | |||
Total long term debt outstanding | 13,000,000 | 13,000,000 | |
SIGECO [Member] | Mortgages [Member] | 2022, 2013 Series C, 1.95% tax exempt [Member] | |||
Long term debt [Abstract] | |||
Total long term debt outstanding | 4,600,000 | 4,600,000 | |
SIGECO [Member] | Mortgages [Member] | 2024, 2013 Series D, 1.95% tax exempt [Member] | |||
Long term debt [Abstract] | |||
Total long term debt outstanding | 22,500,000 | 22,500,000 | |
SIGECO [Member] | Mortgages [Member] | 2025, 1998 Pollution Control Series A, current adjustable rate 0.05%, tax exempt, 2013 weighted average: 0.10% | |||
Long term debt [Abstract] | |||
Total long term debt outstanding | 0 | 31,500,000 | |
SIGECO [Member] | Mortgages [Member] | 2025, 2014 Series B, 0.722% tax exempt [Member] | |||
Long term debt [Abstract] | |||
Total long term debt outstanding | 41,300,000 | 0 | |
SIGECO [Member] | Mortgages [Member] | 2029, 1999 Senior Notes, 6.72% [Member] | |||
Long term debt [Abstract] | |||
Total long term debt outstanding | 80,000,000 | 80,000,000 | |
SIGECO [Member] | Mortgages [Member] | 2037, 2013 Series E 1.95% Tax Exempt [Member] | |||
Long term debt [Abstract] | |||
Total long term debt outstanding | 22,000,000 | 22,000,000 | |
SIGECO [Member] | Mortgages [Member] | 2038, 2013 Series A, 4.00% Tax Exempt [Member] | |||
Long term debt [Abstract] | |||
Fixed rate stated percentage (in hundredths) | 4.00% | ||
Total long term debt outstanding | 22,200,000 | 22,200,000 | |
SIGECO [Member] | Mortgages [Member] | 2040, 2009 Environmental Improvement Series, 5.40%, tax exempt [Member] | |||
Long term debt [Abstract] | |||
Total long term debt outstanding | 0 | 22,300,000 | |
SIGECO [Member] | Mortgages [Member] | 2043, 2013 Series B 4.05% Tax Exempt [Member] | |||
Long term debt [Abstract] | |||
Fixed rate stated percentage (in hundredths) | 4.05% | ||
Total long term debt outstanding | 39,600,000 | 39,600,000 | |
SIGECO [Member] | Mortgages [Member] | 2044, 2014 Series A 4.00% Tax Exempt [Member] | |||
Long term debt [Abstract] | |||
Fixed rate stated percentage (in hundredths) | 4.00% | ||
Total long term debt outstanding | 22,300,000 | 0 | |
Vectren Capital Corp. [Member] | |||
Debt guarantees [Abstract] | |||
Long-term guarantees | 320,000,000 | ||
Short-term debt guarantees | 0 | ||
Vectren Capital Corp. [Member] | Fixed Rate Senior Unsecured Notes [Member] | |||
Long term debt [Abstract] | |||
Total long term debt outstanding | 320,000,000 | 550,000,000 | |
Vectren Capital Corp. [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2014, 6.37% [Member] | |||
Long term debt [Abstract] | |||
Fixed rate stated percentage (in hundredths) | 6.37% | ||
Total long term debt outstanding | 0 | 30,000,000 | |
Vectren Capital Corp. [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2015, 5.31% [Member] | |||
Long term debt [Abstract] | |||
Total long term debt outstanding | 75,000,000 | 75,000,000 | |
Vectren Capital Corp. [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2016, 6.92% [Member] | |||
Long term debt [Abstract] | |||
Total long term debt outstanding | 60,000,000 | 60,000,000 | |
Vectren Capital Corp. [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2017, 3.48% [Member] | |||
Long term debt [Abstract] | |||
Total long term debt outstanding | 75,000,000 | 75,000,000 | |
Vectren Capital Corp. [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2019, 7.30% [Member] | |||
Long term debt [Abstract] | |||
Total long term debt outstanding | 60,000,000 | 60,000,000 | |
Vectren Capital Corp. [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2025, 4.53% [Member] | |||
Long term debt [Abstract] | |||
Total long term debt outstanding | 50,000,000 | 50,000,000 | |
Vectren Capital Corp. [Member] | Variable Rate Term Loan [Member] | 2015 Adjustable Rate 117 Term Loan [Member] [Member] | |||
Long term debt [Abstract] | |||
Proceeds from debt issuance | 100,000,000 | ||
Total long term debt outstanding | 0 | 100,000,000 | |
Vectren Capital Corp. [Member] | Variable Rate Term Loan [Member] | 2016 Term Loan [Member] | |||
Long term debt [Abstract] | |||
Proceeds from debt issuance | 100,000,000 | ||
Total long term debt outstanding | 0 | 100,000,000 | |
Vectren Capital Corp. [Member] | Nonutility Group [Member] | Variable Rate Term Loan [Member] | |||
Debt Instrument [Line Items] | |||
Extinguishment of Debt, Amount | 200,000,000 | ||
Vectren Utility Holdings Inc [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2023, 3.72% [Member] | |||
Long term debt [Abstract] | |||
Proceeds from debt issuance | 149,100,000 | ||
Debt Instrument Issuance Date | 5-Dec-13 | ||
Vectren Utility Holdings Inc [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2028, 3.20% [Member] | |||
Long term debt [Abstract] | |||
Proceeds from debt issuance | 44,800,000 | ||
Debt Instrument Issuance Date | 5-Jun-13 | ||
Vectren Utility Holdings Inc [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2043, 4.25% [Member] | |||
Long term debt [Abstract] | |||
Proceeds from debt issuance | 79,600,000 | ||
Debt Instrument Issuance Date | 5-Jun-13 | ||
Vectren Utility Holdings Inc [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2039, 6.25% [Member] | |||
Long term debt [Abstract] | |||
Debt Issuance | 121,600,000 | ||
Fixed rate stated percentage (in hundredths) | 6.25% | ||
Debt Instrument Maturity Date Year | 2039 | ||
Current maturities of long-term debt | ($121,600,000) | ||
Debt redemption date | 1-Apr-13 |
Borrowing_Arrangements_ShortTe
Borrowing Arrangements Short-Term Borrowings (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Short-term borrowings [Abstract] | |||
Short-term borrowing capacity | $600 | ||
Balance Outstanding, end of period | 156.4 | 68.6 | |
Utility Group [Member] | |||
Short-term borrowings [Abstract] | |||
Short-term borrowing capacity | 350 | ||
Short term borrowings available | 194 | ||
Balance Outstanding, end of period | 156.4 | 28.6 | 116.7 |
Weighted Average Interest Rate, end of period (in hundredths) | 0.50% | 0.29% | 0.40% |
Balance Outstanding, annual average | 35.6 | 119.6 | 77.6 |
Weighted Average Interest Rate, annual average (in hundredths) | 0.34% | 0.34% | 0.47% |
Maximum Month End Balance Outstanding | 156.4 | 176.1 | 214.2 |
Nonutility Group [Member] | |||
Short-term borrowings [Abstract] | |||
Short-term borrowing capacity | 250 | ||
Short term borrowings available | 250 | ||
Balance Outstanding, end of period | 0 | 40 | 162.1 |
Weighted Average Interest Rate, end of period (in hundredths) | 1.27% | 1.35% | |
Balance Outstanding, annual average | 34.5 | 119.3 | 151.5 |
Weighted Average Interest Rate, annual average (in hundredths) | 1.29% | 1.35% | 1.44% |
Maximum Month End Balance Outstanding | $76.30 | $173.80 | $216.10 |
Common_Shareholders_Equity_Det
Common Shareholder's Equity (Details) | Dec. 31, 2014 | Dec. 31, 2013 |
In Millions, unless otherwise specified | ||
Authorized, reserved common and preferred shares [Abstract] | ||
Common stock, shares authorized for issue (in shares) | 480 | 480 |
Preferred stock , shares authorized for issue (in shares) | 20 | 20 |
Authorized shares of common stock available for issuance (in shares) | 392.2 | 391.7 |
Authorized shares of preferred stock available for issuance (in shares) | 20 | 20 |
Number of shares reserved for issuance under share-based compensation plans, benefit plans, and dividend reinvestment plan (in shares) | 5.3 | 5.8 |
Earnings_Per_Share_Details
Earnings Per Share (Details) (USD $) | 3 Months Ended | 12 Months Ended | |||||||||
In Millions, except Per Share data, unless otherwise specified | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Earnings Per Share [Abstract] | |||||||||||
Numerator for basic earnings per share | $166.90 | $136.60 | $159 | ||||||||
Add back earnings attributable to participating securities | 0 | 0 | 0 | ||||||||
Reported net income (Numerator for diluted earnings per share) | $166.90 | $136.60 | $159 | ||||||||
Weighted average common shares outstanding (Basic earnings per share) (in shares) | 82.5 | 82.3 | 82 | ||||||||
Conversion of share based compensation arrangements | 0 | 0.1 | 0.1 | ||||||||
Adjusted weighted average shares outstanding and assumed conversions outstanding (Diluted earnings per share) (in shares) | 82.5 | 82.4 | 82.1 | ||||||||
Earnings Per Share, Basic | $0.68 | $0.57 | $0.14 | $0.62 | $0.60 | $0.52 | ($0.07) | $0.61 | $2.02 | $1.66 | $1.94 |
Earnings Per Share, Diluted | $0.68 | $0.57 | $0.14 | $0.62 | $0.60 | $0.52 | ($0.07) | $0.61 | $2.02 | $1.66 | $1.94 |
Accumulated_Other_Comprehensiv2
Accumulated Other Comprehensive Income (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||
Balance, beginning of period | ($0.70) | ($4.30) | ($13.30) |
Changes during period | -0.6 | 3.6 | 9 |
Balance, end of period | -1.3 | -0.7 | -4.3 |
Unconsolidated Affiliates [Member] | |||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||
Balance, beginning of period | 0 | -4.6 | -15.9 |
Changes during period | 0 | 4.6 | 11.3 |
Balance, end of period | 0 | 0 | -4.6 |
Pension and Other Benefit Costs [Member] | |||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||
Balance, beginning of period | -1.2 | -2.6 | -6.6 |
Changes during period | -1 | 1.4 | 4 |
Balance, end of period | -2.2 | -1.2 | -2.6 |
Cash Flow Hedges [Member] | |||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||
Balance, beginning of period | 0 | 0 | 0.1 |
Changes during period | 0 | 0 | -0.1 |
Balance, end of period | 0 | 0 | 0 |
Deferred Income Taxes [Member] | |||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||
Balance, beginning of period | 0.5 | 2.9 | 9.1 |
Changes during period | 0.4 | -2.4 | -6.2 |
Balance, end of period | $0.90 | $0.50 | $2.90 |
ShareBased_Compensation_Deferr2
Share-Based Compensation & Deferred Compensation Arrangements (Details) (USD $) | 12 Months Ended | ||
In Millions, except Share data, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |||
Total cost of share-based compensation | $25.20 | $14.80 | $6.30 |
Less capitalized cost | 5.3 | 2.8 | 1.2 |
Total in other operating expense | 19.9 | 12 | 5.1 |
Less income tax benefit in earnings | 7.9 | 4.8 | 2.1 |
After tax effect of share-based compensation | 12 | 7.2 | 3 |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Vesting period for performance-based awards to executives and key non-officer employees (in years) | 4 | ||
Performance Measurement Time Frame For Grants To Executives And Key Nonofficer Emplyees In Years | third | ||
Share Based Payment Award Equity Instruments Other Than Options [Roll Forward] | |||
Total unrecognized compensation cost related to performance based awards | 16.5 | ||
Weighted-average life of unrecognized compensation cost (in years) | 1 year 11 months | ||
Deferred Compensation Plans [Abstract] | |||
Liability associated with deferred compensation plans | 31.2 | 26.1 | |
Portion of liability classified in Accrued liabilities | 1.4 | 1.6 | |
Impact of deferred compensation plans on Other operating expenses | 5 | 4 | 1.7 |
Amount recorded in earnings related to the investment activities in phantom stock associated with deferred compensation plans | 4 | 2.6 | 0.6 |
Cash surrender value of life insurance policies | 32.3 | 32.9 | |
Earnings from investments in corporate-owned life insurance policies | 2.8 | 4.8 | 1.8 |
Performance Based Units Equity Method [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Vesting period for awards to certain non-utility employees (in years) | 5 | ||
Share Based Payment Award Equity Instruments Other Than Options [Roll Forward] | |||
Performance based awards at beginning of period (in shares) | 79,957 | ||
Granted (in shares) | 5,910 | ||
Vested (in shares) | -51,594 | ||
Forfeited (in shares) | 0 | ||
Performance based awards at end of period (in shares) | 34,273 | 79,957 | |
Weighted average grant date fair value at beginning of period (in dollars per share) | $29.12 | ||
Weighted average grant date fair value of shares granted during period (in dollars per share) | $31.24 | ||
Weighted average grant date fair value of shares vested during period (in dollars per share) | $28.36 | ||
Weighted average grant date fair value of shares forfeited during period (in dollars per share) | $0 | ||
Weighted average grant date fair value at end of period (in dollars per share) | $30.55 | $29.12 | |
Total fair value of equity awards vested | 0.9 | 0.4 | 0.1 |
Performance Based Units Liability Method [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Vesting period for time-vested awards to non-officer employees (in years) | 3 | ||
Vesting period for awards to non-employee directors (in years) | 1 | ||
Share Based Payment Award Equity Instruments Other Than Options [Roll Forward] | |||
Performance based awards at beginning of period (in shares) | 731,251 | ||
Granted (in shares) | 331,344 | ||
Vested (in shares) | -347,031 | ||
Forfeited (in shares) | -22,405 | ||
Performance based awards at end of period (in shares) | 693,159 | 731,251 | |
Weighted average grant date fair value at end of period (in dollars per share) | $46.23 | ||
Total fair value of liability awards vested | 15.1 | 5.7 | 4.4 |
Stock Options [Member] | |||
Share Based Payment Award Equity Instruments Other Than Options [Roll Forward] | |||
Length of continuous service required for option awards (in years) | 3 years | ||
Option awards term (in years) | 10 | ||
Vesting period of option awards (in years) | 3 years | ||
Share Based Payment Award Options Outstanding [Roll Forward] | |||
Exercisable at end of period (in shares) | 946 | ||
Intrinsic value of options exercised | 0.1 | 3.8 | 0.1 |
Tax benefit realized for tax deductions from option exercises | $0.20 | $1.50 | $0.10 |
Commitments_and_Contingencies_
Commitments and Contingencies (Details) (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Commitments [Abstract] | |||
Future minimum operating lease payments due within one year of the balance sheet date | $8,200,000 | ||
Future minimum operating lease payments due within the second year of the balance sheet date | 5,600,000 | ||
Future minimum operating lease payments due within the third year of the balance sheet date | 3,200,000 | ||
Future minimum operating lease payments due within the fourth year of the balance sheet date | 2,000,000 | ||
Future minimum operating lease payments due within the fifth year of the balance sheet date | 1,600,000 | ||
Future minimum operating lease payments due within after the fifth year of the balance sheet date | 3,600,000 | ||
Total lease expense | 13,200,000 | 9,900,000 | 8,500,000 |
Guarantees for ESG [Member] | |||
Performance Guarantees and Product Warranties [Abstract] | |||
Number of surety bonds wholly owned subsidiary has outstanding in role as general contractor (in number of surety bonds) | 50 | ||
Average face amount of surety bonds wholly owned subsidiary has outstanding | 6,900,000 | ||
Maximum face amount of surety bond wholly owned subsidiary had outstanding | 57,300,000 | ||
Percent of work completed on projects covered by open surety bonds (in hundredths) | 42.00% | ||
Timeframe when significant portion of performance guarantee commitments will be fulfilled | within one year | ||
Product Warranty Accrual | 0 | ||
Performance Guarantee [Member] | Guarantees for ESG [Member] | |||
Corporate Guarantees [Abstract] | |||
Maximum exposure by parent company on guarantees. | 25,000,000 | ||
Performance Guarantee [Member] | Guarantees for Other Unconsolidated Affiliates [Member] | |||
Corporate Guarantees [Abstract] | |||
Maximum exposure by parent company on guarantees. | 17,000,000 | ||
Other Guarantees Outstanding [Member] | Guarantees for ESG [Member] | |||
Corporate Guarantees [Abstract] | |||
Maximum exposure by parent company on guarantees. | 35,000,000 | ||
Financial Standby Letter of Credit [Member] | Guarantees for Other Unconsolidated Affiliates [Member] | |||
Corporate Guarantees [Abstract] | |||
Maximum exposure by parent company on guarantees. | 11,000,000 | ||
Energy Performance Guarantee [Member] | Guarantees for ESG [Member] | |||
Corporate Guarantees [Abstract] | |||
Maximum exposure by parent company on guarantees. | $140 |
Gas_Rate_Regulatory_Matters_De
Gas Rate & Regulatory Matters (Details) (USD $) | 12 Months Ended | 3 Months Ended | |||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2014 | Sep. 30, 2014 | |
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items] | |||||
Other Nonoperating Income (Expense) | $19,700,000 | $17,700,000 | $8,300,000 | ||
Ohio [Member] | Ohio Recovery and Deferral Mechanisms [Member] | |||||
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items] | |||||
Cumulative gross plant invesment made under Distribution Replacement Rider | 150,500,000 | 150,500,000 | |||
Regulatory Asset associated with DRR deferrals of depreciation and post in-service carrying costs | 13,100,000 | 9,300,000 | 13,100,000 | ||
Initial DRR term | 5 | ||||
Extension period requested to recover capital investments | 5 | ||||
Amount of Capital Investment Expected Over Next Five Years Recoverable Under DRR | 200,000,000 | 200,000,000 | |||
Ohio [Member] | House Bill 95 [Member] | |||||
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items] | |||||
Bill impact per customer per month | 1.5 | ||||
Other Nonoperating Income (Expense) | 3,900,000 | 2,200,000 | |||
Amount of deferral related to depreciation and property tax expense | 3,100,000 | 1,700,000 | 3,100,000 | ||
Indiana [Member] | Senate Bill 251 and 560 [Member] | |||||
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items] | |||||
Percentage of costs eligible for recovery using periodic rate recovery mechanism | 80.00% | 80.00% | |||
Percentage of project costs to be deferred for future recovery | 20.00% | 20.00% | |||
Length of project plan required for recovery under new legislation | 7 | ||||
Expected Seven Year Period Modernization Investment | 900,000,000 | 900,000,000 | |||
Capital Expenditure Increases | 35,000,000 | 35,000,000 | |||
Economic Development Expenditures | 30,000,000 | 30,000,000 | |||
Expected annual operating costs associated with new pipeline safety regulations | 15,000,000 | ||||
Indiana [Member] | Indiana Recovery and Deferral Mechanisms [Member] | |||||
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items] | |||||
Regulatory Assset balance associated with Vectren north and south programs | 16,400,000 | 12,100,000 | 16,400,000 | ||
SIGECO [Member] | Indiana [Member] | Indiana Recovery and Deferral Mechanisms [Member] | |||||
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items] | |||||
Allowable expenditures under Vectren South program | 3,000,000 | 3,000,000 | |||
Limitations of deferrals of debt-related post in service carrying costs | 3 | ||||
Indiana Gas [Member] | Indiana [Member] | Indiana Recovery and Deferral Mechanisms [Member] | |||||
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items] | |||||
Allowable capital expenditures under Vectren North Program | 20,000,000 | 20,000,000 | |||
Limitations of deferrals of debt-related post in service carrying costs | 4 | ||||
INDIANA | Indiana Gas [Member] | Indiana Gas GCA Cost Recovery [Member] | |||||
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items] | |||||
Original amount of recovery opposed by OUCC | 3,900,000 | ||||
Amount of recovery supported by OUCC | $3,000,000 |
Electric_Rate_and_Regulatory_M1
Electric Rate and Regulatory Matters Electric Rate and Regulatory Matters (Details) (USD $) | 12 Months Ended | ||||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Feb. 01, 2014 |
Vectren South Electric Environmental Compliance Filing [Abstract] | |||||
Lower range of request for approval of capital investments on cola-fired generation units | $80 | ||||
Upper range of request for approval of capital investments on cola-fired generation units | 90 | ||||
FERC Return On Equity Complaint [Abstract] | |||||
Current return on equity used in MISO transmission owners rates | 12.38% | ||||
Reduced return on equity percentage sought by third party through joint complaint | 9.15% | ||||
Equity component, upper limit, as a percentage, sought by third party through joint complaint | 50.00% | ||||
Gross Investment In Qualifying Transmission Projects | 157.7 | ||||
Net Investment in Qualifying Transmission Projects | 143.6 | ||||
Incentive return granted on qualifying investments in NETO | 11.14% | ||||
Percentage return approved by FERC on ROE complaint against NETO | 10.57% | ||||
Number of incentive basis point above and beyond approved FERC approved ROE | 50 | ||||
Coal Procurement Procedures [Abstract] | |||||
Number of years for recovery of coal costs | 6 years | ||||
Cumulative total deferrals related to coal purchases | 35.3 | 42.4 | |||
Vectren South Electric Demand Side Management Program Filing [Abstract] | |||||
Number Of Years In Initial Demand Side Management Program | 3 | ||||
Maximum Deferral Of Lost Margin Associated With Small Customer DSM Programs | 3 | 1 | |||
Electric revenue recognized associated with lost margin recovery | $8.70 | $5 | |||
Percent of industrial load opt out of applicable energy efficiency programs | 80.00% |
Environmental_Matters_Details
Environmental Matters (Details) (USD $) | 12 Months Ended | |
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 |
MW | ||
Air Quality [Abstract] | ||
SIGECO investment in Property, Plant and Equipment, Pollution control equipment | $411 | |
Property, Plant and Equipment, amount of investment in pollution control equipment included in rate base | 411 | |
Percentage of coal fired generating fleet currently being scrubbed for SO2 (in hundredths) | 100.00% | |
Percentage of coal fired generating fleet currently controlled for NOx (in hundredths) | 90.00% | |
Cost of most of the allowances granted to company for NOx and SO2 inventory usage | 0 | |
Clean Water Act [Abstract] | ||
Estimated capital expenditures to comply with Clean Water Act (Lower Range) | 4 | |
Estimated capital expenditures to comply with Clean Water Act (Upper Range) | 8 | |
Coal Ash Waste Disposal and Ash Ponds [Abstract] | ||
Estimated capital expenditures to comply with ash pond and coal ash disposal regulations | 30 | |
Potential estimated capital expenditures to comply with ash pond and coal ash disposal regulations with stringent alternative | 100 | |
Estimated annual compliance costs maximum with ash pond and coal ash disposal regulation | 5 | |
Climate Changes [Abstract] | ||
Maximum level of greenhouse gas emissions that prompts requirement to obtain permit for facilities to construct new facility of significant modification to existing facility (in tons) | 75,000 | |
Vectren's share of Indiana's total CO2 emmisions in 2013 (in tons) | 6,300,000 | |
Vectren's share of Indiana's total CO2 emissions in 2013 (as a percent) | 6.00% | |
Percent reduction of Vectren's CO2 emissions since 2005 | 23.00% | |
Long term contract for purchase of electric power generated by wind energy (in megawatts) | 80 | |
Percentage of total electricity obtained by the supplier to meet the energy needs of its retail customers provided by clean energy sources (in hundredths) | 4.00% | |
Vectren's emission rate (as measured in lbs CO2/MWh) prior to installation of new technology | 1,967 | |
Vectren's emission rate (as measured in lbs CO2/MWh) after installation of new technology | 1,922 | |
Percentage reduction of lbs CO2/MWh since 2005 | 3.00% | |
Manufactured Gas Plants | ||
Site contingency, accrual, undiscounted amount | 43.4 | |
Accrual for Environmental Loss Contingencies | 3.6 | 5.7 |
SIGECO [Member] | ||
Manufactured Gas Plants | ||
Number of sites identified with potential remedial responsibility for entity (in number of sites) | 5 | |
Site contingency, accrual, undiscounted amount | 20.2 | |
Environmental cost recognized, recover from insurance carriers credited to expense | 14.3 | |
Expected Site Contingency Recovery from Insurance Carriers of Environmental Remediation Costs | 15.8 | |
Indiana Gas [Member] | ||
Manufactured Gas Plants | ||
Number of sites identified with potential remedial responsibility for entity (in number of sites) | 26 | |
Site contingency, accrual, undiscounted amount | 23.2 | |
Environmental cost recognized, recover from insurance carriers credited to expense | $20.80 |
Fair_Value_Measurements_Detail
Fair Value Measurements (Details) (USD $) | 12 Months Ended | |
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 |
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Other Assets, Fair Value Disclosure | $10.40 | $10.40 |
Period to recover call premiums on reacquisition of long-term debt | 15 | |
Carrying Amount [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Long-term debt | 1,577.30 | 1,807.10 |
Short-term borrowings & notes payable | 156.4 | 68.6 |
Cash and cash equivalents | 86.4 | 21.5 |
Estimated Fair Value [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Long-term debt | 1,754.50 | 1,895.20 |
Short-term borrowings & notes payable | 156.4 | 68.6 |
Cash and cash equivalents | $86.40 | $21.50 |
Segment_Reporting_Details
Segment Reporting (Details) (USD $) | 3 Months Ended | 12 Months Ended | |||||||||
In Millions, unless otherwise specified | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Segment Reporting Information [Line Items] | |||||||||||
Property, Plant and Equipment, Additions | $448.30 | $393.40 | $365.80 | ||||||||
Number of reporting segments | 3 | 3 | |||||||||
Number of operating segments in the Nonutility Group | 4 | 4 | |||||||||
Portion Of Indiana That Is Provided Natural Gas Distribution And Transportation Services By Gas Utility Services Segment | 66.67% | 66.67% | |||||||||
Revenues | 676.8 | 595.6 | 542.5 | 796.8 | 680 | 579.6 | 531 | 700.6 | 2,611.70 | 2,491.20 | 2,232.80 |
Net income (loss) | 56.5 | 47.3 | 11.9 | 51.2 | 49.8 | 42.8 | -5.8 | 49.8 | 166.9 | 136.6 | 159 |
Amounts Included in Profitability Measures [Abstract] | |||||||||||
Depreciation and Amortization | 273.4 | 277.8 | 254.6 | ||||||||
Interest Expense | 86.7 | 87.9 | 96 | ||||||||
Income Taxes | 81.1 | 67.1 | 82.5 | ||||||||
Assets | 5,162.30 | 5,102.60 | 5,162.30 | 5,102.60 | |||||||
Utility Group [Member] | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Property, Plant and Equipment, Additions | 350.7 | 261.1 | 246 | ||||||||
Revenues | 1,569.70 | 1,429.60 | 1,333.60 | ||||||||
Net income (loss) | 148.4 | 141.8 | 138 | ||||||||
Amounts Included in Profitability Measures [Abstract] | |||||||||||
Depreciation and Amortization | 203.1 | 196.4 | 190 | ||||||||
Interest Expense | 66.6 | 65 | 71.5 | ||||||||
Income Taxes | 83.2 | 85.3 | 85.3 | ||||||||
Assets | 4,428.10 | 4,140.80 | 4,428.10 | 4,140.80 | |||||||
Utility Group [Member] | Gas Utility Services [Member] | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Property, Plant and Equipment, Additions | 245.9 | 150.5 | 128.8 | ||||||||
Revenues | 944.6 | 810 | 738.1 | ||||||||
Net income (loss) | 57 | 55.7 | 60 | ||||||||
Amounts Included in Profitability Measures [Abstract] | |||||||||||
Depreciation and Amortization | 93.3 | 90.5 | 85.4 | ||||||||
Interest Expense | 34.9 | 30.6 | 31.8 | ||||||||
Income Taxes | 35.7 | 36.6 | 39.1 | ||||||||
Assets | 2,605.10 | 2,287.90 | 2,605.10 | 2,287.90 | |||||||
Utility Group [Member] | Electric Utility Services [Member] | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Property, Plant and Equipment, Additions | 92.4 | 100 | 108.8 | ||||||||
Revenues | 624.8 | 619.3 | 594.9 | ||||||||
Net income (loss) | 79.7 | 75.8 | 68 | ||||||||
Amounts Included in Profitability Measures [Abstract] | |||||||||||
Depreciation and Amortization | 85.7 | 84 | 81.3 | ||||||||
Interest Expense | 29 | 29.2 | 33.8 | ||||||||
Income Taxes | 48.1 | 48.3 | 46.4 | ||||||||
Assets | 1,659.30 | 1,679 | 1,659.30 | 1,679 | |||||||
Utility Group [Member] | Intersegment Elimination [Member] | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Revenues | -38 | -37.8 | -39.5 | ||||||||
Utility Group [Member] | Non-Cash Cost and Change in Accruals [Member] | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Property, Plant and Equipment, Additions | -10.9 | -15.2 | -7.8 | ||||||||
Utility Group [Member] | Other Segments [Member] | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Property, Plant and Equipment, Additions | 23.3 | 25.8 | 16.2 | ||||||||
Revenues | 38.3 | 38.1 | 40.1 | ||||||||
Net income (loss) | 11.7 | 10.3 | 10 | ||||||||
Amounts Included in Profitability Measures [Abstract] | |||||||||||
Depreciation and Amortization | 24.1 | 21.9 | 23.3 | ||||||||
Interest Expense | 2.7 | 5.2 | 5.9 | ||||||||
Income Taxes | -0.6 | 0.4 | -0.2 | ||||||||
Assets | 163.7 | 173.9 | 163.7 | 173.9 | |||||||
Nonutility Group [Member] | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Property, Plant and Equipment, Additions | 97.6 | 132.3 | 119.8 | ||||||||
Revenues | 1,143.10 | 1,167.60 | 1,017.60 | ||||||||
Net income (loss) | 18 | -4.5 | 21.7 | ||||||||
Amounts Included in Profitability Measures [Abstract] | |||||||||||
Depreciation and Amortization | 70.3 | 81.4 | 64.6 | ||||||||
Interest Expense | 20.8 | 23.2 | 24.9 | ||||||||
Income Taxes | -1 | -17.1 | -1.7 | ||||||||
Assets | 748.5 | 1,030.60 | 748.5 | 1,030.60 | |||||||
Nonutility Group [Member] | Infrastructure Services [Member] | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Property, Plant and Equipment, Additions | 54.1 | 79.2 | 53.7 | ||||||||
Revenues | 779 | 783.5 | 663.6 | ||||||||
Net income (loss) | 43.1 | 49 | 40.5 | ||||||||
Amounts Included in Profitability Measures [Abstract] | |||||||||||
Depreciation and Amortization | 36.2 | 28.8 | 20.7 | ||||||||
Interest Expense | 11.1 | 10.1 | 7.5 | ||||||||
Income Taxes | 28.9 | 34.3 | 29.6 | ||||||||
Assets | 541.6 | 465.8 | 541.6 | 465.8 | |||||||
Nonutility Group [Member] | Energy Services [Member] | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Property, Plant and Equipment, Additions | 1.6 | 6.9 | 2.3 | ||||||||
Revenues | 129.8 | 91.3 | 117.7 | ||||||||
Net income (loss) | -3.2 | 1 | 5.7 | ||||||||
Amounts Included in Profitability Measures [Abstract] | |||||||||||
Depreciation and Amortization | 3.9 | 1.7 | 1.9 | ||||||||
Interest Expense | 1.3 | 0.6 | 0.4 | ||||||||
Income Taxes | -7.8 | -11.9 | -9 | ||||||||
Assets | 87.1 | 63 | 87.1 | 63 | |||||||
Nonutility Group [Member] | Coal Mining [Member] | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Property, Plant and Equipment, Additions | 41.9 | 46.2 | 63.8 | ||||||||
Revenues | 234.3 | 292.8 | 235.8 | ||||||||
Net income (loss) | -21.1 | -16 | -3.5 | ||||||||
Amounts Included in Profitability Measures [Abstract] | |||||||||||
Depreciation and Amortization | 29.9 | 50.8 | 41.8 | ||||||||
Interest Expense | 7.5 | 9.8 | 11.5 | ||||||||
Income Taxes | -21.8 | -14.6 | -8.6 | ||||||||
Assets | 0 | 433 | 0 | 433 | |||||||
Nonutility Group [Member] | Energy Marketing [Member] | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Net income (loss) | 0 | -37.5 | -17.6 | ||||||||
Amounts Included in Profitability Measures [Abstract] | |||||||||||
Interest Expense | 0 | 2.2 | 4.8 | ||||||||
Income Taxes | 0 | -23.3 | -11.7 | ||||||||
Assets | 30.6 | 33.9 | 30.6 | 33.9 | |||||||
Nonutility Group [Member] | Other Businesses [Member] | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Revenues | 0 | 0 | 0.5 | ||||||||
Net income (loss) | -0.8 | -1 | -3.4 | ||||||||
Amounts Included in Profitability Measures [Abstract] | |||||||||||
Depreciation and Amortization | 0.3 | 0.1 | 0.2 | ||||||||
Interest Expense | 0.9 | 0.5 | 0.7 | ||||||||
Income Taxes | -0.3 | -1.6 | -2 | ||||||||
Assets | 89.2 | 34.9 | 89.2 | 34.9 | |||||||
Corporate and Other [Member] | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Net income (loss) | 0.5 | -0.7 | -0.7 | ||||||||
Amounts Included in Profitability Measures [Abstract] | |||||||||||
Interest Expense | -0.7 | -0.3 | -0.4 | ||||||||
Income Taxes | -1.1 | -1.1 | -1.1 | ||||||||
Assets | 658.1 | 828.1 | 658.1 | 828.1 | |||||||
Eliminations [Member] | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Revenues | -101.1 | -106 | -118.4 | ||||||||
Amounts Included in Profitability Measures [Abstract] | |||||||||||
Assets | ($672.40) | ($896.90) | ($672.40) | ($896.90) |
Additional_Balance_Sheet_Opera2
Additional Balance Sheet & Operational Information (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Inventory, Net [Abstract] | |||
Gas in storage - at LIFO cost | $40.50 | $33.20 | |
Coal and Oil for electric generation - at average cost | 33.8 | 16.5 | |
Materials and supplies | 42.5 | 57.3 | |
Nonutility Coal - at LIFO cost | 0 | 26.2 | |
Other | 1.7 | 1.2 | |
Total inventories | 118.5 | 134.4 | |
Amount by which cost of replacing inventories carried at LIFO cost exceeded carrying value | 3 | 8.5 | |
Prepayments and other current assets [Abstract] | |||
Prepaid gas delivery service | 40.7 | 32.9 | |
Deferred income taxes | 16.3 | 13.9 | |
Prepaid taxes | 37.5 | 11.2 | |
Other prepayments and current assets | 16.4 | 17.6 | |
Total prepayments and other current assets | 110.9 | 75.6 | |
Investments in unconsolidated affiliates [Abstract] | |||
Total investments in unconsolidated affiliates | 23.4 | 24 | |
Equity in earnings (loss) of unconsolidated affiliates [Abstract] | |||
Equity in earnings (losses) of unconsolidated affiliates | 0.5 | -59.7 | -23.3 |
Other utility and corporate investments [Abstract] | |||
Cash surrender value of life insurance policies | 32.3 | 32.9 | |
Municipal bond | 3.1 | 3.4 | |
Restricted cash & other investments | 1.8 | 1.8 | |
Other utility and corporate investments | 37.2 | 38.1 | |
Goodwill | 289.9 | 262.3 | |
Accrued liabilities [Abstract] | |||
Refunds to customers and customer deposits | 51.3 | 50.2 | |
Accrued taxes | 35.8 | 36.2 | |
Accrued interest | 19.1 | 20 | |
Deferred compensation & post-retirement benefits | 7.3 | 7.5 | |
Accrued salaries and other | 71.4 | 68.2 | |
Total accrued liabilities | 184.9 | 182.1 | |
Asset Retirement Obligation [Roll Forward] | |||
Asset retirement obligation, beginning balance | 41.3 | 37.7 | |
Accretion | 1.7 | 2.2 | |
Changes in estimates, net of cash payments | 23.8 | 1.4 | |
Asset Retirement Obligation, Liabilities Settled | -11.8 | 0 | |
Asset retirement obligation, ending balance | 55 | 41.3 | 37.7 |
Other - net in the consolidated statement of income [Abstract] | |||
AFUDC - borrowed funds | 11.4 | 5.9 | 4.6 |
AFUDC - equity funds | 3.2 | 0.8 | 0.4 |
Nonutility plant capitalized interest | 0 | 0.5 | 1.8 |
Interest income, net | 1.1 | 1.1 | 1.1 |
Other nonutility investment impairment charges | -1 | 0 | -2.7 |
Cash surrender value of life insurance policies | 2.8 | 4.8 | 1.8 |
All other income | 2.2 | 4.6 | 1.3 |
Total other income (expense) – net | 19.7 | 17.7 | 8.3 |
Cash paid (received) for [Abstract] | |||
Interest | 87.5 | 91 | 94.6 |
Income taxes | 69.4 | 6.8 | 21.8 |
Accruals related to utility and nonutility plant purchases [Abstract] | |||
Accruals related to utility and nonutility plant purchases | 20.2 | 19.4 | |
ProLiance Holdings, LLC [Member] | |||
Investments in unconsolidated affiliates [Abstract] | |||
Total investments in unconsolidated affiliates | 20.5 | 20.8 | |
Equity in earnings (loss) of unconsolidated affiliates [Abstract] | |||
Equity in earnings (losses) of unconsolidated affiliates | -0.3 | -57.7 | -22.7 |
Other Nonutility Partnerships and Corporations [Member] | |||
Investments in unconsolidated affiliates [Abstract] | |||
Total investments in unconsolidated affiliates | 2.7 | 3 | |
Other Utility Investments [Member] | |||
Investments in unconsolidated affiliates [Abstract] | |||
Total investments in unconsolidated affiliates | 0.2 | 0.2 | |
Other Unconsolidated Affiliates [Member] | |||
Equity in earnings (loss) of unconsolidated affiliates [Abstract] | |||
Equity in earnings (losses) of unconsolidated affiliates | 0.8 | -2 | -0.6 |
Utility Group [Member] | Gas Utility Services [Member] | |||
Other utility and corporate investments [Abstract] | |||
Goodwill | 205 | 205 | |
Nonutility Group [Member] | |||
Investments in unconsolidated affiliates [Abstract] | |||
Total investments in unconsolidated affiliates | 1.6 | ||
Nonutility Group [Member] | Infrastructure Services [Member] | |||
Other utility and corporate investments [Abstract] | |||
Goodwill | 55.2 | 55.2 | |
Nonutility Group [Member] | Energy Services [Member] | |||
Other utility and corporate investments [Abstract] | |||
Goodwill | $29.70 | $2.10 |
Quarterly_Financial_Data_Unaud2
Quarterly Financial Data (Unaudited) (Details) (USD $) | 3 Months Ended | 12 Months Ended | |||||||||
In Millions, except Per Share data, unless otherwise specified | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Quarterly Financial Information Disclosure [Abstract] | |||||||||||
Operating revenues | $676.80 | $595.60 | $542.50 | $796.80 | $680 | $579.60 | $531 | $700.60 | $2,611.70 | $2,491.20 | $2,232.80 |
Operating income | 97.1 | 84.5 | 33.9 | 99 | 85.6 | 83.3 | 57.9 | 106.8 | 314.5 | 333.6 | 352.5 |
Net Income | $56.50 | $47.30 | $11.90 | $51.20 | $49.80 | $42.80 | ($5.80) | $49.80 | $166.90 | $136.60 | $159 |
Earnings per share [Abstract] | |||||||||||
Basic | $0.68 | $0.57 | $0.14 | $0.62 | $0.60 | $0.52 | ($0.07) | $0.61 | $2.02 | $1.66 | $1.94 |
DILUTED (in dollars per share) | $0.68 | $0.57 | $0.14 | $0.62 | $0.60 | $0.52 | ($0.07) | $0.61 | $2.02 | $1.66 | $1.94 |
SCHEDULE_II_VALUATION_AND_QUAL1
SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Accumulated Provision for Uncollectible Accounts [Member] | |||
Valuation and Qualifying Accounts Disclosure [Line Items] | |||
Balance, at beginning of year | $6.80 | $6.80 | $6.70 |
Additions charged to expenses | 7.3 | 6.8 | 8.2 |
Additions charged to other accounts | 0 | 0 | 0 |
Deductions from Reserves, Net | 8.1 | 6.8 | 8.1 |
Balance, at end of period | 6 | 6.8 | 6.8 |
Reserve for Impaired Notes Receivable [Member] | |||
Valuation and Qualifying Accounts Disclosure [Line Items] | |||
Balance, at beginning of year | 0.6 | 0.6 | 15.7 |
Additions charged to expenses | 0 | 0 | 0.5 |
Additions charged to other accounts | 0 | 0 | 0 |
Deductions from Reserves, Net | 0.6 | 0 | 15.6 |
Balance, at end of period | 0 | 0.6 | 0.6 |
Restructuring Costs [Member] | |||
Valuation and Qualifying Accounts Disclosure [Line Items] | |||
Balance, at beginning of year | 0.2 | 0.3 | 0.4 |
Additions charged to expenses | 0 | 0 | 0 |
Additions charged to other accounts | 0 | 0 | 0 |
Deductions from Reserves, Net | 0.2 | 0.1 | 0.1 |
Balance, at end of period | $0 | $0.20 | $0.30 |