Document_And_Entity_Informatio
Document And Entity Information (USD $) | 12 Months Ended | ||
Dec. 31, 2013 | Jan. 31, 2014 | Jun. 30, 2013 | |
Entity Information [Line Items] | ' | ' | ' |
Entity Registrant Name | 'VECTREN CORP | ' | ' |
Entity Central Index Key | '0001096385 | ' | ' |
Entity Well-known Seasoned Issuer | 'Yes | ' | ' |
Entity Voluntary Filers | 'No | ' | ' |
Entity Current Reporting Status | 'No | ' | ' |
Entity Filer Category | 'Large Accelerated Filer | ' | ' |
Entity Public Float | ' | ' | $2,776,650,228 |
Entity Common Stock, Shares Outstanding | ' | 82,418,221 | ' |
Document Fiscal Year Focus | '2013 | ' | ' |
Document Fiscal Period Focus | 'FY | ' | ' |
Document Type | '10-K | ' | ' |
Amendment Flag | 'false | ' | ' |
Document Period End Date | 31-Dec-13 | ' | ' |
Current Fiscal Year End Date | '--12-31 | ' | ' |
Balance_Sheet
Balance Sheet (USD $) | Dec. 31, 2013 | Dec. 31, 2012 |
In Millions, unless otherwise specified | ||
Current Assets | ' | ' |
Cash and cash equivalents | $21.50 | $19.50 |
Accounts receivable - less reserves of $6.8 & $6.8, respectively | 259.2 | 216.7 |
Accrued unbilled revenues | 134.2 | 185 |
Inventories | 134.4 | 158.6 |
Recoverable fuel and natural gas costs | 5.5 | 25.3 |
Prepayments and other current assets | 75.6 | 73.3 |
Total current assets | 630.4 | 678.4 |
Utility Plant | ' | ' |
Original cost | 5,389.60 | 5,176.80 |
Less: accumulated depreciation and amortization | 2,165.30 | 2,057.20 |
Net utility plant | 3,224.30 | 3,119.60 |
Investments in unconsolidated affiliates | 24 | 78.1 |
Other utility and corporate investments | 38.1 | 34.6 |
Other nonutility investments | 33.8 | 24.9 |
Nonutility plant - net | 657.2 | 598 |
Goodwill - net | 262.3 | 262.3 |
Regulatory assets | 193.4 | 252.7 |
Other assets | 39.1 | 40.5 |
TOTAL ASSETS | 5,102.60 | 5,089.10 |
Current Liabilities | ' | ' |
Accounts payable | 227.2 | 180.6 |
Accounts payable to affiliated companies | 0 | 29.7 |
Refundable fuel and natural gas costs | 2.6 | 0 |
Accrued liabilities | 182.1 | 198.8 |
Short-term borrowings | 68.6 | 278.8 |
Current maturities of long-term debt | 30 | 106.4 |
Total current liabilities | 510.5 | 794.3 |
Long-term Debt - Net of Current Maturities | 1,777.10 | 1,553.40 |
Deferred Income Taxes and Other Liabilities | ' | ' |
Deferred income taxes | 707.4 | 637.2 |
Regulatory liabilities | 387.3 | 364.2 |
Deferred credits and other liabilities | 166 | 213.9 |
Total deferred credits and other liabilities | 1,260.70 | 1,215.30 |
Commitments & Contingencies (Notes 7, 17-19) | ' | ' |
Common Shareholders' Equity | ' | ' |
Common stock (no par value) – issued & outstanding 82.4 & 82.2 shares, respectively | 709.3 | 700.5 |
Retained earnings | 845.7 | 829.9 |
Accumulated other comprehensive income/(loss) | -0.7 | -4.3 |
Total common shareholders' equity | 1,554.30 | 1,526.10 |
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY | $5,102.60 | $5,089.10 |
Income_Statement
Income Statement (USD $) | 12 Months Ended | ||
In Millions, except Per Share data, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
OPERATING REVENUES | ' | ' | ' |
Gas utility | $810 | $738.10 | $819.10 |
Electric utility | 619.3 | 594.9 | 635.9 |
Nonutility | 1,061.90 | 899.8 | 870.2 |
Total operating revenues | 2,491.20 | 2,232.80 | 2,325.20 |
OPERATING EXPENSES | ' | ' | ' |
Cost of gas sold | 358.1 | 301.3 | 375.4 |
Cost of fuel and purchased power | 202.9 | 192 | 240.4 |
Cost of nonutility revenues | 366.7 | 295.1 | 385.3 |
Other operating | 891.6 | 781 | 652.2 |
Depreciation and amortization | 277.8 | 254.6 | 244.3 |
Taxes other than income taxes | 60.5 | 56.3 | 57.6 |
Total operating expenses | 2,157.60 | 1,880.30 | 1,955.20 |
OPERATING INCOME | 333.6 | 352.5 | 370 |
OTHER INCOME (EXPENSE) | ' | ' | ' |
Equity in (losses) of unconsolidated affiliates | -59.7 | -23.3 | -32 |
Other income (expense) - net | 17.7 | 8.3 | -3.5 |
Total other income (expense) | -42 | -15 | -35.5 |
Interest expense | 87.9 | 96 | 106.5 |
INCOME BEFORE INCOME TAXES | 203.7 | 241.5 | 228 |
Income taxes | 67.1 | 82.5 | 86.4 |
Net income | $136.60 | $159 | $141.60 |
AVERAGE COMMON SHARES OUTSTANDING (in shares) | 82.3 | 82 | 81.8 |
DILUTED COMMON SHARES OUTSTANDING (in shares) | 82.4 | 82.1 | 81.8 |
EARNINGS PER SHARE OF COMMON STOCK: | ' | ' | ' |
BASIC (in dollars per share) | $1.66 | $1.94 | $1.73 |
DILUTED (in dollars per share) | $1.66 | $1.94 | $1.73 |
Balance_Sheet_Parenthetical
Balance Sheet (Parenthetical) (USD $) | Dec. 31, 2013 | Dec. 31, 2012 |
In Millions, unless otherwise specified | ||
Current Assets | ' | ' |
Reserves | $6.80 | $6.80 |
Common Shareholders' Equity | ' | ' |
Common stock Shares, Issued (in shares) | 82.4 | 82.2 |
Common stock, Shares Outstanding (in shares) | 82.4 | 82.2 |
CONSOLIDATED_CONDENSED_STATEME
CONSOLIDATED CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Net Income | $136.60 | $159 | $141.60 |
Other comprehensive income | 3.6 | 9 | -8.9 |
TOTAL COMPREHENSIVE INCOME | 140.2 | 168 | 132.7 |
AOCI of Unconsolidated Affiliates [Member] | ' | ' | ' |
Net amount arising during the year before tax | 4.6 | 11.3 | -9.3 |
Income taxes | -1.8 | -4.6 | 3.8 |
Other comprehensive income | 2.8 | 6.7 | -5.5 |
Pensions and Other Benefits [Member] | ' | ' | ' |
Amounts arising during the year before tax | 61.4 | -3.3 | -41.6 |
Reclassifications to periodic cost before tax | 9.1 | 7.1 | 6.4 |
Deferrals to regulatory assets | -69.1 | 0.2 | 33.5 |
Income taxes | -0.6 | -1.6 | 0.7 |
Other comprehensive income | 0.8 | 2.4 | -1 |
Cash Flow Hedges [Member] | ' | ' | ' |
Unrealized gains & losses before tax | 0 | 0 | -3.6 |
Reclassifications to net income before tax | 0 | -0.1 | -0.3 |
Income taxes | 0 | 0 | 1.5 |
Other comprehensive income | $0 | ($0.10) | ($2.40) |
Statement_of_Cash_Flows
Statement of Cash Flows (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
CASH FLOWS FROM OPERATING ACTIVITIES | ' | ' | ' |
Net Income | $136.60 | $159 | $141.60 |
Adjustments to reconcile net income to cash from operating activities: | ' | ' | ' |
Depreciation and amortization | 277.8 | 254.6 | 244.3 |
Deferred income taxes and investment tax credits | 43.3 | 84.3 | 71.7 |
Equity in losses of unconsolidated affiliates | 59.7 | 23.3 | 32 |
Provision for uncollectible accounts | 6.8 | 8.2 | 11.8 |
Expense portion of pension and postretirement benefit cost | 9.9 | 8.7 | 9 |
Other non-cash expense - net | 5.8 | 9.8 | -0.1 |
Changes in working capital accounts: | ' | ' | ' |
Accounts receivable & accrued unbilled revenues | 1.5 | -67.1 | -17.5 |
Inventories | 24.2 | 3.3 | -26.1 |
Recoverable/refundable fuel and natural gas costs | 22.4 | -12.9 | -4.5 |
Prepayments and other current assets | 12.8 | -5.1 | 17.9 |
Accounts payable, including to affiliated companies | 6.8 | -14.8 | -21.2 |
Accrued liabilities | -1.2 | 3.4 | 6.4 |
Unconsolidated affiliate dividends | 1.1 | 0.1 | 0.1 |
Employer contributions to pension and postretirement plans | -13.7 | -20.5 | -38.8 |
Changes in noncurrent assets | -2.1 | -35.3 | 0.3 |
Changes in noncurrent liabilities | -4.7 | -11.6 | -10 |
Net cash flows from operating activities | 587 | 387.4 | 416.9 |
Proceeds from: | ' | ' | ' |
Long-term debt, net of issuance costs | 481.7 | 199.5 | 148.9 |
Dividend reinvestment plan and other common stock issuances | 6.9 | 7.2 | 7.9 |
Requirements for: | ' | ' | ' |
Dividends on common stock | -117.3 | -115.3 | -113.2 |
Retirement of long-term debt | -338.9 | -62.7 | -349.1 |
Other financing activities | -2.1 | 0 | -2.3 |
Net change in short-term borrowings | -210.2 | -48.3 | 208.8 |
Net cash flows from financing activities | -179.9 | -19.6 | -99 |
Proceeds from: | ' | ' | ' |
Sale of business | 0 | 0 | 84.3 |
Unconsolidated affiliate distributions | 0 | 0.2 | 0.5 |
Other collections | 5.6 | 9.9 | 1.1 |
Requirements for: | ' | ' | ' |
Capital expenditures, excluding AFUDC equity | -393.4 | -365.8 | -321.3 |
Business acquisition, net of cash acquired | 0 | 0 | -83.4 |
Other investments | -17.3 | -1.2 | -0.9 |
Net cash flows from investing activities | -405.1 | -356.9 | -319.7 |
Net change in cash and cash equivalents | 2 | 10.9 | -1.8 |
Cash and cash equivalents at beginning of period | 19.5 | 8.6 | 10.4 |
Cash and cash equivalents at end of period | $21.50 | $19.50 | $8.60 |
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, 2010 | $1,438.90 | $683.40 | $759.90 | ($4.40) |
Balance at beginning of period (in shares) at Dec. 31, 2010 | ' | 81.7 | ' | ' |
Comprehensive income: | ' | ' | ' | ' |
Net Income | 141.6 | ' | 141.6 | ' |
Other comprehensive income | -8.9 | ' | ' | -8.9 |
Common stock: | ' | ' | ' | ' |
Issuance: option exercises and dividend reinvestment plan (in shares) | ' | 0.2 | ' | ' |
Stock Issued During Period Value Stock Options Exercised And Dividend Reinvestment Plan | 7.9 | 7.9 | ' | ' |
Dividends ($1.425, $1.405, and $1.385 per share) | -113.2 | ' | -113.2 | ' |
Other | -0.8 | 1.3 | -2.1 | ' |
Balance at end of period at Dec. 31, 2011 | 1,465.50 | 692.6 | 786.2 | -13.3 |
Balance at end 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 | ' | ' |
Stock Issued During Period Value Stock Options Exercised And Dividend Reinvestment Plan | 7.2 | 7.2 | ' | ' |
Dividends ($1.425, $1.405, and $1.385 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 | 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 | ' | ' |
Stock Issued During Period Value Stock Options Exercised And Dividend Reinvestment Plan | 6.9 | 6.9 | ' | ' |
Dividends ($1.425, $1.405, and $1.385 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 | $709.30 | $845.70 | ($0.70) |
Balance at end of period (in shares) at Dec. 31, 2013 | 82.4 | 82.4 | ' | ' |
Statement_of_Shareholders_Equi1
Statement of Shareholders' Equity (Parenthetical) (USD $) | 12 Months Ended | ||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |
Statement of Stockholders' Equity [Abstract] | ' | ' | ' |
Dividends (in dollars per share) | $1.43 | $1.41 | $1.39 |
Organization_and_Nature_of_Ope
Organization and Nature of Operations | 12 Months Ended |
Dec. 31, 2013 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | ' |
Organization and Nature of Operations | ' |
Organization 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), serves as the intermediate holding company for three public utilities: Indiana Gas Company, Inc. (Indiana Gas or Vectren North), Southern Indiana Gas and Electric Company (SIGECO or Vectren South), and Vectren Energy Delivery of Ohio, Inc. (VEDO). Utility Holdings also has other assets that provide information technology and other services to the three utilities. 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 570,000 natural gas customers located in central and southern Indiana. SIGECO provides energy delivery services to approximately 142,000 electric customers and approximately 110,000 gas customers located near Evansville in southwestern Indiana. SIGECO also owns and operates electric generation assets to serve its electric customers and optimizes those assets in the wholesale power market. Indiana Gas and SIGECO generally do business as Vectren Energy Delivery of Indiana. VEDO provides energy delivery services to over 312,000 natural gas customers located near Dayton in west central Ohio. | |
The Company, through Vectren Enterprises, Inc. (Enterprises), is involved in nonutility activities in three primary business areas: Infrastructure Services, Energy Services, and Coal Mining. Infrastructure Services provides underground pipeline construction and repair services. Energy Services provides performance contracting and renewable energy services. Coal Mining owns, and through its contract miners, mines and then sells coal. Enterprises also has other legacy businesses that have invested in energy-related opportunities and services, real estate, and a leveraged lease, among other investments. Prior to June 18, 2013, the Company, through Enterprises, was involved in nonutility activities in its Energy Marketing business area. Energy Marketing marketed and supplied natural gas and provided energy management services through ProLiance Holdings, LLC and Vectren Source. Pursuant to service contracts, Energy Marketing provided the Company's regulated utilities natural gas supply services. All of the above are collectively referred to as the Nonutility Group. Enterprises supports the Company's regulated utilities by providing infrastructure services and coal. |
Summary_of_Significant_Account
Summary of Significant Accounting Policies | 12 Months Ended | |
Dec. 31, 2013 | ||
Accounting Policies [Abstract] | ' | |
Summary of Significant Accounting Policies | ' | |
Summary of Significant Accounting Policies | ||
In applying its accounting policies, the Company makes judgments, assumptions, and estimates that affect the amounts reported in these consolidated financial statements and related footnotes. Examples of transactions for which estimation techniques are used include valuing pension and postretirement benefit obligations, deferred tax obligations, unbilled revenue, uncollectible accounts, regulatory assets and liabilities, reclamation liabilities, and derivatives and other financial instruments. Estimates also impact the depreciation of utility and nonutility plant and the testing of goodwill and other assets for impairment. Recorded estimates are revised when better information becomes available or when actual amounts can be determined. Actual results could differ from current estimates. | ||
Principles of Consolidation | ||
The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries, after elimination of 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 and coal inventory at the Company’s nonutility coal mines 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 or units-of-production method of amortization for certain coal mining assets. When nonutility property is retired, or otherwise disposed of, the asset and accumulated depreciation are removed, and the resulting gain or loss is reflected in income, typically impacting operating expenses. | ||
Impairment Reviews | ||
Property, plant and equipment along with other long-lived assets are reviewed as facts and circumstances indicate that the carrying amount may be impaired. This impairment review involves the comparison of an asset’s (or group of assets’) carrying value to the estimated future cash flows the asset (or asset group) is expected to generate over a remaining life. If this evaluation were to conclude that the carrying value is impaired, an impairment charge would be recorded based on the difference between the carrying amount and its fair value (less costs to sell for assets to be disposed of by sale) as a charge to operations or discontinued operations. There were no impairments related to property, plant and equipment or other long-lived assets during the periods presented. | ||
Specific to the Company’s investment in its owned coal mines, in 2013, as a result of continued operating losses at the Company’s Prosperity mine, increased production costs as a result of various factors, including poor mining conditions, and an overall decline in market prices for Illinois Basin coal, the Company performed a more detailed analysis to support the carrying value of that mine. Specifically, several third party-prepared price curves were obtained and were used to develop revenue forecasts for the remainder of the mine life, using estimated production volumes. Additionally, cost estimates were developed that considered prior actual costs, annualized current costs, and projected future costs. The various revenue scenarios were used in conjunction with estimated costs to derive estimated net operating cash flows for the remaining life of the mine. These estimates are highly subjective and may differ materially from actual results, but the results of the various analyses indicate that there is no impairment related to the coal mine assets, specifically the Prosperity mine assets, at December 31, 2013. | ||
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 – net when received. 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. | ||
Regulation | ||
Retail public utility operations affecting Indiana customers are subject to regulation by the IURC, and retail public utility operations affecting Ohio customers are subject to regulation by the PUCO. The Company’s accounting policies give recognition to the ratemaking and accounting practices authorized by these agencies. | ||
Refundable or Recoverable Gas Costs & Cost of Fuel & Purchased Power | ||
All metered gas rates contain a gas cost adjustment clause that allows the Company to charge for changes in the cost of purchased gas. Metered electric rates contain a fuel adjustment clause that allows for adjustment in charges for electric energy to reflect changes in the cost of fuel. The net energy cost of purchased power, subject to a variable benchmark based on NYMEX natural gas prices, is also recovered through regulatory proceedings. The Company records any under-or-over-recovery resulting from gas and fuel adjustment clauses each month in revenues. A corresponding asset or liability is recorded until the under or over-recovery is billed or refunded to utility customers. The cost of gas sold is charged to operating expense as delivered to customers, and the cost of fuel and purchased power for electric generation is charged to operating expense when consumed. | ||
Regulatory Assets & Liabilities | ||
Regulatory assets represent probable future revenues associated with certain incurred costs, which will be recovered from customers through the ratemaking process. Regulatory liabilities represent probable expenditures by the Company for removal costs or future reductions in revenues associated with amounts that are to be credited to customers through the ratemaking process. The Company continually assesses the recoverability of costs recognized as regulatory assets and liabilities and the ability to recognize new regulatory assets and liabilities associated with its regulated utility operations. Given the current regulatory environment in its jurisdictions, the Company believes such accounting is appropriate. | ||
The Company collects an estimated cost of removal of its utility plant through depreciation rates established in regulatory proceedings. The Company records amounts expensed in advance of payments as a Regulatory liability because the liability does not meet the threshold of an asset retirement obligation. | ||
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, 2013 or 2012, 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, 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 $29.6 million in 2013, $26.9 million in 2012, and $29.3 million in 2011. Expense associated with excise and utility receipts taxes are recorded as a component of Taxes other than income taxes. | ||
Operating Segments | ||
The Company’s chief operating decision maker is the Chief Executive Officer. The Company uses net income calculated in accordance with generally accepted accounting principles as its most relevant performance measure. The Company has three operating segments within its Utility Group, five 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, 2013 | |||||||||||||||
Property, Plant and Equipment [Abstract] | ' | ||||||||||||||
Utility and Nonutility Plant | ' | ||||||||||||||
Utility & Nonutility Plant | |||||||||||||||
The original cost of Utility plant, together with depreciation rates expressed as a percentage of original cost, follows: | |||||||||||||||
At December 31, | |||||||||||||||
(In millions) | 2013 | 2012 | |||||||||||||
Original Cost | Depreciation | Original Cost | Depreciation | ||||||||||||
Rates as a | Rates as a | ||||||||||||||
Percent of | Percent of | ||||||||||||||
Original Cost | Original Cost | ||||||||||||||
Gas utility plant | $ | 2,762.20 | 3.5 | % | $ | 2,614.30 | 3.5 | % | |||||||
Electric utility plant | 2,519.80 | 3.3 | % | 2,463.60 | 3.3 | % | |||||||||
Common utility plant | 53.4 | 3 | % | 52 | 3 | % | |||||||||
Construction work in progress | 54.2 | — | 46.9 | — | |||||||||||
Total original cost | $ | 5,389.60 | $ | 5,176.80 | |||||||||||
SIGECO and Alcoa Generating Corporation (AGC), a subsidiary of ALCOA, own the 300 MW Unit 4 at the Warrick Power Plant as tenants in common. SIGECO's share of the cost of this unit at December 31, 2013, is $186.3 million with accumulated depreciation totaling $84.4 million. AGC and SIGECO also share equally in the cost of operation and output of the unit. SIGECO's share of operating costs is included in Other operating expenses in the Consolidated Statements of Income. | |||||||||||||||
Nonutility plant, net of accumulated depreciation and amortization follows: | |||||||||||||||
At December 31, | |||||||||||||||
(In millions) | 2013 | 2012 | |||||||||||||
Coal mine development costs & equipment | $ | 242 | $ | 241.9 | |||||||||||
Computer hardware & software | 102.7 | 97.3 | |||||||||||||
Land & buildings | 129.3 | 120.4 | |||||||||||||
Vehicles & equipment | 165.2 | 119.8 | |||||||||||||
All other | 18 | 18.6 | |||||||||||||
Nonutility plant - net | $ | 657.2 | $ | 598 | |||||||||||
Nonutility plant is presented net of accumulated depreciation and amortization totaling $541.7 million and $468.4 million as of December 31, 2013 and 2012, respectively. For the years ended December 31, 2013, 2012, and 2011, the Company capitalized interest totaling $0.5 million, $1.8 million, and $2.1 million, respectively, on nonutility plant construction projects. |
Regulatory_Assets_Liabilities
Regulatory Assets & Liabilities | 12 Months Ended | ||||||||
Dec. 31, 2013 | |||||||||
Regulatory Assets and Liabilities Disclosure [Abstract] | ' | ||||||||
Regulatory Assets and Liabilities | ' | ||||||||
Regulatory Assets & Liabilities | |||||||||
Regulatory Assets | |||||||||
Regulatory assets consist of the following: | |||||||||
At December 31, | |||||||||
(In millions) | 2013 | 2012 | |||||||
Future amounts recoverable from ratepayers related to: | |||||||||
Benefit obligations (See Note 11) | $ | 57.1 | $ | 126.2 | |||||
Net deferred income taxes (See Note 10) | (5.8 | ) | (3.9 | ) | |||||
Asset retirement obligations & other | 2.4 | 2.6 | |||||||
53.7 | 124.9 | ||||||||
Amounts deferred for future recovery related to: | |||||||||
Deferred coal costs (See Note 18) | 42.4 | 42.4 | |||||||
Cost recovery riders & other | 18.6 | 10.2 | |||||||
61 | 52.6 | ||||||||
Amounts currently recovered in customer rates related to: | |||||||||
Unamortized debt issue costs & hedging proceeds | 34.6 | 32.6 | |||||||
Demand side management programs | 2.5 | 4.4 | |||||||
Indiana authorized trackers | 30.8 | 32.1 | |||||||
Ohio authorized trackers | 7.9 | 1.5 | |||||||
Premiums paid to reacquire debt | 2.2 | 2.7 | |||||||
Other base rate recoveries | 0.7 | 1.9 | |||||||
78.7 | 75.2 | ||||||||
Total regulatory assets | $ | 193.4 | $ | 252.7 | |||||
Of the $78.7 million currently being recovered in customer rates, $2.5 million that is associated with demand side management programs is earning a return. The weighted average recovery period of regulatory assets currently being recovered in base rates, which totals $40 million, is 23 years. The remainder of the regulatory assets are being recovered timely through periodic recovery mechanisms. The Company has rate orders for all deferred costs not yet in rates and therefore believes that future recovery is probable. | |||||||||
Assets arising from benefit obligations represent the funded status of retirement plans less amounts previously recognized in the statement of income. The decrease in 2013 of approximately $69 million is a result of plan asset performance and an increase in discount rate 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, 2013 and 2012, the Company has approximately $387.3 million and $364.2 million, respectively, in Regulatory liabilities. Of these amounts, $373.0 million and $349.5 million relate to cost of removal obligations. The remaining amounts primarily relate to timing differences associated with asset retirement obligations and deferred financing costs. |
Acquisition_of_Minnesota_Limit
Acquisition of Minnesota Limited, Inc. | 12 Months Ended | ||||
Dec. 31, 2013 | |||||
Business Combinations [Abstract] | ' | ||||
Acquisition of Minnesota Limited, Inc. | ' | ||||
Acquisition of Minnesota Limited, LLC | |||||
On March 31, 2011, the Company, through its wholly owned subsidiary Vectren Infrastructure Services Company, Inc., purchased Minnesota Limited, LLC, excluding certain assets. Minnesota Limited is a specialty contractor focusing on transmission pipeline construction and maintenance; pump station, compressor station, terminal and refinery construction; and hydrostatic testing. Minnesota Limited is headquartered in Big Lake, Minnesota and the majority of its customers are generally located in the northern Midwest region. | |||||
Along with the Company’s wholly owned subsidiary, Miller Pipeline LLC, Minnesota Limited is included in the Infrastructure Services operating segment. | |||||
The Company accounted for the cash acquisition in accordance with FASB authoritative guidance for business combinations, which requires the Company to recognize the assets acquired and the liabilities assumed, measured at their fair values as of the date of acquisition. | |||||
The cash paid at acquisition, net of cash acquired, was $83.4 million. For the period from April 1, 2011 through December 31, 2011, Minnesota Limited contributed approximately $116.5 million and $9.4 million to the Company's revenue and net income, respectively. | |||||
The following table presents the Company's unaudited proforma results of operations for the year ended December 31, 2011 as if the acquisition had occurred on January 1, 2011. | |||||
(In millions, except per share data) | 2011 | ||||
Total operating revenues | $ | 2,346.30 | |||
Net income | $ | 141.4 | |||
Basic earnings per share | $ | 1.73 | |||
Diluted earnings per share | $ | 1.73 | |||
In addition to the incremental revenues and expenses recorded by Minnesota Limited during this period, the proforma financial data contain several adjustments including the following: recording the additional amortization expense from the identifiable intangible assets; adjusting the estimated tax provision of the proforma combined results; and adjusting for the issuance of short-term debt to facilitate the acquisition. The Company prepared the proforma financial information for the combined entities for comparative purposes only, and it 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. | |||||
Concurrent with the purchase agreement, the Company executed a lease arrangement at fair value for the Minnesota Limited corporate headquarters, which is owned by a member of the Minnesota Limited management team and certain family members. The lease obligates the Company to pay approximately $83,333 per month for ten years along with certain executory costs for taxes and other operating expenses. In 2013, $1.5 million of leasehold improvements were made to the facility. Pursuant to FASB guidance, the Company accounts for the obligation as an operating lease, expensing the lease payments and executory costs as incurred. |
Sale_of_Retail_Gas_Marketing_O
Sale of Retail Gas Marketing Operations | 12 Months Ended |
Dec. 31, 2013 | |
Discontinued Operations and Disposal Groups [Abstract] | ' |
Sale of Retail Gas Marketing Operations | ' |
Sale of Retail Gas Marketing Operations | |
On December 31, 2011, the Company sold its retail gas marketing operations performed through Vectren Source, receiving cash proceeds of approximately $84.3 million, excluding minor working capital adjustments. The sale, net of transaction costs, resulted in a pre-tax gain of approximately $25.4 million, which is included in Other operating expenses in the Consolidated Statements of Income. VEDO continues doing business with the third party purchaser of Vectren Source. This third party continues to sell natural gas directly to customers in VEDO’s service territory, and VEDO purchases receivables and natural gas from the third party. Vectren Source was a component of the Energy Marketing operating segment. |
Investment_in_ProLiance_Holdin
Investment in ProLiance Holdings, LLC | 12 Months Ended | |||
Dec. 31, 2013 | ||||
Equity Method Investments and Joint Ventures [Abstract] | ' | |||
Investment in ProLiance Holdings, LLC | ' | |||
Investment in ProLiance Holdings, LLC | ||||
The Company has an investment in ProLiance, a nonutility affiliate of Vectren and Citizens Energy Group (Citizens). On June 18, 2013, ProLiance exited the natural gas marketing business through the disposition of certain of the net assets, 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). ProLiance Energy provided services to a broad range of municipalities, utilities, industrial operations, schools, and healthcare institutions located throughout the Midwest and Southeast United States. ProLiance Energy’s customers included, among others, Vectren’s Indiana utilities as well as Citizens’ utilities. Consistent with its ownership percentage, Vectren 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. ProLiance funded an estimated equity shortfall at ProLiance Energy of $16.6 million at the time of the sale. To fund this estimated shortfall, the Company issued a note to ProLiance for its 61 percent ownership share of the $16.6 million shortfall, or $10.1 million, which was utilized by ProLiance to invest additional equity in ProLiance Energy. This interest-bearing note is classified as Other nonutility investments in the Consolidated Balance Sheets. | ||||
In addition, in connection with the sale, the Company and Citizens issued a guarantee to ETC. The guarantee issued by the Company and Citizens is a backup guarantee to the $50 million guarantee issued by ProLiance to ETC, and provides for a maximum guarantee of $25.0 million, or $15.3 million for the Company's 61 percent ownership share, and extends until 2016. This guarantee will be called upon only in the event of default as defined in the asset sale agreement and only if the ProLiance guarantee is not sufficient to satisfy the relevant obligations. Although there can be no assurance that these guarantees will not be called upon, the Company believes that the likelihood that the Company or ProLiance will be called upon to satisfy any obligations pursuant to these guarantees is remote. | ||||
As part of the transaction discussed above, ProLiance filed two petitions with the FERC seeking waivers of certain capacity release regulations. Under the first petition ProLiance sought to permanently release pipeline capacity to ETC that is used to provide service to retail customers. Under the second petition, ProLiance sought the same type of waiver in order to permanently release back to the utilities the pipeline contracts used to provide supply services to the utilities. The FERC has granted both requested waivers. ETC has taken assignment of the Portfolio Administration Agreements (PAAs) pursuant to which the utilities receive gas supply. With the receipt of the FERC waivers and with pipeline contracts having been transferred to the utilities, the utilities entered into an Asset Management Agreement (AMA) with ETC on September 1, 2013 and have temporarily released the pipeline contracts to ETC. ETC will fulfill the requirements of the PAAs through their remaining term ending in March 2016. | ||||
Vectren's remaining investment in ProLiance at December 31, 2013 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) | 2013 | |||
ProLiance Energy | $ | 1.5 | ||
Midstream assets and cash from sale of | ||||
storage assets | 7.8 | |||
LA Storage | 21.6 | |||
Total investment in ProLiance | $ | 30.9 | ||
Included in: | ||||
Investments in unconsolidated affiliates | 20.8 | |||
Other nonutility investments | 10.1 | |||
LA Storage, LLC Storage Asset Investment, Formerly Referred to as Liberty Gas Storage | ||||
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 was expected to include 17 Bcf of capacity in its North site, and an additional capacity of at least 17 Bcf at the South site. The South site also has the potential for further expansion. The LA Storage 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. | ||||
In late 2008, the project at the North site was halted due to subsurface and well-completion problems, which resulted in the joint venture recording a $132 million impairment charge. The Company, through ProLiance, recorded its share of the charge in 2009. As a result of the issues encountered at the North site, Liberty requested and the FERC approved the separation of the North site from the South site. Approximately 12 Bcf of the storage at the South site, 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. As of December 31, 2013 and December 31, 2012, ProLiance’s investment in the joint venture was $35.4 million and $35.5 million, respectively. | ||||
The joint venture received a demand for Arbitration from Williams Midstream Natural Gas Liquids, Inc. (“Williams”) on February 8, 2011 related to a Sublease Agreement (“Sublease”) between the joint venture and Williams at the North site. Williams alleges that the joint venture was negligent in its attempt to convert certain salt caverns to natural gas storage and thereby damaged the caverns. Williams alleges 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, 2013, 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, 2012, and 2011, totaled $200.5 million, $274.5 million, and $378.7 million, respectively. The Company purchases from ProLiance all occurred prior to June 18, 2013 when ProLiance exited the natural gas marketing business. The amounts owed to ProLiance at December 31, 2012, for those purchases was $29.7 million and is included in Accounts payable to affiliated companies in the Consolidated Balance Sheets. |
Nonutility_Real_Estate_Other_L
Nonutility Real Estate & Other Legacy Holdings | 12 Months Ended | ||||||||||||
Dec. 31, 2013 | |||||||||||||
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, 2013 and 2012, total remaining legacy investments included in the Other Businesses portfolio total $26.5 million and $28.7 million, respectively. Further separation of that 2013 investment by type of investment follows: | |||||||||||||
December 31, 2013 | |||||||||||||
Value Included In | |||||||||||||
(In millions) | Carrying | Other Nonutility Investments | Investments in Unconsolidated Affiliates | ||||||||||
Value | |||||||||||||
Commercial real estate investments | $ | 8 | $ | 8 | $ | — | |||||||
Leveraged lease | 14.4 | 14.4 | — | ||||||||||
Other investments | 4.1 | 1.3 | 2.8 | ||||||||||
$ | 26.5 | $ | 23.7 | $ | 2.8 | ||||||||
Commercial Real Estate Charge | |||||||||||||
During the fourth quarter of 2011, the Company obtained new evidence confirming further weakness in markets where the Company holds legacy real estate investments. The Company holds real estate investments such as an office building and affordable housing projects. The evaluation of the evidence resulted in a $15.4 million charge in 2011. Of the $15.4 million charge, $8.8 million is reflected in Other-net, $3.6 million is reflected in Equity in (losses) of unconsolidated affiliates, and $3.0 million is reflected in Other operating expenses. | |||||||||||||
Leveraged Lease | |||||||||||||
At December 31, 2013, 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 $19.6 million at December 31, 2013. The book value of this leverage lease is $4.0 million at December 31, 2013, net of related deferred taxes of $10.4 million. | |||||||||||||
Other Investments | |||||||||||||
Other investments totaled $4.1 million at December 31, 2013 and are comprised of investments in partnership-like structures involved in multifamily housing and an asset from an exited generation project. The investments involving multifamily housing are variable interest entities where the Company is a limited partner. The Company's exposure to loss is limited to its investment, and the Company does not consolidate any of these entities. The multifamily housing investments are accounted for using the equity method. |
Intangible_Assets
Intangible Assets | 12 Months Ended | ||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||
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, | ||||||||||||||||
2013 | 2012 | ||||||||||||||||
Amortizing | Non-amortizing | Amortizing | Non-amortizing | ||||||||||||||
Customer-related assets | $ | 17.4 | $ | — | $ | 18.9 | $ | — | |||||||||
Market-related assets | 1.9 | 7 | 2.7 | 7 | |||||||||||||
Intangible assets, net | $ | 19.3 | $ | 7 | $ | 21.6 | $ | 7 | |||||||||
As of December 31, 2013, the weighted average remaining life for amortizing customer-related assets and all amortizing intangibles is 13 years. These amortizing intangible assets have no significant residual values. Intangible assets are presented net of accumulated amortization totaling $8.1 million for customer-related assets and $2.6 million for market-related assets at December 31, 2013 and $6.6 million for customer-related assets and $1.7 million for market-related assets at December 31, 2012. Annual amortization associated with intangible assets totaled $2.3 million in 2013, $2.6 million in 2012 and $2.3 million in 2011. Amortization should approximate (in millions) $2.3, $2.2, $1.6, $1.4, and $1.4 in 2014, 2015, 2016, 2017, and 2018, respectively. Intangible assets are primarily in the Nonutility Group. |
Income_Taxes
Income Taxes | 12 Months Ended | ||||||||||||
Dec. 31, 2013 | |||||||||||||
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, | |||||||||||||
2013 | 2012 | 2011 | |||||||||||
Statutory rate: | 35 | % | 35 | % | 35 | % | |||||||
State & local taxes-net of federal benefit | 4.6 | 4 | 4.2 | ||||||||||
Amortization of investment tax credit | (0.3 | ) | (0.3 | ) | (0.3 | ) | |||||||
Depletion | (1.5 | ) | (1.5 | ) | (1.9 | ) | |||||||
Energy efficiency building deductions | (3.8 | ) | (3.0 | ) | (1.1 | ) | |||||||
Other tax credits | (1.1 | ) | (0.1 | ) | (0.2 | ) | |||||||
Adjustment of income tax accruals and all other-net | 0.1 | 0.1 | 2.2 | ||||||||||
Effective tax rate | 33 | % | 34.2 | % | 37.9 | % | |||||||
Significant components of the net deferred tax liability follow: | |||||||||||||
At December 31, | |||||||||||||
(In millions) | 2013 | 2012 | |||||||||||
Noncurrent deferred tax liabilities (assets): | |||||||||||||
Depreciation & cost recovery timing differences | $ | 725.2 | $ | 681.6 | |||||||||
Leveraged lease | 10.4 | 10.8 | |||||||||||
Regulatory assets recoverable through future rates | 22.8 | 23.5 | |||||||||||
Other comprehensive income | (1.6 | ) | (4.0 | ) | |||||||||
Alternative minimum tax carryforward | (23.5 | ) | (44.1 | ) | |||||||||
Employee benefit obligations | (6.7 | ) | (2.1 | ) | |||||||||
Net operating loss & other carryforwards | (1.2 | ) | (11.7 | ) | |||||||||
Regulatory liabilities to be settled through future rates | (18.7 | ) | (18.3 | ) | |||||||||
Impairments | (6.2 | ) | (6.1 | ) | |||||||||
Other – net | 6.9 | 7.6 | |||||||||||
Net noncurrent deferred tax liability | 707.4 | 637.2 | |||||||||||
Current deferred tax liabilities (assets): | |||||||||||||
Deferred fuel costs-net | 22.9 | 25.7 | |||||||||||
Demand side management programs | 0.1 | 2.7 | |||||||||||
Alternative minimum tax carryforward | (33.7 | ) | (2.7 | ) | |||||||||
Net operating loss & other carryforwards | (4.9 | ) | — | ||||||||||
Other – net | 1.7 | (10.8 | ) | ||||||||||
Net current deferred tax liability (asset) | (13.9 | ) | 14.9 | ||||||||||
Net deferred tax liability | $ | 693.5 | $ | 652.1 | |||||||||
At December 31, 2013 and 2012, investment tax credits totaling $5.3 million and $3.7 million respectively, are included in Deferred credits & other liabilities. The investment tax credit generated in 2013 will expire in 20 years. At December 31, 2013, the Company has alternative minimum tax carryforwards which do not expire. In addition, the Company has $6.1 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, 2013 and 2012, the valuation allowance was $3.6 million and $1.3 million, respectively. | |||||||||||||
Indiana House Bill 1004 | |||||||||||||
In May 2011, House Bill 1004 was signed into law. This legislation phases in over four years a 2 percent rate reduction to the Indiana Adjusted Gross Income Tax for corporations. Pursuant to House Bill 1004, the tax rate will be lowered by 0.5 percent each year beginning on July 1, 2012, to the final rate of 6.5 percent effective July 1, 2015. Pursuant to FASB guidance, the Company accounted for the effect of the change in tax law on its deferred taxes in the second quarter of 2011, the period of enactment. The remeasurement of these temporary differences at the lower tax rate was recorded as a reduction of a regulatory asset. | |||||||||||||
The components of income tax expense and utilization of investment tax credits follow: | |||||||||||||
Year Ended December 31, | |||||||||||||
(In millions) | 2013 | 2012 | 2011 | ||||||||||
Current: | |||||||||||||
Federal | $ | 12.4 | $ | (8.2 | ) | $ | 4.4 | ||||||
State | 11.4 | 6.4 | 10.3 | ||||||||||
Total current taxes | 23.8 | (1.8 | ) | 14.7 | |||||||||
Deferred: | |||||||||||||
Federal | 43.4 | 80.3 | 66 | ||||||||||
State | 0.5 | 4.6 | 6.4 | ||||||||||
Total deferred taxes | 43.9 | 84.9 | 72.4 | ||||||||||
Amortization of investment tax credits | (0.6 | ) | (0.6 | ) | (0.7 | ) | |||||||
Total income tax expense | $ | 67.1 | $ | 82.5 | $ | 86.4 | |||||||
Uncertain Tax Positions | |||||||||||||
Following is a roll forward of unrecognized tax benefits for the three years ended December 31, 2013: | |||||||||||||
(In millions) | 2013 | 2012 | 2011 | ||||||||||
Unrecognized tax benefits at January 1 | $ | 4.8 | $ | 12.4 | $ | 13.3 | |||||||
Gross increases - tax positions in prior periods | — | 0.2 | 3.3 | ||||||||||
Gross decreases - tax positions in prior periods | (0.2 | ) | (9.4 | ) | (4.5 | ) | |||||||
Gross increases - current period tax positions | 1.2 | 1.9 | 0.6 | ||||||||||
Settlements | — | (0.3 | ) | (0.3 | ) | ||||||||
Lapse of statute of limitations | 0.1 | — | — | ||||||||||
Unrecognized tax benefits at December 31 | $ | 5.9 | $ | 4.8 | $ | 12.4 | |||||||
Of the change in unrecognized tax benefits during 2013, 2012, and 2011, almost none impacted the effective rate. The amount of unrecognized tax benefits, which if recognized, that would impact the effective tax rate was $0.7 million at each of December 31, 2013, 2012 and 2011. As of December 31, 2013, the unrecognized tax benefit relates to tax positions for which the ultimate deductibility is more likely than not but for which there is uncertainty about the timing of such deductibility. Because of the impact of deferred tax accounting, other than interest and penalties, the disallowance of the shorter deductibility period would not affect the annual effective tax rate but would accelerate the payment of cash to the taxing authority. Thus, it is not expected that any changes to these tax positions would have a significant impact on earnings. | |||||||||||||
The Company recognized income related to a reversal of interest expense previously accrued and net of penalties totaling approximately $0.1 million in 2013 and $0.7 million in 2012. In 2011, the Company recognized expense related to interest and penalties totaling approximately $0.4 million . The Company had approximately $0.5 million and $0.6 million for the payment of interest and penalties accrued as of December 31, 2013 and 2012, 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 $3.8 million and $3.2 million, respectively, at December 31, 2013 and 2012. | |||||||||||||
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 primary focus of the 2008 IRS examination was certain repairs and maintenance deductions, an area of particular focus by the IRS throughout the utility industry. In 2012, the IRS suspended all examinations related to this issue generally, resulting in the elimination of the audit risk in this area for the Company through 2012. The Company does not expect any changes to this liability for unrecognized income tax benefits within the next 12 months that would significantly impact the Company's results of operations or financial condition. The State of Indiana, 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 Internal Revenue Service (IRS) released final tangible property regulations regarding the deduction and capitalization of expenditures related to tangible property. The final regulations are generally effective for tax years beginning on or after January 1, 2014, but may be adopted for 2013 tax years. The Company intends to adopt the guidance for its 2014 tax year. The IRS has been working with the utility industry to provide industry specific guidance concerning the deductibility and capitalization of expenditures related to tangible property. The IRS has indicated that it expects to issue guidance with respect to natural gas transmission and distribution assets during 2014. The Company continues to evaluate the impact adoption of the regulations and industry guidance will have on its consolidated financial statements. As of this date, the Company does not expect the adoption of the regulations to have a material impact on its consolidated financial statements. |
Retirement_Plans_Other_Postret
Retirement Plans & Other Postretirement Benefits | 12 Months Ended | ||||||||||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||||||||||
Compensation and Retirement Disclosure [Abstract] | ' | ||||||||||||||||||||||||
Retirement Plans and Other Postretirement Benefits | ' | ||||||||||||||||||||||||
Retirement Plans & Other Postretirement Benefits | |||||||||||||||||||||||||
At December 31, 2013, 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, 2013 follows: | |||||||||||||||||||||||||
Pension Benefits | Other Benefits | ||||||||||||||||||||||||
(In millions) | 2013 | 2012 | 2011 | 2013 | 2012 | 2011 | |||||||||||||||||||
Service cost | $ | 8.6 | $ | 7.7 | $ | 6.9 | $ | 0.5 | $ | 0.5 | $ | 0.5 | |||||||||||||
Interest cost | 14.7 | 15.5 | 15.9 | 2 | 2.8 | 4.3 | |||||||||||||||||||
Expected return on plan assets | (22.1 | ) | (21.2 | ) | (21.2 | ) | — | — | — | ||||||||||||||||
Amortization of prior service cost (benefit) | 1.5 | 1.6 | 1.7 | (3.2 | ) | (2.5 | ) | (0.8 | ) | ||||||||||||||||
Amortization of actuarial loss (gain) | 10.1 | 6.8 | 3.8 | 0.7 | 0.7 | 0.6 | |||||||||||||||||||
Amortization of transitional obligation | — | — | — | — | 0.5 | 1.1 | |||||||||||||||||||
Settlement (credit) charge | 1.3 | — | — | — | — | — | |||||||||||||||||||
Net periodic benefit cost | $ | 14.1 | $ | 10.4 | $ | 7.1 | $ | — | $ | 2 | $ | 5.7 | |||||||||||||
A portion of the net periodic benefit cost disclosed in the table above is capitalized as Utility plant. Costs capitalized in 2013, 2012, and 2011 are estimated at $4.2 million, $3.7 million, and $3.9 million, respectively. | |||||||||||||||||||||||||
The Company lowered the discount rate used to measure periodic cost from 4.82 percent in 2012 to 4.03 percent in 2013 due to lower benchmark interest rates that approximated the expected duration of the Company’s benefit obligations as of that valuation date. For fiscal year 2014, the weighted average discount rate assumption will increase to 4.74 percent for the defined benefit pension plans, based on increased benchmark interest rates. | |||||||||||||||||||||||||
The weighted averages of significant assumptions used to determine net periodic benefit costs follow: | |||||||||||||||||||||||||
Pension Benefits | Other Benefits | ||||||||||||||||||||||||
2013 | 2012 | 2011 | 2013 | 2012 | 2011 | ||||||||||||||||||||
Discount rate | 4.03 | % | 4.82 | % | 5.5 | % | 3.91 | % | 4.75 | % | 5.5 | % | |||||||||||||
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 | % | 8 | % | N/A | N/A | 8 | % | |||||||||||||||
Expected increase in Consumer Price Index | N/A | N/A | N/A | 2.75 | % | 2.75 | % | 3 | % | ||||||||||||||||
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, 2013 and 2012 follows: | |||||||||||||||||||||||||
Pension Benefits | Other Benefits | ||||||||||||||||||||||||
(In millions) | 2013 | 2012 | 2013 | 2012 | |||||||||||||||||||||
Benefit obligation, beginning of period | $ | 377.3 | $ | 329.2 | $ | 54.4 | $ | 79.7 | |||||||||||||||||
Service cost – benefits earned during the period | 8.6 | 7.7 | 0.5 | 0.5 | |||||||||||||||||||||
Interest cost on projected benefit obligation | 14.7 | 15.5 | 2 | 2.8 | |||||||||||||||||||||
Plan participants' contributions | — | — | 0.8 | 1.6 | |||||||||||||||||||||
Plan amendments | — | 0.7 | (0.2 | ) | (26.6 | ) | |||||||||||||||||||
Actuarial loss (gain) | (32.7 | ) | 39 | (2.4 | ) | 2.8 | |||||||||||||||||||
Settlement loss (gain) | 1.5 | — | — | — | |||||||||||||||||||||
Medicare subsidy receipts | — | — | — | 0.5 | |||||||||||||||||||||
Benefit payments | (22.8 | ) | (14.8 | ) | (3.8 | ) | (6.9 | ) | |||||||||||||||||
Settlement payments | (8.2 | ) | — | — | — | ||||||||||||||||||||
Benefit obligation, end of period | $ | 338.4 | $ | 377.3 | $ | 51.3 | $ | 54.4 | |||||||||||||||||
The accumulated benefit obligation for all defined benefit pension plans was $321.9 million and $354.5 million at December 31, 2013 and 2012, respectively. | |||||||||||||||||||||||||
Postretirement Benefit Change | |||||||||||||||||||||||||
Effective September 1, 2012, the Company no longer offers postretirement health coverage for participants 65 and older. Rather, the Company provides a subsidy to plan participants to purchase health coverage through a private Medicare exchange. This change in benefits provides a comparable benefit at a reduced cost made possible by current market pricing. Since this change in benefits was a significant event pursuant to GAAP, the Company remeasured its postretirement benefit obligations as of June 1, 2012, consistent with the notification date to participants. The change in benefits, net of the impacts associated with remeasuring the benefit obligations using a lower discount rate, resulted in a $23 million reduction in the postretirement liability. Substantially all of the amount was recorded as a reduction to Regulatory Assets, as the Company's retirement costs primarily relate to its regulated utilities. The discount rate used to remeasure the postretirement benefit obligation was 3.93 percent. | |||||||||||||||||||||||||
The benefit obligation as of December 31, 2013 and 2012 was calculated using the following weighted average assumptions: | |||||||||||||||||||||||||
Pension Benefits | Other Benefits | ||||||||||||||||||||||||
2013 | 2012 | 2013 | 2012 | ||||||||||||||||||||||
Discount rate | 4.74 | % | 4.03 | % | 4.66 | % | 3.91 | % | |||||||||||||||||
Rate of compensation increase | 3.5 | % | 3.5 | % | N/A | N/A | |||||||||||||||||||
Expected increase in Consumer Price Index | N/A | N/A | 2.75 | % | 2.75 | % | |||||||||||||||||||
To calculate the 2013 ending postretirement benefit obligation, medical claims costs in 2014 were assumed to be 7 percent higher than those incurred in 2013. 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 $0.4 million. | |||||||||||||||||||||||||
Plan Assets | |||||||||||||||||||||||||
A reconciliation of the Company’s plan assets at December 31, 2013 and 2012 follows: | |||||||||||||||||||||||||
Pension Benefits | Other Benefits | ||||||||||||||||||||||||
(In millions) | 2013 | 2012 | 2013 | 2012 | |||||||||||||||||||||
Plan assets at fair value, beginning of period | $ | 295.7 | $ | 261 | $ | — | $ | — | |||||||||||||||||
Actual return on plan assets | 48.4 | 33.8 | — | — | |||||||||||||||||||||
Employer contributions | 10.8 | 15.7 | 3 | 5.3 | |||||||||||||||||||||
Plan participants' contributions | — | — | 0.8 | 1.6 | |||||||||||||||||||||
Benefit payments | (22.8 | ) | (14.8 | ) | (3.8 | ) | (6.9 | ) | |||||||||||||||||
Settlement payments | (8.2 | ) | — | — | — | ||||||||||||||||||||
Fair value of plan assets, end of period | $ | 323.9 | $ | 295.7 | $ | — | $ | — | |||||||||||||||||
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 53 percent and 42 percent, respectively, of their fair value as of December 31, 2013 and approximately 53 percent and 38 percent, respectively, as of December 31, 2012. 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 $161.7 million at December 31, 2013 and $145.0 million at December 31, 2012. 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, 2013 and 2012, the estimate of undiscounted funds necessary to satisfy John Hancock’s remaining obligation was $3.7 million and $3.6 million, respectively. If funds retained by John Hancock are not sufficient to satisfy retirement payments due 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, 2013 and 2012 was 4.75 percent and 5.17 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, 2013 and December 31, 2012 by asset category and by fair value hierarchy are as follows: | |||||||||||||||||||||||||
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 | |||||||||||||||||
As of December 31, 2012 | |||||||||||||||||||||||||
(In millions) | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||||||
Domestic equities & equity funds | $ | 62.8 | $ | 77.6 | $ | — | $ | 140.4 | |||||||||||||||||
International equities & equity funds | 34.3 | — | — | 34.3 | |||||||||||||||||||||
Domestic bonds & bond funds | 41.7 | 42.3 | — | 84 | |||||||||||||||||||||
Inflation protected security fund | — | 12.6 | — | 12.6 | |||||||||||||||||||||
Real estate, commodities & other | 8 | 12.5 | 3.9 | 24.4 | |||||||||||||||||||||
Total plan investments | $ | 146.8 | $ | 145 | $ | 3.9 | $ | 295.7 | |||||||||||||||||
A roll forward of the fair value of the guaranteed annuity contract calculated using Level 3 valuation assumptions follows: | |||||||||||||||||||||||||
(In millions) | 2013 | 2012 | |||||||||||||||||||||||
Fair value, beginning of year | $ | 3.9 | $ | 3.8 | |||||||||||||||||||||
Unrealized gains related to | 0.2 | 0.2 | |||||||||||||||||||||||
investments still held at reporting date | |||||||||||||||||||||||||
Purchases, sales and settlements, net | — | (0.1 | ) | ||||||||||||||||||||||
Fair value, end of year | $ | 4.1 | $ | 3.9 | |||||||||||||||||||||
Funded Status | |||||||||||||||||||||||||
The funded status of the plans as of December 31, 2013 and 2012 follows: | |||||||||||||||||||||||||
Pension Benefits | Other Benefits | ||||||||||||||||||||||||
(In millions) | 2013 | 2012 | 2013 | 2012 | |||||||||||||||||||||
Qualified Plans | |||||||||||||||||||||||||
Benefit obligation, end of period | $ | (321.0 | ) | $ | (360.0 | ) | $ | (51.4 | ) | $ | (54.4 | ) | |||||||||||||
Fair value of plan assets, end of period | 323.9 | 295.7 | — | — | |||||||||||||||||||||
Funded Status of Qualified Plans, end of period | 2.9 | (64.3 | ) | (51.4 | ) | (54.4 | ) | ||||||||||||||||||
Benefit obligation of SERP Plan, end of period | (17.5 | ) | (17.3 | ) | — | — | |||||||||||||||||||
Total funded status, end of period | $ | (14.6 | ) | $ | (81.6 | ) | $ | (51.4 | ) | $ | (54.4 | ) | |||||||||||||
Accrued liabilities | $ | 1 | $ | 1 | $ | 4.9 | $ | 4.5 | |||||||||||||||||
Deferred credits & other liabilities | $ | 20.1 | $ | 80.6 | $ | 46.4 | $ | 49.9 | |||||||||||||||||
Other Assets | $ | 6.5 | $ | — | $ | — | $ | — | |||||||||||||||||
Expected Cash Flows | |||||||||||||||||||||||||
In 2014, the Company anticipates making no contributions to its qualified pension plans. In addition, the Company expects to make payments totaling approximately $1.0 million directly to SERP participants and approximately $3.7 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 2013 are approximately (in millions) $23.7 in 2014, $23.6 in 2015, $24.6 in 2016, $34.3 in 2017, $25.5 in 2018, and $140.4 in years 2019-2023. Expected benefit payments projected to be required for postretirement benefits during the years following 2013 (in millions) are approximately $4.9 in 2014, $5.0 in 2015, $5.2 in 2016, $5.5 in 2017, $5.9 in 2018, and $31.9 in years 2019-2023. | |||||||||||||||||||||||||
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, 2011 | $ | 7.1 | $ | 78.2 | $ | (2.0 | ) | $ | 10.3 | $ | 3.8 | ||||||||||||||
Amounts arising during the period | — | 42.2 | — | (0.6 | ) | — | |||||||||||||||||||
Reclassification to benefit costs | (1.7 | ) | (3.8 | ) | 0.8 | (0.6 | ) | (1.1 | ) | ||||||||||||||||
Balance at December 31, 2011 | $ | 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 | $ | — | ||||||||||||||
Following is a reconciliation of the amounts in Accumulated other comprehensive income (AOCI) and Regulatory assets related to retirement plan obligations at December 31, 2013 and 2012. | |||||||||||||||||||||||||
(In millions) | 2013 | 2012 | |||||||||||||||||||||||
Pensions | Other Benefits | Pensions | Other Benefits | ||||||||||||||||||||||
Prior service cost | $ | 3 | $ | (20.1 | ) | $ | 4.5 | $ | (23.1 | ) | |||||||||||||||
Unamortized actuarial gain/(loss) | 67.3 | 8.1 | 136.2 | 11.2 | |||||||||||||||||||||
Transition obligation | — | — | — | — | |||||||||||||||||||||
70.3 | (12.0 | ) | 140.7 | (11.9 | ) | ||||||||||||||||||||
Less: Regulatory asset deferral | (68.9 | ) | 11.8 | (137.9 | ) | 11.7 | |||||||||||||||||||
AOCI before taxes | $ | 1.4 | $ | (0.2 | ) | $ | 2.8 | $ | (0.2 | ) | |||||||||||||||
Related to pension plans, $1.1 million of prior service cost and $4.7 million of actuarial gain/loss is expected to be amortized to cost in 2014. Related to other benefits, $0.4 million of actuarial gain/loss is expected to be amortized to periodic cost in 2014, and $3.0 million of prior service cost is expected to reduce costs in 2014. | |||||||||||||||||||||||||
Multi-employer Benefit Plan | |||||||||||||||||||||||||
The Company, through its Infrastructure Services operating segment, participates in several industry wide multi-employer pension plans for its union employees which provide for monthly benefits based on length of service. The risks of participating in multi-employer pension plans are different from the risks of participating in single-employer pension plans in the following respects: 1) assets contributed to the multi-employer 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 multi-employer 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 multi-employer plans was $33.2 million, $27.6 million and $18.3 million for the years ended December 31, 2013, 2012, and 2011, respectively. The increase in expense is due primarily to the increase in work performed. During 2013, the Company, made contributions to these multi-employer plans on behalf of employees that participate in approximately 270 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 2014 through 2016. The average contribution related to these local unions was less than $0.2 million, and the largest contribution was $4.0 million. Multiple unions can contribute to a single multi-employer plan. The Company made contributions to at least sixty plans in 2013, 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 2013 and 2012 is for the plan year end at January 31, 2012 and 2011 for the Central Pension Fund, December 31, 2012 and 2011 for the Pipeline Industry Benefit Fund, May 31, 2013 and 2012 for the Indiana Laborers Pension Fund, and December 31, 2012 and 2011 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 multi-employer contributions listed in the table below are the Company's multi-employer contributions made in 2013, 2012, and 2011. | |||||||||||||||||||||||||
(In millions) | |||||||||||||||||||||||||
Pension Protection Act Zone Status | Multi-Employer Contributions | ||||||||||||||||||||||||
Pension Fund | EIN/Pension Plan Number | 2013 | 2012 | FIP/RP Status Pending/Implemented | 2013 | 2012 | 2011 | Surcharge Imposed | |||||||||||||||||
Central Pension Fund | 36-6052390-001 | Green | Green | No | $8.50 | $4.00 | $2.30 | No | |||||||||||||||||
Pipeline Industry Benefit Fund | 73-0742835-001 | Green | Green | No | 5.3 | 3.9 | 1 | No | |||||||||||||||||
Indiana Laborers Pension Fund (1) | 35-6027150-001 | Yellow | Yellow | Implemented | 2.4 | 3.2 | 1.6 | No | |||||||||||||||||
Minnesota Laborers Pension Fund | 41-6159599-001 | Green | Green | No | 2.8 | 2 | 0.7 | No | |||||||||||||||||
Other | 14.2 | 14.5 | 12.7 | ||||||||||||||||||||||
Total Contributions | $33.20 | $27.60 | $18.30 | ||||||||||||||||||||||
(1) Federal law requires pension plans in endangered status to adopt a funding improvement plan aimed at restoring the financial health of the plan. Since this plan 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. Based on the plan's most current actuarial projections, the plan is projected to meet or exceed these benchmarks. | |||||||||||||||||||||||||
While not considered significant to the Company, there are eight plans in red zone status receiving Company contributions and three other plans where Company contributions exceed 5 percent of each plan's total contributions. | |||||||||||||||||||||||||
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 2013, 2012 and 2011, the Company made contributions to these plans of $7.5 million, $6.7 million, and $6.2 million, respectively. |
Borrowing_Arrangements
Borrowing Arrangements | 12 Months Ended | ||||||||||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||||||||||
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) | 2013 | 2012 | |||||||||||||||||||||||
Utility Holdings | |||||||||||||||||||||||||
Fixed Rate Senior Unsecured Notes | |||||||||||||||||||||||||
2013, 5.25% | $ | — | $ | 100 | |||||||||||||||||||||
2015, 5.45% | 75 | 75 | |||||||||||||||||||||||
2018, 5.75% | 100 | 100 | |||||||||||||||||||||||
2020, 6.28% | 100 | 100 | |||||||||||||||||||||||
2021, 4.67% | 55 | 55 | |||||||||||||||||||||||
2023, 3.72% | 150 | — | |||||||||||||||||||||||
2026, 5.02% | 60 | 60 | |||||||||||||||||||||||
2028, 3.20% | 45 | — | |||||||||||||||||||||||
2035, 6.10% | 75 | 75 | |||||||||||||||||||||||
2039, 6.25% | — | 121.6 | |||||||||||||||||||||||
2041, 5.99% | 35 | 35 | |||||||||||||||||||||||
2042, 5.00% | 100 | 100 | |||||||||||||||||||||||
2043, 4.25% | 80 | — | |||||||||||||||||||||||
Total Utility Holdings | 875 | 821.6 | |||||||||||||||||||||||
Indiana Gas | |||||||||||||||||||||||||
Fixed Rate Senior Unsecured Notes | |||||||||||||||||||||||||
2013, Series E, 6.69% | — | 5 | |||||||||||||||||||||||
2015, Series E, 7.15% | 5 | 5 | |||||||||||||||||||||||
2015, Series E, 6.69% | 5 | 5 | |||||||||||||||||||||||
2015, Series E, 6.69% | 10 | 10 | |||||||||||||||||||||||
2025, Series E, 6.53% | 10 | 10 | |||||||||||||||||||||||
2027, Series E, 6.42% | 5 | 5 | |||||||||||||||||||||||
2027, Series E, 6.68% | 1 | 1 | |||||||||||||||||||||||
2027, Series F, 6.34% | 20 | 20 | |||||||||||||||||||||||
2028, Series F, 6.36% | 10 | 10 | |||||||||||||||||||||||
2028, Series F, 6.55% | 20 | 20 | |||||||||||||||||||||||
2029, Series G, 7.08% | 30 | 30 | |||||||||||||||||||||||
Total Indiana Gas | 116 | 121 | |||||||||||||||||||||||
SIGECO | |||||||||||||||||||||||||
First Mortgage Bonds | |||||||||||||||||||||||||
2015, 1985 Pollution Control Series A, current adjustable rate 0.05%, tax exempt, | |||||||||||||||||||||||||
2013 weighted average: 0.10% | 9.8 | 9.8 | |||||||||||||||||||||||
2016, 1986 Series, 8.875% | 13 | 13 | |||||||||||||||||||||||
2020, 1998 Pollution Control Series B, 4.50%, tax exempt | — | 4.6 | |||||||||||||||||||||||
2022, 2013 Series C, 1.95%, tax exempt | 4.6 | — | |||||||||||||||||||||||
2023, 1993 Environmental Improvement Series B, 5.15%, tax exempt | — | 22.6 | |||||||||||||||||||||||
2024, 2000 Environmental Improvement Series A, 4.65%, tax exempt | — | 22.5 | |||||||||||||||||||||||
2024, 2013 Series D, 1.95%, tax exempt | 22.5 | — | |||||||||||||||||||||||
2025, 1998 Pollution Control Series A, current adjustable rate 0.05%, tax exempt, | |||||||||||||||||||||||||
2013 weighted average: 0.10% | 31.5 | 31.5 | |||||||||||||||||||||||
2029, 1999 Series, 6.72% | 80 | 80 | |||||||||||||||||||||||
2030, 1998 Pollution Control Series B, 5.00%, tax exempt | — | 22 | |||||||||||||||||||||||
At December 31, | |||||||||||||||||||||||||
(In millions) | 2013 | 2012 | |||||||||||||||||||||||
2030, 1998 Pollution Control Series C, 5.35%, tax exempt | — | 22.2 | |||||||||||||||||||||||
2037, 2013 Series E, 1.95%, tax exempt | 22 | — | |||||||||||||||||||||||
2038, 2013 Series A, 4.0%, tax exempt | 22.2 | — | |||||||||||||||||||||||
2040, 2009 Environmental Improvement Series, 5.40%, tax exempt | 22.3 | 22.3 | |||||||||||||||||||||||
2041, 2007 Pollution Control Series, 5.45%, tax exempt | — | 17 | |||||||||||||||||||||||
2043, 2013 Series B, 4.05%, tax exempt | 39.6 | — | |||||||||||||||||||||||
Total SIGECO | 267.5 | 267.5 | |||||||||||||||||||||||
Vectren Capital Corp. | |||||||||||||||||||||||||
Fixed Rate Senior Unsecured Notes | |||||||||||||||||||||||||
2014, 6.37% | 30 | 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, current adjustable rate 1.17% | 100 | 100 | |||||||||||||||||||||||
2016, current adjustable rate 1.17% | 100 | — | |||||||||||||||||||||||
Total Vectren Capital Corp. | 550 | 450 | |||||||||||||||||||||||
Other Long-Term Notes Payable | — | 1.4 | |||||||||||||||||||||||
Total long-term debt outstanding | 1,808.50 | 1,661.50 | |||||||||||||||||||||||
Current maturities of long-term debt | (30.0 | ) | (106.4 | ) | |||||||||||||||||||||
Unamortized debt premium & discount - net | (1.4 | ) | (1.7 | ) | |||||||||||||||||||||
Total long-term debt-net | $ | 1,777.10 | $ | 1,553.40 | |||||||||||||||||||||
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 bear interest at either a Eurodollar rate or base rate plus an additional margin which is based on the Company's credit rating. Interest periods are variable and may range 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 is guaranteed by Vectren Corporation and includes 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 August 2013. | |||||||||||||||||||||||||
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 December 31, 2038, and $39.6 million at 4.05 percent per annum due December 31, 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 bear interest at either a Eurodollar rate or base rate plus an additional margin which is based on the Company's credit rating. Interest periods are variable and may range 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 is guaranteed by Vectren Corporation and includes 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. | |||||||||||||||||||||||||
Utility Holdings 2012 Debt Transactions | |||||||||||||||||||||||||
On February 1, 2012, Utility Holdings issued $100 million of senior unsecured notes at an interest rate of 5.00 percent per annum and with a maturity date of February 3, 2042. The notes were sold to various institutional investors pursuant to a private placement note purchase agreement executed in November 2011 with a delayed draw feature. These senior notes are unsecured and jointly and severally guaranteed by Utility Holdings’ regulated utility subsidiaries, SIGECO, Indiana Gas, and VEDO. The proceeds from the sale of the notes, net of issuance costs, totaled approximately $99.5 million. These notes have no sinking fund requirements and interest payments are due semi-annually. These notes contain customary representations, warranties and covenants, including a leverage covenant consistent with leverage covenants contained in other Utility Holdings’ borrowing arrangements. | |||||||||||||||||||||||||
Utility Holdings 2011 Debt Issuance | |||||||||||||||||||||||||
On November 21, 2011, the Company exercised a call option on Utility Holdings' $96.2 million 5.95 percent senior notes due 2036. This debt was refinanced on November 30, 2011. On that date, Utility Holdings closed a financing under a private placement note purchase agreement pursuant to which various institutional investors purchased the following tranches of notes: (i) $55 million of 4.67 percent Senior Guaranteed Notes, due November 30, 2021, (ii) $60 million of 5.02 percent Senior Guaranteed Notes, due November 30, 2026, and (iii) $35 million of 5.99 percent Senior Guaranteed Notes, due December 2, 2041. These senior notes are unsecured and jointly and severally guaranteed by Utility Holdings’ regulated utility subsidiaries, SIGECO, Indiana Gas, and VEDO. The proceeds from the sale of the notes, net of issuance costs, totaled $149.0 million. These notes have no sinking fund requirements and interest payments are due semi-annually. These notes contain customary representations, warranties and covenants, including a leverage covenant consistent with leverage covenants contained in other Utility Holdings’ borrowing arrangements. | |||||||||||||||||||||||||
Long-Term Debt Puts, Calls, and Mandatory Tenders | |||||||||||||||||||||||||
Certain long-term debt issues contain optional put and call provisions that can be exercised on various dates before maturity. During 2013, the Company had no repayments related to investor put provisions and at December 31, 2013, the only debt with investor puts were two series of SIGECO variable rate demand bonds, aggregating $41.3 million, with a variable interest rate that is reset weekly. This SIGECO debt is fully supported by letters of credit that are available should any of the debt holders decide to put the debt to SIGECO and the remarketing agent is unable to remarket it to other investors. | |||||||||||||||||||||||||
Certain other series of SIGECO bonds, aggregating $49.1 million, currently bear interest at fixed rates and are subject to mandatory tender in September 2017. | |||||||||||||||||||||||||
In March and April, 2013, the Company notified holders of six issues of SIGECO's tax exempt long-term debt totaling $110.9 million with interest rates ranging from 4.50 percent to 5.45 percent, and with maturity dates from 2020 to 2041of its intent to call this debt. The call options were exercised at par in April and May, 2013. | |||||||||||||||||||||||||
Letters of Credit Supporting Long-Term Debt | |||||||||||||||||||||||||
As of December 31, 2013, Utility Holdings has letters of credit outstanding in support of two SIGECO tax exempt adjustable rate first mortgage bonds totaling $41.7 million. In the unlikely event the letters of credit were called, the Company could settle with the financial institutions supporting these letters of credit with general assets or by drawing from its credit facility that expires in September 2016. Due to the long-term nature of the credit agreement, such debt is classified as long-term at December 31, 2013. | |||||||||||||||||||||||||
Future Long-Term Debt Sinking Fund Requirements and Maturities | |||||||||||||||||||||||||
The annual sinking fund requirement of SIGECO's first mortgage bonds is 1 percent of the greatest amount of bonds outstanding under the Mortgage Indenture. This requirement may be satisfied by certification to the Trustee of unfunded property additions in the prescribed amount as provided in the Mortgage Indenture. SIGECO intends to meet the 2013 sinking fund requirement by this means and, accordingly, the sinking fund requirement for 2013 is excluded from Current liabilities in the Consolidated Balance Sheets. At December 31, 2013, $1.2 billion of SIGECO's utility plant remained unfunded under SIGECO's Mortgage Indenture. SIGECO’s gross utility plant balance subject to the Mortgage Indenture approximated $2.9 billion at December 31, 2013. | |||||||||||||||||||||||||
Consolidated maturities of long-term debt during the five years following 2013 (in millions) are $30.0 in 2014, $279.8 in 2015, $173.0 in 2016, $75.0 in 2017, $100.0 in 2018, and $1,149.3 thereafter. | |||||||||||||||||||||||||
Debt Guarantees | |||||||||||||||||||||||||
Vectren Corporation guarantees Vectren Capital’s long-term debt, including current maturities, and short-term debt, which totaled $550 million and $40 million, respectively, at December 31, 2013. Utility Holdings’ currently outstanding long-term and short-term debt is jointly and severally guaranteed by Indiana Gas, SIGECO, and VEDO. Utility Holdings’ long-term debt and short-term debt outstanding at December 31, 2013, totaled $875 million and $29 million, respectively. | |||||||||||||||||||||||||
Covenants | |||||||||||||||||||||||||
Both long-term and short-term borrowing arrangements contain customary default provisions; restrictions on liens, sale-leaseback transactions, mergers or consolidations, and sales of assets; and restrictions on leverage, among other restrictions. Multiple debt agreements contain a covenant that the ratio of consolidated total debt to consolidated total capitalization will not exceed 65 percent. As of December 31, 2013, the Company was in compliance with all financial covenants. | |||||||||||||||||||||||||
Short-Term Borrowings | |||||||||||||||||||||||||
At December 31, 2013, 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 $321 million was available for the Utility Group operations and approximately $210 million was available for the wholly owned Nonutility Group and corporate operations. Both Vectren Capital’s and Utility Holdings’ short-term credit facilities were renewed in November 2011 and are available through September 2016. The maximum limit of both facilities remained unchanged. 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) | 2013 | 2012 | 2011 | 2013 | 2012 | 2011 | |||||||||||||||||||
As of Year End | |||||||||||||||||||||||||
Balance Outstanding | $ | 28.6 | $ | 116.7 | $ | 242.8 | $ | 40 | $ | 162.1 | $ | 84.3 | |||||||||||||
Weighted Average Interest Rate | 0.29 | % | 0.4 | % | 0.57 | % | 1.27 | % | 1.35 | % | 1.45 | % | |||||||||||||
Annual Average | |||||||||||||||||||||||||
Balance Outstanding | $ | 119.6 | $ | 77.6 | $ | 39.6 | $ | 119.3 | $ | 151.5 | $ | 124.9 | |||||||||||||
Weighted Average Interest Rate | 0.34 | % | 0.47 | % | 0.48 | % | 1.35 | % | 1.44 | % | 1.92 | % | |||||||||||||
Maximum Month End Balance Outstanding | $ | 176.1 | $ | 214.2 | $ | 242.8 | $ | 173.8 | $ | 216.1 | $ | 180.1 | |||||||||||||
Throughout 2013, 2012, and 2011, 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, 2013 | |
Stockholders' Equity Note [Abstract] | ' |
Common Shareholder's Equity | ' |
Common Shareholders’ Equity | |
Authorized, Reserved Common and Preferred Shares | |
At December 31, 2013 and 2012, 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 5.8 million shares at December 31, 2013 and 6.5 million shares at December 31, 2012, 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, 2013 and 2012, there were 391.7 million and 391.3 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, 2013 | |||||||||||||
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, 2013: | |||||||||||||
Year Ended December 31, | |||||||||||||
(In millions, except per share data) | 2013 | 2012 | 2011 | ||||||||||
Numerator: | |||||||||||||
Numerator for basic EPS | $ | 136.6 | $ | 159 | $ | 141.6 | |||||||
Add back earnings attributable to participating securities | — | — | — | ||||||||||
Reported net income (Numerator for Diluted EPS) | $ | 136.6 | $ | 159 | $ | 141.6 | |||||||
Denominator: | |||||||||||||
Weighted average common shares outstanding (Basic EPS) | 82.3 | 82 | 81.8 | ||||||||||
Conversion of share based compensation arrangements | 0.1 | 0.1 | 0 | ||||||||||
Adjusted weighted average shares outstanding and | |||||||||||||
assumed conversions outstanding (Diluted EPS) | 82.4 | 82.1 | 81.8 | ||||||||||
Basic earnings per share | $ | 1.66 | $ | 1.94 | $ | 1.73 | |||||||
Diluted earnings per share | $ | 1.66 | $ | 1.94 | $ | 1.73 | |||||||
For the years ended December 31, 2013 , 2012, and 2011, all options and equity based instruments were dilutive. |
Accumulated_Other_Comprehensiv
Accumulated Other Comprehensive Income | 12 Months Ended | ||||||||||||||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||||||||||||||
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: | |||||||||||||||||||||||||||||
2011 | 2012 | 2013 | |||||||||||||||||||||||||||
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 | $ | (6.6 | ) | $ | (9.3 | ) | $ | (15.9 | ) | $ | 11.3 | $ | (4.6 | ) | $ | 4.6 | $ | — | |||||||||||
Pension & other benefit costs | (4.9 | ) | (1.7 | ) | (6.6 | ) | 4 | (2.6 | ) | 1.4 | (1.2 | ) | |||||||||||||||||
Cash flow hedges | 4 | (3.9 | ) | 0.1 | (0.1 | ) | — | — | — | ||||||||||||||||||||
Deferred income taxes | 3.1 | 6 | 9.1 | (6.2 | ) | 2.9 | (2.4 | ) | 0.5 | ||||||||||||||||||||
Accumulated other comprehensive income (loss) | $ | (4.4 | ) | $ | (8.9 | ) | $ | (13.3 | ) | $ | 9 | $ | (4.3 | ) | $ | 3.6 | $ | (0.7 | ) | ||||||||||
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, 2013 | ||||||||||||||
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 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) | 2013 | 2012 | 2011 | |||||||||||
Total cost of share-based compensation | $ | 14.8 | $ | 6.3 | $ | 5.8 | ||||||||
Less capitalized cost | 2.8 | 1.2 | 0.8 | |||||||||||
Total in other operating expense | 12 | 5.1 | 5 | |||||||||||
Less income tax benefit in earnings | 4.8 | 2.1 | 2 | |||||||||||
After tax effect of share-based compensation | $ | 7.2 | $ | 3 | $ | 3 | ||||||||
Performance Based Awards & Other Awards | ||||||||||||||
The vesting of awards issued to Company officers and other key non-officer employees is contingent upon meeting a total return and return on equity performance objectives. Grants to Company officers and key non-officer employees generally vest at the end of a four-year period, with performance measured at the end of the third year. Based on that performance, awards could double or could be entirely forfeited. However, a limited number of awards have also been time-vested awards that 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. Certain share awards to key 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, 2013, and changes during the year ended December 31, 2013, follows: | ||||||||||||||
Equity Awards | ||||||||||||||
Wtd. Avg. | ||||||||||||||
Grant Date | Liability Awards | |||||||||||||
Units | Fair value | Units | Fair value | |||||||||||
Awards at January 1, 2013 | 70,493 | $ | 27.45 | 628,810 | ||||||||||
Granted | 28,579 | 30.19 | 305,617 | |||||||||||
Vested | -15,175 | 26.04 | -158,187 | |||||||||||
Forfeited | -3,940 | 26.2 | -44,989 | |||||||||||
Awards at December 31, 2013 | 79,957 | $ | 29.12 | 731,251 | $ | 35.5 | ||||||||
As of December 31, 2013, there was $11.8 million of total unrecognized compensation cost associated with outstanding grants. That cost is expected to be recognized over a weighted-average period of 2.3 years. The total fair value of shares vested for liability awards during the years ended December 31, 2013, 2012, and 2011, was $5.7 million, $4.4 million, and $3.0 million, respectively. The total fair value of equity awards vesting during the year ended December 31, 2013, 2012, and 2011 was $0.4 million, $0.1 million, $0.2 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 does not intend to issue options in the future. All compensation cost has been recognized. A summary of the status of the Company’s stock option awards as of December 31, 2013, and changes during the year ended December 31, 2013, follows: | ||||||||||||||
Weighted average | Aggregate | |||||||||||||
Shares | Exercise | Remaining | Intrinsic | |||||||||||
Price | Contractual | Value | ||||||||||||
Term (years) | (In millions) | |||||||||||||
Outstanding at January 1, 2013 | 386,565 | $ | 25.88 | |||||||||||
Exercised | (378,592 | ) | $ | 25.87 | ||||||||||
Forfeited or expired | (727 | ) | $ | 22.57 | ||||||||||
Outstanding at December 31, 2013 | 7,246 | $ | 26.7 | 1 | $ | 0.6 | ||||||||
Exercisable at December 31, 2013 | 7,246 | $ | 26.7 | 1 | $ | 0.6 | ||||||||
The total intrinsic value of options exercised during the year ended December 31, 2013 , 2012, and 2011 was $3.8 million, $0.1 million, and $2.4 million respectively. The actual tax benefit realized for tax deductions from option exercises was approximately $1.5 million , $0.1 million, and $1.0 million in 2013 , 2012, and 2011, respectively. | ||||||||||||||
The Company periodically issues new shares and also from time to time repurchases shares to satisfy share option exercises. During the year ended December 31, 2013 , 2012, and 2011 the Company received cash upon exercise of stock options totaling approximately $9.7 million , $0.3 million, and $12.3 million respectively. During these periods, the Company repurchased shares totaling approximately $12.3 million , $0.1 million, and $12.8 million respectively. | ||||||||||||||
The fair value of option awards granted in prior years was estimated on the date of grant using a Black-Scholes option valuation model. Expected volatilities were based on historical volatility of the Company’s stock and other factors. The Company used historical data to estimate the expected term and forfeiture patterns of the options. The risk-free rate for periods within the contractual life of the option was based on the U.S. Treasury yield curve in effect at the time of grant. | ||||||||||||||
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, 2013 and 2012, the liability associated with these plans totaled $26.1 million and $22.9 million, respectively. Other than $1.6 million and $1.3 million which are classified in Accrued liabilities at December 31, 2013 and 2012, respectively, the liability is included in Deferred credits & other liabilities. The impact of these plans on Other operating expenses was expense of $4.0 million in 2013, $1.7 million in 2012 and $2.1 million in 2011. The amount recorded in earnings related to the investment activities in Vectren phantom stock associated with these plans during the years ended December 31, 2013, 2012, and 2011, was a cost of $2.6 million, $0.6 million and $1.7 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 $32.9 million and $29.1 million at December 31, 2013 and 2012, respectively. Earnings from those investments, which are recorded in Other-net, were earnings of $4.8 million in 2013, $1.8 million in 2012, and $0.1 million in 2011. |
Commitments_and_Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2013 | |
Commitments and Contingencies Disclosure [Abstract] | ' |
Commitments and Contingencies | ' |
Commitments & Contingencies | |
Commitments | |
Future minimum lease payments required under operating leases that have initial or remaining noncancelable lease terms in excess of one year during the five years following 2013 and thereafter (in millions) are $6.9 in 2014, $5.0 in 2015, $2.9 in 2016, $1.3 in 2017, $1.2 in 2018, and $5.0 thereafter. Total lease expense (in millions) was $9.9 in 2013, $8.5 in 2012, and $6.9 in 2011. | |
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, 2013, parent level guarantees support a maximum of $25 million of ESG’s performance contracting commitments and warranty obligations and $45 million of other project guarantees. The broader scope of ESG’s performance contracting obligations, including those not guaranteed by the parent company, are described below. In addition, the parent company has approximately $25 million of other guarantees outstanding supporting other consolidated subsidiary operations, of which $19 million represent letters of credit supporting other nonutility operations. As disclosed in Note 7, a guarantee issued and outstanding to an unrelated party in connection with ProLiance's disposition of certain of the net assets of ProLiance Energy totaled $15.3 million at December 31, 2013. Although there can be no assurance that these guarantees will not be called upon, the Company believes that the likelihood the Company will be called upon to satisfy any obligations pursuant to these guarantees 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, 2013, there are 57 open surety bonds supporting future performance. The average face amount of these obligations is $4.4 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, 2013, approximately 47 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 significant accruals for these warranty obligations as of December 31, 2013. In addition, ESG has an $8 million stand-alone letter of credit facility and as of December 31, 2013, $3.4 million was outstanding. | |
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. |
Rate_Regulatory_Matters
Rate & Regulatory Matters | 12 Months Ended |
Dec. 31, 2013 | |
Public Utilities, General Disclosures [Abstract] | ' |
Rate and Regulatory Matters | ' |
Rate & Regulatory Matters | |
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement | |
Vectren monitors and maintains its natural gas distribution system to ensure that natural gas is delivered in a safe and efficient manner. Vectren's natural gas utilities are currently engaged in replacement programs in both Indiana and Ohio, the primary purpose of which is preventive maintenance and continual renewal and operational improvement. Laws in both Indiana and Ohio were passed that expand the ability of utilities to recover certain costs of federally mandated projects and other infrastructure improvement projects, outside of a base rate proceeding. Utilization of these recovery mechanisms is discussed below. | |
Ohio Recovery and Deferral Mechanisms | |
The PUCO order approving the Company's 2009 base rate case in the Ohio service territory authorized a distribution replacement rider (DRR). The DRR's primary purpose is recovery of investments in utility plant and related operating expenses associated with replacing bare steel and cast iron pipelines and certain other infrastructure. This rider is updated annually for qualifying capital expenditures and allows for a return to be earned on those capital expenditures based on the rate of return approved in the 2009 base rate case. In addition, deferral of depreciation and the ability to accrue debt-related post in service carrying costs is also allowed until the related capital expenditures are recovered through the DRR. The order also established a prospective bill impact evaluation on the annual deferrals, limiting the deferrals at a level which would equal a change over the prior year rate of $1.00 per residential and small general service customer per month. To date, the Company has made capital investments under this rider totaling $109 million. During 2013, 2012, and 2011 gas operating revenues associated with the DRR were $9.8 million, $6.5 million, and $3.6 million, respectively. Other income associated with the debt-related post in service carrying costs totaled $2.0 million, $1.8 million, and $2.0 million for 2013, 2012, and 2011, respectively. Regulatory assets associated with post in service carrying costs and depreciation deferrals were $9.3 million, $6.5 million, and $3.0 million at December 31, 2013, 2012, and 2011 respectively. Due to the expiration of the initial five year term for the DRR in early 2014, the Company filed a request in August 2013 to extend and expand the DRR. On February 19, 2014, the PUCO approved a Stipulation entered into by the PUCO Staff and the Company which provided for the extension of the DRR through 2017 and expanded the types of investment covered by the DRR to include recovery of other infrastructure investments. The Order approved the Company's five-year capital expenditure plan for calendar years 2013 through 2017 totaling $187 million related to these infrastructure investments, along with savings credits associated with reduced operations and maintenance expenses for each mile of aging infrastructure replaced. In addition, the Order approved the Company's commitment that the DRR can only be further extended as part of a base rate case. | |
In June 2011, Ohio House Bill 95 was signed into law. Outside of a base rate proceeding, this legislation permits a natural gas company to apply for recovery of much of its capital expenditure program. The legislation also allows for the deferral of costs, such as depreciation, property taxes, and debt-related post in service carrying costs. On December 12, 2012, the PUCO issued an order approving the Company's initial application using this law, reflecting its $23.5 million capital expenditure program covering the fifteen month period ending December 31, 2012. Such capital expenditures include infrastructure expansion and improvements not covered by the DRR as well as expenditures necessary to comply with PUCO rules, regulations, orders, and system expansion to some new customers. The order also established a prospective bill impact evaluation on the cumulative deferrals, limiting the total deferrals at a level which would equal $1.50 per residential and small general service customer per month. On December 4, 2013, the Company received an order granting the accounting authority described above on its capital expenditure program for the 2013 calendar year totaling $61.5 million. Of this total amount, $34.8 million relates to expenditures that potentially could be recoverable under the pending DRR discussed above. If this amount is found by the PUCO to not be recoverable through the DRR, the order granted deferral for future recovery through a House Bill 95 mechanism. In addition, the order approved the Company's proposal that subsequent requests for accounting authority will be filed annually in April. During 2013 and 2012, these approved capital expenditure programs under House Bill 95 generated Other income associated with the debt-related post in service carrying costs totaling $2.2 million and $0.9 million, respectively. Deferral of depreciation and property tax expenses related to these programs in 2013 and 2012 totaled $1.7 million and $0.6 million, respectively. | |
Based on the deferral of costs and continuing recognition of debt-related post in service carrying costs using the 2009 capital structure, regulatory assets associated with these Ohio infrastructure programs increased $6.7 million in 2013. Regulatory assets are expected to continue to increase in future periods as post in service carrying costs are recognized in the statement of income and operating costs are deferred. Historical relationships between rate base growth and depreciation expense and property taxes will also be impacted. | |
Indiana Recovery and Deferral Mechanisms | |
The Company's Indiana natural gas utilities received orders in 2008 and 2007 associated with the most recent base rate cases. These orders authorized the deferral of financial impacts associated with bare steel and cast iron replacement activities. The orders provide for the deferral of depreciation and post in service carrying costs on qualifying projects totaling $20 million annually at Vectren North and $3 million annually at Vectren South. The debt-related post in service carrying costs are recognized in the Consolidated Statements of Income currently. The recording of post in service carrying costs and depreciation deferral is limited by individual qualifying project to three years after being placed into service at Vectren South and four years after being placed into service at Vectren North. At December 31, 2013 and 2012, the Company has regulatory assets totaling $12.1 million and $8.5 million, respectively, associated with the deferral of depreciation and debt-related post in service carrying cost activities. | |
In April 2011, Senate Bill 251 was signed into Indiana law. The law provides a framework to recover 80 percent of federally mandated costs through a periodic rate adjustment mechanism outside of a general rate case. Such costs include a return on the federally mandated capital investment, along with recovery of depreciation and other operating costs associated with these mandates. The remaining 20 percent of those costs are to be deferred for future recovery in the utility's next general rate case. | |
In April 2013, Senate Bill 560 was signed into law. This legislation supplements Senate Bill 251 described above, which addressed federally-mandated investment, and provides for cost recovery outside of a base rate proceeding for projects that either improve electric and gas system reliability and safety or are economic development projects that provide rural areas with access to gas service. Provisions of the legislation require that, among other things, requests for recovery include a seven-year project plan. Once the plan is approved by the IURC, 80 percent of such costs are eligible for recovery using a periodic rate adjustment mechanism. Recoverable costs include a return on and of the investment, as well as property taxes and operating expenses. The remaining 20 percent of project costs are to be deferred for future recovery in the Company's next general rate case. The adjustment mechanism is capped at an annual increase in retail revenues of no more than two percent. | |
Pipeline Safety Law | |
On January 3, 2012, the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 (Pipeline Safety Law) was signed into law. The Pipeline Safety Law, which reauthorizes federal pipeline safety programs through fiscal year 2015, provides for enhanced safety, reliability, and environmental protection in the transportation of energy products by pipeline. The law increases federal enforcement authority; grants the federal government expanded authority over pipeline safety; provides for new safety regulations and standards; and authorizes or requires the completion of several pipeline safety-related studies. The DOT is required to promulgate a number of new regulatory requirements over the next two years. Those regulations may eventually lead to further regulatory or statutory requirements. | |
While the Company continues to study the impact of the Pipeline Safety Law and potential new regulations associated with its implementation, it is expected that the law will result in further investment in pipeline inspections, and where necessary, additional investments in pipeline infrastructure and, therefore, result in both increased levels of operating expenses and capital expenditures associated with the Company's natural gas distribution businesses. | |
Requests for Recovery Under Indiana Regulatory Mechanisms | |
The Company filed in November 2013 for authority to recover appropriate costs related to its gas infrastructure replacement and improvement programs in Indiana, including costs associated with existing pipeline safety regulations, using the mechanisms allowed under Senate Bill 251 and Senate Bill 560. The combined Vectren South and Vectren North Indiana filing requests recovery of the capital expenditures associated with the infrastructure replacement and improvement plan pursuant to the legislation, estimated to be approximately $865 million combined over the seven year period beginning in 2014, along with approximately $13 million combined annual operating costs associated with pipeline safety rules. A hearing in this proceeding is scheduled for April 2014, and an order is expected later in 2014. | |
Vectren South Electric Environmental Compliance Filing | |
On January 17, 2014, Vectren South filed a request with the IURC for approval of capital investments estimated to be between $70 million and $90 million on its coal-fired generation units to comply with new EPA mandates related to mercury and air toxin standards effective in 2016. Roughly half of the investment will be made to control mercury in both air and water emissions. The remaining investment will be made to address EPA concerns on alleged increases in sulfur trioxide emissions. Although the Company believes these investments are recoverable as a federally mandated investment under Senate Bill 251, the Company has requested deferred accounting treatment in lieu of timely recovery to avoid immediate customer impacts. The accounting treatment request seeks deferral of depreciation and property tax expense related to these investments, accrual of post in service carrying costs, and deferral of incremental operating expenses related to compliance with these standards. A procedural schedule in this case has not been set as the Company has not yet filed testimony in support of its request. The company will file its case-in-chief testimony on March 14, 2014 and a hearing is scheduled for July 9, 2014. | |
Vectren South Electric Base Rate Filing | |
The IURC issued an order on April 27, 2011, providing for a revenue increase to recover costs associated with approximately $325 million in system upgrades that were completed in the three years leading up to the December 2009 filing and modest increases in maintenance and operating expenses. The approved revenue increase is based on rate base of $1,295.6 million, return on equity of 10.4 percent, and an overall rate of return of 7.29 percent. The new rates were effective May 3, 2011. The IURC, in its order, provided for deferred accounting treatment related to the Company's investment in dense pack technology, of which approximately $28.7 million was spent as of December 31, 2013. Addressing issues raised in the case concerning coal supply contracts and related costs, the IURC found that current coal contracts remain effective and that a prospective review process of future procurement decisions would be initiated and is discussed below. | |
Coal Procurement Procedures | |
Vectren South submitted a request for proposal (RFP) in April 2011 regarding coal purchases for a four year period beginning in 2012. After negotiations with bidders, Vectren South reached an agreement in principle for multi-year purchases with two suppliers, one of which is Vectren Fuels, Inc. Consistent with the IURC direction in the electric rate case, a sub docket proceeding was established to review the Company’s prospective coal procurement procedures, and the Company submitted evidence related to its 2011 RFP. In March 2012, the IURC issued its order in the sub docket which concluded that Vectren South’s 2011 RFP process resulted in the lowest fuel cost reasonably possible. In late 2012, Vectren South terminated its contract with one of the suppliers due to coal quality issues that were identified during test burns of the coal. In addition to coal purchased under these contracts, Vectren South also contracted with Vectren Fuels, Inc. in 2012 to purchase lower priced spot coal. This spot purchase, which was completed in 2012, was found to be reasonable in a recent fuel adjustment clause (FAC) order issued in July 2012. The IURC will continue to regularly monitor Vectren South’s procurement process in future fuel adjustment proceedings. | |
Delivery to Vectren's power plants of lower priced contract coal from the April 2011 RFP process began during 2012. On December 5, 2011 within the quarterly FAC filing, Vectren South submitted a joint proposal with the OUCC to reduce its fuel costs billed to customers by accelerating into 2012 the impact of lower cost coal under these new term contracts effective after 2012. The cost difference was deferred to a regulatory asset and will be recovered over a six-year period without interest beginning in 2014. The IURC approved this proposal on January 25, 2012, with the reduction to customer’s rates effective February 1, 2012. The total deferred balance as of December 31, 2013 was $42.4 million. Recovery of this deferred balance began in February 2014. | |
Vectren South Electric Demand Side Management Program Filing | |
On August 16, 2010, Vectren South filed a petition with the IURC, seeking approval of its proposed electric Demand Side Management (DSM) Programs, recovery of the costs associated with these programs, recovery of lost margins as a result of implementing these programs for large customers, and recovery of performance incentives linked with specific measurement criteria on all programs. The DSM Programs proposed were consistent with a December 9, 2009 order issued by the IURC, which, among other actions, defined long-term conservation objectives and goals of DSM programs for all Indiana electric utilities under a consistent statewide approach. In order to meet these objectives, the IURC order divided the DSM programs into Core and Core Plus programs. Core programs are joint programs required to be offered by all Indiana electric utilities to all customers, and include some for large industrial customers. Core Plus programs are those programs not required specifically by the IURC, but defined by each utility to meet the overall energy savings targets defined by the IURC. | |
On August 31, 2011 the IURC issued an order approving an initial three year DSM plan in the Vectren South service territory that complied with the IURC’s energy saving targets. Consistent with the Company’s proposal, the order approved, among other items, the following: 1) recovery of costs associated with implementing the DSM Plan; 2) the recovery of a performance incentive mechanism based on measured savings related to certain DSM programs; 3) lost margin recovery associated with the implementation of DSM programs for large customers; and 4) deferral of lost margin up to $3 million in 2012 and $1 million in 2011 associated with small customer DSM programs for subsequent recovery under a tracking mechanism to be proposed by the Company. On June 20, 2012, the IURC issued an order approving a small customer lost margin recovery mechanism, inclusive of all previous deferrals. This mechanism is an alternative to the electric decoupling proposal that was denied by the IURC in the Company's last base rate proceeding discussed earlier. For the twelve months ended December 31, 2013, the Company recognized Electric revenue of $5.0 million associated with this approved lost margin recovery mechanism. | |
Vectren North Pipeline Safety Investigation | |
On April 11, 2012, the IURC's pipeline safety division filed a complaint against Vectren North alleging several violations of safety regulations pertaining to damage that occurred at a residence in Vectren North's service territory during a pipeline replacement project. The Company negotiated a settlement with the IURC's pipeline safety division, agreeing to a fine and several modifications to the Company's operating policies. The amount of the fine was not material to the Company's financial results. The IURC approved the settlement but modified certain terms of the settlement and added a requirement that Company employees conduct inspections of pipeline excavations. The Company sought and was granted a request for rehearing on the sole issue related to the requirement to use Company employees to inspect excavations. A settlement in the case was reached between the IURC's pipeline safety division and Vectren North that allowed Vectren North to continue to use its risk based approach to inspecting excavations and to allow the Company to continue using a mix of highly trained and qualified contractors and employees to perform inspections. On January 15, 2014, the IURC issued a Final Order in the case approving the settlement agreement, without modification. | |
Vectren North & Vectren South Gas Decoupling Extension Filing | |
On August 18, 2011, the IURC issued an order granting the extension of the current decoupling mechanism in place at both gas companies and recovery of new conservation program costs through December 2015. | |
FERC Return on Equity Complaint | |
On November 12, 2013, certain parties representing a group of industrial customers filed a joint complaint with the FERC under Section 206 of the Federal Power Act against MISO and various MISO transmission owners, including SIGECO. The joint parties seek to reduce the 12.38 percent return on equity used in the MISO transmission owners’ rates, including SIGECO’s formula transmission rates, to 9.15 percent, and to set a capital structure in which the equity component does not exceed 50 percent. In the event a refund is required upon resolution of the complaint, the parties are seeking a refund calculated as of the filing date of the complaint. The MISO transmission owners filed their response to the complaint on January 6, 2014, opposing any change to the return. In addition to the group response, the Company filed a supplemental response, stating that if FERC allows the complaint to go forward, the complaint should not be applied to the Company’s recently completed Gibson-Brown-Reid 345 Kv transmission line investment. | |
FERC has no deadline for action. This joint complaint is similar to a complaint against the New England Transmission Owners (NETO) filed in September 2011, which requested that the 11.14 percent incentive return granted on qualifying investments in NETO be lowered. In August 2013, a FERC administrative law judge recommended in that proceeding that the return be lowered to 9.7 percent, retroactive to the date of the complaint filing. The FERC has yet to rule on that case. | |
The Company is unable to predict the outcome of the proceeding. A 100 basis point change in the incentive rate of return would equate to approximately $0.8 million of net income on an annual basis. |
Environmental_Matters
Environmental Matters | 12 Months Ended |
Dec. 31, 2013 | |
Environmental Matters Disclosure [Abstract] | ' |
Environmental Matters | ' |
Environmental Matters | |
Indiana Senate Bill 251 is also applicable to federal environmental mandates impacting Vectren South's electric operations. The Company continues to evaluate the impact Senate Bill 251 may have on its operations, including applicability of the stricter regulations the EPA is currently considering involving air quality, fly ash disposal, cooling tower intake facilities, waste water discharges, and greenhouse gases. These issues are further discussed below. | |
Air Quality | |
Clean Air Interstate Rule / Cross-State Air Pollution Rule | |
In July 2011, the EPA finalized the Cross-State Air Pollution Rule (CSAPR). CSAPR was the EPA’s response to the US Court of Appeals for the District of Columbia’s (the Court) remand of the Clean Air Interstate Rule (CAIR). CAIR was originally established in 2005 as an allowance cap and trade program that required reductions from coal-burning power plants for NOx emissions beginning January 1, 2009 and SO2 emissions beginning January 1, 2010, with a second phase of reductions in 2015. In an effort to address the Court’s finding that CAIR did not adequately ensure attainment of pollutants in certain downwind states due to unlimited trading of SO2 and NOx allowances, CSAPR reduced the ability of facilities to meet emission reduction targets through allowance trading. Like CAIR, CSAPR set individual state caps for SO2 and NOx emissions. However, unlike CAIR in which states allocated allowances to generating units through state implementation plans, CSAPR allowances were allocated to individual units directly through the federal rule. CSAPR reductions were to be achieved with initial step reductions beginning January 1, 2012, and final compliance to be achieved in 2014. Multiple administrative and judicial challenges were filed. On December 30, 2011, the Court granted a stay of CSAPR and left CAIR in place pending its review. On August 21, 2012, the Court vacated CSAPR and directed the EPA to continue to administer CAIR. In October 2012, the EPA filed its request for a hearing before the full federal appeals court that struck down the CSAPR. EPA's request for rehearing was denied by the Court on January 24, 2013. In March 2013, the EPA filed a petition for review with the US Supreme Court, and in June 2013 the Supreme Court agreed to review the lower court decision. A decision by the Supreme Court is expected in 2014. The Company remains in full compliance with CAIR (see additional information below "Conclusions Regarding Environmental Regulations"). | |
Mercury and Air Toxics (MATS) Rule | |
On December 21, 2011, the EPA finalized the Utility MATS Rule. The MATS Rule sets emission limits for hazardous air pollutants for existing and new coal-fired power plants and identifies the following broad categories of hazardous air pollutants: mercury, non-mercury hazardous air pollutants (primarily arsenic, chromium, cobalt, and selenium), and acid gases (hydrogen cyanide, hydrogen chloride, and hydrogen fluoride). The rule imposes mercury emission limits for two sub-categories of coal, and proposed surrogate limits for non-mercury and acid gas hazardous air pollutants. The EPA did not grant blanket compliance extensions, but asserted that states have broad authority to grant one year extensions for individual electric generating units where potential reliability impacts have been demonstrated. Reductions are to be achieved within three years of publication of the final rule in the Federal register (April 2015). Initiatives to suspend CSAPR’s implementation by Congress also apply to the implementation of the MATS rule. Multiple judicial challenges were filed and briefing is proceeding. The EPA agreed to reconsider MATS requirements for new construction. Such requirements are more stringent than those for existing plants. Utilities planning new coal-fired generation had argued standards outlined in the MATS could not be attained even using the best available control technology. The EPA issued its revised emission limits for new construction in March 2013. | |
Notice of Violation for A.B. Brown Power Plant | |
The Company received a notice of violation (NOV) from the EPA in November 2011 pertaining to its A.B. Brown power plant. The NOV asserts that when the power plant was equipped with Selective Catalytic Reduction (SCR) systems, the correct permits were not obtained or the best available control technology to control incidental sulfuric acid mist was not installed. The Company is currently in discussions with the EPA to resolve this NOV. | |
Information Request | |
SIGECO and Alcoa Generating Corporation (AGC), a subsidiary of ALCOA, own a 300 MW Unit 4 at the Warrick Power Plant as tenants in common. AGC and SIGECO also share equally in the cost of operation and output of the unit. In January 2013, AGC received an information request from the EPA under Section 114 of the Clean Air Act for historical operational information on the Warrick Power Plant. In April 2013, ALCOA filed a timely response to the information request. | |
Water | |
Section 316(b) of the Clean Water Act requires that generating facilities use the “best technology available” to minimize adverse environmental impacts in a body of water. More specifically, Section 316(b) is concerned with impingement and entrainment of aquatic species in once-through cooling water intake structures used at electric generating facilities. In April 2009, the U.S. Supreme Court affirmed that the EPA could, but was not required to, consider costs and benefits in making the evaluation as to the best technology available for existing generating facilities. The regulation was remanded back to the EPA for further consideration. In March 2011, the EPA released its proposed Section 316(b) regulations. The EPA did not mandate the retrofitting of cooling towers in the proposed regulation, but if finalized, the regulation will leave it to each state to determine whether cooling towers should be required on a case by case basis. A final rule is expected in 2014. Depending on the final rule and on the Company’s facts and circumstances, capital investments could approximate $40 million if new infrastructure, such as new cooling water towers, is required. Costs for compliance with these final regulations should qualify as federally mandated regulatory requirements and be recoverable under Indiana Senate Bill 251 referenced above. | |
Under the Clean Water Act, EPA sets technology-based guidelines for water discharges from new and existing facilities. EPA is currently in the process of revising the existing steam electric effluent limitation guidelines that set the technology-based water discharge limits for the electric power industry. EPA is focusing its rulemaking on wastewater generated primarily by pollution control equipment necessitated by the comprehensive air regulations. The EPA released proposed rules on April 19, 2013 and the Company is reviewing the proposal. At this time, it is not possible to estimate what potential costs may be required to meet these new water discharge limits, however costs for compliance with these regulations should qualify as federally mandated regulatory requirements and be recoverable under Senate Bill 251 referenced above. | |
Conclusions Regarding Environmental Regulations | |
To comply with Indiana’s implementation plan of the Clean Air Act, and other federal air quality standards, the Company obtained authority from the IURC to invest in clean coal technology. Using this authorization, the Company invested approximately $411 million starting in 2001 with the last equipment being placed into service on January 1, 2010. The pollution control equipment included SCR systems, fabric filters, and an SO2 scrubber at its generating facility that is jointly owned with AGC (the Company’s portion is 150 MW). SCR technology is the most effective method of reducing NOx emissions where high removal efficiencies are required and fabric filters control particulate matter emissions. The unamortized portion of the $411 million clean coal technology investment was included in rate base for purposes of determining SIGECO’s new electric base rates approved in the latest base rate order obtained April 27, 2011. SIGECO’s coal-fired generating fleet is 100 percent scrubbed for SO2 and 90 percent controlled for NOx. | |
Utilization of the Company’s NOx and SO2 allowances can be impacted as regulations are revised and implemented. Most of these allowances were granted to the Company at zero cost; therefore, any reduction in carrying value that could result from future changes in regulations would be immaterial. | |
The Company continues to review the sufficiency of its existing pollution control equipment in relation to the requirements described in the MATS Rule, the recent renewal of water discharge permits, and the NOV discussed above. Some operational modifications to the control equipment are likely. The Company is continuing to evaluate potential technologies to address compliance and what the additional costs may be associated with these efforts. Currently, it is expected that the capital costs could be between $70 million and $90 million. Compliance is required by government regulation, and the Company believes that such additional costs, if incurred, should be recoverable under Senate Bill 251 referenced above. On January 17, 2014, the Company filed its request with the IURC seeking approval to upgrade its existing emissions control equipment to comply with the MATS Rule, take steps to address EPA's allegations in the NOV and comply with new mercury limits to the waste water discharge permits at the Culley and Brown generating stations. In that filing, the Company has proposed to defer recovery of the costs until 2020 in order to mitigate the impact on customer rates in the near term. | |
Coal Ash Waste Disposal & Ash Ponds | |
In June 2010, the EPA issued proposed regulations affecting the management and disposal of coal combustion products, such as ash generated by the Company’s coal-fired power plants. The proposed rules more stringently regulate these byproducts and would likely increase the cost of operating or expanding existing ash ponds and the development of new ash ponds. The alternatives include regulating coal combustion by-products that are not being beneficially reused as hazardous waste. The EPA did not offer a preferred alternative, but took public comment on multiple alternative regulations. Rules have not been finalized given oversight hearings, congressional interest, and other factors. Recently EPA entered into a consent decree in which it agreed to finalize by December 2014 its determination whether to regulate ash as hazardous waste, or the less stringent solid waste designation. | |
At this time, the majority of the Company’s ash is being beneficially reused. However, the alternatives proposed would require modification to, or closure of, existing ash ponds. The Company estimates capital expenditures to comply could be as much as $30 million, and such expenditures could exceed $100 million if the most stringent of the alternatives is selected. Annual compliance costs could increase only slightly or be impacted by as much as $5 million. Costs for compliance with these regulations should qualify as federally mandated regulatory requirements and be recoverable under Senate Bill 251 referenced above. | |
Climate Change | |
In April 2007, the US Supreme Court determined that greenhouse gases (GHG's) meet the definition of "air pollutant" under the Clean Air Act and ordered the EPA to determine whether GHG emissions from motor vehicles cause or contribute to air pollution that may reasonably be anticipated to endanger public health or welfare. In April 2009, the EPA published its proposed endangerment finding for public comment. The proposed endangerment finding concludes that carbon emissions from mobile sources pose an endangerment to public health and the environment. The endangerment finding was finalized in December 2009, and is the first step toward the EPA regulating carbon emissions through the existing Clean Air Act in the absence of specific carbon legislation from Congress. | |
The EPA has promulgated two GHG regulations that apply to the Company’s generating facilities. In 2009, the EPA finalized a mandatory GHG emissions registry which requires the reporting of emissions. The EPA has also finalized a revision to the Prevention of Significant Deterioration (PSD) and Title V permitting rules which would require facilities that emit 75,000 tons or more of GHG's a year to obtain a PSD permit for new construction or a significant modification of an existing facility. The EPA's PSD and Title V permitting rules for GHG's were upheld by the US Court of Appeals for the District of Columbia. In 2012, the EPA proposed New Source Performance Standards (NSPS) for GHG's for new electric generating facilities under the Clean Air Act Section 111(b). On October 15, 2013, the US Supreme Court agreed to review a focused appeal on the issue of whether the GHG rule applicable to mobile sources triggered PSD permitting for all stationary sources such as Vectren's power plants. A decision is expected in 2014. | |
In July 2013, the President announced a Climate Action Plan, which calls on the EPA to re-propose and finalize the new source rule expeditiously, and by June 2014 propose, and by June 2015 finalize, NSPS standards for GHG's for existing electric generating units which would apply to Vectren's power plants. States must have their implementation plans to the EPA no later than June 2016. The President's Climate Action Plan did not provide any detail as to actual emission targets or compliance requirements. The Company anticipates that these initial standards will focus on power plant efficiency and other coal fleet carbon intensity reduction measures. The Company believes that such additional costs, if necessary, should be recoverable under Indiana Senate Bill 251 referenced above. | |
Numerous competing federal legislative proposals have also been introduced in recent years that involve carbon, energy efficiency, and renewable energy. Comprehensive energy legislation at the federal level continues to be debated, but there has been little progress to date. The progression of regional initiatives throughout the United States has also slowed. | |
Impact of Legislative Actions & Other Initiatives is Unknown | |
If regulations are enacted by the EPA or other agencies or if legislation requiring reductions in CO2 and other GHG's or legislation mandating a renewable energy portfolio standard is adopted, such regulation could substantially affect both the costs and operating characteristics of the Company’s fossil fuel generating plants, nonutility coal mining operations, and natural gas distribution businesses. At this time and in the absence of final legislation or rulemaking, compliance costs and other effects associated with reductions in GHG emissions or obtaining renewable energy sources remain uncertain. The Company has gathered preliminary estimates of the costs to control GHG emissions. A preliminary investigation demonstrated costs to comply would be significant, first with regard to operating expenses and later for capital expenditures as technology becomes available to control GHG emissions. However, these compliance cost estimates are based on highly uncertain assumptions, including allowance prices if a cap and trade approach were employed, and energy efficiency targets. Costs to purchase allowances that cap GHG emissions or expenditures made to control emissions should be considered a federally mandated cost of providing electricity, and as such, the Company believes such costs and expenditures should be recoverable from customers through Senate Bill 251 as referenced above. | |
Senate Bill 251 also established a voluntary clean energy portfolio standard that provides incentives to Indiana electricity suppliers participating in the program. The goal of the program is that by 2025, at least 10 percent of the total electricity obtained by the supplier to meet the energy needs of Indiana retail customers will be provided by clean energy sources, as defined. In advance of a federal portfolio standard and Senate Bill 251, SIGECO received regulatory approval to purchase a 3 MW landfill gas generation facility from a related entity. The facility was purchased in 2009 and is directly connected to the Company's distribution system. In 2008 and 2009, the Company executed long-term purchase power commitments for a total of 80 MW of wind energy. The Company currently has approximately 5 percent of its electricity being provided by clean energy sources due to the long-term wind contracts and landfill gas investment. | |
Manufactured Gas Plants | |
In the past, the Company operated facilities to manufacture natural gas. Given the availability of natural gas transported by pipelines, these facilities have not been operated for many years. Under current environmental laws and regulations, those that owned or operated these facilities may now be required to take remedial action if certain contaminants are found above the regulatory thresholds. | |
In the Indiana Gas service territory, the existence, location, and certain general characteristics of 26 gas manufacturing and storage sites have been identified for which the Company may have some remedial responsibility. A remedial investigation/feasibility study (RI/FS) was completed at one of the sites under an agreed order between Indiana Gas and the IDEM, and a Record of Decision was issued by the IDEM in January 2000. The remaining sites have been submitted to the IDEM's Voluntary Remediation Program (VRP). The Company has identified its involvement in five manufactured gas plant sites in SIGECO’s service territory, all of which are currently enrolled in the IDEM’s VRP. The Company is currently conducting some level of remedial activities, including groundwater monitoring at certain sites. | |
The Company has accrued the estimated costs for further investigation, remediation, groundwater monitoring, and related costs for the sites. While the total costs that may be incurred in connection with addressing these sites cannot be determined at this time, the Company has recorded cumulative costs that it has incurred or reasonably expects to incur totaling approximately $43.4 million ($23.2 million at Indiana Gas and $20.2 million at SIGECO). The estimated accrued costs are limited to the Company’s share of the remediation efforts and are therefore net of exposures of other potentially responsible parties (PRP). | |
With respect to insurance coverage, Indiana Gas has received approximately $20.8 million from all known insurance carriers under insurance policies in effect when these plants were in operation. Likewise, SIGECO has settlement agreements with all known insurance carriers and has received to date approximately $14.3 million of the expected $15.8 million in insurance recoveries. | |
The costs the Company expects to incur are estimated by management using assumptions based on actual costs incurred, the timing of expected future payments, and inflation factors, among others. While the Company’s utilities have recorded all costs which they presently expect to incur in connection with activities at these sites, it is possible that future events may require remedial activities which are not presently foreseen and those costs may not be subject to PRP or insurance recovery. As of December 31, 2013 and 2012, approximately $5.7 million and $4.6 million, respectively, of accrued, but not yet spent, costs are included in Other Liabilities related to the Indiana Gas and SIGECO sites. |
Fair_Value_Measurements
Fair Value Measurements | 12 Months Ended | ||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||
Fair Value Disclosures [Abstract] | ' | ||||||||||||||||
Fair Value Measurements | ' | ||||||||||||||||
Fair Value Measurements | |||||||||||||||||
The carrying values and estimated fair values using primarily Level 2 assumptions of the Company's other financial instruments follow: | |||||||||||||||||
At December 31, | |||||||||||||||||
2013 | 2012 | ||||||||||||||||
(In millions) | Carrying | Est. Fair | Carrying | Est. Fair | |||||||||||||
Amount | Value | Amount | Value | ||||||||||||||
Long-term debt | $ | 1,807.10 | $ | 1,895.20 | $ | 1,659.80 | $ | 1,873.30 | |||||||||
Short-term borrowings & notes payable | 68.6 | 68.6 | 278.8 | 278.8 | |||||||||||||
Cash & cash equivalents | 21.5 | 21.5 | 19.5 | 19.5 | |||||||||||||
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, 2013 and 2012, the fair value for these financial instruments was not estimated. The carrying value of these investments was approximately $10.4 million and $2.1 million at December 31, 2013 and 2012, respectively. |
Segment_Reporting
Segment Reporting | 12 Months Ended | ||||||||||||
Dec. 31, 2013 | |||||||||||||
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 is comprised of five operating segments: Infrastructure Services, Energy Services, Coal Mining, Energy Marketing,and Other Businesses. Results in the Energy Marketing segment include the results of the Company's investment in ProLiance through June 18, 2013 when it exited the natural gas marketing business (see Note 7 for more details of this transaction). The acquisition of Minnesota Limited was completed on March 31, 2011 (See Note 5) and is included in the Infrastructure Services operating segment. The sale of Vectren Source was completed on December 31, 2011 (See Note 6) and the results of Vectren Source's operations are included in the Energy Marketing operating segment in 2011. | |||||||||||||
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) | 2013 | 2012 | 2011 | ||||||||||
Revenues | |||||||||||||
Utility Group | |||||||||||||
Gas Utility Services | $ | 810 | $ | 738.1 | $ | 819.1 | |||||||
Electric Utility Services | 619.3 | 594.9 | 635.9 | ||||||||||
Other Operations | 38.1 | 40.1 | 43.9 | ||||||||||
Eliminations | (37.8 | ) | (39.5 | ) | (41.9 | ) | |||||||
Total Utility Group | 1,429.60 | 1,333.60 | 1,457.00 | ||||||||||
Nonutility Group | |||||||||||||
Infrastructure Services | 783.5 | 663.6 | 421.3 | ||||||||||
Energy Services | 91.3 | 117.7 | 161.8 | ||||||||||
Coal Mining | 292.8 | 235.8 | 285.6 | ||||||||||
Energy Marketing | — | — | 149.9 | ||||||||||
Other Businesses | — | 0.5 | — | ||||||||||
Total Nonutility Group | 1,167.60 | 1,017.60 | 1,018.60 | ||||||||||
Eliminations, net of Corporate & Other Revenues | (106.0 | ) | (118.4 | ) | (150.4 | ) | |||||||
Consolidated Revenues | $ | 2,491.20 | $ | 2,232.80 | $ | 2,325.20 | |||||||
Profitability Measures - Net Income | |||||||||||||
Utility Group Net Income | |||||||||||||
Gas Utility Services | $ | 55.7 | $ | 60 | $ | 52.5 | |||||||
Electric Utility Services | 75.8 | 68 | 65 | ||||||||||
Other Operations | 10.3 | 10 | 5.4 | ||||||||||
Total Utility Group Net Income | 141.8 | 138 | 122.9 | ||||||||||
Nonutility Group Net Income (Loss) | |||||||||||||
Infrastructure Services | 49 | 40.5 | 14.9 | ||||||||||
Energy Services | 1 | 5.7 | 6.7 | ||||||||||
Coal Mining | (16.0 | ) | (3.5 | ) | 16.6 | ||||||||
Energy Marketing | (37.5 | ) | (17.6 | ) | (4.2 | ) | |||||||
Other Businesses | (1.0 | ) | (3.4 | ) | (10.2 | ) | |||||||
Total Nonutility Group Net Income | (4.5 | ) | 21.7 | 23.8 | |||||||||
Corporate & Other Net Loss | (0.7 | ) | (0.7 | ) | (5.1 | ) | |||||||
Consolidated Net Income | $ | 136.6 | $ | 159 | $ | 141.6 | |||||||
Year Ended December 31, | |||||||||||||
(In millions) | 2013 | 2012 | 2011 | ||||||||||
Amounts Included in Profitability Measures | |||||||||||||
Depreciation & Amortization | |||||||||||||
Utility Group | |||||||||||||
Gas Utility Services | $ | 90.5 | $ | 85.4 | $ | 84.3 | |||||||
Electric Utility Services | 84 | 81.3 | 80.2 | ||||||||||
Other Operations | 21.9 | 23.3 | 27.8 | ||||||||||
Total Utility Group | 196.4 | 190 | 192.3 | ||||||||||
Nonutility Group | |||||||||||||
Infrastructure Services | 28.8 | 20.7 | 14.9 | ||||||||||
Energy Services | 1.7 | 1.9 | 1.5 | ||||||||||
Coal Mining | 50.8 | 41.8 | 35.1 | ||||||||||
Energy Marketing | — | — | 0.5 | ||||||||||
Other Businesses | 0.1 | 0.2 | — | ||||||||||
Total Nonutility Group | 81.4 | 64.6 | 52 | ||||||||||
Consolidated Depreciation & Amortization | $ | 277.8 | $ | 254.6 | $ | 244.3 | |||||||
Interest Expense | |||||||||||||
Utility Group | |||||||||||||
Gas Utility Services | $ | 30.6 | $ | 31.8 | $ | 37.1 | |||||||
Electric Utility Services | 29.2 | 33.8 | 36.4 | ||||||||||
Other Operations | 5.2 | 5.9 | 6.8 | ||||||||||
Total Utility Group | 65 | 71.5 | 80.3 | ||||||||||
Nonutility Group | |||||||||||||
Infrastructure Services | 10.1 | 7.5 | 7.4 | ||||||||||
Energy Services | 0.6 | 0.4 | 0.6 | ||||||||||
Coal Mining | 9.8 | 11.5 | 11.3 | ||||||||||
Energy Marketing | 2.2 | 4.8 | 6.4 | ||||||||||
Other Businesses | 0.5 | 0.7 | 1.3 | ||||||||||
Total Nonutility Group | 23.2 | 24.9 | 27 | ||||||||||
Corporate & Other | (0.3 | ) | (0.4 | ) | (0.8 | ) | |||||||
Consolidated Interest Expense | $ | 87.9 | $ | 96 | $ | 106.5 | |||||||
Income Taxes | |||||||||||||
Utility Group | |||||||||||||
Gas Utility Services | $ | 36.6 | $ | 39.1 | $ | 34.5 | |||||||
Electric Utility Services | 48.3 | 46.4 | 45.3 | ||||||||||
Other Operations | 0.4 | (0.2 | ) | 3.1 | |||||||||
Total Utility Group | 85.3 | 85.3 | 82.9 | ||||||||||
Nonutility Group | |||||||||||||
Infrastructure Services | 34.3 | 29.6 | 10.7 | ||||||||||
Energy Services | (11.9 | ) | (9.0 | ) | 1.1 | ||||||||
Coal Mining | (14.6 | ) | (8.6 | ) | 3.9 | ||||||||
Energy Marketing | (23.3 | ) | (11.7 | ) | (2.4 | ) | |||||||
Other Businesses | (1.6 | ) | (2.0 | ) | (7.0 | ) | |||||||
Total Nonutility Group | (17.1 | ) | (1.7 | ) | 6.3 | ||||||||
Corporate & Other | (1.1 | ) | (1.1 | ) | (2.8 | ) | |||||||
Consolidated Income Taxes | $ | 67.1 | $ | 82.5 | $ | 86.4 | |||||||
Year Ended December 31, | |||||||||||||
(In millions) | 2013 | 2012 | 2011 | ||||||||||
Capital Expenditures | |||||||||||||
Utility Group | |||||||||||||
Gas Utility Services | $ | 150.5 | $ | 128.8 | $ | 113.5 | |||||||
Electric Utility Services | 100 | 108.8 | 102.2 | ||||||||||
Other Operations | 25.8 | 16.2 | 17.8 | ||||||||||
Non-cash costs & changes in accruals | (15.2 | ) | (7.8 | ) | (0.1 | ) | |||||||
Total Utility Group | 261.1 | 246 | 233.4 | ||||||||||
Nonutility Group | |||||||||||||
Infrastructure Services | 79.2 | 53.7 | 22.8 | ||||||||||
Energy Services | 6.9 | 2.3 | 9.7 | ||||||||||
Coal Mining | 46.2 | 63.8 | 55.1 | ||||||||||
Energy Marketing | — | — | 0.3 | ||||||||||
Total Nonutility Group | 132.3 | 119.8 | 87.9 | ||||||||||
Consolidated Capital Expenditures | $ | 393.4 | $ | 365.8 | $ | 321.3 | |||||||
At December 31, | |||||||||||||
(In millions) | 2013 | 2012 | 2011 | ||||||||||
Assets | |||||||||||||
Utility Group | |||||||||||||
Gas Utility Services | $ | 2,287.90 | $ | 2,173.50 | $ | 2,125.20 | |||||||
Electric Utility Services | 1,679.00 | 1,705.10 | 1,656.50 | ||||||||||
Other Operations, net of eliminations | 173.9 | 168.2 | 192.8 | ||||||||||
Total Utility Group | 4,140.80 | 4,046.80 | 3,974.50 | ||||||||||
Nonutility Group | |||||||||||||
Infrastructure Services | 465.8 | 420 | 295 | ||||||||||
Energy Services | 63 | 69.7 | 81.2 | ||||||||||
Coal Mining | 433 | 380 | 352.8 | ||||||||||
Energy Marketing | 33.9 | 73.9 | 112.5 | ||||||||||
Other Businesses, net of eliminations and reclassifications | 34.9 | 37.1 | 46.8 | ||||||||||
Total Nonutility Group | 1,030.60 | 980.7 | 888.3 | ||||||||||
Corporate & Other | 828.1 | 785.6 | 727.3 | ||||||||||
Eliminations | (896.9 | ) | (724.0 | ) | (711.2 | ) | |||||||
Consolidated Assets | $ | 5,102.60 | $ | 5,089.10 | $ | 4,878.90 | |||||||
Additional_Balance_Sheet_Opera
Additional Balance Sheet & Operational Information | 12 Months Ended | ||||||||||||
Dec. 31, 2013 | |||||||||||||
Additional Balance Sheet and Operational Information [Abstract] | ' | ||||||||||||
Additional Balance Sheet and Operational Information | ' | ||||||||||||
Additional Balance Sheet & Operational Information | |||||||||||||
Inventories consist of the following: | |||||||||||||
At December 31, | |||||||||||||
(In millions) | 2013 | 2012 | |||||||||||
Gas in storage – at LIFO cost | $ | 33.2 | $ | 22.4 | |||||||||
Coal & oil for electric generation - at average cost | 16.5 | 52 | |||||||||||
Materials & supplies | 57.3 | 57.6 | |||||||||||
Nonutility coal - at LIFO cost | 26.2 | 25.4 | |||||||||||
Other | 1.2 | 1.2 | |||||||||||
Total inventories | $ | 134.4 | $ | 158.6 | |||||||||
Based on the average cost of gas purchased and coal produced during December, the cost of replacing inventories carried at LIFO cost exceeded that carrying value at December 31, 2013, and 2012, by approximately $8.5 million and $12.7 million, respectively. | |||||||||||||
Prepayments & other current assets consist of the following: | |||||||||||||
At December 31, | |||||||||||||
(In millions) | 2013 | 2012 | |||||||||||
Prepaid gas delivery service | $ | 32.9 | $ | 28.5 | |||||||||
Deferred income taxes | 13.9 | — | |||||||||||
Prepaid taxes | 11.2 | 26.4 | |||||||||||
Other prepayments & current assets | 17.6 | 18.4 | |||||||||||
Total prepayments & other current assets | $ | 75.6 | $ | 73.3 | |||||||||
Investments in unconsolidated affiliates consist of the following: | |||||||||||||
At December 31, | |||||||||||||
(In millions) | 2013 | 2012 | |||||||||||
ProLiance Holdings, LLC | $ | 20.8 | $ | 73.9 | |||||||||
Other nonutility partnerships & corporations | 3 | 4 | |||||||||||
Other utility investments | 0.2 | 0.2 | |||||||||||
Total investments in unconsolidated affiliates | $ | 24 | $ | 78.1 | |||||||||
Other utility & corporate investments consist of the following: | |||||||||||||
At December 31, | |||||||||||||
(In millions) | 2013 | 2012 | |||||||||||
Cash surrender value of life insurance policies | $ | 32.9 | $ | 29.1 | |||||||||
Municipal bond | 3.4 | 3.6 | |||||||||||
Restricted cash & other investments | 1.8 | 1.9 | |||||||||||
Other utility & corporate investments | $ | 38.1 | $ | 34.6 | |||||||||
Goodwill by operating segment follows: | |||||||||||||
At December 31, | |||||||||||||
(In millions) | 2013 | 2012 | |||||||||||
Utility Group | |||||||||||||
Gas Utility Services | $ | 205 | $ | 205 | |||||||||
Nonutility Group | |||||||||||||
Infrastructure Services | 55.2 | 55.2 | |||||||||||
Energy Services | 2.1 | 2.1 | |||||||||||
Consolidated goodwill | $ | 262.3 | $ | 262.3 | |||||||||
Accrued liabilities consist of the following: | |||||||||||||
At December 31, | |||||||||||||
(In millions) | 2013 | 2012 | |||||||||||
Refunds to customers & customer deposits | $ | 50.2 | $ | 53.1 | |||||||||
Accrued taxes | 36.2 | 34.4 | |||||||||||
Accrued interest | 20 | 23.1 | |||||||||||
Deferred compensation & post-retirement benefits | 7.5 | 6.8 | |||||||||||
Deferred income taxes | — | 14.9 | |||||||||||
Accrued salaries & other | 68.2 | 66.5 | |||||||||||
Total accrued liabilities | $ | 182.1 | $ | 198.8 | |||||||||
Asset retirement obligations roll forward as follows: | |||||||||||||
(In millions) | 2013 | 2012 | |||||||||||
Asset retirement obligation, January 1 | $ | 37.7 | $ | 43.7 | |||||||||
Accretion | 2.2 | 2.7 | |||||||||||
Changes in estimates, net of cash payments | 1.4 | (8.7 | ) | ||||||||||
Asset retirement obligation, December 31 | 41.3 | 37.7 | |||||||||||
Equity in (losses) of unconsolidated affiliates consists of the following: | |||||||||||||
Year Ended December 31, | |||||||||||||
(In millions) | 2013 | 2012 | 2011 | ||||||||||
ProLiance Holdings, LLC | $ | (57.7 | ) | $ | (22.7 | ) | $ | (28.6 | ) | ||||
Other | (2.0 | ) | (0.6 | ) | (3.4 | ) | |||||||
Total equity in (losses) of unconsolidated affiliates | $ | (59.7 | ) | $ | (23.3 | ) | $ | (32.0 | ) | ||||
Other income (expense) – net consists of the following: | |||||||||||||
Year Ended December 31, | |||||||||||||
(In millions) | 2013 | 2012 | 2011 | ||||||||||
AFUDC – borrowed funds | $ | 5.9 | $ | 4.6 | $ | 2.5 | |||||||
AFUDC – equity funds | 0.8 | 0.4 | 0.2 | ||||||||||
Nonutility plant capitalized interest | 0.5 | 1.8 | 2.1 | ||||||||||
Interest income, net | 1.1 | 1.1 | 1.4 | ||||||||||
Other nonutility investment impairment charges | — | (2.7 | ) | (9.9 | ) | ||||||||
Cash surrender value of life insurance policies | 4.8 | 1.8 | 0.1 | ||||||||||
All other income | 4.6 | 1.3 | 0.1 | ||||||||||
Total other income (expense) – net | $ | 17.7 | $ | 8.3 | $ | (3.5 | ) | ||||||
Supplemental Cash Flow Information: | |||||||||||||
Year Ended December 31, | |||||||||||||
(In millions) | 2013 | 2012 | 2011 | ||||||||||
Cash paid (received) for: | |||||||||||||
Interest | $ | 91 | $ | 94.6 | $ | 108.6 | |||||||
Income taxes | 6.8 | 21.8 | (9.0 | ) | |||||||||
As of December 31, 2013 and 2012, the Company has accruals related to utility and nonutility plant purchases totaling approximately $19.4 million and $11.1 million, respectively. |
Impact_of_Recently_Issued_Acco
Impact of Recently Issued Accounting Guidance | 12 Months Ended |
Dec. 31, 2013 | |
New Accounting Pronouncements and Changes in Accounting Principles [Abstract] | ' |
Recently Issued Accounting Standards | ' |
Impact of Recently Issued Accounting Guidance | |
Offsetting Assets and Liabilities | |
In January 2013, the FASB issued new accounting guidance on disclosures of offsetting assets and liabilities. This guidance amends prior requirements to add clarification to the scope of the offsetting disclosures. The amendment clarifies that the scope applies to derivative instruments accounted for in accordance with reporting topics on derivatives and hedging, including bifurcated embedded derivatives, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions that are either offset in accordance with US GAAP or subject to an enforceable master netting arrangement or similar agreement. This guidance is effective for fiscal years beginning on or after January 1, 2013 and interim periods within annual periods. The Company adopted this guidance as of January 1, 2013. The adoption of this guidance did not have a material impact on the Company's financial statements. | |
Accumulated Other Comprehensive Income (AOCI) | |
In February 2013, the FASB issued new accounting guidance on the reporting of reclassifications from AOCI. The guidance requires an entity to report the effect of significant reclassification from AOCI on the respective line items in net income if the amount being reclassified is required under US GAAP to be reclassified in its entirety to net income. For other amounts that are not required under US GAAP to be reclassified in their entirety to net income in the same reporting period, an entity is required to cross-reference to other disclosures required that provide additional details about these amounts. The new guidance is effective for fiscal years, and interim periods within annual periods, beginning after December 15, 2012. As this guidance provides only disclosure requirements, the adoption of this standard did not impact the Company's results of operations, cash flows or financial position. | |
Unrecognized Tax Benefit Presentation | |
In July 2013, the FASB issued new accounting guidance on presenting an unrecognized tax benefit when net operating loss carryforwards exist. The new standard was issued in an effort to eliminate diversity in practice resulting from a lack of guidance on this topic in the current US GAAP. The update provides that an unrecognized tax benefit, or a portion of an unrecognized tax benefit, should be presented in the financial statements as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward, except under certain circumstances outlined in the update. The amendments in the update are effective for fiscal years, and interim periods within those years, beginning after December 15, 2013, with early adoption permitted. This update is consistent with how the Company currently presents unrecognized tax benefits, therefore, adoption of this guidance resulted in no material impact on the Company's financial statements. |
Quarterly_Financial_Data_Unaud
Quarterly Financial Data (Unaudited) | 12 Months Ended | ||||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||||
Quarterly Financial Information Disclosure [Abstract] | ' | ||||||||||||||||||
Quarterly Financial Data (Unaudited) | ' | ||||||||||||||||||
Quarterly Financial Data (Unaudited) | |||||||||||||||||||
Information in any one quarterly period is not indicative of annual results due to the seasonal variations common to the Company’s utility operations. Summarized quarterly financial data for 2013 and 2012 follows: | |||||||||||||||||||
(In millions, except per share amounts) | Q1 | Q2 | Q3 | Q4 | |||||||||||||||
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 | ||||||||||||||
2012 | |||||||||||||||||||
Operating revenues | $ | 604.6 | $ | 470.6 | $ | 513.5 | $ | 644.1 | |||||||||||
Operating income | 109.9 | 70.2 | 81.6 | 90.8 | |||||||||||||||
Net income | 51.3 | 25.6 | 39.3 | 42.8 | |||||||||||||||
Earnings per share: | |||||||||||||||||||
Basic | $ | 0.63 | $ | 0.31 | $ | 0.48 | $ | 0.52 | |||||||||||
Diluted | 0.62 | 0.31 | 0.48 | 0.52 | |||||||||||||||
SCHEDULE_II_VALUATION_AND_QUAL
SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES | 12 Months Ended | ||||||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||||||
Valuation and Qualifying Accounts [Abstract] | ' | ||||||||||||||||||||
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES | ' | ||||||||||||||||||||
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 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 2011 – Accumulated provision for | |||||||||||||||||||||
uncollectible accounts | $ | 5.3 | $ | 11.8 | $ | — | $ | 10.4 | $ | 6.7 | |||||||||||
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 | |||||||||||
Year 2011 – Reserve for impaired | |||||||||||||||||||||
notes receivable | $ | 6.1 | $ | 9.6 | $ | — | $ | — | $ | 15.7 | |||||||||||
OTHER RESERVES: | |||||||||||||||||||||
Year 2013 - Restructuring costs | $ | 0.3 | $ | — | $ | — | $ | 0.1 | $ | 0.2 | |||||||||||
Year 2012 – Restructuring costs | $ | 0.4 | $ | — | $ | — | $ | 0.1 | $ | 0.3 | |||||||||||
Year 2011 – Restructuring costs | $ | 0.4 | $ | — | $ | — | $ | — | $ | 0.4 | |||||||||||
Summary_of_Significant_Account1
Summary of Significant Accounting Policies (Policies) | 12 Months Ended | |
Dec. 31, 2013 | ||
Accounting Policies [Abstract] | ' | |
Principles of Consolidation | ' | |
Principles of Consolidation | ||
The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries, after elimination of 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 and coal inventory at the Company’s nonutility coal mines 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 or units-of-production method of amortization for certain coal mining assets. When nonutility property is retired, or otherwise disposed of, the asset and accumulated depreciation are removed, and the resulting gain or loss is reflected in income, typically impacting operating expenses. | ||
Impairment Reviews | ||
Property, plant and equipment along with other long-lived assets are reviewed as facts and circumstances indicate that the carrying amount may be impaired. This impairment review involves the comparison of an asset’s (or group of assets’) carrying value to the estimated future cash flows the asset (or asset group) is expected to generate over a remaining life. If this evaluation were to conclude that the carrying value is impaired, an impairment charge would be recorded based on the difference between the carrying amount and its fair value (less costs to sell for assets to be disposed of by sale) as a charge to operations or discontinued operations. There were no impairments related to property, plant and equipment or other long-lived assets during the periods presented. | ||
Specific to the Company’s investment in its owned coal mines, in 2013, as a result of continued operating losses at the Company’s Prosperity mine, increased production costs as a result of various factors, including poor mining conditions, and an overall decline in market prices for Illinois Basin coal, the Company performed a more detailed analysis to support the carrying value of that mine. Specifically, several third party-prepared price curves were obtained and were used to develop revenue forecasts for the remainder of the mine life, using estimated production volumes. Additionally, cost estimates were developed that considered prior actual costs, annualized current costs, and projected future costs. The various revenue scenarios were used in conjunction with estimated costs to derive estimated net operating cash flows for the remaining life of the mine. These estimates are highly subjective and may differ materially from actual results, but the results of the various analyses indicate that there is no impairment related to the coal mine assets, specifically the Prosperity mine assets, at December 31, 2013. | ||
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 – net when received. 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. | ||
Regulation | ' | |
Regulation | ||
Retail public utility operations affecting Indiana customers are subject to regulation by the IURC, and retail public utility operations affecting Ohio customers are subject to regulation by the PUCO. The Company’s accounting policies give recognition to the ratemaking and accounting practices authorized by these agencies. | ||
Refundable or Recoverable Gas Costs & Cost of Fuel & Purchased Power | ||
All metered gas rates contain a gas cost adjustment clause that allows the Company to charge for changes in the cost of purchased gas. Metered electric rates contain a fuel adjustment clause that allows for adjustment in charges for electric energy to reflect changes in the cost of fuel. The net energy cost of purchased power, subject to a variable benchmark based on NYMEX natural gas prices, is also recovered through regulatory proceedings. The Company records any under-or-over-recovery resulting from gas and fuel adjustment clauses each month in revenues. A corresponding asset or liability is recorded until the under or over-recovery is billed or refunded to utility customers. The cost of gas sold is charged to operating expense as delivered to customers, and the cost of fuel and purchased power for electric generation is charged to operating expense when consumed. | ||
Regulatory Assets & Liabilities | ||
Regulatory assets represent probable future revenues associated with certain incurred costs, which will be recovered from customers through the ratemaking process. Regulatory liabilities represent probable expenditures by the Company for removal costs or future reductions in revenues associated with amounts that are to be credited to customers through the ratemaking process. The Company continually assesses the recoverability of costs recognized as regulatory assets and liabilities and the ability to recognize new regulatory assets and liabilities associated with its regulated utility operations. Given the current regulatory environment in its jurisdictions, the Company believes such accounting is appropriate. | ||
The Company collects an estimated cost of removal of its utility plant through depreciation rates established in regulatory proceedings. The Company records amounts expensed in advance of payments as a Regulatory liability because the liability does not meet the threshold of an asset retirement obligation. | ||
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, 2013 or 2012, 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, 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 $29.6 million in 2013, $26.9 million in 2012, and $29.3 million in 2011. 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, five 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, 2013 | |||||||||||||||
Property, Plant and Equipment [Abstract] | ' | ||||||||||||||
Cost of Utility Plant, together with depreciation rates expressed as a percentage of original costs | ' | ||||||||||||||
The original cost of Utility plant, together with depreciation rates expressed as a percentage of original cost, follows: | |||||||||||||||
At December 31, | |||||||||||||||
(In millions) | 2013 | 2012 | |||||||||||||
Original Cost | Depreciation | Original Cost | Depreciation | ||||||||||||
Rates as a | Rates as a | ||||||||||||||
Percent of | Percent of | ||||||||||||||
Original Cost | Original Cost | ||||||||||||||
Gas utility plant | $ | 2,762.20 | 3.5 | % | $ | 2,614.30 | 3.5 | % | |||||||
Electric utility plant | 2,519.80 | 3.3 | % | 2,463.60 | 3.3 | % | |||||||||
Common utility plant | 53.4 | 3 | % | 52 | 3 | % | |||||||||
Construction work in progress | 54.2 | — | 46.9 | — | |||||||||||
Total original cost | $ | 5,389.60 | $ | 5,176.80 | |||||||||||
Nonutility Plant, Net of Depreciation and Amortization | ' | ||||||||||||||
Nonutility plant, net of accumulated depreciation and amortization follows: | |||||||||||||||
At December 31, | |||||||||||||||
(In millions) | 2013 | 2012 | |||||||||||||
Coal mine development costs & equipment | $ | 242 | $ | 241.9 | |||||||||||
Computer hardware & software | 102.7 | 97.3 | |||||||||||||
Land & buildings | 129.3 | 120.4 | |||||||||||||
Vehicles & equipment | 165.2 | 119.8 | |||||||||||||
All other | 18 | 18.6 | |||||||||||||
Nonutility plant - net | $ | 657.2 | $ | 598 | |||||||||||
Regulatory_Assets_Liabilities_
Regulatory Assets & Liabilities (Tables) | 12 Months Ended | ||||||||
Dec. 31, 2013 | |||||||||
Regulatory Assets and Liabilities Disclosure [Abstract] | ' | ||||||||
Schedule of Regulatory Assets | ' | ||||||||
Regulatory assets consist of the following: | |||||||||
At December 31, | |||||||||
(In millions) | 2013 | 2012 | |||||||
Future amounts recoverable from ratepayers related to: | |||||||||
Benefit obligations (See Note 11) | $ | 57.1 | $ | 126.2 | |||||
Net deferred income taxes (See Note 10) | (5.8 | ) | (3.9 | ) | |||||
Asset retirement obligations & other | 2.4 | 2.6 | |||||||
53.7 | 124.9 | ||||||||
Amounts deferred for future recovery related to: | |||||||||
Deferred coal costs (See Note 18) | 42.4 | 42.4 | |||||||
Cost recovery riders & other | 18.6 | 10.2 | |||||||
61 | 52.6 | ||||||||
Amounts currently recovered in customer rates related to: | |||||||||
Unamortized debt issue costs & hedging proceeds | 34.6 | 32.6 | |||||||
Demand side management programs | 2.5 | 4.4 | |||||||
Indiana authorized trackers | 30.8 | 32.1 | |||||||
Ohio authorized trackers | 7.9 | 1.5 | |||||||
Premiums paid to reacquire debt | 2.2 | 2.7 | |||||||
Other base rate recoveries | 0.7 | 1.9 | |||||||
78.7 | 75.2 | ||||||||
Total regulatory assets | $ | 193.4 | $ | 252.7 | |||||
Acquisition_of_Minnesota_Limit1
Acquisition of Minnesota Limited, Inc. (Tables) | 12 Months Ended | ||||
Dec. 31, 2013 | |||||
Business Combinations [Abstract] | ' | ||||
Business Acquisition, Pro Forma Information [Table Text Block] | ' | ||||
The following table presents the Company's unaudited proforma results of operations for the year ended December 31, 2011 as if the acquisition had occurred on January 1, 2011. | |||||
(In millions, except per share data) | 2011 | ||||
Total operating revenues | $ | 2,346.30 | |||
Net income | $ | 141.4 | |||
Basic earnings per share | $ | 1.73 | |||
Diluted earnings per share | $ | 1.73 | |||
Investment_in_ProLiance_Holdin1
Investment in ProLiance Holdings, LLC (Tables) | 12 Months Ended | |||
Dec. 31, 2013 | ||||
Equity Method Investments and Joint Ventures [Abstract] | ' | |||
Summarized Financial Information of Equity Investment [Table Text Block] | ' | |||
Vectren's remaining investment in ProLiance at December 31, 2013 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) | 2013 | |||
ProLiance Energy | $ | 1.5 | ||
Midstream assets and cash from sale of | ||||
storage assets | 7.8 | |||
LA Storage | 21.6 | |||
Total investment in ProLiance | $ | 30.9 | ||
Included in: | ||||
Investments in unconsolidated affiliates | 20.8 | |||
Other nonutility investments | 10.1 | |||
Nonutility_Real_Estate_Other_L1
Nonutility Real Estate & Other Legacy Holdings (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2013 | |||||||||||||
Nonutility Real Estate Other Legacy Holdings [Abstract] | ' | ||||||||||||
Investment by type of investment | ' | ||||||||||||
Further separation of that 2013 investment by type of investment follows: | |||||||||||||
December 31, 2013 | |||||||||||||
Value Included In | |||||||||||||
(In millions) | Carrying | Other Nonutility Investments | Investments in Unconsolidated Affiliates | ||||||||||
Value | |||||||||||||
Commercial real estate investments | $ | 8 | $ | 8 | $ | — | |||||||
Leveraged lease | 14.4 | 14.4 | — | ||||||||||
Other investments | 4.1 | 1.3 | 2.8 | ||||||||||
$ | 26.5 | $ | 23.7 | $ | 2.8 | ||||||||
Intangible_Assets_Tables
Intangible Assets (Tables) | 12 Months Ended | ||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||
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, | ||||||||||||||||
2013 | 2012 | ||||||||||||||||
Amortizing | Non-amortizing | Amortizing | Non-amortizing | ||||||||||||||
Customer-related assets | $ | 17.4 | $ | — | $ | 18.9 | $ | — | |||||||||
Market-related assets | 1.9 | 7 | 2.7 | 7 | |||||||||||||
Intangible assets, net | $ | 19.3 | $ | 7 | $ | 21.6 | $ | 7 | |||||||||
Income_Taxes_Tables
Income Taxes (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2013 | |||||||||||||
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, | |||||||||||||
2013 | 2012 | 2011 | |||||||||||
Statutory rate: | 35 | % | 35 | % | 35 | % | |||||||
State & local taxes-net of federal benefit | 4.6 | 4 | 4.2 | ||||||||||
Amortization of investment tax credit | (0.3 | ) | (0.3 | ) | (0.3 | ) | |||||||
Depletion | (1.5 | ) | (1.5 | ) | (1.9 | ) | |||||||
Energy efficiency building deductions | (3.8 | ) | (3.0 | ) | (1.1 | ) | |||||||
Other tax credits | (1.1 | ) | (0.1 | ) | (0.2 | ) | |||||||
Adjustment of income tax accruals and all other-net | 0.1 | 0.1 | 2.2 | ||||||||||
Effective tax rate | 33 | % | 34.2 | % | 37.9 | % | |||||||
Significant components of the net deferred tax liability (assets) | ' | ||||||||||||
Significant components of the net deferred tax liability follow: | |||||||||||||
At December 31, | |||||||||||||
(In millions) | 2013 | 2012 | |||||||||||
Noncurrent deferred tax liabilities (assets): | |||||||||||||
Depreciation & cost recovery timing differences | $ | 725.2 | $ | 681.6 | |||||||||
Leveraged lease | 10.4 | 10.8 | |||||||||||
Regulatory assets recoverable through future rates | 22.8 | 23.5 | |||||||||||
Other comprehensive income | (1.6 | ) | (4.0 | ) | |||||||||
Alternative minimum tax carryforward | (23.5 | ) | (44.1 | ) | |||||||||
Employee benefit obligations | (6.7 | ) | (2.1 | ) | |||||||||
Net operating loss & other carryforwards | (1.2 | ) | (11.7 | ) | |||||||||
Regulatory liabilities to be settled through future rates | (18.7 | ) | (18.3 | ) | |||||||||
Impairments | (6.2 | ) | (6.1 | ) | |||||||||
Other – net | 6.9 | 7.6 | |||||||||||
Net noncurrent deferred tax liability | 707.4 | 637.2 | |||||||||||
Current deferred tax liabilities (assets): | |||||||||||||
Deferred fuel costs-net | 22.9 | 25.7 | |||||||||||
Demand side management programs | 0.1 | 2.7 | |||||||||||
Alternative minimum tax carryforward | (33.7 | ) | (2.7 | ) | |||||||||
Net operating loss & other carryforwards | (4.9 | ) | — | ||||||||||
Other – net | 1.7 | (10.8 | ) | ||||||||||
Net current deferred tax liability (asset) | (13.9 | ) | 14.9 | ||||||||||
Net deferred tax liability | $ | 693.5 | $ | 652.1 | |||||||||
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) | 2013 | 2012 | 2011 | ||||||||||
Current: | |||||||||||||
Federal | $ | 12.4 | $ | (8.2 | ) | $ | 4.4 | ||||||
State | 11.4 | 6.4 | 10.3 | ||||||||||
Total current taxes | 23.8 | (1.8 | ) | 14.7 | |||||||||
Deferred: | |||||||||||||
Federal | 43.4 | 80.3 | 66 | ||||||||||
State | 0.5 | 4.6 | 6.4 | ||||||||||
Total deferred taxes | 43.9 | 84.9 | 72.4 | ||||||||||
Amortization of investment tax credits | (0.6 | ) | (0.6 | ) | (0.7 | ) | |||||||
Total income tax expense | $ | 67.1 | $ | 82.5 | $ | 86.4 | |||||||
Roll forward of unrecognized tax benefits | ' | ||||||||||||
Following is a roll forward of unrecognized tax benefits for the three years ended December 31, 2013: | |||||||||||||
(In millions) | 2013 | 2012 | 2011 | ||||||||||
Unrecognized tax benefits at January 1 | $ | 4.8 | $ | 12.4 | $ | 13.3 | |||||||
Gross increases - tax positions in prior periods | — | 0.2 | 3.3 | ||||||||||
Gross decreases - tax positions in prior periods | (0.2 | ) | (9.4 | ) | (4.5 | ) | |||||||
Gross increases - current period tax positions | 1.2 | 1.9 | 0.6 | ||||||||||
Settlements | — | (0.3 | ) | (0.3 | ) | ||||||||
Lapse of statute of limitations | 0.1 | — | — | ||||||||||
Unrecognized tax benefits at December 31 | $ | 5.9 | $ | 4.8 | $ | 12.4 | |||||||
Retirement_Plans_Other_Postret1
Retirement Plans & Other Postretirement Benefits (Tables) | 12 Months Ended | ||||||||||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||||||||||
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, 2013 follows: | |||||||||||||||||||||||||
Pension Benefits | Other Benefits | ||||||||||||||||||||||||
(In millions) | 2013 | 2012 | 2011 | 2013 | 2012 | 2011 | |||||||||||||||||||
Service cost | $ | 8.6 | $ | 7.7 | $ | 6.9 | $ | 0.5 | $ | 0.5 | $ | 0.5 | |||||||||||||
Interest cost | 14.7 | 15.5 | 15.9 | 2 | 2.8 | 4.3 | |||||||||||||||||||
Expected return on plan assets | (22.1 | ) | (21.2 | ) | (21.2 | ) | — | — | — | ||||||||||||||||
Amortization of prior service cost (benefit) | 1.5 | 1.6 | 1.7 | (3.2 | ) | (2.5 | ) | (0.8 | ) | ||||||||||||||||
Amortization of actuarial loss (gain) | 10.1 | 6.8 | 3.8 | 0.7 | 0.7 | 0.6 | |||||||||||||||||||
Amortization of transitional obligation | — | — | — | — | 0.5 | 1.1 | |||||||||||||||||||
Settlement (credit) charge | 1.3 | — | — | — | — | — | |||||||||||||||||||
Net periodic benefit cost | $ | 14.1 | $ | 10.4 | $ | 7.1 | $ | — | $ | 2 | $ | 5.7 | |||||||||||||
Schedule of assumptions used | ' | ||||||||||||||||||||||||
The benefit obligation as of December 31, 2013 and 2012 was calculated using the following weighted average assumptions: | |||||||||||||||||||||||||
Pension Benefits | Other Benefits | ||||||||||||||||||||||||
2013 | 2012 | 2013 | 2012 | ||||||||||||||||||||||
Discount rate | 4.74 | % | 4.03 | % | 4.66 | % | 3.91 | % | |||||||||||||||||
Rate of compensation increase | 3.5 | % | 3.5 | % | N/A | N/A | |||||||||||||||||||
Expected increase in Consumer Price Index | N/A | N/A | 2.75 | % | 2.75 | % | |||||||||||||||||||
The weighted averages of significant assumptions used to determine net periodic benefit costs follow: | |||||||||||||||||||||||||
Pension Benefits | Other Benefits | ||||||||||||||||||||||||
2013 | 2012 | 2011 | 2013 | 2012 | 2011 | ||||||||||||||||||||
Discount rate | 4.03 | % | 4.82 | % | 5.5 | % | 3.91 | % | 4.75 | % | 5.5 | % | |||||||||||||
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 | % | 8 | % | N/A | N/A | 8 | % | |||||||||||||||
Expected increase in Consumer Price Index | N/A | N/A | N/A | 2.75 | % | 2.75 | % | 3 | % | ||||||||||||||||
Schedule of changes in projected benefit obligations | ' | ||||||||||||||||||||||||
A reconciliation of the Company’s benefit obligations at December 31, 2013 and 2012 follows: | |||||||||||||||||||||||||
Pension Benefits | Other Benefits | ||||||||||||||||||||||||
(In millions) | 2013 | 2012 | 2013 | 2012 | |||||||||||||||||||||
Benefit obligation, beginning of period | $ | 377.3 | $ | 329.2 | $ | 54.4 | $ | 79.7 | |||||||||||||||||
Service cost – benefits earned during the period | 8.6 | 7.7 | 0.5 | 0.5 | |||||||||||||||||||||
Interest cost on projected benefit obligation | 14.7 | 15.5 | 2 | 2.8 | |||||||||||||||||||||
Plan participants' contributions | — | — | 0.8 | 1.6 | |||||||||||||||||||||
Plan amendments | — | 0.7 | (0.2 | ) | (26.6 | ) | |||||||||||||||||||
Actuarial loss (gain) | (32.7 | ) | 39 | (2.4 | ) | 2.8 | |||||||||||||||||||
Settlement loss (gain) | 1.5 | — | — | — | |||||||||||||||||||||
Medicare subsidy receipts | — | — | — | 0.5 | |||||||||||||||||||||
Benefit payments | (22.8 | ) | (14.8 | ) | (3.8 | ) | (6.9 | ) | |||||||||||||||||
Settlement payments | (8.2 | ) | — | — | — | ||||||||||||||||||||
Benefit obligation, end of period | $ | 338.4 | $ | 377.3 | $ | 51.3 | $ | 54.4 | |||||||||||||||||
Schedule of changes in fair value of plan assets | ' | ||||||||||||||||||||||||
A reconciliation of the Company’s plan assets at December 31, 2013 and 2012 follows: | |||||||||||||||||||||||||
Pension Benefits | Other Benefits | ||||||||||||||||||||||||
(In millions) | 2013 | 2012 | 2013 | 2012 | |||||||||||||||||||||
Plan assets at fair value, beginning of period | $ | 295.7 | $ | 261 | $ | — | $ | — | |||||||||||||||||
Actual return on plan assets | 48.4 | 33.8 | — | — | |||||||||||||||||||||
Employer contributions | 10.8 | 15.7 | 3 | 5.3 | |||||||||||||||||||||
Plan participants' contributions | — | — | 0.8 | 1.6 | |||||||||||||||||||||
Benefit payments | (22.8 | ) | (14.8 | ) | (3.8 | ) | (6.9 | ) | |||||||||||||||||
Settlement payments | (8.2 | ) | — | — | — | ||||||||||||||||||||
Fair value of plan assets, end of period | $ | 323.9 | $ | 295.7 | $ | — | $ | — | |||||||||||||||||
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, 2013 and December 31, 2012 by asset category and by fair value hierarchy are as follows: | |||||||||||||||||||||||||
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 | |||||||||||||||||
As of December 31, 2012 | |||||||||||||||||||||||||
(In millions) | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||||||
Domestic equities & equity funds | $ | 62.8 | $ | 77.6 | $ | — | $ | 140.4 | |||||||||||||||||
International equities & equity funds | 34.3 | — | — | 34.3 | |||||||||||||||||||||
Domestic bonds & bond funds | 41.7 | 42.3 | — | 84 | |||||||||||||||||||||
Inflation protected security fund | — | 12.6 | — | 12.6 | |||||||||||||||||||||
Real estate, commodities & other | 8 | 12.5 | 3.9 | 24.4 | |||||||||||||||||||||
Total plan investments | $ | 146.8 | $ | 145 | $ | 3.9 | $ | 295.7 | |||||||||||||||||
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) | 2013 | 2012 | |||||||||||||||||||||||
Fair value, beginning of year | $ | 3.9 | $ | 3.8 | |||||||||||||||||||||
Unrealized gains related to | 0.2 | 0.2 | |||||||||||||||||||||||
investments still held at reporting date | |||||||||||||||||||||||||
Purchases, sales and settlements, net | — | (0.1 | ) | ||||||||||||||||||||||
Fair value, end of year | $ | 4.1 | $ | 3.9 | |||||||||||||||||||||
Schedule of net funded status of plans | ' | ||||||||||||||||||||||||
The funded status of the plans as of December 31, 2013 and 2012 follows: | |||||||||||||||||||||||||
Pension Benefits | Other Benefits | ||||||||||||||||||||||||
(In millions) | 2013 | 2012 | 2013 | 2012 | |||||||||||||||||||||
Qualified Plans | |||||||||||||||||||||||||
Benefit obligation, end of period | $ | (321.0 | ) | $ | (360.0 | ) | $ | (51.4 | ) | $ | (54.4 | ) | |||||||||||||
Fair value of plan assets, end of period | 323.9 | 295.7 | — | — | |||||||||||||||||||||
Funded Status of Qualified Plans, end of period | 2.9 | (64.3 | ) | (51.4 | ) | (54.4 | ) | ||||||||||||||||||
Benefit obligation of SERP Plan, end of period | (17.5 | ) | (17.3 | ) | — | — | |||||||||||||||||||
Total funded status, end of period | $ | (14.6 | ) | $ | (81.6 | ) | $ | (51.4 | ) | $ | (54.4 | ) | |||||||||||||
Accrued liabilities | $ | 1 | $ | 1 | $ | 4.9 | $ | 4.5 | |||||||||||||||||
Deferred credits & other liabilities | $ | 20.1 | $ | 80.6 | $ | 46.4 | $ | 49.9 | |||||||||||||||||
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, 2011 | $ | 7.1 | $ | 78.2 | $ | (2.0 | ) | $ | 10.3 | $ | 3.8 | ||||||||||||||
Amounts arising during the period | — | 42.2 | — | (0.6 | ) | — | |||||||||||||||||||
Reclassification to benefit costs | (1.7 | ) | (3.8 | ) | 0.8 | (0.6 | ) | (1.1 | ) | ||||||||||||||||
Balance at December 31, 2011 | $ | 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 | $ | — | ||||||||||||||
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, 2013 and 2012. | |||||||||||||||||||||||||
(In millions) | 2013 | 2012 | |||||||||||||||||||||||
Pensions | Other Benefits | Pensions | Other Benefits | ||||||||||||||||||||||
Prior service cost | $ | 3 | $ | (20.1 | ) | $ | 4.5 | $ | (23.1 | ) | |||||||||||||||
Unamortized actuarial gain/(loss) | 67.3 | 8.1 | 136.2 | 11.2 | |||||||||||||||||||||
Transition obligation | — | — | — | — | |||||||||||||||||||||
70.3 | (12.0 | ) | 140.7 | (11.9 | ) | ||||||||||||||||||||
Less: Regulatory asset deferral | (68.9 | ) | 11.8 | (137.9 | ) | 11.7 | |||||||||||||||||||
AOCI before taxes | $ | 1.4 | $ | (0.2 | ) | $ | 2.8 | $ | (0.2 | ) | |||||||||||||||
Schedule of Multiemployer Contributions In Current Year [Table Text Block] | ' | ||||||||||||||||||||||||
The multi-employer contributions listed in the table below are the Company's multi-employer contributions made in 2013, 2012, and 2011. | |||||||||||||||||||||||||
(In millions) | |||||||||||||||||||||||||
Pension Protection Act Zone Status | Multi-Employer Contributions | ||||||||||||||||||||||||
Pension Fund | EIN/Pension Plan Number | 2013 | 2012 | FIP/RP Status Pending/Implemented | 2013 | 2012 | 2011 | Surcharge Imposed | |||||||||||||||||
Central Pension Fund | 36-6052390-001 | Green | Green | No | $8.50 | $4.00 | $2.30 | No | |||||||||||||||||
Pipeline Industry Benefit Fund | 73-0742835-001 | Green | Green | No | 5.3 | 3.9 | 1 | No | |||||||||||||||||
Indiana Laborers Pension Fund (1) | 35-6027150-001 | Yellow | Yellow | Implemented | 2.4 | 3.2 | 1.6 | No | |||||||||||||||||
Minnesota Laborers Pension Fund | 41-6159599-001 | Green | Green | No | 2.8 | 2 | 0.7 | No | |||||||||||||||||
Other | 14.2 | 14.5 | 12.7 | ||||||||||||||||||||||
Total Contributions | $33.20 | $27.60 | $18.30 |
Borrowing_Arrangements_Tables
Borrowing Arrangements (Tables) | 12 Months Ended | ||||||||||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||||||||||
Debt Disclosure [Abstract] | ' | ||||||||||||||||||||||||
Short term borrowing arrangements | ' | ||||||||||||||||||||||||
Following is certain information regarding these short-term borrowing arrangements. | |||||||||||||||||||||||||
Utility Group Borrowings | Nonutility Group Borrowings | ||||||||||||||||||||||||
(In millions) | 2013 | 2012 | 2011 | 2013 | 2012 | 2011 | |||||||||||||||||||
As of Year End | |||||||||||||||||||||||||
Balance Outstanding | $ | 28.6 | $ | 116.7 | $ | 242.8 | $ | 40 | $ | 162.1 | $ | 84.3 | |||||||||||||
Weighted Average Interest Rate | 0.29 | % | 0.4 | % | 0.57 | % | 1.27 | % | 1.35 | % | 1.45 | % | |||||||||||||
Annual Average | |||||||||||||||||||||||||
Balance Outstanding | $ | 119.6 | $ | 77.6 | $ | 39.6 | $ | 119.3 | $ | 151.5 | $ | 124.9 | |||||||||||||
Weighted Average Interest Rate | 0.34 | % | 0.47 | % | 0.48 | % | 1.35 | % | 1.44 | % | 1.92 | % | |||||||||||||
Maximum Month End Balance Outstanding | $ | 176.1 | $ | 214.2 | $ | 242.8 | $ | 173.8 | $ | 216.1 | $ | 180.1 | |||||||||||||
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) | 2013 | 2012 | |||||||||||||||||||||||
Utility Holdings | |||||||||||||||||||||||||
Fixed Rate Senior Unsecured Notes | |||||||||||||||||||||||||
2013, 5.25% | $ | — | $ | 100 | |||||||||||||||||||||
2015, 5.45% | 75 | 75 | |||||||||||||||||||||||
2018, 5.75% | 100 | 100 | |||||||||||||||||||||||
2020, 6.28% | 100 | 100 | |||||||||||||||||||||||
2021, 4.67% | 55 | 55 | |||||||||||||||||||||||
2023, 3.72% | 150 | — | |||||||||||||||||||||||
2026, 5.02% | 60 | 60 | |||||||||||||||||||||||
2028, 3.20% | 45 | — | |||||||||||||||||||||||
2035, 6.10% | 75 | 75 | |||||||||||||||||||||||
2039, 6.25% | — | 121.6 | |||||||||||||||||||||||
2041, 5.99% | 35 | 35 | |||||||||||||||||||||||
2042, 5.00% | 100 | 100 | |||||||||||||||||||||||
2043, 4.25% | 80 | — | |||||||||||||||||||||||
Total Utility Holdings | 875 | 821.6 | |||||||||||||||||||||||
Indiana Gas | |||||||||||||||||||||||||
Fixed Rate Senior Unsecured Notes | |||||||||||||||||||||||||
2013, Series E, 6.69% | — | 5 | |||||||||||||||||||||||
2015, Series E, 7.15% | 5 | 5 | |||||||||||||||||||||||
2015, Series E, 6.69% | 5 | 5 | |||||||||||||||||||||||
2015, Series E, 6.69% | 10 | 10 | |||||||||||||||||||||||
2025, Series E, 6.53% | 10 | 10 | |||||||||||||||||||||||
2027, Series E, 6.42% | 5 | 5 | |||||||||||||||||||||||
2027, Series E, 6.68% | 1 | 1 | |||||||||||||||||||||||
2027, Series F, 6.34% | 20 | 20 | |||||||||||||||||||||||
2028, Series F, 6.36% | 10 | 10 | |||||||||||||||||||||||
2028, Series F, 6.55% | 20 | 20 | |||||||||||||||||||||||
2029, Series G, 7.08% | 30 | 30 | |||||||||||||||||||||||
Total Indiana Gas | 116 | 121 | |||||||||||||||||||||||
SIGECO | |||||||||||||||||||||||||
First Mortgage Bonds | |||||||||||||||||||||||||
2015, 1985 Pollution Control Series A, current adjustable rate 0.05%, tax exempt, | |||||||||||||||||||||||||
2013 weighted average: 0.10% | 9.8 | 9.8 | |||||||||||||||||||||||
2016, 1986 Series, 8.875% | 13 | 13 | |||||||||||||||||||||||
2020, 1998 Pollution Control Series B, 4.50%, tax exempt | — | 4.6 | |||||||||||||||||||||||
2022, 2013 Series C, 1.95%, tax exempt | 4.6 | — | |||||||||||||||||||||||
2023, 1993 Environmental Improvement Series B, 5.15%, tax exempt | — | 22.6 | |||||||||||||||||||||||
2024, 2000 Environmental Improvement Series A, 4.65%, tax exempt | — | 22.5 | |||||||||||||||||||||||
2024, 2013 Series D, 1.95%, tax exempt | 22.5 | — | |||||||||||||||||||||||
2025, 1998 Pollution Control Series A, current adjustable rate 0.05%, tax exempt, | |||||||||||||||||||||||||
2013 weighted average: 0.10% | 31.5 | 31.5 | |||||||||||||||||||||||
2029, 1999 Series, 6.72% | 80 | 80 | |||||||||||||||||||||||
2030, 1998 Pollution Control Series B, 5.00%, tax exempt | — | 22 | |||||||||||||||||||||||
At December 31, | |||||||||||||||||||||||||
(In millions) | 2013 | 2012 | |||||||||||||||||||||||
2030, 1998 Pollution Control Series C, 5.35%, tax exempt | — | 22.2 | |||||||||||||||||||||||
2037, 2013 Series E, 1.95%, tax exempt | 22 | — | |||||||||||||||||||||||
2038, 2013 Series A, 4.0%, tax exempt | 22.2 | — | |||||||||||||||||||||||
2040, 2009 Environmental Improvement Series, 5.40%, tax exempt | 22.3 | 22.3 | |||||||||||||||||||||||
2041, 2007 Pollution Control Series, 5.45%, tax exempt | — | 17 | |||||||||||||||||||||||
2043, 2013 Series B, 4.05%, tax exempt | 39.6 | — | |||||||||||||||||||||||
Total SIGECO | 267.5 | 267.5 | |||||||||||||||||||||||
Vectren Capital Corp. | |||||||||||||||||||||||||
Fixed Rate Senior Unsecured Notes | |||||||||||||||||||||||||
2014, 6.37% | 30 | 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, current adjustable rate 1.17% | 100 | 100 | |||||||||||||||||||||||
2016, current adjustable rate 1.17% | 100 | — | |||||||||||||||||||||||
Total Vectren Capital Corp. | 550 | 450 | |||||||||||||||||||||||
Other Long-Term Notes Payable | — | 1.4 | |||||||||||||||||||||||
Total long-term debt outstanding | 1,808.50 | 1,661.50 | |||||||||||||||||||||||
Current maturities of long-term debt | (30.0 | ) | (106.4 | ) | |||||||||||||||||||||
Unamortized debt premium & discount - net | (1.4 | ) | (1.7 | ) | |||||||||||||||||||||
Total long-term debt-net | $ | 1,777.10 | $ | 1,553.40 | |||||||||||||||||||||
Earnings_Per_Share_Tables
Earnings Per Share (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2013 | |||||||||||||
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, 2013: | |||||||||||||
Year Ended December 31, | |||||||||||||
(In millions, except per share data) | 2013 | 2012 | 2011 | ||||||||||
Numerator: | |||||||||||||
Numerator for basic EPS | $ | 136.6 | $ | 159 | $ | 141.6 | |||||||
Add back earnings attributable to participating securities | — | — | — | ||||||||||
Reported net income (Numerator for Diluted EPS) | $ | 136.6 | $ | 159 | $ | 141.6 | |||||||
Denominator: | |||||||||||||
Weighted average common shares outstanding (Basic EPS) | 82.3 | 82 | 81.8 | ||||||||||
Conversion of share based compensation arrangements | 0.1 | 0.1 | 0 | ||||||||||
Adjusted weighted average shares outstanding and | |||||||||||||
assumed conversions outstanding (Diluted EPS) | 82.4 | 82.1 | 81.8 | ||||||||||
Basic earnings per share | $ | 1.66 | $ | 1.94 | $ | 1.73 | |||||||
Diluted earnings per share | $ | 1.66 | $ | 1.94 | $ | 1.73 | |||||||
Accumulated_Other_Comprehensiv1
Accumulated Other Comprehensive Income (Tables) | 12 Months Ended | ||||||||||||||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||||||||||||||
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: | |||||||||||||||||||||||||||||
2011 | 2012 | 2013 | |||||||||||||||||||||||||||
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 | $ | (6.6 | ) | $ | (9.3 | ) | $ | (15.9 | ) | $ | 11.3 | $ | (4.6 | ) | $ | 4.6 | $ | — | |||||||||||
Pension & other benefit costs | (4.9 | ) | (1.7 | ) | (6.6 | ) | 4 | (2.6 | ) | 1.4 | (1.2 | ) | |||||||||||||||||
Cash flow hedges | 4 | (3.9 | ) | 0.1 | (0.1 | ) | — | — | — | ||||||||||||||||||||
Deferred income taxes | 3.1 | 6 | 9.1 | (6.2 | ) | 2.9 | (2.4 | ) | 0.5 | ||||||||||||||||||||
Accumulated other comprehensive income (loss) | $ | (4.4 | ) | $ | (8.9 | ) | $ | (13.3 | ) | $ | 9 | $ | (4.3 | ) | $ | 3.6 | $ | (0.7 | ) | ||||||||||
ShareBased_Compensation_Deferr1
Share-Based Compensation & Deferred Compensation Arrangements (Tables) | 12 Months Ended | |||||||||||||
Dec. 31, 2013 | ||||||||||||||
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) | 2013 | 2012 | 2011 | |||||||||||
Total cost of share-based compensation | $ | 14.8 | $ | 6.3 | $ | 5.8 | ||||||||
Less capitalized cost | 2.8 | 1.2 | 0.8 | |||||||||||
Total in other operating expense | 12 | 5.1 | 5 | |||||||||||
Less income tax benefit in earnings | 4.8 | 2.1 | 2 | |||||||||||
After tax effect of share-based compensation | $ | 7.2 | $ | 3 | $ | 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, 2013, and changes during the year ended December 31, 2013, follows: | ||||||||||||||
Equity Awards | ||||||||||||||
Wtd. Avg. | ||||||||||||||
Grant Date | Liability Awards | |||||||||||||
Units | Fair value | Units | Fair value | |||||||||||
Awards at January 1, 2013 | 70,493 | $ | 27.45 | 628,810 | ||||||||||
Granted | 28,579 | 30.19 | 305,617 | |||||||||||
Vested | -15,175 | 26.04 | -158,187 | |||||||||||
Forfeited | -3,940 | 26.2 | -44,989 | |||||||||||
Awards at December 31, 2013 | 79,957 | $ | 29.12 | 731,251 | $ | 35.5 | ||||||||
Status of stock option awards and changes during the period | ' | |||||||||||||
A summary of the status of the Company’s stock option awards as of December 31, 2013, and changes during the year ended December 31, 2013, follows: | ||||||||||||||
Weighted average | Aggregate | |||||||||||||
Shares | Exercise | Remaining | Intrinsic | |||||||||||
Price | Contractual | Value | ||||||||||||
Term (years) | (In millions) | |||||||||||||
Outstanding at January 1, 2013 | 386,565 | $ | 25.88 | |||||||||||
Exercised | (378,592 | ) | $ | 25.87 | ||||||||||
Forfeited or expired | (727 | ) | $ | 22.57 | ||||||||||
Outstanding at December 31, 2013 | 7,246 | $ | 26.7 | 1 | $ | 0.6 | ||||||||
Exercisable at December 31, 2013 | 7,246 | $ | 26.7 | 1 | $ | 0.6 | ||||||||
Fair_Value_Measurements_Tables
Fair Value Measurements (Tables) | 12 Months Ended | ||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||
Fair Value Disclosures [Abstract] | ' | ||||||||||||||||
Carrying value and estimated fair value of other financial instruments | ' | ||||||||||||||||
The carrying values and estimated fair values using primarily Level 2 assumptions of the Company's other financial instruments follow: | |||||||||||||||||
At December 31, | |||||||||||||||||
2013 | 2012 | ||||||||||||||||
(In millions) | Carrying | Est. Fair | Carrying | Est. Fair | |||||||||||||
Amount | Value | Amount | Value | ||||||||||||||
Long-term debt | $ | 1,807.10 | $ | 1,895.20 | $ | 1,659.80 | $ | 1,873.30 | |||||||||
Short-term borrowings & notes payable | 68.6 | 68.6 | 278.8 | 278.8 | |||||||||||||
Cash & cash equivalents | 21.5 | 21.5 | 19.5 | 19.5 | |||||||||||||
Segment_Reporting_Tables
Segment Reporting (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2013 | |||||||||||||
Segment Reporting [Abstract] | ' | ||||||||||||
Schedule of Segment Reporting Information, by Segment [Table Text Block] | ' | ||||||||||||
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) | 2013 | 2012 | 2011 | ||||||||||
Revenues | |||||||||||||
Utility Group | |||||||||||||
Gas Utility Services | $ | 810 | $ | 738.1 | $ | 819.1 | |||||||
Electric Utility Services | 619.3 | 594.9 | 635.9 | ||||||||||
Other Operations | 38.1 | 40.1 | 43.9 | ||||||||||
Eliminations | (37.8 | ) | (39.5 | ) | (41.9 | ) | |||||||
Total Utility Group | 1,429.60 | 1,333.60 | 1,457.00 | ||||||||||
Nonutility Group | |||||||||||||
Infrastructure Services | 783.5 | 663.6 | 421.3 | ||||||||||
Energy Services | 91.3 | 117.7 | 161.8 | ||||||||||
Coal Mining | 292.8 | 235.8 | 285.6 | ||||||||||
Energy Marketing | — | — | 149.9 | ||||||||||
Other Businesses | — | 0.5 | — | ||||||||||
Total Nonutility Group | 1,167.60 | 1,017.60 | 1,018.60 | ||||||||||
Eliminations, net of Corporate & Other Revenues | (106.0 | ) | (118.4 | ) | (150.4 | ) | |||||||
Consolidated Revenues | $ | 2,491.20 | $ | 2,232.80 | $ | 2,325.20 | |||||||
Profitability Measures - Net Income | |||||||||||||
Utility Group Net Income | |||||||||||||
Gas Utility Services | $ | 55.7 | $ | 60 | $ | 52.5 | |||||||
Electric Utility Services | 75.8 | 68 | 65 | ||||||||||
Other Operations | 10.3 | 10 | 5.4 | ||||||||||
Total Utility Group Net Income | 141.8 | 138 | 122.9 | ||||||||||
Nonutility Group Net Income (Loss) | |||||||||||||
Infrastructure Services | 49 | 40.5 | 14.9 | ||||||||||
Energy Services | 1 | 5.7 | 6.7 | ||||||||||
Coal Mining | (16.0 | ) | (3.5 | ) | 16.6 | ||||||||
Energy Marketing | (37.5 | ) | (17.6 | ) | (4.2 | ) | |||||||
Other Businesses | (1.0 | ) | (3.4 | ) | (10.2 | ) | |||||||
Total Nonutility Group Net Income | (4.5 | ) | 21.7 | 23.8 | |||||||||
Corporate & Other Net Loss | (0.7 | ) | (0.7 | ) | (5.1 | ) | |||||||
Consolidated Net Income | $ | 136.6 | $ | 159 | $ | 141.6 | |||||||
Year Ended December 31, | |||||||||||||
(In millions) | 2013 | 2012 | 2011 | ||||||||||
Amounts Included in Profitability Measures | |||||||||||||
Depreciation & Amortization | |||||||||||||
Utility Group | |||||||||||||
Gas Utility Services | $ | 90.5 | $ | 85.4 | $ | 84.3 | |||||||
Electric Utility Services | 84 | 81.3 | 80.2 | ||||||||||
Other Operations | 21.9 | 23.3 | 27.8 | ||||||||||
Total Utility Group | 196.4 | 190 | 192.3 | ||||||||||
Nonutility Group | |||||||||||||
Infrastructure Services | 28.8 | 20.7 | 14.9 | ||||||||||
Energy Services | 1.7 | 1.9 | 1.5 | ||||||||||
Coal Mining | 50.8 | 41.8 | 35.1 | ||||||||||
Energy Marketing | — | — | 0.5 | ||||||||||
Other Businesses | 0.1 | 0.2 | — | ||||||||||
Total Nonutility Group | 81.4 | 64.6 | 52 | ||||||||||
Consolidated Depreciation & Amortization | $ | 277.8 | $ | 254.6 | $ | 244.3 | |||||||
Interest Expense | |||||||||||||
Utility Group | |||||||||||||
Gas Utility Services | $ | 30.6 | $ | 31.8 | $ | 37.1 | |||||||
Electric Utility Services | 29.2 | 33.8 | 36.4 | ||||||||||
Other Operations | 5.2 | 5.9 | 6.8 | ||||||||||
Total Utility Group | 65 | 71.5 | 80.3 | ||||||||||
Nonutility Group | |||||||||||||
Infrastructure Services | 10.1 | 7.5 | 7.4 | ||||||||||
Energy Services | 0.6 | 0.4 | 0.6 | ||||||||||
Coal Mining | 9.8 | 11.5 | 11.3 | ||||||||||
Energy Marketing | 2.2 | 4.8 | 6.4 | ||||||||||
Other Businesses | 0.5 | 0.7 | 1.3 | ||||||||||
Total Nonutility Group | 23.2 | 24.9 | 27 | ||||||||||
Corporate & Other | (0.3 | ) | (0.4 | ) | (0.8 | ) | |||||||
Consolidated Interest Expense | $ | 87.9 | $ | 96 | $ | 106.5 | |||||||
Income Taxes | |||||||||||||
Utility Group | |||||||||||||
Gas Utility Services | $ | 36.6 | $ | 39.1 | $ | 34.5 | |||||||
Electric Utility Services | 48.3 | 46.4 | 45.3 | ||||||||||
Other Operations | 0.4 | (0.2 | ) | 3.1 | |||||||||
Total Utility Group | 85.3 | 85.3 | 82.9 | ||||||||||
Nonutility Group | |||||||||||||
Infrastructure Services | 34.3 | 29.6 | 10.7 | ||||||||||
Energy Services | (11.9 | ) | (9.0 | ) | 1.1 | ||||||||
Coal Mining | (14.6 | ) | (8.6 | ) | 3.9 | ||||||||
Energy Marketing | (23.3 | ) | (11.7 | ) | (2.4 | ) | |||||||
Other Businesses | (1.6 | ) | (2.0 | ) | (7.0 | ) | |||||||
Total Nonutility Group | (17.1 | ) | (1.7 | ) | 6.3 | ||||||||
Corporate & Other | (1.1 | ) | (1.1 | ) | (2.8 | ) | |||||||
Consolidated Income Taxes | $ | 67.1 | $ | 82.5 | $ | 86.4 | |||||||
Year Ended December 31, | |||||||||||||
(In millions) | 2013 | 2012 | 2011 | ||||||||||
Capital Expenditures | |||||||||||||
Utility Group | |||||||||||||
Gas Utility Services | $ | 150.5 | $ | 128.8 | $ | 113.5 | |||||||
Electric Utility Services | 100 | 108.8 | 102.2 | ||||||||||
Other Operations | 25.8 | 16.2 | 17.8 | ||||||||||
Non-cash costs & changes in accruals | (15.2 | ) | (7.8 | ) | (0.1 | ) | |||||||
Total Utility Group | 261.1 | 246 | 233.4 | ||||||||||
Nonutility Group | |||||||||||||
Infrastructure Services | 79.2 | 53.7 | 22.8 | ||||||||||
Energy Services | 6.9 | 2.3 | 9.7 | ||||||||||
Coal Mining | 46.2 | 63.8 | 55.1 | ||||||||||
Energy Marketing | — | — | 0.3 | ||||||||||
Total Nonutility Group | 132.3 | 119.8 | 87.9 | ||||||||||
Consolidated Capital Expenditures | $ | 393.4 | $ | 365.8 | $ | 321.3 | |||||||
At December 31, | |||||||||||||
(In millions) | 2013 | 2012 | 2011 | ||||||||||
Assets | |||||||||||||
Utility Group | |||||||||||||
Gas Utility Services | $ | 2,287.90 | $ | 2,173.50 | $ | 2,125.20 | |||||||
Electric Utility Services | 1,679.00 | 1,705.10 | 1,656.50 | ||||||||||
Other Operations, net of eliminations | 173.9 | 168.2 | 192.8 | ||||||||||
Total Utility Group | 4,140.80 | 4,046.80 | 3,974.50 | ||||||||||
Nonutility Group | |||||||||||||
Infrastructure Services | 465.8 | 420 | 295 | ||||||||||
Energy Services | 63 | 69.7 | 81.2 | ||||||||||
Coal Mining | 433 | 380 | 352.8 | ||||||||||
Energy Marketing | 33.9 | 73.9 | 112.5 | ||||||||||
Other Businesses, net of eliminations and reclassifications | 34.9 | 37.1 | 46.8 | ||||||||||
Total Nonutility Group | 1,030.60 | 980.7 | 888.3 | ||||||||||
Corporate & Other | 828.1 | 785.6 | 727.3 | ||||||||||
Eliminations | (896.9 | ) | (724.0 | ) | (711.2 | ) | |||||||
Consolidated Assets | $ | 5,102.60 | $ | 5,089.10 | $ | 4,878.90 | |||||||
Additional_Balance_Sheet_Opera1
Additional Balance Sheet & Operational Information (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2013 | |||||||||||||
Additional Balance Sheet and Operational Information [Abstract] | ' | ||||||||||||
Summary of inventories | ' | ||||||||||||
Inventories consist of the following: | |||||||||||||
At December 31, | |||||||||||||
(In millions) | 2013 | 2012 | |||||||||||
Gas in storage – at LIFO cost | $ | 33.2 | $ | 22.4 | |||||||||
Coal & oil for electric generation - at average cost | 16.5 | 52 | |||||||||||
Materials & supplies | 57.3 | 57.6 | |||||||||||
Nonutility coal - at LIFO cost | 26.2 | 25.4 | |||||||||||
Other | 1.2 | 1.2 | |||||||||||
Total inventories | $ | 134.4 | $ | 158.6 | |||||||||
Summary of prepayments and other current assets | ' | ||||||||||||
Prepayments & other current assets consist of the following: | |||||||||||||
At December 31, | |||||||||||||
(In millions) | 2013 | 2012 | |||||||||||
Prepaid gas delivery service | $ | 32.9 | $ | 28.5 | |||||||||
Deferred income taxes | 13.9 | — | |||||||||||
Prepaid taxes | 11.2 | 26.4 | |||||||||||
Other prepayments & current assets | 17.6 | 18.4 | |||||||||||
Total prepayments & other current assets | $ | 75.6 | $ | 73.3 | |||||||||
Schedule of investments in unconsolidated affiliates | ' | ||||||||||||
Investments in unconsolidated affiliates consist of the following: | |||||||||||||
At December 31, | |||||||||||||
(In millions) | 2013 | 2012 | |||||||||||
ProLiance Holdings, LLC | $ | 20.8 | $ | 73.9 | |||||||||
Other nonutility partnerships & corporations | 3 | 4 | |||||||||||
Other utility investments | 0.2 | 0.2 | |||||||||||
Total investments in unconsolidated affiliates | $ | 24 | $ | 78.1 | |||||||||
Other utility and corporate investments in the consolidated balance sheets | ' | ||||||||||||
Other utility & corporate investments consist of the following: | |||||||||||||
At December 31, | |||||||||||||
(In millions) | 2013 | 2012 | |||||||||||
Cash surrender value of life insurance policies | $ | 32.9 | $ | 29.1 | |||||||||
Municipal bond | 3.4 | 3.6 | |||||||||||
Restricted cash & other investments | 1.8 | 1.9 | |||||||||||
Other utility & corporate investments | $ | 38.1 | $ | 34.6 | |||||||||
Goodwill by operating segment | ' | ||||||||||||
Goodwill by operating segment follows: | |||||||||||||
At December 31, | |||||||||||||
(In millions) | 2013 | 2012 | |||||||||||
Utility Group | |||||||||||||
Gas Utility Services | $ | 205 | $ | 205 | |||||||||
Nonutility Group | |||||||||||||
Infrastructure Services | 55.2 | 55.2 | |||||||||||
Energy Services | 2.1 | 2.1 | |||||||||||
Consolidated goodwill | $ | 262.3 | $ | 262.3 | |||||||||
Accrued Liabilities | ' | ||||||||||||
Accrued liabilities consist of the following: | |||||||||||||
At December 31, | |||||||||||||
(In millions) | 2013 | 2012 | |||||||||||
Refunds to customers & customer deposits | $ | 50.2 | $ | 53.1 | |||||||||
Accrued taxes | 36.2 | 34.4 | |||||||||||
Accrued interest | 20 | 23.1 | |||||||||||
Deferred compensation & post-retirement benefits | 7.5 | 6.8 | |||||||||||
Deferred income taxes | — | 14.9 | |||||||||||
Accrued salaries & other | 68.2 | 66.5 | |||||||||||
Total accrued liabilities | $ | 182.1 | $ | 198.8 | |||||||||
Asset retirement obligation | ' | ||||||||||||
Asset retirement obligations roll forward as follows: | |||||||||||||
(In millions) | 2013 | 2012 | |||||||||||
Asset retirement obligation, January 1 | $ | 37.7 | $ | 43.7 | |||||||||
Accretion | 2.2 | 2.7 | |||||||||||
Changes in estimates, net of cash payments | 1.4 | (8.7 | ) | ||||||||||
Asset retirement obligation, December 31 | 41.3 | 37.7 | |||||||||||
Equity in earnings (losses) of unconsolidated affiliates | ' | ||||||||||||
Equity in (losses) of unconsolidated affiliates consists of the following: | |||||||||||||
Year Ended December 31, | |||||||||||||
(In millions) | 2013 | 2012 | 2011 | ||||||||||
ProLiance Holdings, LLC | $ | (57.7 | ) | $ | (22.7 | ) | $ | (28.6 | ) | ||||
Other | (2.0 | ) | (0.6 | ) | (3.4 | ) | |||||||
Total equity in (losses) of unconsolidated affiliates | $ | (59.7 | ) | $ | (23.3 | ) | $ | (32.0 | ) | ||||
Other, net in the consolidated statements of income | ' | ||||||||||||
Other income (expense) – net consists of the following: | |||||||||||||
Year Ended December 31, | |||||||||||||
(In millions) | 2013 | 2012 | 2011 | ||||||||||
AFUDC – borrowed funds | $ | 5.9 | $ | 4.6 | $ | 2.5 | |||||||
AFUDC – equity funds | 0.8 | 0.4 | 0.2 | ||||||||||
Nonutility plant capitalized interest | 0.5 | 1.8 | 2.1 | ||||||||||
Interest income, net | 1.1 | 1.1 | 1.4 | ||||||||||
Other nonutility investment impairment charges | — | (2.7 | ) | (9.9 | ) | ||||||||
Cash surrender value of life insurance policies | 4.8 | 1.8 | 0.1 | ||||||||||
All other income | 4.6 | 1.3 | 0.1 | ||||||||||
Total other income (expense) – net | $ | 17.7 | $ | 8.3 | $ | (3.5 | ) | ||||||
Supplemental cash flow information | ' | ||||||||||||
Supplemental Cash Flow Information: | |||||||||||||
Year Ended December 31, | |||||||||||||
(In millions) | 2013 | 2012 | 2011 | ||||||||||
Cash paid (received) for: | |||||||||||||
Interest | $ | 91 | $ | 94.6 | $ | 108.6 | |||||||
Income taxes | 6.8 | 21.8 | (9.0 | ) | |||||||||
Quarterly_Financial_Data_Unaud1
Quarterly Financial Data (Unaudited) (Tables) | 12 Months Ended | ||||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||||
Quarterly Financial Information Disclosure [Abstract] | ' | ||||||||||||||||||
Summarized quarterly financial data | ' | ||||||||||||||||||
Information in any one quarterly period is not indicative of annual results due to the seasonal variations common to the Company’s utility operations. Summarized quarterly financial data for 2013 and 2012 follows: | |||||||||||||||||||
(In millions, except per share amounts) | Q1 | Q2 | Q3 | Q4 | |||||||||||||||
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 | ||||||||||||||
2012 | |||||||||||||||||||
Operating revenues | $ | 604.6 | $ | 470.6 | $ | 513.5 | $ | 644.1 | |||||||||||
Operating income | 109.9 | 70.2 | 81.6 | 90.8 | |||||||||||||||
Net income | 51.3 | 25.6 | 39.3 | 42.8 | |||||||||||||||
Earnings per share: | |||||||||||||||||||
Basic | $ | 0.63 | $ | 0.31 | $ | 0.48 | $ | 0.52 | |||||||||||
Diluted | 0.62 | 0.31 | 0.48 | 0.52 | |||||||||||||||
Organization_and_Nature_of_Ope1
Organization and Nature of Operations (Details) | 12 Months Ended |
Dec. 31, 2013 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | ' |
Number of public utility subsidiaries owned by wholly owned subsidiary, Vectren Utility Holdings, Inc. (in number of subsidiaries) | 3 |
Estimated number of natural gas customers located in central and southern Indiana serviced by Indiana Gas Company (in number of customers) | 570,000 |
Estimated number of electric customers located near Evansville in southwestern Indiana serviced by Southern Indiana Gas and Electric Company (in number of customers) | 142,000 |
Estimated number of natural gas customers located near Evansville in southwestern Indiana serviced by Southern Indiana Gas and Electric Company (in number of customers) | 110,000 |
Estimated number of natural gas customers located near Dayton in west central Ohio serviced by the Ohio operations (in number of customers) | 312,000 |
Summary_of_Significant_Account2
Summary of Significant Accounting Policies (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Accounting Policies [Abstract] | ' | ' | ' |
Excise taxes and a portion of utility receipts taxes | $29.60 | $26.90 | $29.30 |
Number of operating segments in Utility group | 3 | ' | ' |
Number of operating segments in Nonutility group | 5 | ' | ' |
Utility_Nonutility_Plant_Detai
Utility & Nonutility Plant (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Utility & Nonutility Plant | ' | ' | ' |
Original Cost | $5,389.60 | $5,176.80 | ' |
Cost of Non-Utility plant, net of depreciation and amortization | 657.2 | 598 | ' |
Utility Group [Member] | ' | ' | ' |
Utility & Nonutility Plant | ' | ' | ' |
Original Cost | 5,389.60 | 5,176.80 | ' |
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 | 2,762.20 | 2,614.30 | ' |
Depreciation Rates as a Percent of Original Cost (in hundredths) | 3.50% | 3.50% | ' |
Utility Group [Member] | Electric Utility Plant [Member] | ' | ' | ' |
Utility & Nonutility Plant | ' | ' | ' |
Original Cost | 2,519.80 | 2,463.60 | ' |
Depreciation Rates as a Percent of Original Cost (in hundredths) | 3.30% | 3.30% | ' |
Utility Group [Member] | Common Utility Plant [Member] | ' | ' | ' |
Utility & Nonutility Plant | ' | ' | ' |
Original Cost | 53.4 | 52 | ' |
Depreciation Rates as a Percent of Original Cost (in hundredths) | 3.00% | 3.00% | ' |
Utility Group [Member] | Construction Work in Progress [Member] | ' | ' | ' |
Utility & Nonutility Plant | ' | ' | ' |
Original Cost | 54.2 | 46.9 | ' |
Depreciation Rates as a Percent of Original Cost (in hundredths) | 0.00% | 0.00% | ' |
Utility Group [Member] | SIGECO [Member] | ' | ' | ' |
Utility & Nonutility Plant | ' | ' | ' |
Southern Indiana Gas And Electric Company's Share Of Cost Of Unit 4 | 186.3 | ' | ' |
Southern Indiana Gas And Electric Company's Share Of Accumulated Depreciation Of Unit 4 | 84.4 | ' | ' |
Nonutility Group [Member] | ' | ' | ' |
Utility & Nonutility Plant | ' | ' | ' |
Cost of Non-Utility plant, net of depreciation and amortization | 657.2 | 598 | ' |
Nonutility plant accumulated depreciation and amortization | 541.7 | 468.4 | ' |
Capitalized interest on nonutility plant construction projects | 0.5 | 1.8 | 2.1 |
Nonutility Group [Member] | Coal Mine Development Costs and Equipment [Member] | ' | ' | ' |
Utility & Nonutility Plant | ' | ' | ' |
Cost of Non-Utility plant, net of depreciation and amortization | 242 | 241.9 | ' |
Nonutility Group [Member] | Computer Hardware and Software [Member] | ' | ' | ' |
Utility & Nonutility Plant | ' | ' | ' |
Cost of Non-Utility plant, net of depreciation and amortization | 102.7 | 97.3 | ' |
Nonutility Group [Member] | Land and Buildings [Member] | ' | ' | ' |
Utility & Nonutility Plant | ' | ' | ' |
Cost of Non-Utility plant, net of depreciation and amortization | 129.3 | 120.4 | ' |
Nonutility Group [Member] | Vehicles and Equipment [Member] | ' | ' | ' |
Utility & Nonutility Plant | ' | ' | ' |
Cost of Non-Utility plant, net of depreciation and amortization | 165.2 | 119.8 | ' |
Nonutility Group [Member] | All Other [Member] | ' | ' | ' |
Utility & Nonutility Plant | ' | ' | ' |
Cost of Non-Utility plant, net of depreciation and amortization | $18 | $18.60 | ' |
Regulatory_Assets_Liabilities_1
Regulatory Assets & Liabilities (Details) (USD $) | 12 Months Ended | |
In Millions, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 |
Regulatory Assets [Line Items] | ' | ' |
Regulatory Assets Currently Being Recovered in Base Rates | $40 | ' |
Regulatory assets | 193.4 | 252.7 |
Weighted average recovery period of regulatory assets currently being recovered (in years) | '23 | ' |
Defined Benefit Plan, decrease in benefit obligation recoverable from ratepayers | 69 | ' |
Regulatory Liabilities [Abstract] | ' | ' |
Regulatory liabilities | 387.3 | 364.2 |
Asset Retirement Obligations and Other [Member] | ' | ' |
Regulatory Liabilities [Abstract] | ' | ' |
Regulatory liabilities | 373 | 349.5 |
Future Amounts Recoverable From Ratepayers [Member] | ' | ' |
Regulatory Assets [Line Items] | ' | ' |
Regulatory assets | 53.7 | 124.9 |
Future Amounts Recoverable From Ratepayers [Member] | Benefit Obligations [Member] | ' | ' |
Regulatory Assets [Line Items] | ' | ' |
Regulatory assets | 57.1 | 126.2 |
Future Amounts Recoverable From Ratepayers [Member] | Deferred Income Taxes [Member] | ' | ' |
Regulatory Assets [Line Items] | ' | ' |
Regulatory assets | -5.8 | -3.9 |
Future Amounts Recoverable From Ratepayers [Member] | Asset Retirement Obligations and Other [Member] | ' | ' |
Regulatory Assets [Line Items] | ' | ' |
Regulatory assets | 2.4 | 2.6 |
Amounts Deferred for Future Recovery [Member] | ' | ' |
Regulatory Assets [Line Items] | ' | ' |
Regulatory assets | 61 | 52.6 |
Amounts Deferred for Future Recovery [Member] | Deferred Coal Costs [Member] | ' | ' |
Regulatory Assets [Line Items] | ' | ' |
Regulatory assets | 42.4 | 42.4 |
Amounts Deferred for Future Recovery [Member] | Cost Recovery Riders Other [Member] | ' | ' |
Regulatory Assets [Line Items] | ' | ' |
Regulatory assets | 18.6 | 10.2 |
Amounts Currently Recovered in Customer Rates [Member] | ' | ' |
Regulatory Assets [Line Items] | ' | ' |
Regulatory assets | 78.7 | 75.2 |
Amounts Currently Recovered in Customer Rates [Member] | Unamortized Debt Issue Costs and Hedging Proceeds [Member] | ' | ' |
Regulatory Assets [Line Items] | ' | ' |
Regulatory assets | 34.6 | 32.6 |
Amounts Currently Recovered in Customer Rates [Member] | Demand Side Management Programs [Member] | ' | ' |
Regulatory Assets [Line Items] | ' | ' |
Regulatory assets | 2.5 | 4.4 |
Amounts Currently Recovered in Customer Rates [Member] | Indiana Authorized Trackers [Member] | ' | ' |
Regulatory Assets [Line Items] | ' | ' |
Regulatory assets | 30.8 | 32.1 |
Amounts Currently Recovered in Customer Rates [Member] | Ohio Authorized Trackers [Member] | ' | ' |
Regulatory Assets [Line Items] | ' | ' |
Regulatory assets | 7.9 | 1.5 |
Amounts Currently Recovered in Customer Rates [Member] | Premiums Paid to Reaquire Debt [Member] | ' | ' |
Regulatory Assets [Line Items] | ' | ' |
Regulatory assets | 2.2 | 2.7 |
Amounts Currently Recovered in Customer Rates [Member] | Other Base Rate Recoveries [Member] | ' | ' |
Regulatory Assets [Line Items] | ' | ' |
Regulatory assets | $0.70 | $1.90 |
Acquisition_of_Minnesota_Limit2
Acquisition of Minnesota Limited, Inc. (Details) (USD $) | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2012 | Sep. 30, 2012 | Jun. 30, 2012 | Mar. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |
Business Combinations [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Acquisition date | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 31-Mar-11 |
Business Acquisition [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Business Acquisition, Pro Forma Revenue | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $2,346,300,000 |
Transaction costs associated with the acquisition included in other operating expenses during the period | ' | ' | ' | ' | ' | ' | ' | ' | 891,600,000 | 781,000,000 | 652,200,000 |
Lease Obligation | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 83,333 |
Number of years the company is obligated to lease acquiree's corporate headquarters | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10 |
Contribution to Nonutility revenues | ' | ' | ' | ' | ' | ' | ' | ' | 1,061,900,000 | 899,800,000 | 870,200,000 |
Net income (loss) | 49,800,000 | 42,800,000 | -5,800,000 | 49,800,000 | 42,800,000 | 39,300,000 | 25,600,000 | 51,300,000 | 136,600,000 | 159,000,000 | 141,600,000 |
Business Acquisition, Pro Forma Net Income (Loss) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 141,400,000 |
Business Acquisition, Pro Forma Earnings Per Share, Basic | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $1.73 |
Business Acquisition, Pro Forma Earnings Per Share, Diluted | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $1.73 |
Minnesota Limited, Inc. [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Business Acquisition [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Contribution to Nonutility revenues | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 116,500,000 |
Net income (loss) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 9,400,000 |
Leasehold Improvements, Gross | $1,500,000 | ' | ' | ' | ' | ' | ' | ' | $1,500,000 | ' | ' |
Sale_of_Retail_Gas_Marketing_O1
Sale of Retail Gas Marketing Operations (Details) (USD $) | 12 Months Ended |
In Millions, unless otherwise specified | Dec. 31, 2011 |
Discontinued Operations and Disposal Groups [Abstract] | ' |
Gain (loss) on disposal | $25.40 |
Investment_in_ProLiance_Holdin2
Investment in ProLiance Holdings, LLC (Details) (USD $) | 12 Months Ended | 12 Months Ended | ||||||||
In Millions, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2010 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 |
ProLiance Holdings, LLC [Member] | ProLiance Holdings, LLC [Member] | Liberty Storage, LLC [Member] | Liberty Storage, LLC [Member] | Liberty Storage, LLC [Member] | Sublease Agreement [Member] | ProLiance Holdings, LLC [Member] | ||||
Vectren Corp [Member] | ProLiance Holdings, LLC [Member] | ProLiance Holdings, LLC [Member] | ProLiance Holdings, LLC [Member] | Liberty Storage, LLC [Member] | ||||||
Schedule of Equity Method Investments [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Equity method investment, ownership percentage (in hundredths) | ' | ' | ' | ' | 61.00% | ' | 25.00% | ' | ' | ' |
Equity Method Investment Governance and Voting Right Percentage | ' | ' | ' | ' | 50.00% | ' | ' | ' | ' | ' |
Equity method investment, loss on sale of ProLiance Energy, before tax | ' | ' | ' | ' | $43.60 | ' | ' | ' | ' | ' |
Equity method investment, loss on sale of ProLiance Energy, after tax | ' | ' | ' | ' | 26.8 | ' | ' | ' | ' | ' |
Equity method investee funding of equity shortfall of ProLiance Energy | ' | ' | ' | 16.6 | ' | ' | ' | ' | ' | ' |
Other nonutility investments | 33.8 | 24.9 | ' | ' | 10.1 | ' | ' | ' | ' | ' |
Equity method investment, amount of guarantee issued by equity method investee (ProLiance) to ETC | ' | ' | ' | 50 | ' | ' | ' | ' | ' | ' |
Maximum gaurantee issued by the Company and Citizens | ' | ' | ' | ' | 25 | ' | ' | ' | ' | ' |
Impairment Charge Recorded By Investee Of Companys Equity Method Investments | ' | ' | ' | ' | ' | 132 | ' | ' | ' | ' |
Equity Method Investment, Aggregate Cost | ' | ' | ' | ' | ' | ' | 35.4 | 35.5 | ' | ' |
Loss contingency, gross damages sought from a party that entered into a sub-lease agreement with a party that is an investment of an equity method investee. | ' | ' | ' | ' | ' | ' | ' | ' | 56.7 | ' |
Purchases from ProLiance for resale and for injections into storage | 200.5 | 274.5 | 378.7 | ' | ' | ' | ' | ' | ' | ' |
Due to Affiliate, Current | ' | ' | ' | ' | ' | ' | ' | ' | ' | 29.7 |
Equity method investment, investment in equity method investee's subsidiary (ProLiance Energy) | 1.5 | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Equity method investment, investment in storage assets and cash from sale of storage assets | 7.8 | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Equity method investment, minority interest in joint venture, investor's portion of interest | 21.6 | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Equity method investment, gross investment in equity method investee | $30.90 | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Nonutility_Real_Estate_Other_L2
Nonutility Real Estate & Other Legacy Holdings (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Investments by type [Abstract] | ' | ' | ' |
Other nonutility investments | $33.80 | $24.90 | ' |
Investments in unconsolidated affiliates | 24 | 78.1 | ' |
Commercial real estate | ' | ' | ' |
Equity in earnings (losses) of unconsolidated affiliates | -59.7 | -23.3 | -32 |
ProLiance Holdings, LLC [Member] | ' | ' | ' |
Investments by type [Abstract] | ' | ' | ' |
Investments in unconsolidated affiliates | 20.8 | 73.9 | ' |
Commercial real estate | ' | ' | ' |
Equity in earnings (losses) of unconsolidated affiliates | -57.7 | -22.7 | -28.6 |
Nonutility Group [Member] | ' | ' | ' |
Investments by type [Abstract] | ' | ' | ' |
Total carrying value by type of investment | 26.5 | 28.7 | ' |
Other nonutility investments | 23.7 | ' | ' |
Investments in unconsolidated affiliates | 2.8 | ' | ' |
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 | ' | ' |
Commercial real estate | ' | ' | ' |
Impairment charge | ' | ' | 15.4 |
Amount of impairment charge included in Other-net | ' | ' | 8.8 |
Equity in earnings (losses) of unconsolidated affiliates | ' | ' | 3.6 |
Other operating expenses | ' | ' | 3 |
Leveraged Leases [Member] | Nonutility Group [Member] | ' | ' | ' |
Investments by type [Abstract] | ' | ' | ' |
Total carrying value by type of investment | 14.4 | ' | ' |
Other nonutility investments | 14.4 | ' | ' |
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 | 19.6 | ' | ' |
Book value of leveraged lease | 4 | ' | ' |
Leveraged Lease Deferred Taxes | 10.4 | ' | ' |
Other Investments [Member] | Nonutility Group [Member] | ' | ' | ' |
Investments by type [Abstract] | ' | ' | ' |
Total carrying value by type of investment | 4.1 | ' | ' |
Other nonutility investments | 1.3 | ' | ' |
Investments in unconsolidated affiliates | $2.80 | ' | ' |
Intangible_Assets_Details
Intangible Assets (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Schedule of intangible assets, excluding goodwill [Line Items] | ' | ' | ' |
Amortizing | $19.30 | $21.60 | ' |
Non-amortizing | 7 | 7 | ' |
Weighted average remaining life for amortizing customer-related assets and all amortizing intangibles (in years) | '13 years | ' | ' |
Amortization expense | 2.3 | 2.6 | 2.3 |
Amortization expense - year one | 2.3 | ' | ' |
Amortization expense - year two | 2.2 | ' | ' |
Amortization expense - year three | 1.6 | ' | ' |
Amortization expense - year four | 1.4 | ' | ' |
Amortization expense - year five | 1.4 | ' | ' |
Customer Related Assets [Member] | ' | ' | ' |
Schedule of intangible assets, excluding goodwill [Line Items] | ' | ' | ' |
Amortizing | 17.4 | 18.9 | ' |
Non-amortizing | 0 | 0 | ' |
Accumulated amortization | 8.1 | 6.6 | ' |
Market Related Assets [Member] | ' | ' | ' |
Schedule of intangible assets, excluding goodwill [Line Items] | ' | ' | ' |
Amortizing | 1.9 | 2.7 | ' |
Non-amortizing | 7 | 7 | ' |
Accumulated amortization | $2.60 | $1.70 | ' |
Income_Taxes_Details
Income Taxes (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
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) | 4.60% | 4.00% | 4.20% |
Amortization of investment tax credit (in hundredths) | -0.30% | -0.30% | -0.30% |
Depletion (in hundredths) | -1.50% | -1.50% | -1.90% |
Energy efficiency building deductions | -3.80% | -3.00% | -1.10% |
Other tax credits (in hundredths) | -1.10% | -0.10% | -0.20% |
Adjustment of income tax accruals and all other-net (in hundredths) | 0.10% | 0.10% | 2.20% |
Effective tax rate (in hundredths) | 33.00% | 34.20% | 37.90% |
Noncurrent deferred tax liabilities (assets) [Abstract] | ' | ' | ' |
Depreciation and cost recovery timing differences | $725.20 | $681.60 | ' |
Leveraged lease | 10.4 | 10.8 | ' |
Regulatory assets recoverable through future rates | 22.8 | 23.5 | ' |
Other comprehensive income | -1.6 | -4 | ' |
Alternative minimum tax carryforward | -23.5 | -44.1 | ' |
Employee benefit obligations | -6.7 | -2.1 | ' |
Net operating loss and other carryforwards | -1.2 | -11.7 | ' |
Regulatory liabilities to be settled through future rates | -18.7 | -18.3 | ' |
Impairments | -6.2 | -6.1 | ' |
Other - net | 6.9 | 7.6 | ' |
Net noncurrent deferred tax liability | 707.4 | 637.2 | ' |
Deferred Tax Assets Liabilities Current Abstract | ' | ' | ' |
Deferred fuel costs-net | 22.9 | 25.7 | ' |
Demand side management programs | 0.1 | 2.7 | ' |
Alternative minimum tax carryforward | -33.7 | -2.7 | ' |
Net operating loss and other carryforwards | -4.9 | 0 | ' |
Other - net | 1.7 | -10.8 | ' |
Net current deferred tax liability (asset) | -13.9 | 14.9 | ' |
Net deferred tax liability | 693.5 | 652.1 | ' |
Investment tax credits | 5.3 | 3.7 | ' |
Investment tax credit expiration | 20 | ' | ' |
Remaining life of NOL's and business credit carryforwards (in years) | '5 to 20 years | ' | ' |
Operating Loss Carryforwards, Valuation Allowance | 3.6 | 1.3 | ' |
Indiana House Bill 1004 [Abstract] | ' | ' | ' |
Phase in period of new legislation | 4 | ' | ' |
Total rate reduction as a result of new legislation | 2.00% | ' | ' |
Annual phase in percentage | 0.50% | ' | ' |
Final tax rate after legislation phase in | 6.50% | ' | ' |
Current: [Abstract] | ' | ' | ' |
Federal | 12.4 | -8.2 | 4.4 |
State | 11.4 | 6.4 | 10.3 |
Total current taxes | 23.8 | -1.8 | 14.7 |
Deferred: [Abstract] | ' | ' | ' |
Federal | 43.4 | 80.3 | 66 |
State | 0.5 | 4.6 | 6.4 |
Total deferred taxes | 43.9 | 84.9 | 72.4 |
Amortization of investment tax credits | -0.6 | -0.6 | -0.7 |
Total income tax expense | 67.1 | 82.5 | 86.4 |
Uncertain tax positions [Roll Forward] | ' | ' | ' |
Unrecognized tax benefits at beginning of period | 4.8 | 12.4 | 13.3 |
Gross increases - tax positions in prior periods | 0 | 0.2 | 3.3 |
Gross decreases - tax positions in prior periods | -0.2 | -9.4 | -4.5 |
Gross increases - current period tax positions | 1.2 | 1.9 | 0.6 |
Settlements | 0 | -0.3 | -0.3 |
Lapse of statute of limitations | 0 | 0 | 0 |
Unrecognized tax benefits at end of period | 5.9 | 4.8 | 12.4 |
Uncertain tax positions [Abstract] | ' | ' | ' |
Amount of unrecognized tax benefits, which if recognized, that would impact the effective tax rate | 0.7 | 0.7 | 0.7 |
Interest and penalties | -0.1 | -0.7 | 0.4 |
Payment of interest and penalties accrued | 0.5 | 0.6 | ' |
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 | $3.80 | $3.20 | ' |
Retirement_Plans_Other_Postret2
Retirement Plans & Other Postretirement Benefits (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Net periodic benefit costs [Abstract] | ' | ' | ' |
Portion of benefit costs capitalized as Utility plant | $4.20 | $3.70 | $3.90 |
Plan Assets [Roll Forward] | ' | ' | ' |
Plan assets at fair value, beginning of period [Roll Forward] | 295.7 | ' | ' |
Fair value of plan assets, end of period | 323.9 | 295.7 | ' |
Fair Value of guaranteed annuity contract [Roll Forward] | ' | ' | ' |
Guaranteed Annuity Contract - estimate of undiscounted funds necessary to satisfy John Hancock's remaining obligation | 3.7 | 3.6 | ' |
Guaranteed Annuity Contract - percent of composite investment return, net of manger fees and other charges (in hundredths) | 4.75% | 5.17% | ' |
Fair value, beginning of year | 3.9 | 3.8 | ' |
Unrealized gains related to investments still held at reporting date | 0.2 | 0.2 | ' |
Purchases, sales and settlements, net | 0 | -0.1 | ' |
Fair value, end of year | 4.1 | 3.9 | ' |
Qualified Plans | ' | ' | ' |
Fair value of plan assets, end of period | 323.9 | 295.7 | ' |
Payments expected to be made to SERP participants in the next fiscal year | 1 | ' | ' |
Reconciliation of amounts in Accumulated other comprehensive income and Regulatory assets | ' | ' | ' |
Less: Regulatory asset deferral | 193.4 | 252.7 | ' |
Multiemployer Benefit Plan [Abstract] | ' | ' | ' |
Number of unions the Company contributed to on behalf of employees | 270 | ' | ' |
Average contributions to each union | '.2 | ' | ' |
Largest union multiemployer plan contribution | 4 | ' | ' |
Expense for the Multiemployer Benefit plan | 33.2 | 27.6 | 18.3 |
Description of Multiemployer Plan | 'Multiple unions can contribute to a single multi-employer plan.  The Company made contributions to at least 36 plans in 2012, 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. Further, of the 36 plans identified, there are four plans that are less than 65 percent funded (i.e. red zone status) and two plans where the Company's contributions represent more than 5 percent of the total contributions received by the plan; however, none of these plans are significant to the Company. The most recent Pension Protection Act Zone Status available in 2012 and 2011 is for the plan year end at December 31, 2011 and 2010, 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. | ' | ' |
Defined Contribution Plan [Abstract] | ' | ' | ' |
Contributions to Defined Contribution Plan | 7.5 | 6.7 | 6.2 |
Central Pension Fund [Member] | ' | ' | ' |
Multiemployer Benefit Plan [Abstract] | ' | ' | ' |
Expense for the Multiemployer Benefit plan | 8.5 | 4 | 2.3 |
Pipeline Industry Benefit Fund [Member] | ' | ' | ' |
Multiemployer Benefit Plan [Abstract] | ' | ' | ' |
Expense for the Multiemployer Benefit plan | 5.3 | 3.9 | 1 |
Indiana Laborers Pension Fund [Member] | ' | ' | ' |
Multiemployer Benefit Plan [Abstract] | ' | ' | ' |
Expense for the Multiemployer Benefit plan | 2.4 | 3.2 | 1.6 |
Minnesota Laborers Pension Fund [Member] | ' | ' | ' |
Multiemployer Benefit Plan [Abstract] | ' | ' | ' |
Expense for the Multiemployer Benefit plan | 2.8 | 2 | 0.7 |
Other Pension Funds [Member] | ' | ' | ' |
Multiemployer Benefit Plan [Abstract] | ' | ' | ' |
Expense for the Multiemployer Benefit plan | 14.2 | 14.5 | 12.7 |
Domestic equities and equity funds [Member] | ' | ' | ' |
Plan Assets [Roll Forward] | ' | ' | ' |
Fair value of plan assets, end of period | 155.2 | 140.4 | ' |
Qualified Plans | ' | ' | ' |
Fair value of plan assets, end of period | 155.2 | 140.4 | ' |
International equities and equity funds [Member] | ' | ' | ' |
Plan Assets [Roll Forward] | ' | ' | ' |
Fair value of plan assets, end of period | 41.9 | 34.3 | ' |
Qualified Plans | ' | ' | ' |
Fair value of plan assets, end of period | 41.9 | 34.3 | ' |
Domestic bonds and bond funds [Member] | ' | ' | ' |
Plan Assets [Roll Forward] | ' | ' | ' |
Fair value of plan assets, end of period | 95.8 | 84 | ' |
Qualified Plans | ' | ' | ' |
Fair value of plan assets, end of period | 95.8 | 84 | ' |
Inflation protected security fund [Member] | ' | ' | ' |
Plan Assets [Roll Forward] | ' | ' | ' |
Fair value of plan assets, end of period | 12.1 | 12.6 | ' |
Qualified Plans | ' | ' | ' |
Fair value of plan assets, end of period | 12.1 | 12.6 | ' |
Real estate, commodities and other [Member] | ' | ' | ' |
Plan Assets [Roll Forward] | ' | ' | ' |
Fair value of plan assets, end of period | 18.9 | 24.4 | ' |
Qualified Plans | ' | ' | ' |
Fair value of plan assets, end of period | 18.9 | 24.4 | ' |
Fair Value, Inputs, Level 1 [Member] | ' | ' | ' |
Plan Assets [Roll Forward] | ' | ' | ' |
Fair value of plan assets, end of period | 158.1 | 146.8 | ' |
Qualified Plans | ' | ' | ' |
Fair value of plan assets, end of period | 158.1 | 146.8 | ' |
Fair Value, Inputs, Level 1 [Member] | Domestic equities and equity funds [Member] | ' | ' | ' |
Plan Assets [Roll Forward] | ' | ' | ' |
Fair value of plan assets, end of period | 69.6 | 62.8 | ' |
Qualified Plans | ' | ' | ' |
Fair value of plan assets, end of period | 69.6 | 62.8 | ' |
Fair Value, Inputs, Level 1 [Member] | International equities and equity funds [Member] | ' | ' | ' |
Plan Assets [Roll Forward] | ' | ' | ' |
Fair value of plan assets, end of period | 41.9 | 34.3 | ' |
Qualified Plans | ' | ' | ' |
Fair value of plan assets, end of period | 41.9 | 34.3 | ' |
Fair Value, Inputs, Level 1 [Member] | Domestic bonds and bond funds [Member] | ' | ' | ' |
Plan Assets [Roll Forward] | ' | ' | ' |
Fair value of plan assets, end of period | 40.4 | 41.7 | ' |
Qualified Plans | ' | ' | ' |
Fair value of plan assets, end of period | 40.4 | 41.7 | ' |
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 | 6.2 | 8 | ' |
Qualified Plans | ' | ' | ' |
Fair value of plan assets, end of period | 6.2 | 8 | ' |
Fair Value, Inputs, Level 2 [Member] | ' | ' | ' |
Plan Assets [Roll Forward] | ' | ' | ' |
Fair value of plan assets, end of period | 161.7 | 145 | ' |
Common Collective Trust Funds [Abstract] | ' | ' | ' |
Portion of Common Collective Trust Funds comprised of equity funds (in hundredths) | 53.00% | 53.00% | ' |
Portion of Common Collective Trust Funds comprised of fixed income funds (in hundredths) | 42.00% | 38.00% | ' |
Fair value of Common Collective Trust Funds | 161.7 | 145 | ' |
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 | 161.7 | 145 | ' |
Fair Value, Inputs, Level 2 [Member] | Domestic equities and equity funds [Member] | ' | ' | ' |
Plan Assets [Roll Forward] | ' | ' | ' |
Fair value of plan assets, end of period | 85.6 | 77.6 | ' |
Qualified Plans | ' | ' | ' |
Fair value of plan assets, end of period | 85.6 | 77.6 | ' |
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 | 55.4 | 42.3 | ' |
Qualified Plans | ' | ' | ' |
Fair value of plan assets, end of period | 55.4 | 42.3 | ' |
Fair Value, Inputs, Level 2 [Member] | Inflation protected security fund [Member] | ' | ' | ' |
Plan Assets [Roll Forward] | ' | ' | ' |
Fair value of plan assets, end of period | 12.1 | 12.6 | ' |
Qualified Plans | ' | ' | ' |
Fair value of plan assets, end of period | 12.1 | 12.6 | ' |
Fair Value, Inputs, Level 2 [Member] | Real estate, commodities and other [Member] | ' | ' | ' |
Plan Assets [Roll Forward] | ' | ' | ' |
Fair value of plan assets, end of period | 8.6 | 12.5 | ' |
Qualified Plans | ' | ' | ' |
Fair value of plan assets, end of period | 8.6 | 12.5 | ' |
Fair Value, Inputs, Level 3 [Member] | ' | ' | ' |
Plan Assets [Roll Forward] | ' | ' | ' |
Fair value of plan assets, end of period | 4.1 | 3.9 | ' |
Qualified Plans | ' | ' | ' |
Fair value of plan assets, end of period | 4.1 | 3.9 | ' |
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 | 4.1 | 3.9 | ' |
Qualified Plans | ' | ' | ' |
Fair value of plan assets, end of period | 4.1 | 3.9 | ' |
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 | 8.6 | 7.7 | 6.9 |
Interest cost | 14.7 | 15.5 | 15.9 |
Expected return on plan assets | -22.1 | -21.2 | -21.2 |
Amortization of prior service cost (benefit) | 1.5 | 1.6 | 1.7 |
Amortization of actuarial loss (gain) | 10.1 | 6.8 | 3.8 |
Amortization of transitional obligation | 0 | 0 | 0 |
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Settlements | -1.3 | 0 | 0 |
Net periodic benefit cost | 14.1 | 10.4 | 7.1 |
Discount Rate (in hundredths) | 4.03% | 4.82% | 5.50% |
Rate of compensation increase (in hundredths) | 3.50% | 3.50% | 3.50% |
Expected return on plan assets (in hundredths) | 7.75% | 7.75% | 8.00% |
Assumptions used to calculate benefit obligations [Abstract] | ' | ' | ' |
Discount rate (in hundredths) | 4.74% | 4.03% | ' |
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 | 377.3 | 329.2 | ' |
Service cost - benefits earned during the period | 8.6 | 7.7 | 6.9 |
Interest cost on projected benefit obligation | 14.7 | 15.5 | 15.9 |
Plan participants' contributions | 0 | 0 | ' |
Plan amendments | 0 | 0.7 | ' |
Actuarial loss (gain) | -32.7 | 39 | ' |
Defined Benefit Plan Settlement Loss (Gain) Benefit Obligation | 1.5 | 0 | ' |
Medicare subsidy receipts | 0 | 0 | ' |
Benefit payments | -22.8 | -14.8 | ' |
Defined Benefit Plan, Settlements, Benefit Obligation | -8.2 | 0 | ' |
Benefit obligation, end of period | 338.4 | 377.3 | 329.2 |
Accumulated benefit obligation for all defined benefit pension plans | 321.9 | 354.5 | ' |
Plan Assets [Roll Forward] | ' | ' | ' |
Plan assets at fair value, beginning of period [Roll Forward] | 295.7 | 261 | ' |
Actual return on plan assets | 48.4 | 33.8 | ' |
Employer contributions | 10.8 | 15.7 | ' |
Plan participants' contributions | 0 | 0 | ' |
Benefit payments | -22.8 | -14.8 | ' |
Settlement payments | -8.2 | 0 | ' |
Fair value of plan assets, end of period | 323.9 | 295.7 | 261 |
Qualified Plans | ' | ' | ' |
Benefit obligation, end of period | -321 | -360 | ' |
Fair value of plan assets, end of period | 323.9 | 295.7 | 261 |
Funded Status of Qualified Plans, end of period | 2.9 | -64.3 | ' |
Benefit obligation of SERP Plan, end of period | -17.5 | -17.3 | ' |
Total funded status, end of period | -14.6 | -81.6 | ' |
Accrued liabilities | 1 | 1 | ' |
Deferred credits and other liabilities | 20.1 | 80.6 | ' |
Other Assets | 6.5 | 0 | ' |
Contributions expected to be made to pension plan trusts in the next fiscal year | 0 | ' | ' |
Estimated future benefit payments [Abstract] | ' | ' | ' |
Expected future benefit payments, year one | 23.7 | ' | ' |
Expected future benefit payments, year two | 23.6 | ' | ' |
Expected future benefit payments, year three | 24.6 | ' | ' |
Expected future benefit payments, year four | 34.3 | ' | ' |
Expected future benefit payments, year five | 25.5 | ' | ' |
Expected future benefit payments, years six through ten | 140.4 | ' | ' |
Prior service costs [Roll Forward] | ' | ' | ' |
Balance, beginning of year | 4.5 | 5.4 | 7.1 |
Amounts arising during the period | 0 | 0.7 | 0 |
Reclassification to benefit costs | -1.5 | -1.6 | -1.7 |
Balance, end of year | 3 | 4.5 | 5.4 |
Net gain or loss [Roll Forward] | ' | ' | ' |
Balance, beginning of year | 136.2 | 116.6 | 78.2 |
Amounts arising during the period | -58.8 | 26.4 | 42.2 |
Reclassification to benefit costs | -10.1 | -6.8 | -3.8 |
Balance, end of year | 67.3 | 136.2 | 116.6 |
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 | 3 | 4.5 | 5.4 |
Unamortized actuarial gain/(loss) | 67.3 | 136.2 | 116.6 |
Transition obligation | 0 | 0 | ' |
Sub total | 70.3 | 140.7 | ' |
Less: Regulatory asset deferral | -68.9 | -137.9 | ' |
AOCI before taxes | 1.4 | 2.8 | ' |
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 | 1.1 | ' | ' |
Actuarial gain/loss expected to be amortized in next year | 4.7 | ' | ' |
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 | 0.5 | 0.5 | 0.5 |
Interest cost | 2 | 2.8 | 4.3 |
Expected return on plan assets | 0 | 0 | 0 |
Amortization of prior service cost (benefit) | -3.2 | -2.5 | -0.8 |
Amortization of actuarial loss (gain) | 0.7 | 0.7 | 0.6 |
Amortization of transitional obligation | 0 | 0.5 | 1.1 |
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Settlements | 0 | 0 | 0 |
Net periodic benefit cost | 0 | 2 | 5.7 |
Discount Rate (in hundredths) | 3.91% | 4.75% | 5.50% |
Expected return on plan assets (in hundredths) | ' | ' | 8.00% |
Expected increase in Consumer Price Index (in hundredths) | 2.75% | 2.75% | 3.00% |
Assumptions used to calculate benefit obligations [Abstract] | ' | ' | ' |
Discount rate (in hundredths) | 4.66% | 3.91% | ' |
Expected increase in Consumer Price Index (in hundredths) | 2.75% | 2.75% | ' |
Benefit Obligation [Roll Forward] | ' | ' | ' |
Benefit obligation, beginning of period | 54.4 | 79.7 | ' |
Service cost - benefits earned during the period | 0.5 | 0.5 | 0.5 |
Interest cost on projected benefit obligation | 2 | 2.8 | 4.3 |
Plan participants' contributions | 0.8 | 1.6 | ' |
Plan amendments | -0.2 | -26.6 | ' |
Actuarial loss (gain) | -2.4 | 2.8 | ' |
Defined Benefit Plan Settlement Loss (Gain) Benefit Obligation | 0 | 0 | ' |
Medicare subsidy receipts | 0 | 0.5 | ' |
Benefit payments | -3.8 | -6.9 | ' |
Defined Benefit Plan, Settlements, Benefit Obligation | 0 | 0 | ' |
Benefit obligation, end of period | 51.3 | 54.4 | 79.7 |
Assumption of percentage increase in medical claims cost for next fiscal year (in hundredths) | 7.00% | ' | ' |
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 | 0.4 | ' | ' |
Decrease in recorded liability from remeasurement | 23 | ' | ' |
Discount rate for remeasurement | 3.93% | ' | ' |
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 | 5.3 | ' |
Plan participants' contributions | 0.8 | 1.6 | ' |
Benefit payments | -3.8 | -6.9 | ' |
Settlement payments | 0 | 0 | ' |
Fair value of plan assets, end of period | 0 | 0 | 0 |
Qualified Plans | ' | ' | ' |
Benefit obligation, end of period | -51.4 | -54.4 | ' |
Fair value of plan assets, end of period | 0 | 0 | 0 |
Funded Status of Qualified Plans, end of period | -51.4 | -54.4 | ' |
Benefit obligation of SERP Plan, end of period | 0 | 0 | ' |
Total funded status, end of period | -51.4 | -54.4 | ' |
Accrued liabilities | 4.9 | 4.5 | ' |
Deferred credits and other liabilities | 46.4 | 49.9 | ' |
Other Assets | 0 | 0 | ' |
Other postretirement benefit payments to be made during the next fiscal year | 3.7 | ' | ' |
Estimated future benefit payments [Abstract] | ' | ' | ' |
Expected future benefit payments, year one | 4.9 | ' | ' |
Expected future benefit payments, year two | 5 | ' | ' |
Expected future benefit payments, year three | 5.2 | ' | ' |
Expected future benefit payments, year four | 5.5 | ' | ' |
Expected future benefit payments, year five | 5.9 | ' | ' |
Expected future benefit payments, years six through ten | 31.9 | ' | ' |
Prior service costs [Roll Forward] | ' | ' | ' |
Balance, beginning of year | -23.1 | -1.2 | -2 |
Amounts arising during the period | -0.2 | -24.4 | 0 |
Reclassification to benefit costs | 3.2 | 2.5 | 0.8 |
Balance, end of year | -20.1 | -23.1 | -1.2 |
Net gain or loss [Roll Forward] | ' | ' | ' |
Balance, beginning of year | 11.2 | 9.1 | 10.3 |
Amounts arising during the period | -2.4 | 2.8 | -0.6 |
Reclassification to benefit costs | -0.7 | -0.7 | -0.6 |
Balance, end of year | 8.1 | 11.2 | 9.1 |
Transition obligation [Roll Forward] | ' | ' | ' |
Balance, beginning of year | 0 | 2.7 | 3.8 |
Amounts arising during the period | 0 | -2.2 | 0 |
Reclassification to benefit costs | 0 | -0.5 | -1.1 |
Balance, end of year | 0 | 0 | 2.7 |
Reconciliation of amounts in Accumulated other comprehensive income and Regulatory assets | ' | ' | ' |
Prior service cost | -20.1 | -23.1 | -1.2 |
Unamortized actuarial gain/(loss) | 8.1 | 11.2 | 9.1 |
Transition obligation | 0 | 0 | 2.7 |
Sub total | -12 | -11.9 | ' |
Less: Regulatory asset deferral | 11.8 | 11.7 | ' |
AOCI before taxes | -0.2 | -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 | $0.40 | ' | ' |
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 | 'sixty | ' | ' |
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 whereby company contributions exceed 5% of plan balance | 3 | ' | ' |
Percentage threshold by which plan contributions are considered significant | 5.00% | ' | ' |
Borrowing_Arrangements_Details
Borrowing Arrangements (Details) (USD $) | 12 Months Ended | 12 Months Ended | 12 Months Ended | 12 Months Ended | 12 Months Ended | 12 Months Ended | 12 Months Ended | 12 Months Ended | 12 Months Ended | 12 Months Ended | 12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | |
Fixed Rate Senior Unsecured Notes [Member] | Other Long Term Notes Payable [Member] | Other Long Term Notes Payable [Member] | Utility Holdings [Member] | Utility Holdings [Member] | Utility Holdings [Member] | Utility Holdings [Member] | Utility Holdings [Member] | Utility Holdings [Member] | Utility Holdings [Member] | Utility Holdings [Member] | Utility Holdings [Member] | Utility Holdings [Member] | Utility Holdings [Member] | Utility Holdings [Member] | Utility Holdings [Member] | Utility Holdings [Member] | Utility Holdings [Member] | Utility Holdings [Member] | Utility Holdings [Member] | Utility Holdings [Member] | Utility Holdings [Member] | Utility Holdings [Member] | Utility Holdings [Member] | Utility Holdings [Member] | Utility Holdings [Member] | Utility Holdings [Member] | Utility Holdings [Member] | Utility Holdings [Member] | Utility Holdings [Member] | Utility Holdings [Member] | Utility Holdings [Member] | Utility Holdings [Member] | Utility Holdings [Member] | Utility Holdings [Member] | Utility Holdings [Member] | Utility Holdings [Member] | Utility Holdings [Member] | Indiana Gas [Member] | Indiana Gas [Member] | Indiana Gas [Member] | Indiana Gas [Member] | Indiana Gas [Member] | Indiana Gas [Member] | Indiana Gas [Member] | Indiana Gas [Member] | Indiana Gas [Member] | Indiana Gas [Member] | Indiana Gas [Member] | Indiana Gas [Member] | Indiana Gas [Member] | Indiana Gas [Member] | Indiana Gas [Member] | Indiana Gas [Member] | Indiana Gas [Member] | Indiana Gas [Member] | Indiana Gas [Member] | Indiana Gas [Member] | Indiana Gas [Member] | Indiana Gas [Member] | Indiana Gas [Member] | Indiana Gas [Member] | SIGECO [Member] | SIGECO [Member] | SIGECO [Member] | SIGECO [Member] | SIGECO [Member] | SIGECO [Member] | SIGECO [Member] | SIGECO [Member] | SIGECO [Member] | SIGECO [Member] | SIGECO [Member] | SIGECO [Member] | SIGECO [Member] | SIGECO [Member] | SIGECO [Member] | SIGECO [Member] | SIGECO [Member] | SIGECO [Member] | SIGECO [Member] | SIGECO [Member] | SIGECO [Member] | SIGECO [Member] | SIGECO [Member] | SIGECO [Member] | SIGECO [Member] | SIGECO [Member] | SIGECO [Member] | SIGECO [Member] | SIGECO [Member] | SIGECO [Member] | SIGECO [Member] | SIGECO [Member] | SIGECO [Member] | SIGECO [Member] | SIGECO [Member] | SIGECO [Member] | SIGECO [Member] | SIGECO [Member] | Vectren Capital Corp. [Member] | Vectren Capital Corp. [Member] | Vectren Capital Corp. [Member] | Vectren Capital Corp. [Member] | Vectren Capital Corp. [Member] | Vectren Capital Corp. [Member] | Vectren Capital Corp. [Member] | Vectren Capital Corp. [Member] | Vectren Capital Corp. [Member] | Vectren Capital Corp. [Member] | Vectren Capital Corp. [Member] | Vectren Capital Corp. [Member] | Vectren Capital Corp. [Member] | Vectren Capital Corp. [Member] | Vectren Capital Corp. [Member] | Vectren Capital Corp. [Member] | Vectren Capital Corp. [Member] | Vectren Capital Corp. [Member] | Vectren Capital Corp. [Member] | Vectren Utility Holdings Inc [Member] | Vectren Utility Holdings Inc [Member] | Vectren Utility Holdings Inc [Member] | Vectren Utility Holdings Inc [Member] | |||
2042, 5.00% [Member] | Fixed Rate Senior Unsecured Notes [Member] | Fixed Rate Senior Unsecured Notes [Member] | Fixed Rate Senior Unsecured Notes [Member] | Fixed Rate Senior Unsecured Notes [Member] | Fixed Rate Senior Unsecured Notes [Member] | Fixed Rate Senior Unsecured Notes [Member] | Fixed Rate Senior Unsecured Notes [Member] | Fixed Rate Senior Unsecured Notes [Member] | Fixed Rate Senior Unsecured Notes [Member] | Fixed Rate Senior Unsecured Notes [Member] | Fixed Rate Senior Unsecured Notes [Member] | Fixed Rate Senior Unsecured Notes [Member] | Fixed Rate Senior Unsecured Notes [Member] | Fixed Rate Senior Unsecured Notes [Member] | Fixed Rate Senior Unsecured Notes [Member] | Fixed Rate Senior Unsecured Notes [Member] | Fixed Rate Senior Unsecured Notes [Member] | Fixed Rate Senior Unsecured Notes [Member] | Fixed Rate Senior Unsecured Notes [Member] | Fixed Rate Senior Unsecured Notes [Member] | Fixed Rate Senior Unsecured Notes [Member] | Fixed Rate Senior Unsecured Notes [Member] | Fixed Rate Senior Unsecured Notes [Member] | Fixed Rate Senior Unsecured Notes [Member] | Fixed Rate Senior Unsecured Notes [Member] | Fixed Rate Senior Unsecured Notes [Member] | Fixed Rate Senior Unsecured Notes [Member] | Fixed Rate Senior Unsecured Notes [Member] | Fixed Rate Senior Unsecured Notes [Member] | Fixed Rate Senior Unsecured Notes [Member] | Fixed Rate Senior Unsecured Notes [Member] | Fixed Rate Senior Unsecured Notes [Member] | Senior Guaranteed Notes [Member] | Senior Guaranteed Notes [Member] | Fixed Rate Senior Unsecured Notes [Member] | Fixed Rate Senior Unsecured Notes [Member] | Fixed Rate Senior Unsecured Notes [Member] | Fixed Rate Senior Unsecured Notes [Member] | Fixed Rate Senior Unsecured Notes [Member] | Fixed Rate Senior Unsecured Notes [Member] | Fixed Rate Senior Unsecured Notes [Member] | Fixed Rate Senior Unsecured Notes [Member] | Fixed Rate Senior Unsecured Notes [Member] | Fixed Rate Senior Unsecured Notes [Member] | Fixed Rate Senior Unsecured Notes [Member] | Fixed Rate Senior Unsecured Notes [Member] | Fixed Rate Senior Unsecured Notes [Member] | Fixed Rate Senior Unsecured Notes [Member] | Fixed Rate Senior Unsecured Notes [Member] | Fixed Rate Senior Unsecured Notes [Member] | Fixed Rate Senior Unsecured Notes [Member] | Fixed Rate Senior Unsecured Notes [Member] | Fixed Rate Senior Unsecured Notes [Member] | Fixed Rate Senior Unsecured Notes [Member] | Fixed Rate Senior Unsecured Notes [Member] | Fixed Rate Senior Unsecured Notes [Member] | Fixed Rate Senior Unsecured Notes [Member] | Fixed Rate Senior Unsecured Notes [Member] | First Mortgage Bonds [Member] | First Mortgage Bonds [Member] | First Mortgage Bonds [Member] | First Mortgage Bonds [Member] | Mortgages [Member] | Mortgages [Member] | Mortgages [Member] | Mortgages [Member] | Mortgages [Member] | Mortgages [Member] | Mortgages [Member] | Mortgages [Member] | Mortgages [Member] | Mortgages [Member] | Mortgages [Member] | Mortgages [Member] | Mortgages [Member] | Mortgages [Member] | Mortgages [Member] | Mortgages [Member] | Mortgages [Member] | Mortgages [Member] | Mortgages [Member] | Mortgages [Member] | Mortgages [Member] | Mortgages [Member] | Mortgages [Member] | Mortgages [Member] | Mortgages [Member] | Mortgages [Member] | Mortgages [Member] | Mortgages [Member] | Mortgages [Member] | Mortgages [Member] | Mortgages [Member] | Mortgages [Member] | Mortgages [Member] | Mortgages [Member] | Fixed Rate Senior Unsecured Notes [Member] | Fixed Rate Senior Unsecured Notes [Member] | Fixed Rate Senior Unsecured Notes [Member] | Fixed Rate Senior Unsecured Notes [Member] | Fixed Rate Senior Unsecured Notes [Member] | Fixed Rate Senior Unsecured Notes [Member] | Fixed Rate Senior Unsecured Notes [Member] | Fixed Rate Senior Unsecured Notes [Member] | Fixed Rate Senior Unsecured Notes [Member] | Fixed Rate Senior Unsecured Notes [Member] | Fixed Rate Senior Unsecured Notes [Member] | Fixed Rate Senior Unsecured Notes [Member] | Fixed Rate Senior Unsecured Notes [Member] | Fixed Rate Senior Unsecured Notes [Member] | Variable Rate Term Loan [Member] | Variable Rate Term Loan [Member] | Variable Rate Term Loan [Member] | Variable Rate Term Loan [Member] | Fixed Rate Senior Unsecured Notes [Member] | Fixed Rate Senior Unsecured Notes [Member] | Fixed Rate Senior Unsecured Notes [Member] | Fixed Rate Senior Unsecured Notes [Member] | |||||||
2013, 5.25% [Member] | 2013, 5.25% [Member] | 2015, 5.45% [Member] | 2015, 5.45% [Member] | 2018, 5.75% [Member] | 2018, 5.75% [Member] | 2020, 6.28% [Member] | 2020, 6.28% [Member] | 2021, 4.67 [Member] | 2021, 4.67 [Member] | 2021, 4.67 [Member] | 2023, 3.72% [Member] | 2023, 3.72% [Member] | 2026, 5.02% [Member] | 2026, 5.02% [Member] | 2026, 5.02% [Member] | 2028, 3.20% [Member] | 2028, 3.20% [Member] | 2035, 6.10% [Member] | 2035, 6.10% [Member] | 2039, 6.25% [Member] | 2039, 6.25% [Member] | 2041, 5.99% [Member] | 2041, 5.99% [Member] | 2041, 5.99% [Member] | 2042, 5.00% [Member] | 2042, 5.00% [Member] | 2036, 5.95% [Member] | 2043, 4.25% [Member] | 2043, 4.25% [Member] | 2028, 3.20% [Member] | 2043, 4.25% [Member] | 2013, Series E, 6.69% [Member] | 2013, Series E, 6.69% [Member] | 2015, Series E, 7.15% [Member] | 2015, Series E, 7.15% [Member] | 2015, Series E1, 6.69% [Member] | 2015, Series E1, 6.69% [Member] | 2015, Series E, 6.69% [Member] | 2015, Series E, 6.69% [Member] | 2025, Series E, 6.53% [Member] | 2025, Series E, 6.53% [Member] | 2027, Series E, 6.42% [Member] | 2027, Series E, 6.42% [Member] | 2027, Series E, 6.68% [Member] | 2027, Series E, 6.68% [Member] | 2027, Series F, 6.34% [Member] | 2027, Series F, 6.34% [Member] | 2028, Series F, 6.36% [Member] | 2028, Series F, 6.36% [Member] | 2028, Series F, 6.55% [Member] | 2028, Series F, 6.55% [Member] | 2029, Series G, 7.08% [Member] | 2029, Series G, 7.08% [Member] | Tax Exempt Debt, 4.00 percent, due 2038 [Member] | Tax Exempt Debt, 4.05 percent, due 2043 [Member] | Tax Exempt Debt, 1.95 Percent [Member] | 2015, 1985 Pollution Control Series A, current adjustable rate 0.15%, tax exempt, 2012 weighted average: 0.17% | 2015, 1985 Pollution Control Series A, current adjustable rate 0.15%, tax exempt, 2012 weighted average: 0.17% | 2016, 1986 Series, 8.875% [Member] | 2016, 1986 Series, 8.875% [Member] | 2020, 1998 Pollution Control Series B, 4.50%, tax exempt [Member] | 2020, 1998 Pollution Control Series B, 4.50%, tax exempt [Member] | 2022, 2013 Series C, 1.95% tax exempt [Member] | 2022, 2013 Series C, 1.95% tax exempt [Member] | 2023, 1993 Environmental Improvement Series B, 5.15%, tax exempt [Member] | 2023, 1993 Environmental Improvement Series B, 5.15%, tax exempt [Member] | 2024, 2000 Environmental Improvement Series A, 4.65%, tax exempt [Member] | 2024, 2000 Environmental Improvement Series A, 4.65%, tax exempt [Member] | 2024, 2013 Series D, 1.95% tax exempt [Member] | 2024, 2013 Series D, 1.95% tax exempt [Member] | 2025, 1998 Pollution Control Series A, current adjustable rate 0.15%, tax exempt, 2012 weighted average: 0.16% | 2025, 1998 Pollution Control Series A, current adjustable rate 0.15%, tax exempt, 2012 weighted average: 0.16% | 2029, 1999 Senior Notes, 6.72% [Member] | 2029, 1999 Senior Notes, 6.72% [Member] | 2030, 1998 Pollution Control Series B, 5.00%, tax exempt [Member] | 2030, 1998 Pollution Control Series B, 5.00%, tax exempt [Member] | 2037, 2013 Series E 1.95% Tax Exempt [Member] | 2037, 2013 Series E 1.95% Tax Exempt [Member] | 2038, 2013 Series A, 4.00% Tax Exempt [Member] | 2038, 2013 Series A, 4.00% Tax Exempt [Member] | 2030, 1998 Pollution Control Series C, 5.35%, tax exempt [Member] | 2030, 1998 Pollution Control Series C, 5.35%, tax exempt [Member] | 2040, 2009 Environmental Improvement Series, 5.40%, tax exempt [Member] | 2040, 2009 Environmental Improvement Series, 5.40%, tax exempt [Member] | 2041, 2007 Pollution Control Series, 5.45%, tax exempt [Member] | 2041, 2007 Pollution Control Series, 5.45%, tax exempt [Member] | 2043, 2013 Series B 4.05% Tax Exempt [Member] | 2043, 2013 Series B 4.05% Tax Exempt [Member] | 2014, 6.37% [Member] | 2014, 6.37% [Member] | 2015, 5.31% [Member] | 2015, 5.31% [Member] | 2016, 6.92% [Member] | 2016, 6.92% [Member] | 2017, 3.48% [Member] | 2017, 3.48% [Member] | 2019, 7.30% [Member] | 2019, 7.30% [Member] | 2025, 4.53% [Member] | 2025, 4.53% [Member] | 2015 Adjustable Rate 117 Term Loan [Member] [Member] | 2015 Adjustable Rate 117 Term Loan [Member] [Member] | 2016 Term Loan [Member] | 2016 Term Loan [Member] | 2043, 4.25% [Member] | 2028, 3.20% [Member] | 2023, 3.72% [Member] | 2039, 6.25% [Member] | |||||||||||||||||
Long term debt [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Debt Issuance | ' | ' | $100,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $55,000,000 | ' | ' | ' | ' | $60,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | $35,000,000 | ' | ' | ' | ' | ' | ' | ' | $45,000,000 | $80,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $62,000,000 | $22,200,000 | $39,600,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $80,000,000 | $45,000,000 | $150,000,000 | $121,600,000 |
Proceeds from debt issuance | ' | ' | 99,500,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 149,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 60,000,000 | ' | ' | 48,300,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 100,000,000 | ' | 100,000,000 | ' | 79,600,000 | 44,800,000 | 149,100,000 | ' |
Fixed rate stated percentage (in hundredths) | ' | ' | 5.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 4.67% | ' | ' | ' | ' | 5.02% | ' | ' | ' | ' | ' | ' | ' | ' | 5.99% | ' | ' | ' | ' | 5.95% | ' | ' | 3.20% | 4.25% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 4.00% | 4.05% | 1.95% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 4.25% | 3.20% | 3.72% | 6.25% |
Maturity date | ' | ' | 3-Feb-42 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 30-Nov-21 | ' | ' | ' | ' | 30-Nov-26 | ' | ' | ' | ' | ' | ' | ' | ' | 2-Dec-41 | ' | ' | ' | ' | 31-Dec-36 | ' | ' | 5-Jun-28 | 5-Jun-43 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 31-Dec-38 | 31-Dec-43 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 5-Jun-43 | 5-Jun-28 | 5-Dec-23 | ' |
Debt Instrument Maturity Date Year | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '2039 |
Debt Instrument, Offering Date | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 22-Aug-13 | ' |
Debt Instrument Issuance Date | ' | ' | 1-Feb-12 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 30-Nov-11 | ' | ' | ' | ' | 30-Nov-11 | ' | ' | ' | ' | ' | ' | ' | ' | 30-Nov-11 | ' | ' | ' | ' | ' | ' | ' | 5-Jun-13 | 5-Jun-13 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 26-Apr-13 | 26-Apr-13 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 5-Jun-13 | 5-Jun-13 | 5-Dec-13 | ' |
Total long term debt outstanding | 1,808,500,000 | 1,661,500,000 | ' | 0 | 1,400,000 | ' | 875,000,000 | 821,600,000 | 0 | 100,000,000 | 75,000,000 | 75,000,000 | 100,000,000 | 100,000,000 | 100,000,000 | 100,000,000 | ' | 55,000,000 | 55,000,000 | 150,000,000 | 0 | ' | 60,000,000 | 60,000,000 | 45,000,000 | 0 | 75,000,000 | 75,000,000 | 0 | 121,600,000 | ' | 35,000,000 | 35,000,000 | 100,000,000 | 100,000,000 | 96,200,000 | 80,000,000 | 0 | ' | ' | 116,000,000 | 121,000,000 | 0 | 5,000,000 | 5,000,000 | 5,000,000 | 10,000,000 | 10,000,000 | 5,000,000 | 5,000,000 | 10,000,000 | 10,000,000 | 5,000,000 | 5,000,000 | 1,000,000 | 1,000,000 | 20,000,000 | 20,000,000 | 10,000,000 | 10,000,000 | 20,000,000 | 20,000,000 | 30,000,000 | 30,000,000 | ' | ' | ' | ' | 267,500,000 | 267,500,000 | 9,800,000 | 9,800,000 | 13,000,000 | 13,000,000 | 0 | 4,600,000 | 4,600,000 | 0 | 0 | 22,600,000 | 0 | 22,500,000 | 22,500,000 | 0 | 31,500,000 | 31,500,000 | 80,000,000 | 80,000,000 | 0 | 22,000,000 | 22,000,000 | 0 | 22,200,000 | 0 | 0 | 22,200,000 | 22,300,000 | 22,300,000 | 0 | 17,000,000 | 39,600,000 | 0 | ' | 550,000,000 | 450,000,000 | 30,000,000 | 30,000,000 | 75,000,000 | 75,000,000 | 60,000,000 | 60,000,000 | 75,000,000 | 75,000,000 | 60,000,000 | 60,000,000 | 50,000,000 | 50,000,000 | 100,000,000 | 100,000,000 | 100,000,000 | 0 | ' | ' | ' | ' |
Current maturities of long-term debt | -30,000,000 | -106,400,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -121,600,000 |
Unamortized debt premium and discount - net | -1,400,000 | -1,700,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Long-term debt - net of current maturities and debt subject to tender | 1,777,100,000 | 1,553,400,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Debt redemption date | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1-Apr-13 |
Amount of debt to be re-marketed | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 49,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Debt re-market date | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 'August 13, 2013 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Debt Instrument Put And Call Exercise Date | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 21-Nov-11 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Letters of Credit Outstanding, Amount | 41,700,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Future long term debt sinking fund fund requirements and maturities [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Annual sinking fund requirement fixed percentage (in hundredths) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Utility plant remaining unfunded under mortgage indenture | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,200,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Gross utility plant balance subject to the mortgage indenture | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,900,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Maturities of long term debt [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Debt maturing within 12 months following date of latest balance sheet | 30,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Debt maturing within two years following date of latest balance sheet | 279,800,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Debt maturing within three years following date of latest balance sheet | 173,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Debt maturing within four years following date of latest balance sheet | 75,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Debt maturing within five years following date of latest balance sheet | 100,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Debt maturing thereafter 5 years following date of the latest balance sheet | 1,149,300,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Debt guarantees [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Long-term guarantees | ' | ' | ' | ' | ' | 875,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 550,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Short-term debt guarantees | ' | ' | ' | ' | ' | $29,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $40,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Covenants [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Ratio of consolidated total debt to consolidated total capitalization, maximum ( in hundredths) | 'not exceed 65 percent | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Borrowing_Arrangements_ShortTe
Borrowing Arrangements Short-Term Borrowings (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Short-term borrowings [Abstract] | ' | ' | ' |
Short-term borrowing capacity | $600 | ' | ' |
Short term credit facilities expiration date | 30-Sep-16 | ' | ' |
Balance Outstanding, end of period | 68.6 | 278.8 | ' |
Utility Group [Member] | ' | ' | ' |
Short-term borrowings [Abstract] | ' | ' | ' |
Short-term borrowing capacity | 350 | ' | ' |
Short term borrowings available | 321 | ' | ' |
Balance Outstanding, end of period | 28.6 | 116.7 | 242.8 |
Weighted Average Interest Rate, end of period (in hundredths) | 0.29% | 0.40% | 0.57% |
Balance Outstanding, annual average | 119.6 | 77.6 | 39.6 |
Weighted Average Interest Rate, annual average (in hundredths) | 0.34% | 0.47% | 0.48% |
Maximum Month End Balance Outstanding | 176.1 | 214.2 | 242.8 |
Nonutility Group [Member] | ' | ' | ' |
Short-term borrowings [Abstract] | ' | ' | ' |
Short-term borrowing capacity | 250 | ' | ' |
Short term borrowings available | 210 | ' | ' |
Balance Outstanding, end of period | 40 | 162.1 | 84.3 |
Weighted Average Interest Rate, end of period (in hundredths) | 1.27% | 1.35% | 1.45% |
Balance Outstanding, annual average | 119.3 | 151.5 | 124.9 |
Weighted Average Interest Rate, annual average (in hundredths) | 1.35% | 1.44% | 1.92% |
Maximum Month End Balance Outstanding | $173.80 | $216.10 | $180.10 |
Common_Shareholders_Equity_Det
Common Shareholder's Equity (Details) | Dec. 31, 2013 | Dec. 31, 2012 |
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) | 391.7 | 391.3 |
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) | 5.8 | 6.5 |
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, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2012 | Sep. 30, 2012 | Jun. 30, 2012 | Mar. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Earnings Per Share Reconciliation [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Numerator for basic earnings per share | ' | ' | ' | ' | ' | ' | ' | ' | $136.60 | $159 | $141.60 |
Earnings attributable to participating securities | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | 0 |
Reported net income (Numerator for diluted earnings per share) | ' | ' | ' | ' | ' | ' | ' | ' | $136.60 | $159 | $141.60 |
Weighted average common shares outstanding (Basic earnings per share) (in shares) | ' | ' | ' | ' | ' | ' | ' | ' | 82.3 | 82 | 81.8 |
Conversion of share based compensation arrangements | ' | ' | ' | ' | ' | ' | ' | ' | 0.1 | 0.1 | 0 |
Adjusted weighted average shares outstanding and assumed conversions outstanding (Diluted earnings per share) (in shares) | ' | ' | ' | ' | ' | ' | ' | ' | 82.4 | 82.1 | 81.8 |
Earnings Per Share, Basic | $0.60 | $0.52 | ($0.07) | $0.61 | $0.52 | $0.48 | $0.31 | $0.63 | $1.66 | $1.94 | $1.73 |
Earnings Per Share, Diluted | $0.60 | $0.52 | ($0.07) | $0.61 | $0.52 | $0.48 | $0.31 | $0.62 | $1.66 | $1.94 | $1.73 |
Accumulated_Other_Comprehensiv2
Accumulated Other Comprehensive Income (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Accumulated Other Comprehensive Income (Loss) [Line Items] | ' | ' | ' |
Balance, beginning of period | ($4.30) | ($13.30) | ($4.40) |
Changes during period | 3.6 | 9 | -8.9 |
Balance, end of period | -0.7 | -4.3 | -13.3 |
Unconsolidated Affiliates [Member] | ' | ' | ' |
Accumulated Other Comprehensive Income (Loss) [Line Items] | ' | ' | ' |
Balance, beginning of period | -4.6 | -15.9 | -6.6 |
Changes during period | 4.6 | 11.3 | -9.3 |
Balance, end of period | 0 | -4.6 | -15.9 |
Pension and Other Benefit Costs [Member] | ' | ' | ' |
Accumulated Other Comprehensive Income (Loss) [Line Items] | ' | ' | ' |
Balance, beginning of period | -2.6 | -6.6 | -4.9 |
Changes during period | 1.4 | 4 | -1.7 |
Balance, end of period | -1.2 | -2.6 | -6.6 |
Cash Flow Hedges [Member] | ' | ' | ' |
Accumulated Other Comprehensive Income (Loss) [Line Items] | ' | ' | ' |
Balance, beginning of period | 0 | 0.1 | 4 |
Changes during period | 0 | -0.1 | -3.9 |
Balance, end of period | 0 | 0 | 0.1 |
Deferred Income Taxes [Member] | ' | ' | ' |
Accumulated Other Comprehensive Income (Loss) [Line Items] | ' | ' | ' |
Balance, beginning of period | 2.9 | 9.1 | 3.1 |
Changes during period | -2.4 | -6.2 | 6 |
Balance, end of period | $0.50 | $2.90 | $9.10 |
ShareBased_Compensation_Deferr2
Share-Based Compensation & Deferred Compensation Arrangements (Details) (USD $) | 12 Months Ended | ||
In Millions, except Share data, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | ' | ' | ' |
Total cost of share-based compensation | $14.80 | $6.30 | $5.80 |
Less capitalized cost | 2.8 | 1.2 | 0.8 |
Total in other operating expense | 12 | 5.1 | 5 |
Less income tax benefit in earnings | 4.8 | 2.1 | 2 |
After tax effect of share-based compensation | 7.2 | 3 | 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 | 11.8 | ' | ' |
Weighted-average life of unrecognized compensation cost (in years) | '2 years 3 months 15 days | ' | ' |
Deferred Compensation Plans [Abstract] | ' | ' | ' |
Liability associated with deferred compensation plans | 26.1 | 22.9 | ' |
Portion of liability classified in Accrued liabilities | 1.6 | 1.3 | ' |
Impact of deferred compensation plans on Other operating expenses | 4 | 1.7 | 2.1 |
Amount recorded in earnings related to the investment activities in phantom stock associated with deferred compensation plans | 2.6 | 0.6 | 1.7 |
Cash surrender value of life insurance policies | 32.9 | 29.1 | ' |
Earnings from investments in corporate-owned life insurance policies | 4.8 | 1.8 | 0.1 |
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) | 70,493 | ' | ' |
Granted (in shares) | 28,579 | ' | ' |
Vested (in shares) | -15,175 | ' | ' |
Forfeited (in shares) | -3,940 | ' | ' |
Performance based awards at end of period (in shares) | 79,957 | 70,493 | ' |
Weighted average grant date fair value at beginning of period (in dollars per share) | $27.45 | ' | ' |
Weighted average grant date fair value of shares granted during period (in dollars per share) | $30.19 | ' | ' |
Weighted average grant date fair value of shares vested during period (in dollars per share) | $26.04 | ' | ' |
Weighted average grant date fair value of shares forfeited during period (in dollars per share) | $26.20 | ' | ' |
Weighted average grant date fair value at end of period (in dollars per share) | $29.12 | $27.45 | ' |
Total fair value of equity awards vested | 0.4 | 0.1 | 0.2 |
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) | 628,810 | ' | ' |
Granted (in shares) | 305,617 | ' | ' |
Vested (in shares) | -158,187 | ' | ' |
Forfeited (in shares) | -44,989 | ' | ' |
Performance based awards at end of period (in shares) | 731,251 | 628,810 | ' |
Weighted average grant date fair value at end of period (in dollars per share) | $35.50 | ' | ' |
Total fair value of liability awards vested | 5.7 | 4.4 | 3 |
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] | ' | ' | ' |
Outstanding at beginning of period (in shares) | 386,565 | ' | ' |
Exercised (in shares) | -378,592 | ' | ' |
Forfeited or expired | -727 | ' | ' |
Outstanding at end of period (in shares) | 7,246 | 386,565 | ' |
Exercisable at end of period (in shares) | 7,246 | ' | ' |
Weighted average exercise price at beginning of period (in dollars per share) | $25.88 | ' | ' |
Weighted average exercise price of options exercised (in dollars per share) | $25.87 | ' | ' |
Weighted average exercise price of forfeited and expired options (in dollars per share) | $22.57 | ' | ' |
Weighted average exercise price at end of period (in dollars per share) | $26.70 | $25.88 | ' |
Weighted average exercise price of exercisable shares at end of period (in dollars per share) | $26.70 | ' | ' |
Remaining contractual term at end of period (in years) | '1 year | ' | ' |
Remaining contractual term of exercisable shares at end of period (in years) | '1 year | ' | ' |
Aggregate intrinsic value, outstanding at end of period | 0.6 | ' | ' |
Aggregate intrinsic value, exercisable at end of period | 0.6 | ' | ' |
Intrinsic value of options exercised | 3.8 | 0.1 | 2.4 |
Tax benefit realized for tax deductions from option exercises | 1.5 | 0.1 | 1 |
Cash received upon exercise of stock options | 9.7 | 0.3 | 12.3 |
Stock repurchased during period | $12.30 | $0.10 | $12.80 |
Commitments_and_Contingencies_
Commitments and Contingencies (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Commitments [Abstract] | ' | ' | ' |
Future minimum operating lease payments due within one year of the balance sheet date | $6.90 | ' | ' |
Future minimum operating lease payments due within the second year of the balance sheet date | 5 | ' | ' |
Future minimum operating lease payments due within the third year of the balance sheet date | 2.9 | ' | ' |
Future minimum operating lease payments due within the fourth year of the balance sheet date | 1.3 | ' | ' |
Future minimum operating lease payments due within the fifth year of the balance sheet date | 1.2 | ' | ' |
Future minimum operating lease payments due within after the fifth year of the balance sheet date | 5 | ' | ' |
Total lease expense | 9.9 | 8.5 | 6.9 |
Performance Guarantees and Product Warranties [Abstract] | ' | ' | ' |
Letters of Credit Outstanding, Amount | 41.7 | ' | ' |
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) | 57 | ' | ' |
Average face amount of surety bonds wholly owned subsidiary has outstanding | 4.4 | ' | ' |
Maximum face amount of surety bond wholly owned subsidiary had outstanding | 57.3 | ' | ' |
Percent of work completed on projects covered by open surety bonds (in hundredths) | 47.00% | ' | ' |
Timeframe when significant portion of performance guarantee commitments will be fulfilled | 'within one year | ' | ' |
Guarantees for Other Unconsolidated Affiliates [Member] | ' | ' | ' |
Corporate Guarantees [Abstract] | ' | ' | ' |
Maximum exposure by parent company on guarantees. | 15.3 | ' | ' |
Performance Guarantee [Member] | Guarantees for ESG [Member] | ' | ' | ' |
Corporate Guarantees [Abstract] | ' | ' | ' |
Maximum exposure by parent company on guarantees. | 25 | ' | ' |
Performance Guarantee [Member] | Guarantees for Other Unconsolidated Affiliates [Member] | ' | ' | ' |
Corporate Guarantees [Abstract] | ' | ' | ' |
Maximum exposure by parent company on guarantees. | 25 | ' | ' |
Other Guarantees Outstanding [Member] | Guarantees for ESG [Member] | ' | ' | ' |
Corporate Guarantees [Abstract] | ' | ' | ' |
Maximum exposure by parent company on guarantees. | 45 | ' | ' |
Financial Standby Letter of Credit [Member] | Guarantees for ESG [Member] | ' | ' | ' |
Performance Guarantees and Product Warranties [Abstract] | ' | ' | ' |
Letter of Credit, Gross Amount | 8 | ' | ' |
Letters of Credit Outstanding, Amount | 3.4 | ' | ' |
Financial Standby Letter of Credit [Member] | Guarantees for Other Unconsolidated Affiliates [Member] | ' | ' | ' |
Corporate Guarantees [Abstract] | ' | ' | ' |
Maximum exposure by parent company on guarantees. | $19 | ' | ' |
Rate_Regulatory_Matters_Detail
Rate & Regulatory Matters (Details) (USD $) | 12 Months Ended | ||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items] | ' | ' | ' |
Other Nonoperating Income (Expense) | $17,700,000 | $8,300,000 | ($3,500,000) |
Vectren South Electric Environmental Compliance Filing [Abstract] | ' | ' | ' |
Lower range of request for approval of capital investments on coal-fired generation units | 70,000,000 | ' | ' |
Upper range of request for approval of capital investments on coal-fired generation units | 90,000,000 | ' | ' |
Vectren South Electric Base Rate Filing [Abstract] | ' | ' | ' |
Amount of infrastructure construction in the three years leading up to December 2009 rate filing | 325,000,000 | ' | ' |
Rate of return included in rate increase (in hundredths) | 7.29% | ' | ' |
Dollar amount of the rate base included in rate increase | 1,295,600,000 | ' | ' |
Amount of rate of return on equity included in rate base (in hundredths) | 10.40% | ' | ' |
Amount of expected capital investment invested to date related to investment in dense pack technology | 28,700,000 | ' | ' |
Coal Procurement Procedures [Abstract] | ' | ' | ' |
Number of years for recovery of coal costs | 6 | ' | ' |
Cumulative total deferrals related to coal purchases | ' | 42,400,000 | ' |
Vectren South Electric Demand Side Management Program Filing [Abstract] | ' | ' | ' |
Number of years in initial demand side management program approved by the IURC (in years) | 3 | ' | ' |
Maximum deferral of lost margin associated with small customer demand side programs | ' | 3,000,000 | 1,000,000 |
Electric revenue recognized associated with lost margin recovery | 5,000,000 | ' | ' |
FERC Return On Equity Complaint [Abstract] | ' | ' | ' |
Reduced return on equity percentage sought by third party | 9.15% | ' | ' |
Current return on equity used in MISO transmission owners rates | 12.38% | ' | ' |
Equity component, upper limit, as a percentage, sought by third party | 50.00% | ' | ' |
Percentage return recommended by FERC on ROE complaint against NETO | 9.70% | ' | ' |
Incentive return granted on qualifying investments in NETO | 11.14% | ' | ' |
Estimate of basis point change that could affect the Company's net income | 100 | ' | ' |
Net income effect of a 100 basis point change on an annual basis | 800,000 | ' | ' |
Ohio [Member] | Ohio Recovery and Deferral Mechanisms [Member] | ' | ' | ' |
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items] | ' | ' | ' |
Cumulative gross plant invesment made under Distribution Replacement Rider | 109,000,000 | ' | ' |
Distribution Replacement Rider revenues | 9,800,000 | 6,500,000 | 3,600,000 |
Other income (AFUDC borrowed) | 2,000,000 | 1,800,000 | 2,000,000 |
Regulatory Asset associated with DRR deferrals of depreciation and post in-service carrying costs | 9,300,000 | 6,500,000 | 3,000,000 |
Initial DRR term | 5 | ' | ' |
Amount of Capital Investment Expected Over Next Five Years Recoverable Under DRR | 187,000,000 | ' | ' |
Bill impact per customer per month | 1 | ' | ' |
Increase in regulatory assets associated with Ohio infrastructure programs | 6,700,000 | ' | ' |
Ohio [Member] | Ohio House Bill95 [Member] | ' | ' | ' |
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items] | ' | ' | ' |
Estimated budget related to Ohio capital expenditure program | 23,500,000 | ' | ' |
Time period (in months) included in VEDO application | '15 | ' | ' |
Bill impact per customer per month | 1.5 | ' | ' |
Amount approved for capital expenditure program | 61,500,000 | ' | ' |
PortionofCapitalInvestmentThatMayBeRecoverableUnderDRR | 34,800,000 | ' | ' |
Other Nonoperating Income (Expense) | 2,200,000 | 900,000 | ' |
Amount of deferral related to depreciation and property tax expense | 1,700,000 | 600,000 | ' |
Indiana [Member] | Indiana Recovery and Deferral Mechanisms [Member] | ' | ' | ' |
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items] | ' | ' | ' |
Regulatory Assset balance associated with Vectren north and south programs | 12,100,000 | 8,500,000 | ' |
Percentage of costs eligible for recovery using periodic rate recovery mechanism | 80.00% | ' | ' |
Percentage of project costs to be deferred for future recovery | 20.00% | ' | ' |
Length of project plan required for recovery under new legislation | 7 | ' | ' |
Adjustment mechanism cap % based on annual retail revenue increase | 2.00% | ' | ' |
Indiana [Member] | Pipeline Safety Law [Member] | ' | ' | ' |
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items] | ' | ' | ' |
Expected Seven Year Period Modernization Investment | 865,000,000 | ' | ' |
Seven Year Plan of Eligible Investments Under Indiana Legislation (In Years) | 7 | ' | ' |
Expected annual operating costs associated with new pipeline safety regulations | 13,000,000 | ' | ' |
SIGECO [Member] | Indiana [Member] | Indiana Recovery and Deferral Mechanisms [Member] | ' | ' | ' |
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items] | ' | ' | ' |
Allowable expenditures under Vectren South program | 3,000,000 | ' | ' |
Limitations of deferrals of debt-related post in service carrying costs | '3 | ' | ' |
Indiana Gas [Member] | Indiana [Member] | Indiana Recovery and Deferral Mechanisms [Member] | ' | ' | ' |
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items] | ' | ' | ' |
Allowable capital expenditures under Vectren North Program | $20,000,000 | ' | ' |
Limitations of deferrals of debt-related post in service carrying costs | '4 | ' | ' |
Environmental_Matters_Details
Environmental Matters (Details) (USD $) | Dec. 31, 2013 | Dec. 31, 2012 |
In Millions, unless otherwise specified | ||
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 related to Clean Water Act | 40 | ' |
Coal Ash Waste Disposal and Ash Ponds [Abstract] | ' | ' |
Estimated capital expenditures to comply with ash pond and coal ash disposal regulations | 30 | ' |
Potential estimated capital expenditures to comply with ash pond and coal ash disposal regulations with stringent alternative | 100 | ' |
Estimated annual compliance costs maximum with ash pond and coal ash disposal regulation | 5 | ' |
Climate Changes [Abstract] | ' | ' |
Maximum level of greenhouse gas emissions that prompts requirement to obtain permit for facilities to construct new facility of significant modification to existing facility (in tons) | 75,000 | ' |
Indiana Senate Bill 251 [Abstract] | ' | ' |
Percentage of total electricity obtained by supplier to meet customer needs | 10.00% | ' |
Power generation capacity for acquired landfill gas generations facility (in megawatts) | 3 | ' |
Long term contract for purchase of electric power generated by wind energy (in megawatts) | 80 | ' |
Percentage of total electricity obtained by the supplier to meet the energy needs of its retail customers provided by clean energy sources (in hundredths) | 5.00% | ' |
Manufactured Gas Plants | ' | ' |
Site contingency, accrual, undiscounted amount | 43.4 | ' |
Accrual for Environmental Loss Contingencies | 5.7 | 4.6 |
Indiana Gas [Member] | ' | ' |
Manufactured Gas Plants | ' | ' |
Number of sites identified with potential remedial responsibility for entity (in number of sites) | 26 | ' |
Site contingency, accrual, undiscounted amount | 23.2 | ' |
Environmental cost recognized, recover from insurance carriers credited to expense | 20.8 | ' |
SIGECO [Member] | ' | ' |
Manufactured Gas Plants | ' | ' |
Number of sites identified with potential remedial responsibility for entity (in number of sites) | 5 | ' |
Site contingency, accrual, undiscounted amount | 20.2 | ' |
Environmental cost recognized, recover from insurance carriers credited to expense | 14.3 | ' |
Expected Site Contingency Recovery from Insurance Carriers of Environmental Remediation Costs | $15.80 | ' |
Fair_Value_Measurements_Detail
Fair Value Measurements (Details) (USD $) | 12 Months Ended | |
In Millions, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 |
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ' | ' |
Other Assets, Fair Value Disclosure | $10.40 | $2.10 |
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 | 1,807.10 | 1,659.80 |
Short-term borrowings & notes payable | 68.6 | 278.8 |
Cash and cash equivalents | 21.5 | 19.5 |
Estimated Fair Value [Member] | ' | ' |
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ' | ' |
Long-term debt | 1,895.20 | 1,873.30 |
Short-term borrowings & notes payable | 68.6 | 278.8 |
Cash and cash equivalents | $21.50 | $19.50 |
Segment_Reporting_Details
Segment Reporting (Details) (USD $) | 3 Months Ended | 12 Months Ended | |||||||||
In Millions, unless otherwise specified | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2012 | Sep. 30, 2012 | Jun. 30, 2012 | Mar. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Property, Plant and Equipment, Additions | ' | ' | ' | ' | ' | ' | ' | ' | $393.40 | $365.80 | $321.30 |
Number of reporting segments | 3 | ' | ' | ' | ' | ' | ' | ' | 3 | ' | ' |
Number of operating segments in the Nonutility Group | 5 | ' | ' | ' | ' | ' | ' | ' | 5 | ' | ' |
Portion Of Indiana That Is Provided Natural Gas Distribution And Transportation Services By Gas Utility Services Segment | 66.67% | ' | ' | ' | ' | ' | ' | ' | 66.67% | ' | ' |
Revenues | 680 | 579.6 | 531 | 700.6 | 644.1 | 513.5 | 470.6 | 604.6 | 2,491.20 | 2,232.80 | 2,325.20 |
Net income (loss) | 49.8 | 42.8 | -5.8 | 49.8 | 42.8 | 39.3 | 25.6 | 51.3 | 136.6 | 159 | 141.6 |
Amounts Included in Profitability Measures [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Depreciation and Amortization | ' | ' | ' | ' | ' | ' | ' | ' | 277.8 | 254.6 | 244.3 |
Interest Expense | ' | ' | ' | ' | ' | ' | ' | ' | 87.9 | 96 | 106.5 |
Income Taxes | ' | ' | ' | ' | ' | ' | ' | ' | 67.1 | 82.5 | 86.4 |
Assets | 5,102.60 | ' | ' | ' | 5,089.10 | ' | ' | ' | 5,102.60 | 5,089.10 | 4,878.90 |
Utility Group [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Property, Plant and Equipment, Additions | ' | ' | ' | ' | ' | ' | ' | ' | 261.1 | 246 | 233.4 |
Revenues | ' | ' | ' | ' | ' | ' | ' | ' | 1,429.60 | 1,333.60 | 1,457 |
Net income (loss) | ' | ' | ' | ' | ' | ' | ' | ' | 141.8 | 138 | 122.9 |
Amounts Included in Profitability Measures [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Depreciation and Amortization | ' | ' | ' | ' | ' | ' | ' | ' | 196.4 | 190 | 192.3 |
Interest Expense | ' | ' | ' | ' | ' | ' | ' | ' | 65 | 71.5 | 80.3 |
Income Taxes | ' | ' | ' | ' | ' | ' | ' | ' | 85.3 | 85.3 | 82.9 |
Assets | 4,140.80 | ' | ' | ' | 4,046.80 | ' | ' | ' | 4,140.80 | 4,046.80 | 3,974.50 |
Utility Group [Member] | Gas Utility Services [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Property, Plant and Equipment, Additions | ' | ' | ' | ' | ' | ' | ' | ' | 150.5 | 128.8 | 113.5 |
Revenues | ' | ' | ' | ' | ' | ' | ' | ' | 810 | 738.1 | 819.1 |
Net income (loss) | ' | ' | ' | ' | ' | ' | ' | ' | 55.7 | 60 | 52.5 |
Amounts Included in Profitability Measures [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Depreciation and Amortization | ' | ' | ' | ' | ' | ' | ' | ' | 90.5 | 85.4 | 84.3 |
Interest Expense | ' | ' | ' | ' | ' | ' | ' | ' | 30.6 | 31.8 | 37.1 |
Income Taxes | ' | ' | ' | ' | ' | ' | ' | ' | 36.6 | 39.1 | 34.5 |
Assets | 2,287.90 | ' | ' | ' | 2,173.50 | ' | ' | ' | 2,287.90 | 2,173.50 | 2,125.20 |
Utility Group [Member] | Electric Utility Services [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Property, Plant and Equipment, Additions | ' | ' | ' | ' | ' | ' | ' | ' | 100 | 108.8 | 102.2 |
Revenues | ' | ' | ' | ' | ' | ' | ' | ' | 619.3 | 594.9 | 635.9 |
Net income (loss) | ' | ' | ' | ' | ' | ' | ' | ' | 75.8 | 68 | 65 |
Amounts Included in Profitability Measures [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Depreciation and Amortization | ' | ' | ' | ' | ' | ' | ' | ' | 84 | 81.3 | 80.2 |
Interest Expense | ' | ' | ' | ' | ' | ' | ' | ' | 29.2 | 33.8 | 36.4 |
Income Taxes | ' | ' | ' | ' | ' | ' | ' | ' | 48.3 | 46.4 | 45.3 |
Assets | 1,679 | ' | ' | ' | 1,705.10 | ' | ' | ' | 1,679 | 1,705.10 | 1,656.50 |
Utility Group [Member] | Intersegment Elimination [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Revenues | ' | ' | ' | ' | ' | ' | ' | ' | -37.8 | -39.5 | -41.9 |
Utility Group [Member] | Non-Cash Cost and Change in Accruals [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Property, Plant and Equipment, Additions | ' | ' | ' | ' | ' | ' | ' | ' | -15.2 | -7.8 | -0.1 |
Utility Group [Member] | Other Segments [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Property, Plant and Equipment, Additions | ' | ' | ' | ' | ' | ' | ' | ' | 25.8 | 16.2 | 17.8 |
Revenues | ' | ' | ' | ' | ' | ' | ' | ' | 38.1 | 40.1 | 43.9 |
Net income (loss) | ' | ' | ' | ' | ' | ' | ' | ' | 10.3 | 10 | 5.4 |
Amounts Included in Profitability Measures [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Depreciation and Amortization | ' | ' | ' | ' | ' | ' | ' | ' | 21.9 | 23.3 | 27.8 |
Interest Expense | ' | ' | ' | ' | ' | ' | ' | ' | 5.2 | 5.9 | 6.8 |
Income Taxes | ' | ' | ' | ' | ' | ' | ' | ' | 0.4 | -0.2 | 3.1 |
Assets | 173.9 | ' | ' | ' | 168.2 | ' | ' | ' | 173.9 | 168.2 | 192.8 |
Nonutility Group [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Property, Plant and Equipment, Additions | ' | ' | ' | ' | ' | ' | ' | ' | 132.3 | 119.8 | 87.9 |
Number of reporting segments | 5 | ' | ' | ' | ' | ' | ' | ' | 5 | ' | ' |
Revenues | ' | ' | ' | ' | ' | ' | ' | ' | 1,167.60 | 1,017.60 | 1,018.60 |
Net income (loss) | ' | ' | ' | ' | ' | ' | ' | ' | -4.5 | 21.7 | 23.8 |
Amounts Included in Profitability Measures [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Depreciation and Amortization | ' | ' | ' | ' | ' | ' | ' | ' | 81.4 | 64.6 | 52 |
Interest Expense | ' | ' | ' | ' | ' | ' | ' | ' | 23.2 | 24.9 | 27 |
Income Taxes | ' | ' | ' | ' | ' | ' | ' | ' | -17.1 | -1.7 | 6.3 |
Assets | 1,030.60 | ' | ' | ' | 980.7 | ' | ' | ' | 1,030.60 | 980.7 | 888.3 |
Nonutility Group [Member] | Infrastructure Services [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Property, Plant and Equipment, Additions | ' | ' | ' | ' | ' | ' | ' | ' | 79.2 | 53.7 | 22.8 |
Revenues | ' | ' | ' | ' | ' | ' | ' | ' | 783.5 | 663.6 | 421.3 |
Net income (loss) | ' | ' | ' | ' | ' | ' | ' | ' | 49 | 40.5 | 14.9 |
Amounts Included in Profitability Measures [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Depreciation and Amortization | ' | ' | ' | ' | ' | ' | ' | ' | 28.8 | 20.7 | 14.9 |
Interest Expense | ' | ' | ' | ' | ' | ' | ' | ' | 10.1 | 7.5 | 7.4 |
Income Taxes | ' | ' | ' | ' | ' | ' | ' | ' | 34.3 | 29.6 | 10.7 |
Assets | 465.8 | ' | ' | ' | 420 | ' | ' | ' | 465.8 | 420 | 295 |
Nonutility Group [Member] | Energy Services [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Property, Plant and Equipment, Additions | ' | ' | ' | ' | ' | ' | ' | ' | 6.9 | 2.3 | 9.7 |
Revenues | ' | ' | ' | ' | ' | ' | ' | ' | 91.3 | 117.7 | 161.8 |
Net income (loss) | ' | ' | ' | ' | ' | ' | ' | ' | 1 | 5.7 | 6.7 |
Amounts Included in Profitability Measures [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Depreciation and Amortization | ' | ' | ' | ' | ' | ' | ' | ' | 1.7 | 1.9 | 1.5 |
Interest Expense | ' | ' | ' | ' | ' | ' | ' | ' | 0.6 | 0.4 | 0.6 |
Income Taxes | ' | ' | ' | ' | ' | ' | ' | ' | -11.9 | -9 | 1.1 |
Assets | 63 | ' | ' | ' | 69.7 | ' | ' | ' | 63 | 69.7 | 81.2 |
Nonutility Group [Member] | Coal Mining [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Property, Plant and Equipment, Additions | ' | ' | ' | ' | ' | ' | ' | ' | 46.2 | 63.8 | 55.1 |
Revenues | ' | ' | ' | ' | ' | ' | ' | ' | 292.8 | 235.8 | 285.6 |
Net income (loss) | ' | ' | ' | ' | ' | ' | ' | ' | -16 | -3.5 | 16.6 |
Amounts Included in Profitability Measures [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Depreciation and Amortization | ' | ' | ' | ' | ' | ' | ' | ' | 50.8 | 41.8 | 35.1 |
Interest Expense | ' | ' | ' | ' | ' | ' | ' | ' | 9.8 | 11.5 | 11.3 |
Income Taxes | ' | ' | ' | ' | ' | ' | ' | ' | -14.6 | -8.6 | 3.9 |
Assets | 433 | ' | ' | ' | 380 | ' | ' | ' | 433 | 380 | 352.8 |
Nonutility Group [Member] | Energy Marketing [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Property, Plant and Equipment, Additions | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | 0.3 |
Revenues | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | 149.9 |
Net income (loss) | ' | ' | ' | ' | ' | ' | ' | ' | -37.5 | -17.6 | -4.2 |
Amounts Included in Profitability Measures [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Depreciation and Amortization | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | 0.5 |
Interest Expense | ' | ' | ' | ' | ' | ' | ' | ' | 2.2 | 4.8 | 6.4 |
Income Taxes | ' | ' | ' | ' | ' | ' | ' | ' | -23.3 | -11.7 | -2.4 |
Assets | 33.9 | ' | ' | ' | 73.9 | ' | ' | ' | 33.9 | 73.9 | 112.5 |
Nonutility Group [Member] | Other Businesses [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Revenues | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 0.5 | 0 |
Net income (loss) | ' | ' | ' | ' | ' | ' | ' | ' | -1 | -3.4 | -10.2 |
Amounts Included in Profitability Measures [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Depreciation and Amortization | ' | ' | ' | ' | ' | ' | ' | ' | 0.1 | 0.2 | 0 |
Interest Expense | ' | ' | ' | ' | ' | ' | ' | ' | 0.5 | 0.7 | 1.3 |
Income Taxes | ' | ' | ' | ' | ' | ' | ' | ' | -1.6 | -2 | -7 |
Assets | 34.9 | ' | ' | ' | 37.1 | ' | ' | ' | 34.9 | 37.1 | 46.8 |
Corporate and Other [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Net income (loss) | ' | ' | ' | ' | ' | ' | ' | ' | -0.7 | -0.7 | -5.1 |
Amounts Included in Profitability Measures [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Interest Expense | ' | ' | ' | ' | ' | ' | ' | ' | -0.3 | -0.4 | -0.8 |
Income Taxes | ' | ' | ' | ' | ' | ' | ' | ' | -1.1 | -1.1 | -2.8 |
Assets | 828.1 | ' | ' | ' | 785.6 | ' | ' | ' | 828.1 | 785.6 | 727.3 |
Eliminations [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Revenues | ' | ' | ' | ' | ' | ' | ' | ' | -106 | -118.4 | -150.4 |
Amounts Included in Profitability Measures [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Assets | ($896.90) | ' | ' | ' | ($724) | ' | ' | ' | ($896.90) | ($724) | ($711.20) |
Additional_Balance_Sheet_Opera2
Additional Balance Sheet & Operational Information (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Inventory, Net [Abstract] | ' | ' | ' |
Gas in storage - at LIFO cost | $33.20 | $22.40 | ' |
Coal and Oil for electric generation - at average cost | 16.5 | 52 | ' |
Materials and supplies | 57.3 | 57.6 | ' |
Nonutility Coal - at LIFO cost | 26.2 | 25.4 | ' |
Other | 1.2 | 1.2 | ' |
Total inventories | 134.4 | 158.6 | ' |
Amount by which cost of replacing inventories carried at LIFO cost exceeded carrying value | 8.5 | 12.7 | ' |
Prepayments and other current assets [Abstract] | ' | ' | ' |
Prepaid gas delivery service | 32.9 | 28.5 | ' |
Deferred income taxes | 13.9 | 0 | ' |
Prepaid taxes | 11.2 | 26.4 | ' |
Other prepayments and current assets | 17.6 | 18.4 | ' |
Total prepayments and other current assets | 75.6 | 73.3 | ' |
Investments in unconsolidated affiliates [Abstract] | ' | ' | ' |
Total investments in unconsolidated affiliates | 24 | 78.1 | ' |
Equity in earnings (loss) of unconsolidated affiliates [Abstract] | ' | ' | ' |
Equity in (losses) of unconsolidated affiliates | -59.7 | -23.3 | -32 |
Other utility and corporate investments [Abstract] | ' | ' | ' |
Cash surrender value of life insurance policies | 32.9 | 29.1 | ' |
Municipal bond | 3.4 | 3.6 | ' |
Restricted cash & other investments | 1.8 | 1.9 | ' |
Other utility and corporate investments | 38.1 | 34.6 | ' |
Goodwill | 262.3 | 262.3 | ' |
Accrued liabilities [Abstract] | ' | ' | ' |
Refunds to customers and customer deposits | 50.2 | 53.1 | ' |
Accrued taxes | 36.2 | 34.4 | ' |
Accrued interest | 20 | 23.1 | ' |
Deferred compensation & post-retirement benefits | 7.5 | 6.8 | ' |
Deferred income taxes | 0 | 14.9 | ' |
Accrued salaries and other | 68.2 | 66.5 | ' |
Total accrued liabilities | 182.1 | 198.8 | ' |
Asset Retirement Obligation [Roll Forward] | ' | ' | ' |
Asset retirement obligation, beginning balance | 37.7 | 43.7 | ' |
Accretion | 2.2 | 2.7 | ' |
Changes in estimates, net of cash payments | 1.4 | -8.7 | ' |
Asset retirement obligation, ending balance | 41.3 | 37.7 | 43.7 |
Other - net in the consolidated statement of income [Abstract] | ' | ' | ' |
AFUDC - borrowed funds | 5.9 | 4.6 | 2.5 |
AFUDC - equity funds | 0.8 | 0.4 | 0.2 |
Nonutility plant capitalized interest | 0.5 | 1.8 | 2.1 |
Interest income, net | 1.1 | 1.1 | 1.4 |
Other nonutility investment impairment charges | 0 | -2.7 | -9.9 |
Cash surrender value of life insurance policies | 4.8 | 1.8 | 0.1 |
All other income | 4.6 | 1.3 | 0.1 |
Total other income (expense) – net | 17.7 | 8.3 | -3.5 |
Cash paid (received) for [Abstract] | ' | ' | ' |
Interest | 91 | 94.6 | 108.6 |
Income taxes | 6.8 | 21.8 | -9 |
Accruals related to utility and nonutility plant purchases [Abstract] | ' | ' | ' |
Accruals related to utility and nonutility plant purchases | 19.4 | 11.1 | ' |
ProLiance Holdings, LLC [Member] | ' | ' | ' |
Investments in unconsolidated affiliates [Abstract] | ' | ' | ' |
Total investments in unconsolidated affiliates | 20.8 | 73.9 | ' |
Equity in earnings (loss) of unconsolidated affiliates [Abstract] | ' | ' | ' |
Equity in (losses) of unconsolidated affiliates | -57.7 | -22.7 | -28.6 |
Other Nonutility Partnerships and Corporations [Member] | ' | ' | ' |
Investments in unconsolidated affiliates [Abstract] | ' | ' | ' |
Total investments in unconsolidated affiliates | 3 | 4 | ' |
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 (losses) of unconsolidated affiliates | -2 | -0.6 | -3.4 |
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 | 2.8 | ' | ' |
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 | $2.10 | $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, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2012 | Sep. 30, 2012 | Jun. 30, 2012 | Mar. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Quarterly Financial Information Disclosure [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Operating revenues | $680 | $579.60 | $531 | $700.60 | $644.10 | $513.50 | $470.60 | $604.60 | $2,491.20 | $2,232.80 | $2,325.20 |
Operating income | 85.6 | 83.3 | 57.9 | 106.8 | 90.8 | 81.6 | 70.2 | 109.9 | 333.6 | 352.5 | 370 |
Net Income | $49.80 | $42.80 | ($5.80) | $49.80 | $42.80 | $39.30 | $25.60 | $51.30 | $136.60 | $159 | $141.60 |
Earnings per share [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Basic | $0.60 | $0.52 | ($0.07) | $0.61 | $0.52 | $0.48 | $0.31 | $0.63 | $1.66 | $1.94 | $1.73 |
DILUTED (in dollars per share) | $0.60 | $0.52 | ($0.07) | $0.61 | $0.52 | $0.48 | $0.31 | $0.62 | $1.66 | $1.94 | $1.73 |
SCHEDULE_II_VALUATION_AND_QUAL1
SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Accumulated Provision for Uncollectible Accounts [Member] | ' | ' | ' |
Valuation and Qualifying Accounts Disclosure [Line Items] | ' | ' | ' |
Balance, at beginning of year | $6.80 | $6.70 | $5.30 |
Additions charged to expenses | 6.8 | 8.2 | 11.8 |
Additions charged to other accounts | 0 | 0 | 0 |
Deductions from Reserves, Net | 6.8 | 8.1 | 10.4 |
Balance, at end of period | 6.8 | 6.8 | 6.7 |
Reserve for Impaired Notes Receivable [Member] | ' | ' | ' |
Valuation and Qualifying Accounts Disclosure [Line Items] | ' | ' | ' |
Balance, at beginning of year | 0.6 | 15.7 | 6.1 |
Additions charged to expenses | 0 | 0.5 | 9.6 |
Additions charged to other accounts | 0 | 0 | 0 |
Deductions from Reserves, Net | 0 | 15.6 | 0 |
Balance, at end of period | 0.6 | 0.6 | 15.7 |
Restructuring Costs [Member] | ' | ' | ' |
Valuation and Qualifying Accounts Disclosure [Line Items] | ' | ' | ' |
Balance, at beginning of year | 0.3 | 0.4 | 0.4 |
Additions charged to expenses | 0 | 0 | 0 |
Additions charged to other accounts | 0 | 0 | 0 |
Deductions from Reserves, Net | 0.1 | 0.1 | 0 |
Balance, at end of period | $0.20 | $0.30 | $0.40 |