Document_and_Entity_Informatio
Document and Entity Information | 6 Months Ended | |
Jun. 30, 2014 | Jul. 31, 2014 | |
Document and Entity Information [Abstract] | ' | ' |
Entity Registrant Name | 'VECTREN CORP | ' |
Entity Central Index Key | '0001096385 | ' |
Current Fiscal Year End Date | '--12-31 | ' |
Entity Filer Category | 'Large Accelerated Filer | ' |
Document Type | '10-Q | ' |
Document Period End Date | 30-Jun-14 | ' |
Document Fiscal Year Focus | '2014 | ' |
Document Fiscal Period Focus | 'Q2 | ' |
Amendment Flag | 'false | ' |
Entity Common Stock, Shares Outstanding | ' | 82,503,531 |
CONSOLIDATED_CONDENSED_BALANCE
CONSOLIDATED CONDENSED BALANCE SHEETS (Unaudited) (USD $) | Jun. 30, 2014 | Dec. 31, 2013 |
In Millions, unless otherwise specified | ||
Current Assets [Abstract] | ' | ' |
Cash & cash equivalents | $8.40 | $21.50 |
Accounts receivable - less reserves of $8.1 & $6.8, respectively | 172.8 | 259.2 |
Accrued unbilled revenues | 75.2 | 134.2 |
Inventories | 80.3 | 134.4 |
Recoverable fuel & natural gas costs | 25.6 | 5.5 |
Assets held for sale | 348.3 | 0 |
Prepayments & other current assets | 67.1 | 75.6 |
Total current assets | 777.7 | 630.4 |
Utility Plant [Abstract] | ' | ' |
Original cost | 5,514.40 | 5,389.60 |
Less: accumulated depreciation & amortization | 2,228.20 | 2,165.30 |
Net utility plant | 3,286.20 | 3,224.30 |
Investments in unconsolidated affiliates | 24.1 | 24 |
Other utility & corporate investments | 38.2 | 38.1 |
Other nonutility investments | 34.2 | 33.8 |
Nonutility plant - net | 367.4 | 657.2 |
Goodwill - net | 289.3 | 262.3 |
Regulatory assets | 184.4 | 193.4 |
Other assets | 46.1 | 39.1 |
TOTAL ASSETS | 5,047.60 | 5,102.60 |
Current Liabilities [Abstract] | ' | ' |
Accounts payable | 146.8 | 227.2 |
Refundable fuel and natural gas costs | 0 | 2.6 |
Accrued liabilities | 198.8 | 182.1 |
Short-term borrowings | 79.1 | 68.6 |
Current maturities of long-term debt | 5 | 30 |
Liabilities held for sale | 38 | 0 |
Total current liabilities | 467.7 | 510.5 |
Long-term Debt - Net of Current Maturities | 1,772.20 | 1,777.10 |
Deferred Credits & Other Liabilities [Abstract] | ' | ' |
Deferred income taxes | 670.7 | 707.4 |
Regulatory liabilities | 400.2 | 387.3 |
Deferred credits & other liabilities | 175.2 | 166 |
Total deferred credits and other liabilities | 1,246.10 | 1,260.70 |
Commitments & Contingencies (Notes 7, 11-13) | ' | ' |
Common Shareholders' Equity [Abstract] | ' | ' |
Common stock (no par value) – issued & outstanding 82.5 & 82.4 shares, respectively | 713 | 709.3 |
Retained earnings | 849.4 | 845.7 |
Accumulated other comprehensive (loss) | -0.8 | -0.7 |
Total common shareholders' equity | 1,561.60 | 1,554.30 |
TOTAL LIABILITIES and SHAREHOLDERS' EQUITY | $5,047.60 | $5,102.60 |
CONSOLIDATED_CONDENSED_BALANCE1
CONSOLIDATED CONDENSED BALANCE SHEETS (Unaudited) (Parenthetical) (USD $) | Jun. 30, 2014 | Dec. 31, 2013 |
In Millions, unless otherwise specified | ||
Current Assets [Abstract] | ' | ' |
Reserves | $8.10 | $6.80 |
Common Shareholders' Equity [Abstract] | ' | ' |
Common Stock, Shares, Issued | 82.5 | 82.4 |
Common Stock, Shares, Outstanding | 82.4 | 82.4 |
CONSOLIDATED_CONDENSED_STATEME
CONSOLIDATED CONDENSED STATEMENTS OF INCOME (Unaudited) (USD $) | 3 Months Ended | 6 Months Ended | ||
In Millions, except Per Share data, unless otherwise specified | Jun. 30, 2014 | Jun. 30, 2013 | Jun. 30, 2014 | Jun. 30, 2013 |
OPERATING REVENUES [Abstract] | ' | ' | ' | ' |
Gas utility | $132.40 | $138 | $576 | $453.90 |
Electric utility | 152 | 154.7 | 315 | 304.2 |
Nonutility | 258.1 | 238.3 | 448.3 | 473.5 |
Total operating revenues | 542.5 | 531 | 1,339.30 | 1,231.60 |
OPERATING EXPENSES [Abstract] | ' | ' | ' | ' |
Cost of gas sold | 43.7 | 50.7 | 314.6 | 207.9 |
Cost of fuel & purchased power | 48.1 | 53.9 | 105.1 | 104.1 |
Cost of nonutility revenues | 79.6 | 77.3 | 147.3 | 163.7 |
Other operating | 247.9 | 209.4 | 455.5 | 425 |
Depreciation & amortization | 75.8 | 68.8 | 149.6 | 135 |
Taxes other than income taxes | 13.5 | 13 | 34.3 | 31.2 |
Total operating expenses | 508.6 | 473.1 | 1,206.40 | 1,066.90 |
OPERATING INCOME | 33.9 | 57.9 | 132.9 | 164.7 |
OTHER INCOME (EXPENSE) [Abstract] | ' | ' | ' | ' |
Equity in (losses) of unconsolidated affiliates | 0.2 | -50.6 | 0.1 | -57.3 |
Other income - net | 4.2 | 3.6 | 8.5 | 6.5 |
Total other income (expense) | 4.4 | -47 | 8.6 | -50.8 |
Interest Expense | 21.9 | 21.5 | 44 | 45 |
INCOME (LOSS) BEFORE INCOME TAXES | 16.4 | -10.6 | 97.5 | 68.9 |
INCOME TAXES | 4.5 | -4.8 | 34.4 | 24.9 |
NET INCOME (LOSS) | $11.90 | ($5.80) | $63.10 | $44 |
AVERAGE COMMON SHARES OUTSTANDING | 82.5 | 82.3 | 82.5 | 82.3 |
DILUTED COMMOM SHARES OUTSTANDING | 82.5 | 82.3 | 82.5 | 82.4 |
EARNINGS (LOSS) PER SHARE OF COMMON STOCK: | ' | ' | ' | ' |
BASIC | $0.14 | ($0.07) | $0.76 | $0.53 |
DILUTED | $0.14 | ($0.07) | $0.76 | $0.53 |
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK | $0.36 | $0.36 | $0.72 | $0.71 |
CONSOLIDATED_CONDENSED_STATEME1
CONSOLIDATED CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (Unaudited) (USD $) | 3 Months Ended | 6 Months Ended | ||
In Millions, unless otherwise specified | Jun. 30, 2014 | Jun. 30, 2013 | Jun. 30, 2014 | Jun. 30, 2013 |
Statement of Comprehensive Income [Abstract] | ' | ' | ' | ' |
Net income (loss) | $11.90 | ($5.80) | $63.10 | $44 |
Other comprehensive income (OCI) of unconsolidated affiliates | ' | ' | ' | ' |
Net amount arising during the year before tax | 0 | 4.3 | 0 | 4.5 |
Income taxes related to items of other comprehensive income | 0 | -1.7 | 0 | -1.8 |
AOCI of unconsolidated affiliates, net of tax | 0 | 2.6 | 0 | 2.7 |
Remeasurement of pension obligation | -0.1 | 0 | -0.1 | 0 |
Total comprehensive income (loss) | $11.80 | ($3.20) | $63 | $46.70 |
CONSOLIDATED_CONDENSED_STATEME2
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS (Unaudited) (USD $) | 6 Months Ended | |
In Millions, unless otherwise specified | Jun. 30, 2014 | Jun. 30, 2013 |
CASH FLOWS FROM OPERATING ACTIVITES [Abstract] | ' | ' |
Net Income | $63.10 | $44 |
Adjustments to Reconcile Net Income (Loss) to Cash Provided by (Used in) Operating Activities [Abstract] | ' | ' |
Depreciation & amortization | 149.6 | 135 |
Deferred income taxes & investment tax credits | 0.4 | 25.7 |
Equity in losses of unconsolidated affiliates | -0.1 | 57.3 |
Provision for uncollectible accounts | 3.2 | 3.9 |
Expense portion of pension & postretirement benefit cost | 3.9 | 4.5 |
Other noncash charges - net | 3.9 | 4.8 |
Loss on assets held for sale | 32.4 | 0 |
Changes in working capital accounts [Abstract] | ' | ' |
Accounts receivable & accrued unbilled revenues | 132.5 | 82.1 |
Inventories | 0.5 | 24.7 |
Recoverable/refundable fuel & natural gas costs | -22.7 | 6.7 |
Prepayments & other current assets | -3.6 | -11.5 |
Accounts payable, including to affiliated companies | -80.3 | -99.4 |
Accrued liabilities | -5.2 | -13.5 |
Unconsolidated affiliate dividends | 0 | 0.3 |
Employer contributions to pension & postretirement plans | -2.5 | -6.8 |
Changes in noncurrent assets | 0.8 | -4.6 |
Changes in noncurrent liabilities | -2 | 1.7 |
Net cash provided by operating activities | 273.9 | 254.9 |
Proceeds from: | ' | ' |
Proceeds from Issuance of Long-term Debt | 0 | 122.3 |
Dividend reinvestment plan & other common stock issuances | 3.3 | 3.8 |
Requirements for: | ' | ' |
Dividends on common stock | -59.4 | -58.4 |
Retirement of long-term debt | -30 | -176.5 |
Other financing activities | 0 | 0.1 |
Net change in short-term borrowings | 10.5 | 19 |
Net cash used in financing activities | -75.6 | -89.7 |
Proceeds from: | ' | ' |
Other collections | 2.2 | 3 |
Requirements for: | ' | ' |
Capital expenditures, excluding AFUDC equity | -195.1 | -171.4 |
Business acquisition | -18.5 | 0 |
Other investments | 0 | -10.4 |
Net cash used in investing activities | -211.4 | -178.8 |
Net change in cash and cash equivalents | -13.1 | -13.6 |
Cash and cash equivalents at beginning of period | 21.5 | 19.5 |
Cash and cash equivalents at end of period | $8.40 | $5.90 |
Organization_and_Nature_of_Ope
Organization and Nature of Operations | 6 Months Ended |
Jun. 30, 2014 | |
Organization and Nature of Operations [Abstract] | ' |
Organization and Nature of Operations | ' |
Organization and Nature of Operations | |
Vectren Corporation (the Company or Vectren), an Indiana corporation, is an energy holding company headquartered in Evansville, Indiana. The Company’s wholly owned subsidiary, Vectren Utility Holdings, Inc. (Utility Holdings), serves as the intermediate holding company for three public utilities: Indiana Gas Company, Inc. (Indiana Gas), Southern Indiana Gas and Electric Company (SIGECO), and Vectren Energy Delivery of Ohio, Inc. (VEDO). Utility Holdings also has other assets that provide information technology and other services to the three utilities. Utility Holdings’ consolidated operations are collectively referred to as the Utility Group. Both Vectren and Utility Holdings are holding companies as defined by the Energy Policy Act of 2005 (Energy Act). Vectren was incorporated under the laws of Indiana on June 10, 1999. | |
Indiana Gas provides energy delivery services to approximately 578,000 natural gas customers located in central and southern Indiana. SIGECO provides energy delivery services to approximately 143,000 electric customers and approximately 111,000 gas customers located near Evansville in southwestern Indiana. SIGECO also owns and operates electric generation assets to serve its electric customers and optimizes those assets in the wholesale power market. Indiana Gas and SIGECO generally do business as Vectren Energy Delivery of Indiana. VEDO provides energy delivery services to approximately 315,000 natural gas customers located near Dayton in west-central Ohio. | |
The Company, through Vectren Enterprises, Inc. (Enterprises), is involved in nonutility activities in three business areas: Infrastructure Services, Energy Services and Coal Mining. Infrastructure Services provides underground pipeline construction and repair services. Energy Services provides energy performance contracting and sustainable infrastructure, such as renewables, distributed generation, and combined heat and power projects. Coal Mining owns, and through its contract miners, mines and then sells coal. On July 1, 2014, the Company announced that it had reached an agreement to sell its wholly owned coal mining subsidiary. The sale is expected to close in the third quarter of 2014. Further, prior to June 18, 2013, the Company, through Enterprises, had activities in its Energy Marketing business area. Energy Marketing marketed and supplied natural gas and provided energy management services through ProLiance Holdings, LLC (ProLiance). Enterprises has other legacy businesses that have invested in energy-related opportunities and services, real estate, and a leveraged lease, among other investments. All of the above are collectively referred to as the Nonutility Group. |
Basis_of_Presentation
Basis of Presentation | 6 Months Ended |
Jun. 30, 2014 | |
Basis of Presentation [Abstract] | ' |
Basis of Presentation | ' |
Basis of Presentation | |
The interim condensed consolidated financial statements included in this report have been prepared by the Company, without audit, as provided in the rules and regulations of the Securities and Exchange Commission and include a review of subsequent events through the date the financial statements were issued. Certain information and note disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States have been omitted as provided in such rules and regulations. The information in this report reflects all adjustments which are, in the opinion of management, necessary to fairly state the interim periods presented, inclusive of adjustments that are normal and recurring in nature. These condensed consolidated financial statements and related notes should be read in conjunction with the Company’s audited annual consolidated financial statements for the year ended December 31, 2013, filed with the Securities and Exchange Commission on February 20, 2014, on Form 10-K. Because of the seasonal nature of the Company’s operations, the results shown on a quarterly basis are not necessarily indicative of annual results. | |
The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates. |
Earnings_Per_Share
Earnings Per Share | 6 Months Ended | |||||||||||||||
Jun. 30, 2014 | ||||||||||||||||
Earnings Per Share [Abstract] | ' | |||||||||||||||
Earnings Per Share | ' | |||||||||||||||
Earnings Per Share | ||||||||||||||||
The Company uses the two class method to calculate earnings per share (EPS). The two class method is an earnings allocation formula that treats a participating security as having rights to earnings that otherwise would have been available to common shareholders. Under the two class method, earnings for a period are allocated between common shareholders and participating security holders based on their respective rights to receive dividends as if all undistributed book earnings for the period were distributed. | ||||||||||||||||
Basic EPS is computed by dividing net income attributable to only the common shareholders by the weighted-average number of common shares outstanding for the period. Diluted EPS includes the impact of stock options and other equity based instruments to the extent the effect is dilutive. | ||||||||||||||||
The following table illustrates the basic and dilutive EPS calculations for the periods presented in these financial statements. | ||||||||||||||||
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
(In millions, except per share data) | 2014 | 2013 | 2014 | 2013 | ||||||||||||
Numerator: | ||||||||||||||||
Reported net income (Numerator for Basic and Diluted EPS) | $ | 11.9 | $ | (5.8 | ) | $ | 63.1 | $ | 44 | |||||||
Denominator: | ||||||||||||||||
Weighted average common shares outstanding | 82.5 | 82.3 | 82.5 | 82.3 | ||||||||||||
(Denominator for Basic EPS) | ||||||||||||||||
Conversion of share based compensation arrangements | 0 | 0 | 0 | 0.1 | ||||||||||||
Adjusted weighted average shares outstanding and assumed | ||||||||||||||||
conversions outstanding (Denominator for Diluted EPS) | 82.5 | 82.3 | 82.5 | 82.4 | ||||||||||||
Basic EPS | $ | 0.14 | $ | (0.07 | ) | $ | 0.76 | $ | 0.53 | |||||||
Diluted EPS | $ | 0.14 | $ | (0.07 | ) | $ | 0.76 | $ | 0.53 | |||||||
For the three and six months ended June 30, 2014 and 2013, all options and equity based instruments were dilutive and immaterial. |
Excise_and_Utility_Receipts_Ta
Excise and Utility Receipts Taxes | 6 Months Ended |
Jun. 30, 2014 | |
Excise and Utility Receipts Taxes [Abstract] | ' |
Excise and Utility Receipts Taxes | ' |
Excise and Utility Receipts Taxes | |
Excise taxes and a portion of utility receipts taxes are included in rates charged to customers. Accordingly, the Company records these taxes received, which totaled $5.5 million and $5.4 million in the three months ended June 30, 2014 and 2013, respectively, as a component of operating revenues. During the six months ended June 30, 2014 and 2013, these taxes totaled $18.4 million and $16.1 million, respectively. Expenses associated with excise and utility receipts taxes are recorded as a component of Taxes other than income taxes. |
Retirement_Plans_and_Other_Pos
Retirement Plans and Other Postretirement Benefits | 6 Months Ended | |||||||||||||||
Jun. 30, 2014 | ||||||||||||||||
Pension and Other Postretirement Benefit Expense [Abstract] | ' | |||||||||||||||
Retirement Plans and Other Postretirement Benefits | ' | |||||||||||||||
Retirement Plans & Other Postretirement Benefits | ||||||||||||||||
The Company maintains three qualified defined benefit pension plans, a nonqualified supplemental executive retirement plan (SERP), and a postretirement benefit plan. The defined benefit pension plans and postretirement benefit plan, which cover eligible full-time regular employees, are primarily noncontributory. The postretirement health care and life insurance plans are a combination of self-insured and fully insured plans. The qualified pension plans and the SERP plan are aggregated under the heading “Pension Benefits.” The postretirement benefit plan is presented under the heading “Other Benefits.” | ||||||||||||||||
Net Periodic Benefit Costs | ||||||||||||||||
A summary of the components of net periodic benefit cost follows and the amortizations shown below are primarily reflected in Regulatory assets as a majority of pension and other postretirement benefits are being recovered through rates. | ||||||||||||||||
Three Months Ended | ||||||||||||||||
June 30, | ||||||||||||||||
Pension Benefits | Other Benefits | |||||||||||||||
(In millions) | 2014 | 2013 | 2014 | 2013 | ||||||||||||
Service cost | $ | 1.9 | $ | 2.2 | $ | 0.1 | $ | 0.1 | ||||||||
Interest cost | 4 | 3.7 | 0.6 | 0.5 | ||||||||||||
Expected return on plan assets | (5.8 | ) | (5.5 | ) | — | — | ||||||||||
Amortization of prior service cost | 0.2 | 0.3 | (0.8 | ) | (0.8 | ) | ||||||||||
Amortization of transitional obligation | — | — | — | — | ||||||||||||
Amortization of actuarial loss | 1.2 | 2.5 | 0.1 | 0.2 | ||||||||||||
Settlement charge | 2.6 | — | — | — | ||||||||||||
Net periodic benefit cost | $ | 4.1 | $ | 3.2 | $ | — | $ | — | ||||||||
Six Months Ended | ||||||||||||||||
June 30, | ||||||||||||||||
Pension Benefits | Other Benefits | |||||||||||||||
(In millions) | 2014 | 2013 | 2014 | 2013 | ||||||||||||
Service cost | $ | 3.7 | $ | 4.3 | $ | 0.2 | $ | 0.2 | ||||||||
Interest cost | 7.9 | 7.4 | 1.1 | 1 | ||||||||||||
Expected return on plan assets | (11.5 | ) | (11.0 | ) | — | — | ||||||||||
Amortization of prior service cost | 0.5 | 0.7 | (1.5 | ) | (1.6 | ) | ||||||||||
Amortization of transitional obligation | — | — | — | — | ||||||||||||
Amortization of actuarial loss | 2.4 | 5 | 0.2 | 0.4 | ||||||||||||
Settlement charge | 2.6 | — | — | — | ||||||||||||
Net periodic benefit cost | $ | 5.6 | $ | 6.4 | $ | — | $ | — | ||||||||
Lump Sum Settlements | ||||||||||||||||
In 2013, the Company modified its three defined benefit pension plans to allow participants to elect a lump sum withdrawal of benefits. Such elections have been made in all plans by plan participants in 2013 and 2014. In one plan the significance of the lump sum distributions triggered settlement accounting rules and required a remeasurement of that plan's obligation as of June 30, 2014, pursuant to generally accepted accounting principles. As a result, the Company recognized a $2.6 million pension settlement charge in the three and six month periods ended June 30, 2014. | ||||||||||||||||
The Company remeasured the pension obligation for that plan using a discount rate of 4.40 percent at June 30, 2014 compared to the discount rate used at December 31, 2013 of 4.97 percent. This decrease in discount rate is the primary driver of a $5.1 million increase in the pension liability upon remeasurement. Of that amount, $5.0 million was recorded as an increase to Regulatory Assets, as the Company's retirement costs primarily relate to its regulated utilities, and the remaining $0.1 million was recorded as a decrease to other comprehensive income. | ||||||||||||||||
Employer Contributions to Qualified Pension Plans | ||||||||||||||||
Currently, the Company anticipates making no contributions to its qualified pension plans in 2014. |
Supplemental_Cash_Flow_Informa
Supplemental Cash Flow Information | 6 Months Ended |
Jun. 30, 2014 | |
Supplemental Cash Flow Information [Abstract] | ' |
Supplemental Cash Flow Information | ' |
Supplemental Cash Flow Information | |
As of June 30, 2014 and December 31, 2013, the Company has accruals related to utility and nonutility plant purchases totaling approximately $19.8 million and $19.4 million, respectively. |
ProLiance_Holdings_LLC
ProLiance Holdings, LLC | 6 Months Ended | |||
Jun. 30, 2014 | ||||
Equity Method Investments and Joint Ventures [Abstract] | ' | |||
ProLiance Holdings, LLC | ' | |||
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). Vectren's remaining investment in ProLiance relates primarily to ProLiance's investment in LA Storage, LLC (LA Storage). 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. At the time of the sale, ProLiance funded an estimated equity shortfall at ProLiance Energy of $16.6 million. 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 Condensed Consolidated Balance Sheets. | ||||
Pursuant to FERC approval, ETC ProLiance Energy has taken assignment of the Portfolio Administration Agreements (PAAs) pursuant to which the utilities receive gas supply. ETC ProLiance Energy will fulfill the requirements of the PAAs through their remaining term ending in March 2016. As part of the transaction, the Company and Citizens issued a guarantee to ETC as a backup guarantee to a $50 million guarantee issued by ProLiance to ETC, that provided for a maximum guarantee of $25.0 million, or $15.3 million for the Company's 61 percent ownership share. | ||||
On March 19, 2014, Constellation Energy Group, LLC, a subsidiary of Exelon Corporation, announced it had reached an agreement to purchase ETC ProLiance Energy, now Constellation ProLiance Energy. That transaction did not change Constellation ProLiance Energy’s obligations to fulfill the terms of the PAAs. In July 2014, the Company and ETC exchanged notices of termination effectively terminating the guarantees described above. | ||||
Vectren's remaining investment in ProLiance at June 30, 2014 is as follows and reflects that it relates primarily to ProLiance's investment in LA Storage, LLC (LA Storage) discussed below. | ||||
As of | ||||
June 30, | ||||
(In millions) | 2014 | |||
ProLiance Energy | $ | 1.3 | ||
Midstream assets and cash from sale of | ||||
storage assets | 7.8 | |||
LA Storage | 21.6 | |||
Total investment in ProLiance | $ | 30.7 | ||
Included in: | ||||
Investments in unconsolidated affiliates | $ | 20.6 | ||
Other nonutility investments | $ | 10.1 | ||
LA Storage, LLC Storage Asset Investment | ||||
ProLiance Transportation and Storage, LLC (PT&S), a subsidiary of ProLiance, and Sempra Energy International (SEI), a subsidiary of Sempra Energy (SE), through a joint venture, have a 100 percent interest in a development project for salt-cavern natural gas storage facilities known as LA Storage. PT&S is the minority member with a 25 percent interest, which it accounts for using the equity method. The project is 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. This pipeline system is currently connected with several interstate pipelines, including the Cameron Interstate Pipeline operated by Sempra Pipelines & Storage, and will connect area liquefied natural gas regasification terminals to an interstate natural gas transmission system and storage facilities. | ||||
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, the joint venture 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 June 30, 2014 and December 31, 2013, ProLiance’s investment in the joint venture was $35.5 million and $35.4 million, respectively. | ||||
The joint venture received a demand for arbitration from Williams Midstream Natural Gas Liquids, Inc. (“Williams”) in February 2011 related to a sublease agreement. Williams alleges that the joint venture was negligent in its attempt to convert certain salt caverns to natural gas storage and seeks damages of $56.7 million. The joint venture intends to vigorously defend itself and has asserted counterclaims substantially in excess of the amounts asserted by Williams. As such, as of June 30, 2014, ProLiance has no material reserve recorded related to this matter and this litigation has not materially impacted ProLiance's results of operations or statement of financial position. | ||||
Transactions with ProLiance | ||||
The Company had no purchases from ProLiance for resale and for injections into storage for the three and six months ended June 30, 2014, as a result of ProLiance exiting the natural gas marketing business. For the three and six months ended June 30, 2013, purchases totaled $92.9 million and $200.5 million, respectively. The Company did not have any amounts owed to ProLiance for purchases at June 30, 2014 or at December 31, 2013. |
Federal_Business_Unit_Acquisit
Federal Business Unit Acquisition Federal Business Unit Acquisition | 6 Months Ended | |||
Jun. 30, 2014 | ||||
Business Combinations [Abstract] | ' | |||
Business Combination Disclosure [Text Block] | ' | |||
Federal Business Unit Acquisition | ||||
On April 1, 2014, the Company, through its wholly owned subsidiary Energy Systems Group (ESG), purchased the federal sector energy services unit of Chevron Energy Solutions (CES) from Chevron USA, referred to hereafter as the Federal Business Unit or FBU. FBU performs under several long-term operations and maintenance contracts (O&M), and has a construction project sales funnel. Included in the acquisition are several Indefinite Delivery / Indefinite Quantity contracts with federal government entities including Energy Savings Performance Contracts (ESPC) with the US Department of Energy and US Army Corps of Engineers. Also included are long-term operation and maintenance and repair contracts with multiple Department of Defense installations. FBU is included in the Company’s nonutility Energy Services operating segment. | ||||
See further discussion of Company issued guarantees and a Vectren Enterprises’ indemnification associated with this acquisition in Footnote 11. | ||||
The base purchase price was approximately $19.2 million in cash, which includes a working capital settlement paid in July 2014. The total purchase price is expected to be $44 million, or $41.6 million on a net present value basis. The purchase price includes additional cash payments made in July of approximately $8.9 million related to specific contract transfers and $13.5 million as the net present value of contingent consideration related to new order targets in 2014 and 2015. The contingent consideration is subject to separate earn-out thresholds for orders in 2014 and 2015, the first of which is a threshold of $50 million in orders before the end of 2014. If $200 million or more of new construction/engineering contracts are signed through 2015, the full amount of the contingent consideration will be paid. The Company expects the full amount of contingent consideration will be paid. | ||||
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 following table summarizes the allocation of the purchase price to the fair value of the assets acquired and liabilities assumed as of April 1, 2014. | ||||
As of | ||||
June 30, | ||||
(In millions) | 2014 | |||
Adjusted Net Working Capital | $ | 2.2 | ||
Depreciable Fixed Assets | $ | 0.4 | ||
Customer Relationships | ||||
(Sales Funnel) | $ | 7.1 | ||
ESPC Licenses | $ | 6 | ||
Deferred Tax Asset | $ | 0.8 | ||
Goodwill | $ | 27.2 | ||
Total Assets acquired | $ | 43.7 | ||
Less: Unfavorable Contract Liabilities Assumed | $ | (2.1 | ) | |
Total Purchase Consideration | $ | 41.6 | ||
As of August 5, 2014, the purchase price and its allocation remain preliminary and are subject to possible adjustments in subsequent periods. Any subsequent material changes to the purchase price and its allocation will be adjusted pursuant to applicable accounting guidance. | ||||
Level 3 market inputs, such as discounted cash flows and revenue growth rates were used to derive the preliminary fair values of the identifiable intangible assets. Identifiable intangible assets include long-term customer relationships and licenses. Goodwill arising from the purchase represents intangible value the Company expects to realize over time. This value includes but is not limited to: 1) expected customer relationships beyond what is in the current sales funnel and 2) the experience of the acquired work force. The goodwill, which does not amortize pursuant to accounting guidance, is deductible over a 15-year period for purposes of computing current income tax expense, and will be included in the Energy Services operating segment. | ||||
Transaction costs associated with the acquisition and expensed by the Company totaled approximately $1.6 million, of which $0.7 million are included in other operating expenses during the six months ended June 30, 2014. For the period from April 1, 2014 through June 30, 2014, the FBU contributed approximately $4.2 million and losses of $0.5 million, respectively, to the Company's revenue and net income. | ||||
During the quarter ended June 30, 2014 and 2013, unaudited proforma results of the combined companies, assuming the acquisition closed on January 1, 2013, would have added approximately $4.2 million and $8.6 million to consolidated revenues, respectively. For the six months ended June 2014 and 2013, unaudited proforma results would have added approximately $8.1 million and $16.6 million to consolidated revenues, respectively. For the periods presented, the impact to net income and earnings per share would have been diminimus. These proforma results may not be indicative of what actual results would have been if the acquisition had taken place on the proforma date or of future results. |
Sale_of_Vectren_Fuels_Inc
Sale of Vectren Fuels, Inc. | 6 Months Ended | |||
Jun. 30, 2014 | ||||
Discontinued Operations and Disposal Groups [Abstract] | ' | |||
Disposal Groups, Including Discontinued Operations, Disclosure [Text Block] | ' | |||
Sale of Vectren Fuels, Inc. | ||||
On July 1, 2014, Vectren announced that it had reached an agreement to sell its wholly owned coal mining subsidiary, Vectren Fuels, Inc., to Sunrise Coal, LLC, an Indiana-based wholly owned subsidiary of Hallador Energy Company, which owns and operates coal mines in the Illinois Basin. The sales price is $296 million in cash, plus the change in working capital, as defined in the agreement, from December 31, 2013, until the transaction is closed. Closing is expected in the third quarter of 2014. At June 30, 2014, the Company reported the coal mining business as held for sale and recorded an estimated loss in other operating expenses, including costs to sell, of approximately $32 million, or $20 million after tax. The change in working capital at June 30, 2014 from December 31, 2013 is approximately $24 million. Expected proceeds of approximately $320 million less cash to be paid related to costs to sell of approximately $10 million results in $310 million of net assets held for sale at June 30, 2014. As assets held for sale, depreciation of the assets to be sold from July 1, 2014, through the closing date will cease. The assets/liabilities held for sale, reported in the Coal Mining segment, consisted of the following: | ||||
As of | ||||
(In millions) | 30-Jun-14 | |||
Accounts Receivable | $ | 13.1 | ||
Coal Inventory | 40.4 | |||
Materials & Supplies | 13.2 | |||
Other Current Assets | 1.8 | |||
Property & Equipment | 277.1 | |||
Non-current Assets | 2.7 | |||
Total Assets Held for Sale | $ | 348.3 | ||
Accounts Payable | $ | 10.9 | ||
Other Current Liabilities | 14.9 | |||
Non-current Liabilities | 12.2 | |||
Total Liabilities Held for Sale | $ | 38 | ||
Net Assets Held for Sale | $ | 310.3 | ||
The sale of Vectren Fuels does not meet the requirements under GAAP to qualify as discontinued operations since Vectren will have significant continuing cash flows related to the purchase of coal from the buyer of these mines. |
Financing_Activities
Financing Activities | 6 Months Ended |
Jun. 30, 2014 | |
Debt Disclosure [Abstract] | ' |
Financing Activities | ' |
Financing Activities | |
Vectren Capital Unsecured Note Retirement | |
On March 11, 2014, a $30 million Vectren Capital senior unsecured note matured. The Series A note, which was part of a private placement Note Purchase Agreement entered into on March 11, 2009, carried a fixed interest rate of 6.37 percent. The repayment of debt was funded from the Company's short-term credit facility. |
Commitments_and_Contingencies
Commitments and Contingencies | 6 Months Ended |
Jun. 30, 2014 | |
Commitments and Contingencies Disclosure [Abstract] | ' |
Commitments and Contingencies | ' |
Commitments & Contingencies | |
Commitments | |
The Company's regulated utilities have both firm and non-firm commitments to purchase natural gas, electricity, and coal as well as certain transportation and storage rights 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 June 30, 2014, parent level guarantees, excluding guarantees of obligations of the federal business unit acquired from Chevron USA on April 1, 2014, as further described below, support a maximum of $25 million of Energy System Group’s (ESG) performance contracting commitments and warranty obligations and $45 million of other project guarantees. | |
On April 1, 2014, Energy Systems Group acquired the federal sector energy services unit of Chevron Energy Solutions, from Chevron USA. Pursuant to the agreement, the acquisition includes a provision whereby Vectren Enterprises, Inc., another wholly owned subsidiary of the Company and the holding company for the Company's nonutility investments, provided CES with an indemnification for potential claims against the seller that could arise related to the performance of work undertaken by ESG. The acquisition includes ESG guarantees of performance under certain assumed contracts. The guarantees include energy savings that are used to satisfy project financing. The total maximum amount of the energy savings guarantees is approximately $140 million and will only be called upon in the event energy savings established under the existing contracts executed by CES are not achieved. The Company guarantees ESG’s performance under these energy savings guarantees. Further, an energy facility operated by ESG and managed by Keenan Ft Detrick Energy, LLC (Keenan), is governed by an operations agreement. All payment obligations to Keenan under this agreement are also guaranteed by the Company. The Vectren Enterprises, Inc. provision providing indemnification to CES and the Company guarantee of the Keenan Ft Detrick Energy operations agreement with Keenan as discussed above, do not state a maximum guarantee. Due to the nature of work performed under these contracts, the Company cannot estimate a maximum potential amount of future payments. | |
In addition, the Company has approximately $24 million of other guarantees outstanding supporting other consolidated subsidiary operations, of which $18 million represent letters of credit supporting other nonutility operations. | |
While there can be no assurance that neither the Vectren Enterprises, Inc.'s indemnification nor the Company guarantee provisions will be called upon, the Company believes that the likelihood of a material amount being triggered under any of these provisions is remote. | |
Performance Guarantees & Product Warranties | |
In the normal course of business, wholly owned subsidiaries, including ESG, issue performance bonds or other forms of assurance that commit them to timely install infrastructure, operate facilities, pay vendors or subcontractors, and/or support warranty obligations. Based on a history of meeting performance obligations and installed products operating effectively, no significant liability or cost has been recognized for the periods presented. | |
Specific to ESG in its role as a general contractor in the performance contracting industry, at June 30, 2014, there are 53 open surety bonds supporting future performance. The average face amount of these obligations is $5.5 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 June 30, 2014, approximately 42 percent of work was completed on projects with open surety bonds. A significant portion of these open surety bonds will be released within one year. In instances where ESG operates facilities, project guarantees extend over a longer period. In addition to its performance obligations, ESG also warrants the functionality of certain installed infrastructure generally for one year and the associated energy savings over a specified number of years. The Company has no significant accruals for these warranty and energy obligations as of June 30, 2014. In addition, ESG has an $8 million stand-alone letter of credit facility and as of June 30, 2014, $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 | 6 Months Ended | |
Jun. 30, 2014 | ||
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, to mitigate risk, improve the system, and comply with applicable regulations. Laws in both Indiana and Ohio were passed that provide utilities the opportunity to timely recover costs of federally mandated projects and other infrastructure improvement projects outside of a base rate proceeding. | ||
Ohio Recovery and Deferral Mechanisms | ||
The PUCO order approving the Company's 2009 base rate case in the Ohio service territory authorized a distribution replacement rider (DRR). The DRR's primary purpose is recovery of investments in utility plant and related operating expenses associated with replacing bare steel and cast iron pipelines and certain other infrastructure. This rider is updated annually for qualifying capital expenditures and allows for a return to be earned on those capital expenditures based on the rate of return approved in the 2009 base rate case. In addition, deferral of depreciation and the ability to accrue debt-related post in service carrying costs is also allowed until the related capital expenditures are included in the DRR. The order also initially established a prospective bill impact evaluation on the annual deferrals. To date, the Company has made capital investments under this rider totaling $118 million. Regulatory assets associated with post in service carrying costs and depreciation deferrals were $11.2 million and $9.3 million at June 30, 2014 and December 31, 2013, respectively. Due to the expiration of the initial five year term for the DRR in early 2014, the Company filed a request in August 2013 to extend and expand the DRR. On February 19, 2014, the PUCO approved a Stipulation entered into by the PUCO Staff and the Company which provided for the extension of the DRR for the recovery of costs incurred through 2017 and expanded the types of investment covered by the DRR to include recovery of other infrastructure investments. The Order also approved an adjustment to the bill impact evaluation, limiting the resulting DRR rate per month for residential and small general service customers to specific graduated levels over the next five years. The Company's five year capital expenditure plan related to these infrastructure investments for calendar years 2013 through 2017 totals $187 million. In addition, the Order approved the Company's commitment that the DRR can only be further extended as part of a base rate case. On May 1, 2014, the Company filed its annual request to adjust the DRR for recovery of costs incurred through December 31, 2013. On July 25, 2014, the PUCO staff completed its audit and recommended approval of the DRR as filed. A hearing in this proceeding is scheduled for August 6, 2014, and an order is expected later in 2014. | ||
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 under this law, reflecting its 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. In addition, the order approved the Company's proposal that subsequent requests for accounting authority will be filed annually in April. The Company submitted its most recent annual filing on April 30, 2014, which covers the Company’s capital expenditure program through calendar year 2014. | ||
Given the extension of the DRR through 2017 as discussed above and the continued ability to defer other capital expenses under House Bill 95, it is anticipated that the Company will file a general rate case for the inclusion in rate base of the above costs near the expiration of the DRR. As such, the rate increase limits discussed above are not expected to be reached given this capital expenditure plan during the remaining four year time frame. | ||
Indiana Recovery and Deferral Mechanisms | ||
The Company's Indiana natural gas utilities received orders in 2008 and 2007 associated with the most recent base rate cases. These orders authorized the deferral of financial impacts associated with bare steel and cast iron replacement activities. The orders provide for the deferral of depreciation and post in service carrying costs on qualifying projects totaling $20 million annually at Indiana Gas and $3 million annually at SIGECO. The debt-related post in service carrying costs are recognized in the Condensed Consolidated Statements of Income currently. The recording of post in service carrying costs and depreciation deferral is limited by individual qualifying project to three years after being placed into service at SIGECO and four years after being placed into service at Indiana Gas. At June 30, 2014 and December 31, 2013, the Company has regulatory assets totaling $14.3 million and $12.1 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, which must be filed no later than the end of the seven year plan. 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 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 SIGECO and Indiana Gas 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, inclusive of an estimated $30 million of possible economic development related expenditures, over the seven year period beginning in 2014. The plan also includes approximately $13 million of combined annual operating costs associated with pipeline safety rules. Intervening parties to the proceeding filed testimony that generally supports the Company's plan and the mechanism for recovery. A hearing in this proceeding was held May 8, 2014, and proposed orders have been filed by all parties. An order is expected in late third quarter of 2014. | ||
SIGECO Electric Environmental Compliance Filing | ||
On January 17, 2014, SIGECO 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 and to address an outstanding Notice of Violation (NOV) from the EPA. 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 the NOV 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 bill 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. The Company filed its case-in-chief on March 14, 2014. Intervening parties filed their testimony on May 28, 2014, to which the Company responded with rebuttal testimony on June 20, 2014. A hearing was held beginning on July 30, 2014. | ||
Coal Procurement Procedures | ||
SIGECO submitted a request for proposal (RFP) in April 2011 regarding coal purchases for a four year period beginning in 2012. After negotiations with bidders, SIGECO reached an agreement in principle for multi-year purchases with two suppliers, one of which was Vectren Fuels, Inc. Consistent with the IURC direction in the Company’s last electric rate case, a sub docket proceeding was established to review the Company’s prospective coal procurement procedures. In March 2012, the IURC issued its order in that sub docket which concluded that SIGECO’s 2011 RFP process resulted in the lowest fuel cost reasonably possible. SIGECO has long term contracts with Vectren Fuels to provide supply for its generating units. Those contracts will be reviewed in a pending sub docket proceeding. A hearing will be held in October 2014. Once the pending sale of Vectren Fuels, as disclosed in footnote 9, is closed, Sunrise Coal will assume responsibility for fulfilling those contract obligations. Procuring this coal is part of the Company’s MATS compliance strategy. | ||
On December 5, 2011 within the quarterly FAC filing, SIGECO submitted a joint proposal with the OUCC to reduce its fuel costs billed to customers by accelerating into 2012 the impact of lower cost coal under new term contracts effective after 2012. The cost difference was deferred to a regulatory asset and 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 balance deferred for recovery through the Company’s FAC, starting February 2014, was $42.4 million, of which $38.9 million remains as of June 30, 2014. | ||
SIGECO Electric Demand Side Management Program Filing | ||
On August 16, 2010, SIGECO 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 SIGECO electric service territory that complied with the IURC’s energy saving targets. Consistent with the Company’s proposal, the order approved, among other items, the following: 1) recovery of costs associated with implementing the DSM Plan; 2) the recovery of a performance incentive mechanism based on measured savings related to certain DSM programs; 3) lost margin recovery associated with the implementation of DSM programs for large customers; and 4) deferral of lost margin up to $3 million in 2012 and $1 million in 2011 associated with small customer DSM programs for subsequent recovery under a tracking mechanism to be proposed by the Company. On June 20, 2012, the IURC issued an order approving a small customer lost margin recovery mechanism, inclusive of all previous deferrals. This mechanism is an alternative to the electric decoupling proposal that was denied by the IURC in the Company's last base rate proceeding discussed earlier. For the six months ended June 30, 2014, the Company recognized Electric revenue of $4.4 million associated with this approved lost margin recovery mechanism. | ||
On March 28, 2014, Senate Bill 340 was signed into law. This legislation ends electric DSM programs on December 31, 2014 that have been conducted to meet the energy savings requirements established in the Commission's 2009 order. The legislation also allows for industrial customers to opt out of participating in energy efficiency programs. As of July 1, 2014, approximately 71 percent of the Company’s eligible industrial load has opted out of participation in the applicable energy efficiency programs. Indiana's Governor has requested that the Commission make new recommendations for energy efficiency programs to be proposed for 2015 and beyond, and has also asked the legislature to consider further legislation requiring some level of utility sponsored energy efficiency programs. The Company has filed a request for Commission approval of a new portfolio of DSM programs on May 29, 2014 to be effective in January 2015. On July 23, 2014, the OUCC and the Company filed a Notice of Settlement regarding the new portfolio with the Commission. A hearing in this proceeding is scheduled for September 3, 2014. | ||
Indiana Gas Pipeline Safety Investigation | ||
On April 11, 2012, the IURC's pipeline safety division filed a complaint against Indiana Gas alleging several violations of safety regulations pertaining to damage that occurred at a residence in Indiana Gas'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 Indiana Gas that allowed Indiana Gas 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. | ||
Indiana Gas & SIGECO Gas Decoupling Extension Filing | ||
On August 18, 2011, the IURC issued an order granting the extension of the current decoupling mechanism in place at both gas companies and recovery of new conservation program costs through December 2015. The order provides that the companies must submit an extension proposal no later than March 1, 2015. | ||
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. As of June 30, 2014, the Company had invested approximately $157.6 million in qualifying projects. The net plant balance for these projects totaled $145.2 million at June 30, 2014. | ||
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. On June 19, 2014, the FERC voted to approve an order in this proceeding that allows for a 10.57 percent return on equity premised upon a top quartile Discounted Cash Flow (DCF) formula using a two-stage growth rate. Although supporting the incentive return on these projects, the FERC ruling was clear that alternative approaches can be evaluated in other proceedings. The Company has established a reserve pending the outcome of this complaint. Consistent with the FERC ruling, the expectation is that the current MISO complainants will update the analysis and file testimony in the pending complaint proceeding. |
Environmental_Matters
Environmental Matters | 6 Months Ended |
Jun. 30, 2014 | |
Environmental Matters Disclosure [Abstract] | ' |
Environmental Matters | ' |
Legislative & Environmental Matters | |
Indiana Senate Bill 1 | |
In March 2014, Indiana Senate Bill 1 was signed into law. This legislation phases in a 1.6 percent rate reduction to the Indiana Adjusted Gross Income Tax Rate for corporations over a six year period. Pursuant to this legislation, the tax rate will be lowered by 0.25 percent each year for the first five years and 0.35 percent in year six beginning on July 1, 2016 to the final rate of 4.9 percent effective July 1, 2021. Pursuant to FASB guidance, the Company accounted for the effect of the change in tax law on its deferred taxes in the first quarter of 2014, the period of enactment. The impact was not material to results of operations. | |
Indiana Senate Bill 251 | |
Indiana Senate Bill 251 is also applicable to federal environmental mandates impacting Vectren South's electric operations. The Company continues with its ongoing evaluation of the impact Senate Bill 251 may have on its operations, including applicability of the stricter regulations the EPA is currently considering involving air quality, fly ash disposal, cooling tower intake facilities, waste water discharges, and greenhouse gases. These issues are further discussed below. | |
Air Quality | |
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. CSAPR reductions were to be achieved with initial step reductions beginning January 1, 2012, and final compliance to be achieved in 2014. On December 30, 2011, a reviewing 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 April 2014, the US Supreme Court upheld CSAPR. On June 26, 2014, the EPA asked the federal appeals court to lift the stay of the rule. EPA also asked the court to approve a new deadline schedule for entities that must comply, with the first phase caps starting in 2015 and 2016, and the second phase in 2017. While it is possible that the EPA could further revise the rule prior to implementation, the Company does not anticipate a significant impact from the Supreme Court's decision based upon the investments it has already made in pollution control technology to meet the requirements of CAIR. The Company remains in full compliance with CAIR (see additional information below "Conclusions Regarding Air and Water 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). Multiple judicial challenges were filed and the EPA agreed to reconsider MATS requirements for new construction, as the 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. In April 2014, the U.S. Court of Appeals for the D.C. Circuit rejected various challenges to the rule for existing sources that were brought by industry and state petitioners. The Company continues to proceed with its MATS compliance strategy. This plan is currently before the IURC for approval, and the Company anticipates full compliance by the applicable deadlines. | |
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. Based on the Company's understanding of the New Source Review provisions in effect when the equipment was installed, it is the Company's position that its SCR project was exempt from such requirements. 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” (BTA) 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 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 was issued on May 19, 2014. The final rule does not mandate cooling water tower retrofits but requires a case by case assessment of BTA for each facility. The final rule lists seven presumptive technologies which would qualify as BTA. These technologies range from intake screen modifications to cooling water tower retrofits. Ecological and technology assessment studies must be completed prior to determining BTA for Vectren’s facilities. Vectren believes that capital investments will likely be in the range of $4 million to $8 million. Costs for compliance with these final regulations should qualify as federally mandated regulatory requirements and be recovered 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 Air and Water 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 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 cause or contribute to air pollution that may reasonably be anticipated to endanger public health or welfare. The endangerment finding was finalized in December 2009, concluding that carbon emissions pose an endangerment to public health and the environment. | |
The EPA has finalized two sets of GHG regulations that apply to the Company’s generating facilities. In 2009, the EPA finalized a mandatory GHG emissions registry which requires the reporting of emissions. The EPA has also finalized a revision to the Prevention of Significant Deterioration (PSD) and Title V permitting rules which would require facilities that emit 75,000 tons or more of GHG's a year to obtain a PSD permit for new construction or a significant modification of an existing facility. The EPA's PSD and Title V permitting rules for GHG's were upheld by the US Court of Appeals for the District of Columbia, and in June 2014 the US Supreme Court upheld the regulations with respect to applicability to major sources such as coal-fired power plants that are required to hold PSD construction and Title V air operating permits for other criteria pollutants. | |
While the Company has no plans to invest in new coal fired generation, there is also a rule making and related legal challenge involving new source performance standards for new construction. This rulemaking must be finalized and withstand legal scrutiny in order for the EPA to implement its proposed new source performance standards for existing units discussed below. | |
In July 2013, the President announced a Climate Action Plan, which calls on the EPA to finalize the rule for new construction expeditiously, and by June 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. On June 2, 2014, EPA proposed its rule for states to regulate CO2 emissions from existing electric generating units. The rule, when final, will require states to adopt plans that reduce CO2 emissions by 30% from 2005 levels by 2030. Unlike most rulemakings which allow for a 30 day public comment period, the EPA provided 120 days from publication of the proposal in the Federal Register. The current deadline for public comment is October 16, 2014. The proposal sets state-specific CO2 emission rate-based CO2 goals (measured in lb CO2/MWh or “megawatt hour”) and guidelines for the development, submission and implementation of state plans to achieve the state goals. These state-specific goals are calculated based upon 2012 average emission rates aggregated for all fossil fuel-based units in the state. For Indiana, the proposal uses a 2012 emission rate of 1,923 lb CO2/MWh, and sets an interim goal of 1,607 lb CO2/MWh and a final emission goal of 1,531 lb CO2/MWh that must be met by 2030. Under this proposal, these CO2 emission rate goals do not apply directly to individual units, or generating systems. They are state goals. As such, the state must establish a framework that will guide how compliance will be met on a statewide basis. The state’s interim or “phase in” goal of 1,607 lb CO2/MWh must be met as averaged over a ten year period (2020 - 2029) with progress toward this goal to be demonstrated for every two rolling calendar years starting in 2020, with the first report due in 2022. | |
Under the proposal all states have unique goals based upon each state’s mix of electric generating assets. The EPA is proposing a 20% reduction in Indiana’s total CO2 emission rate compared to 2012. At 20% Indiana’s CO2 emission rate reduction requirement is tied with West Virginia as the 9th lowest reduction requirement in US. This is due in part to the EPA’s attempt to recognize the existing generating resource mix in the state and take into account each state’s ability to cost effectively lower its CO2 emission rate through a portfolio approach including energy efficiency and renewables, improving power plant heat rates, and dispatching lower emitting fuel sources. Each state’s goals were set by taking 2012 emissions data and applying four “building blocks” of emission rate improvements that the EPA asserts can be achieved by that state. These four building blocks constitute the EPA’s determination of “Best System of Emission Reductions that has been adequately demonstrated”, which defines the EPA’s authority under § 111(d) for existing sources. When applied to each state, the portfolio approach leads to significant differences in requirements across state lines. With the exception of building block number 1 (heat rate improvement of 6%), other building blocks are tailored to individual states based upon each state’s existing generating mix and what the EPA concluded a state could reasonably accomplish to reduce its CO2 emission rate. Despite having just been recently proposed and not expected to be finalized until June of 2015, legal challenges to the EPA's proposal have begun. On July 31, 2014, litigation was filed by the state of Indiana and other parties challenging the rules which may delay the timing of approval of the various state plans. | |
With respect to the state of Indiana, the four building blocks that support Indiana’s goal are as follows: | |
(1) Heat rate (HR) improvements of 6% (this is consistently applied to all states); | |
(2) Increasing the dispatch of existing natural gas baseload generation sources to 70%. | |
(3) Renewable energy portfolio requirements of 5% (interim) and 7% (final). | |
(4) Energy efficiency / DSM that results in reductions of 1.5% annually starting in 2020, ending at a sustained 11% by 2030. | |
Under the proposal, Indiana may choose to implement a program based upon an annual average emission rate target or convert that target rate to a comparable CO2 emission cap. Indiana is the 5th largest carbon emitter in the nation in tons of CO2 produced from electric generation. In 2013, Indiana’s electric utilities generated 105.6 million tons of CO2. Vectren’s share of that total was 6.3 million, or < 6%. Since 2005, Vectren’s emissions of CO2 have declined 23% (on a tonnage basis). These reductions have come from the retirement of FB Culley Unit 1, expiration of municipal contracts, electric conservation and the addition of renewable generation and the installation of more efficient dense pack turbine technology. With respect to CO2 emission rate, since 2005 Vectren has lowered its CO2 emission rate (as measured in lbs CO2 / MWh) from 1967 lbs CO2 / MWh to 1922 lbs CO2 / MWh, for a reduction of 3%. Vectren’s CO2 emission rate of 1922 lbs/MWh is basically the same as the State’s average CO2 emission rate of 1923 lb CO2 / MWh. | |
Impact of Legislative Actions & Other Initiatives is Unknown | |
If the regulations referenced above are finalized by the EPA, or if legislation requiring reductions in CO2 and other GHG's or legislation mandating a renewable energy portfolio standard is adopted, such regulation could substantially affect both the costs and operating characteristics of the Company’s fossil fuel generating plants, 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 were based on highly uncertain assumptions, including allowance prices if a cap and trade approach were employed, and energy efficiency targets. As the EPA moves toward finalization of the NSPS for existing sources and the State of Indiana begins formulation of its state implementation plan, the Company will have more information to enable it to better assess potential compliance costs with a final regulation. Costs to purchase allowances that cap GHG emissions or expenditures made to control emissions or lower carbon emission rates should be considered a federally mandated cost of providing electricity, and as such, the Company believes such costs and expenditures should be recoverable from customers through Senate Bill 251 as referenced above or Senate Bill 29. | |
Renewables | |
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 4 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 June 30, 2014 and December 31, 2013, approximately $4.6 million and $5.7 million, respectively, of accrued, but not yet spent, costs are included in Other Liabilities related to the Indiana Gas and SIGECO sites. |
Impact_of_Recently_Issued_Acco
Impact of Recently Issued Accounting Principles | 6 Months Ended |
Jun. 30, 2014 | |
New Accounting Pronouncements and Changes in Accounting Principles [Abstract] | ' |
Impact of Recently Issued Accounting Principles | ' |
Impact of Recently Issued Accounting Principles | |
Revenue Recognition Guidance | |
In May 2014, the FASB issued new accounting guidance to clarify the principles for recognizing revenue and to develop a common revenue standard for GAAP and IFRS. The amendments in this guidance state that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This new guidance requires improved disclosures to help users of financial statements better understand the nature, amount, timing, and uncertainty of revenue that is recognized. For a public entity, the guidance is effective for annual reporting periods beginning after December 15, 2016, with early adoption not permitted. An entity should apply the amendments in this update retrospectively to each prior reporting period presented or retrospectively with the cumulative effect of initially applying this update recognized at the date of initial application. The Company is currently evaluating the standard to understand the overall impact it will have on the financial statements. | |
Investments in Qualified Affordable Housing Projects | |
In January 2014, the FASB issued new accounting guidance on accounting for investments in qualified affordable housing projects. The amendments in this guidance allows an entity to make an accounting policy election to account for investments in qualified affordable housing projects using a proportional amortization method, if certain conditions are met. Under the election, the entity would amortize the initial cost of the investment in proportion to the tax credits and other benefits received while recognizing the net investment performance in the income statement as a component of income tax expense (benefit). The guidance is effective for annual periods and interim reporting periods within those annual periods, beginning after December 15, 2014, with early adoption permitted. The Company is assessing if its affordable housing investments will qualify for the election and whether or not it will choose to exercise the election. Adoption of this guidance will not have a material impact on the Company's financial statements. | |
Financial Reporting of Discontinued Operations | |
In April 2014, the FASB issued new accounting guidance on reporting discontinued operations and disclosures of disposals of a company or entity. The guidance changes the criteria for reporting discontinued operations and provides for enhanced disclosures in this area. Under the new guidance, only disposals representing a strategic shift in operations should be presented as discontinued operations. Those strategic shifts should have a major effect on the organization's operations and financial results. Additionally, the new guidance requires expanded disclosures about discontinued operations to provide more information about the assets, liabilities, income, and expenses of discontinued operations. The new guidance also requires disclosure of the pre-tax income attributable to a disposal of a significant part of an organization that does not qualify for discontinued operations reporting. This guidance is effective for fiscal years beginning on or after December 15, 2014, with early adoption permitted. The Company did not adopt this guidance in accounting for the sale of its Coal Mining assets as discussed in footnote 9. The Company is currently evaluating the impact of this guidance, if any. | |
Accounting for Stock Compensation | |
In June 2014, the FASB issued new accounting guidance on accounting for share-based payments when the terms of an award provide that a performance target could be achieved after the requisite service period. These amendments provide explicit guidance on whether to treat a performance target that could be achieved after the requisite service period as a performance condition that affects vesting or as a non-vesting condition that affects the grant-date fair value of an award. This guidance is effective for annual periods and interim periods within those periods beginning after December 15, 2015, with early adoption permitted. The Company’s current practice for accounting for stock compensation follows the prescribed manner as suggested by the update. Adoption of this guidance will not have a material impact on the Company’s financial statements. |
Fair_Value_Measurements
Fair Value Measurements | 6 Months Ended | |||||||||||||||
Jun. 30, 2014 | ||||||||||||||||
Fair Value Disclosures [Abstract] | ' | |||||||||||||||
Fair Value Measurements | ' | |||||||||||||||
Fair Value Measurements | ||||||||||||||||
The carrying values and estimated fair values using primarily Level 2 assumptions of the Company's other financial instruments follow: | ||||||||||||||||
June 30, 2014 | December 31, 2013 | |||||||||||||||
(In millions) | Carrying | Est. Fair | Carrying | Est. Fair | ||||||||||||
Amount | Value | Amount | Value | |||||||||||||
Long-term debt | $ | 1,777.20 | $ | 1,960.10 | $ | 1,807.10 | $ | 1,895.20 | ||||||||
Short-term borrowings | 79.1 | 79.1 | 68.6 | 68.6 | ||||||||||||
Cash & cash equivalents | 8.4 | 8.4 | 21.5 | 21.5 | ||||||||||||
For the balance sheet dates presented in these financial statements, the Company had no material assets or liabilities marked to fair value. | ||||||||||||||||
Certain methods and assumptions must be used to estimate the fair value of financial instruments. The fair value of the Company's long-term debt was estimated based on the quoted market prices for the same or similar issues or on the current rates offered to the Company for instruments with similar characteristics. Because of the maturity dates and variable interest rates of short-term borrowings and cash & cash equivalents, those carrying amounts approximate fair value. Because of the inherent difficulty of estimating interest rate and other market risks, the methods used to estimate fair value may not always be indicative of actual realizable value, and different methodologies could produce different fair value estimates at the reporting date. | ||||||||||||||||
Under current regulatory treatment, call premiums on reacquisition of utility-related long-term debt are generally recovered in customer rates over the life of the refunding issue or over a 15-year period. Accordingly, any reacquisition of this debt would not be expected to have a material effect on the Company's results of operations. | ||||||||||||||||
Because of the nature of certain other investments and lack of a readily available market, it is not practical to estimate the fair value of these financial instruments at specific dates without considerable effort and cost. At June 30, 2014 and December 31, 2013, the fair value for these financial instruments was not estimated. The carrying value of these investments was approximately $10.4 million at both June 30, 2014 and December 31, 2013, and is included in Other nonutility investments. |
Segment_Reporting
Segment Reporting | 6 Months Ended | |||||||||||||||
Jun. 30, 2014 | ||||||||||||||||
Segment Reporting [Abstract] | ' | |||||||||||||||
Segment Reporting | ' | |||||||||||||||
Segment Reporting | ||||||||||||||||
The Company segregates its operations into three groups: 1) Utility Group, 2) Nonutility Group, and 3) Corporate and Other. | ||||||||||||||||
The Utility Group is comprised of Vectren Utility Holdings, Inc.’s operations, which consist of the Company’s regulated operations and other operations that provide information technology and other support services to those regulated operations. The Company segregates its regulated operations between a Gas Utility Services operating segment and an Electric Utility Services operating segment. The Gas Utility Services segment provides natural gas distribution and transportation services to nearly two-thirds of Indiana and to west-central Ohio. The Electric Utility Services segment provides electric distribution services primarily to southwestern Indiana, and includes the Company’s power generating and wholesale power operations. Regulated operations supply natural gas and/or electricity to over one million customers. In total, the Utility Group reports three segments: Gas Utility Services, Electric Utility Services, and Other operations. | ||||||||||||||||
The Nonutility Group has historically reported five segments: Infrastructure Services, Energy Services, Coal Mining, Energy Marketing, and Other Businesses. In 2013, ProLiance exited the energy marketing business. In its 2014 periodic reports, the Company reports the Energy Marketing segment information for 2013, which is inclusive of the Company's share of the loss from operations and its share of the loss on sale as recorded by ProLiance Energy. | ||||||||||||||||
Corporate and Other includes unallocated corporate expenses such as advertising and charitable contributions, among other activities, that benefit the Company’s other operations. Net income is the measure of profitability used by management for all operations. | ||||||||||||||||
Information related to the Company’s reportable segments is summarized as follows. The presentation for Other Operations and Eliminations revenue for the prior year was overstated by offsetting amounts that had no effect on revenue. The presentation has been revised in the table below: | ||||||||||||||||
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
(In millions) | 2014 | 2013 | 2014 | 2013 | ||||||||||||
Revenues | ||||||||||||||||
Utility Group | ||||||||||||||||
Gas Utility Services | $ | 132.4 | $ | 138 | $ | 576 | $ | 453.9 | ||||||||
Electric Utility Services | 152 | 154.7 | 315 | 304.2 | ||||||||||||
Other Operations | 9.5 | 9.5 | 19.1 | 19 | ||||||||||||
Eliminations | (9.4 | ) | (9.4 | ) | (19.0 | ) | (18.8 | ) | ||||||||
Total Utility Group | 284.5 | 292.8 | 891.1 | 758.3 | ||||||||||||
Nonutility Group | ||||||||||||||||
Infrastructure Services | 178 | 174.4 | 301 | 346.2 | ||||||||||||
Energy Services | 32.7 | 23.9 | 50.2 | 44.4 | ||||||||||||
Coal Mining | 85.6 | 72.1 | 167.1 | 135.2 | ||||||||||||
Total Nonutility Group | 296.3 | 270.4 | 518.3 | 525.8 | ||||||||||||
Corporate & Other Group | 0.2 | — | 0.5 | — | ||||||||||||
Eliminations | (38.5 | ) | (32.2 | ) | (70.6 | ) | (52.5 | ) | ||||||||
Consolidated Revenues | $ | 542.5 | $ | 531 | $ | 1,339.30 | $ | 1,231.60 | ||||||||
Profitability Measure - Net Income (Loss) | ||||||||||||||||
Utility Group Net Income | ||||||||||||||||
Gas Utility Services | $ | 0.7 | $ | 2.9 | $ | 39 | $ | 41 | ||||||||
Electric Utility Services | 19.9 | 18.9 | 39.2 | 33.5 | ||||||||||||
Other Operations | 2.3 | 2.4 | 6 | 4.8 | ||||||||||||
Utility Group Net Income | 22.9 | 24.2 | 84.2 | 79.3 | ||||||||||||
Nonutility Group Net Income (Loss) | ||||||||||||||||
Infrastructure Services | 9.4 | 7.9 | 4.1 | 14.8 | ||||||||||||
Energy Services | (1.8 | ) | (0.8 | ) | (4.8 | ) | (2.2 | ) | ||||||||
Coal Mining | (18.2 | ) | (3.7 | ) | (19.3 | ) | (9.7 | ) | ||||||||
Energy Marketing | — | (32.9 | ) | — | (37.5 | ) | ||||||||||
Other Businesses | (0.2 | ) | (0.2 | ) | (0.5 | ) | (0.5 | ) | ||||||||
Nonutility Group Net (Loss) | (10.8 | ) | (29.7 | ) | (20.5 | ) | (35.1 | ) | ||||||||
Corporate & Other Group Net (Loss) | (0.2 | ) | (0.3 | ) | (0.6 | ) | (0.2 | ) | ||||||||
Consolidated Net Income (Loss) | $ | 11.9 | $ | (5.8 | ) | $ | 63.1 | $ | 44 | |||||||
Earnings_Per_Share_Tables
Earnings Per Share (Tables) | 6 Months Ended | |||||||||||||||
Jun. 30, 2014 | ||||||||||||||||
Earnings Per Share [Abstract] | ' | |||||||||||||||
Basic and dilutive EPS | ' | |||||||||||||||
The following table illustrates the basic and dilutive EPS calculations for the periods presented in these financial statements. | ||||||||||||||||
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
(In millions, except per share data) | 2014 | 2013 | 2014 | 2013 | ||||||||||||
Numerator: | ||||||||||||||||
Reported net income (Numerator for Basic and Diluted EPS) | $ | 11.9 | $ | (5.8 | ) | $ | 63.1 | $ | 44 | |||||||
Denominator: | ||||||||||||||||
Weighted average common shares outstanding | 82.5 | 82.3 | 82.5 | 82.3 | ||||||||||||
(Denominator for Basic EPS) | ||||||||||||||||
Conversion of share based compensation arrangements | 0 | 0 | 0 | 0.1 | ||||||||||||
Adjusted weighted average shares outstanding and assumed | ||||||||||||||||
conversions outstanding (Denominator for Diluted EPS) | 82.5 | 82.3 | 82.5 | 82.4 | ||||||||||||
Basic EPS | $ | 0.14 | $ | (0.07 | ) | $ | 0.76 | $ | 0.53 | |||||||
Diluted EPS | $ | 0.14 | $ | (0.07 | ) | $ | 0.76 | $ | 0.53 | |||||||
Retirement_Plans_and_Other_Pos1
Retirement Plans and Other Postretirement Benefits (Tables) | 6 Months Ended | |||||||||||||||
Jun. 30, 2014 | ||||||||||||||||
Pension and Other Postretirement Benefit Expense [Abstract] | ' | |||||||||||||||
Schedule of Defined Benefit Plans Disclosures [Table Text Block] | ' | |||||||||||||||
A summary of the components of net periodic benefit cost follows and the amortizations shown below are primarily reflected in Regulatory assets as a majority of pension and other postretirement benefits are being recovered through rates. | ||||||||||||||||
Three Months Ended | ||||||||||||||||
June 30, | ||||||||||||||||
Pension Benefits | Other Benefits | |||||||||||||||
(In millions) | 2014 | 2013 | 2014 | 2013 | ||||||||||||
Service cost | $ | 1.9 | $ | 2.2 | $ | 0.1 | $ | 0.1 | ||||||||
Interest cost | 4 | 3.7 | 0.6 | 0.5 | ||||||||||||
Expected return on plan assets | (5.8 | ) | (5.5 | ) | — | — | ||||||||||
Amortization of prior service cost | 0.2 | 0.3 | (0.8 | ) | (0.8 | ) | ||||||||||
Amortization of transitional obligation | — | — | — | — | ||||||||||||
Amortization of actuarial loss | 1.2 | 2.5 | 0.1 | 0.2 | ||||||||||||
Settlement charge | 2.6 | — | — | — | ||||||||||||
Net periodic benefit cost | $ | 4.1 | $ | 3.2 | $ | — | $ | — | ||||||||
Six Months Ended | ||||||||||||||||
June 30, | ||||||||||||||||
Pension Benefits | Other Benefits | |||||||||||||||
(In millions) | 2014 | 2013 | 2014 | 2013 | ||||||||||||
Service cost | $ | 3.7 | $ | 4.3 | $ | 0.2 | $ | 0.2 | ||||||||
Interest cost | 7.9 | 7.4 | 1.1 | 1 | ||||||||||||
Expected return on plan assets | (11.5 | ) | (11.0 | ) | — | — | ||||||||||
Amortization of prior service cost | 0.5 | 0.7 | (1.5 | ) | (1.6 | ) | ||||||||||
Amortization of transitional obligation | — | — | — | — | ||||||||||||
Amortization of actuarial loss | 2.4 | 5 | 0.2 | 0.4 | ||||||||||||
Settlement charge | 2.6 | — | — | — | ||||||||||||
Net periodic benefit cost | $ | 5.6 | $ | 6.4 | $ | — | $ | — | ||||||||
ProLiance_Holdings_LLC_Tables
ProLiance Holdings, LLC (Tables) | 6 Months Ended | |||
Jun. 30, 2014 | ||||
Equity Method Investments and Joint Ventures [Abstract] | ' | |||
Summarized Financial Information of Equity Investment [Table Text Block] | ' | |||
Vectren's remaining investment in ProLiance at June 30, 2014 is as follows and reflects that it relates primarily to ProLiance's investment in LA Storage, LLC (LA Storage) discussed below. | ||||
As of | ||||
June 30, | ||||
(In millions) | 2014 | |||
ProLiance Energy | $ | 1.3 | ||
Midstream assets and cash from sale of | ||||
storage assets | 7.8 | |||
LA Storage | 21.6 | |||
Total investment in ProLiance | $ | 30.7 | ||
Included in: | ||||
Investments in unconsolidated affiliates | $ | 20.6 | ||
Other nonutility investments | $ | 10.1 | ||
Federal_Business_Unit_Acquisit1
Federal Business Unit Acquisition Federal Business Unit Acquisition (Tables) | 6 Months Ended | |||
Jun. 30, 2014 | ||||
Business Combinations [Abstract] | ' | |||
Schedule of Business Acquisitions, by Acquisition [Table Text Block] | ' | |||
The following table summarizes the allocation of the purchase price to the fair value of the assets acquired and liabilities assumed as of April 1, 2014. | ||||
As of | ||||
June 30, | ||||
(In millions) | 2014 | |||
Adjusted Net Working Capital | $ | 2.2 | ||
Depreciable Fixed Assets | $ | 0.4 | ||
Customer Relationships | ||||
(Sales Funnel) | $ | 7.1 | ||
ESPC Licenses | $ | 6 | ||
Deferred Tax Asset | $ | 0.8 | ||
Goodwill | $ | 27.2 | ||
Total Assets acquired | $ | 43.7 | ||
Less: Unfavorable Contract Liabilities Assumed | $ | (2.1 | ) | |
Total Purchase Consideration | $ | 41.6 | ||
Sale_of_Vectren_Fuels_Inc_Tabl
Sale of Vectren Fuels, Inc. (Tables) | 6 Months Ended | |||
Jun. 30, 2014 | ||||
Discontinued Operations and Disposal Groups [Abstract] | ' | |||
Schedule of Disposal Groups, Including Discontinued Operations, Income Statement, Balance Sheet and Additional Disclosures [Table Text Block] | ' | |||
As assets held for sale, depreciation of the assets to be sold from July 1, 2014, through the closing date will cease. The assets/liabilities held for sale, reported in the Coal Mining segment, consisted of the following: | ||||
As of | ||||
(In millions) | 30-Jun-14 | |||
Accounts Receivable | $ | 13.1 | ||
Coal Inventory | 40.4 | |||
Materials & Supplies | 13.2 | |||
Other Current Assets | 1.8 | |||
Property & Equipment | 277.1 | |||
Non-current Assets | 2.7 | |||
Total Assets Held for Sale | $ | 348.3 | ||
Accounts Payable | $ | 10.9 | ||
Other Current Liabilities | 14.9 | |||
Non-current Liabilities | 12.2 | |||
Total Liabilities Held for Sale | $ | 38 | ||
Net Assets Held for Sale | $ | 310.3 | ||
Fair_Value_Measurements_Tables
Fair Value Measurements (Tables) | 6 Months Ended | |||||||||||||||
Jun. 30, 2014 | ||||||||||||||||
Fair Value Disclosures [Abstract] | ' | |||||||||||||||
Fair Value, by Balance Sheet Grouping [Table Text Block] | ' | |||||||||||||||
The carrying values and estimated fair values using primarily Level 2 assumptions of the Company's other financial instruments follow: | ||||||||||||||||
June 30, 2014 | December 31, 2013 | |||||||||||||||
(In millions) | Carrying | Est. Fair | Carrying | Est. Fair | ||||||||||||
Amount | Value | Amount | Value | |||||||||||||
Long-term debt | $ | 1,777.20 | $ | 1,960.10 | $ | 1,807.10 | $ | 1,895.20 | ||||||||
Short-term borrowings | 79.1 | 79.1 | 68.6 | 68.6 | ||||||||||||
Cash & cash equivalents | 8.4 | 8.4 | 21.5 | 21.5 | ||||||||||||
Segment_Reporting_Tables
Segment Reporting (Tables) | 6 Months Ended | |||||||||||||||
Jun. 30, 2014 | ||||||||||||||||
Segment Reporting [Abstract] | ' | |||||||||||||||
Schedule of Segment Reporting Information, by Segment [Table Text Block] | ' | |||||||||||||||
Information related to the Company’s reportable segments is summarized as follows. The presentation for Other Operations and Eliminations revenue for the prior year was overstated by offsetting amounts that had no effect on revenue. The presentation has been revised in the table below: | ||||||||||||||||
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
(In millions) | 2014 | 2013 | 2014 | 2013 | ||||||||||||
Revenues | ||||||||||||||||
Utility Group | ||||||||||||||||
Gas Utility Services | $ | 132.4 | $ | 138 | $ | 576 | $ | 453.9 | ||||||||
Electric Utility Services | 152 | 154.7 | 315 | 304.2 | ||||||||||||
Other Operations | 9.5 | 9.5 | 19.1 | 19 | ||||||||||||
Eliminations | (9.4 | ) | (9.4 | ) | (19.0 | ) | (18.8 | ) | ||||||||
Total Utility Group | 284.5 | 292.8 | 891.1 | 758.3 | ||||||||||||
Nonutility Group | ||||||||||||||||
Infrastructure Services | 178 | 174.4 | 301 | 346.2 | ||||||||||||
Energy Services | 32.7 | 23.9 | 50.2 | 44.4 | ||||||||||||
Coal Mining | 85.6 | 72.1 | 167.1 | 135.2 | ||||||||||||
Total Nonutility Group | 296.3 | 270.4 | 518.3 | 525.8 | ||||||||||||
Corporate & Other Group | 0.2 | — | 0.5 | — | ||||||||||||
Eliminations | (38.5 | ) | (32.2 | ) | (70.6 | ) | (52.5 | ) | ||||||||
Consolidated Revenues | $ | 542.5 | $ | 531 | $ | 1,339.30 | $ | 1,231.60 | ||||||||
Profitability Measure - Net Income (Loss) | ||||||||||||||||
Utility Group Net Income | ||||||||||||||||
Gas Utility Services | $ | 0.7 | $ | 2.9 | $ | 39 | $ | 41 | ||||||||
Electric Utility Services | 19.9 | 18.9 | 39.2 | 33.5 | ||||||||||||
Other Operations | 2.3 | 2.4 | 6 | 4.8 | ||||||||||||
Utility Group Net Income | 22.9 | 24.2 | 84.2 | 79.3 | ||||||||||||
Nonutility Group Net Income (Loss) | ||||||||||||||||
Infrastructure Services | 9.4 | 7.9 | 4.1 | 14.8 | ||||||||||||
Energy Services | (1.8 | ) | (0.8 | ) | (4.8 | ) | (2.2 | ) | ||||||||
Coal Mining | (18.2 | ) | (3.7 | ) | (19.3 | ) | (9.7 | ) | ||||||||
Energy Marketing | — | (32.9 | ) | — | (37.5 | ) | ||||||||||
Other Businesses | (0.2 | ) | (0.2 | ) | (0.5 | ) | (0.5 | ) | ||||||||
Nonutility Group Net (Loss) | (10.8 | ) | (29.7 | ) | (20.5 | ) | (35.1 | ) | ||||||||
Corporate & Other Group Net (Loss) | (0.2 | ) | (0.3 | ) | (0.6 | ) | (0.2 | ) | ||||||||
Consolidated Net Income (Loss) | $ | 11.9 | $ | (5.8 | ) | $ | 63.1 | $ | 44 | |||||||
Organization_and_Nature_of_Ope1
Organization and Nature of Operations (Details) | 6 Months Ended |
Jun. 30, 2013 | |
Organization and Nature of Operations [Abstract] | ' |
Number of public utility subsidiaries owned by wholly owned subsidiary, Vectren Utility Holdings, Inc. (in number of subsidiaries) | 3 |
Estimated number of natural gas customers located in central and southern Indiana serviced by Indiana Gas Company, Inc. (in number of customers) | 578,000 |
Estimated number of electric customers located near Evansville in southwestern Indiana serviced by Southern Indiana Gas and Electric Company (in number of customers) | 143,000 |
Estimated number of natural gas customers located near Evansville in southwestern Indiana serviced by Southern Indiana Gas and Electric Company (in number of customers) | 111,000 |
Estimated number of natural gas customers located near Dayton in west central Ohio serviced by the Ohio operations (in number of customers) | 315,000 |
Earnings_Per_Share_Details
Earnings Per Share (Details) (USD $) | 3 Months Ended | 6 Months Ended | ||
In Millions, except Per Share data, unless otherwise specified | Jun. 30, 2014 | Jun. 30, 2013 | Jun. 30, 2014 | Jun. 30, 2013 |
Numerator [Abstract] | ' | ' | ' | ' |
Net income (loss) | $11.90 | ($5.80) | $63.10 | $44 |
Denominator [Abstract] | ' | ' | ' | ' |
Weighted average common shares outstanding (Denominator for Basic EPS) (in shares) | 82.5 | 82.3 | 82.5 | 82.3 |
Conversion of share based compensation arrangements (in shares) | 0 | 0 | 0 | 0.1 |
Adjusted weighted average shares outstanding and assumed conversions outstanding (Denominator for Diluted EPS) (in shares) | 82.5 | 82.3 | 82.5 | 82.4 |
Basic EPS (in dollars per share) | $0.14 | ($0.07) | $0.76 | $0.53 |
Diluted EPS (in dollars per share) | $0.14 | ($0.07) | $0.76 | $0.53 |
Excise_and_Utility_Receipts_Ta1
Excise and Utility Receipts Taxes (Details) (USD $) | 3 Months Ended | 6 Months Ended | ||
In Millions, unless otherwise specified | Jun. 30, 2014 | Jun. 30, 2013 | Jun. 30, 2014 | Jun. 30, 2013 |
Excise and Utility Receipts Taxes [Abstract] | ' | ' | ' | ' |
Excise and utility taxes collected and reported in operating revenue | $5.50 | $5.40 | $18.40 | $16.10 |
Retirement_Plans_and_Other_Pos2
Retirement Plans and Other Postretirement Benefits (Details) (USD $) | 3 Months Ended | 6 Months Ended | 12 Months Ended | ||
In Millions, unless otherwise specified | Jun. 30, 2014 | Jun. 30, 2013 | Jun. 30, 2014 | Jun. 30, 2013 | Dec. 31, 2013 |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ' | ' | ' | ' | ' |
Regulatory assets | $184.40 | ' | $184.40 | ' | 193.4 |
Number of qualified defined benefit pension plans | ' | ' | '3 | ' | ' |
Expected contribution to defined benefit plans for current year by employer | ' | ' | 0 | ' | ' |
Pension Benefits [Member] | ' | ' | ' | ' | ' |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ' | ' | ' | ' | ' |
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate | ' | ' | 4.40% | ' | 4.97% |
Increase in pension liability resulting from remeasurement | ' | ' | 5.1 | ' | ' |
Regulatory assets | 5 | ' | 5 | ' | ' |
Service cost | 1.9 | 2.2 | 3.7 | 4.3 | ' |
Interest cost | 4 | 3.7 | 7.9 | 7.4 | ' |
Expected return on plan assets | -5.8 | -5.5 | -11.5 | -11 | ' |
Amortization of prior service cost | 0.2 | 0.3 | 0.5 | 0.7 | ' |
Amortization of transitional obligation | 0 | 0 | 0 | 0 | ' |
Amortization of actuarial loss | 1.2 | 2.5 | 2.4 | 5 | ' |
Settlement Charge | 2.6 | 0 | 2.6 | 0 | ' |
Net periodic benefit cost | 4.1 | 3.2 | 5.6 | 6.4 | ' |
Other Benefits [Member] | ' | ' | ' | ' | ' |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ' | ' | ' | ' | ' |
Service cost | 0.1 | 0.1 | 0.2 | 0.2 | ' |
Interest cost | 0.6 | 0.5 | 1.1 | 1 | ' |
Expected return on plan assets | 0 | 0 | 0 | 0 | ' |
Amortization of prior service cost | -0.8 | -0.8 | -1.5 | -1.6 | ' |
Amortization of transitional obligation | 0 | 0 | 0 | 0 | ' |
Amortization of actuarial loss | 0.1 | 0.2 | 0.2 | 0.4 | ' |
Settlement Charge | 0 | 0 | 0 | 0 | ' |
Net periodic benefit cost | $0 | $0 | $0 | $0 | ' |
Supplemental_Cash_Flow_Informa1
Supplemental Cash Flow Information (Details) (USD $) | Jun. 30, 2014 | Dec. 31, 2013 |
In Millions, unless otherwise specified | ||
Supplemental Cash Flow Information [Abstract] | ' | ' |
Accruals related to utility and nonutility plant purchases | $19.80 | $19.40 |
ProLiance_Holdings_LLC_Details
ProLiance Holdings, LLC (Details) (USD $) | 0 Months Ended | 3 Months Ended | 6 Months Ended | 12 Months Ended | |||
In Millions, unless otherwise specified | Jun. 18, 2013 | Jun. 30, 2014 | Jun. 30, 2013 | Jun. 30, 2014 | Jun. 30, 2013 | Dec. 31, 2008 | Dec. 31, 2013 |
Disposal Date | ' | ' | ' | 18-Jun-13 | ' | ' | ' |
Combined Joint Venture Ownership Percentage | ' | 100.00% | ' | 100.00% | ' | ' | ' |
Equity Method Investment, Ownership Percentage | ' | 61.00% | ' | 61.00% | ' | ' | ' |
Equity method investment,governance and voting rights percentage (in hundredths) | ' | 50.00% | ' | 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 | ' | 34.2 | ' | 34.2 | ' | ' | 33.8 |
Equity method investment, amount of guarantee issued by equity method investee (ProLiance) to ETC | ' | 50 | ' | 50 | ' | ' | ' |
Maximum gaurantee issued by the Company and a subsidiary of Citizens | ' | 25 | ' | 25 | ' | ' | ' |
Equity in (losses) of unconsolidated affiliates | ' | 0.2 | -50.6 | 0.1 | -57.3 | ' | ' |
Investments in unconsolidated affiliates | ' | 24.1 | ' | 24.1 | ' | ' | 24 |
Equity method investment, investment in equity method investee's subsidiary (ProLiance Energy) | ' | 1.3 | ' | 1.3 | ' | ' | ' |
Equity method investment, investment in storage assets and cash from sale of storage assets | ' | 7.8 | ' | 7.8 | ' | ' | ' |
Equity method investment, minority interest in joint venture, investor's portion of interest | ' | 21.6 | ' | 21.6 | ' | ' | ' |
Equity method investment, gross investment in equity method investee | ' | 30.7 | ' | 30.7 | ' | ' | ' |
Equity method investment holding minority interest in equity method investment (in hundredths) | ' | 25.00% | ' | 25.00% | ' | ' | ' |
Impairment charge recorded by an investee of the company's equity method investments | ' | ' | ' | ' | ' | 132 | ' |
Equity method investment minority interest in joint ventures | ' | 35.5 | ' | 35.5 | ' | ' | 35.4 |
Loss contingency, gross damages sought from a party that entered into a sub-lease agreement with a party that is an investment of an equity method investee | ' | ' | ' | 56.7 | ' | ' | ' |
Purchases from ProLiance for resale and for injections into storage | ' | ' | 92.9 | ' | 200.5 | ' | ' |
Proliance Holdings Llc [Member] | ' | ' | ' | ' | ' | ' | ' |
Other nonutility investments | $10.10 | ' | ' | ' | ' | ' | ' |
Federal_Business_Unit_Acquisit2
Federal Business Unit Acquisition Federal Business Unit Acquisition (Details) (USD $) | 0 Months Ended | 3 Months Ended | 6 Months Ended | ||
In Millions, unless otherwise specified | Apr. 01, 2014 | Jun. 30, 2014 | Jun. 30, 2013 | Jun. 30, 2014 | Jun. 30, 2013 |
Business Acquisition [Line Items] | ' | ' | ' | ' | ' |
Effective Date of Acquisition | 1-Apr-14 | ' | ' | ' | ' |
Amount of Transaction Costs in Other Cost and Expense, Operating | ' | $247.90 | $209.40 | $455.50 | $425 |
Federal Business Unit [Member] | ' | ' | ' | ' | ' |
Business Acquisition [Line Items] | ' | ' | ' | ' | ' |
Base purchase price of FBU - cash paid | ' | ' | ' | 19.2 | ' |
Gross purchase price | 44 | ' | ' | ' | ' |
Business Combination, Consideration Transferred | 41.6 | ' | ' | ' | ' |
Additional cash payments made beyond cash paid for base purchase price | ' | ' | ' | 8.9 | ' |
Contingent consideration related to new order targets | ' | 13.5 | ' | 13.5 | ' |
Earn out threshold, first threshold amount | ' | ' | ' | 50 | ' |
Amount of new signed construction/engineering contracts needed for contingent consideration to be considered paid in full | ' | ' | ' | 200 | ' |
Adjusted net working capital | ' | 2.2 | ' | 2.2 | ' |
Depreciable fixed assets | ' | 0.4 | ' | 0.4 | ' |
Customer Relationships (Sales Funnel) | ' | 7.1 | ' | 7.1 | ' |
ESPC Licenses | ' | 6 | ' | 6 | ' |
Deferred Tax Asset | ' | 0.8 | ' | 0.8 | ' |
Goodwill | ' | 27.2 | ' | 27.2 | ' |
Total assets acquired | ' | 43.7 | ' | 43.7 | ' |
Less: Unfavorable Contract Liabilities Assumed | ' | -2.1 | ' | -2.1 | ' |
Total Purchase Consideration | ' | 41.6 | ' | 41.6 | ' |
Goodwill deductibility period for income tax purposes | ' | ' | ' | '15 years | ' |
Transaction Costs | ' | 1.6 | ' | 1.6 | ' |
Amount of Transaction Costs in Other Cost and Expense, Operating | ' | ' | ' | 0.7 | ' |
Pro Forma Revenue | ' | 4.2 | 8.6 | 8.1 | 16.6 |
Pro Forma Income (Loss) | ' | ($0.50) | ' | ' | ' |
Sale_of_Vectren_Fuels_Inc_Deta
Sale of Vectren Fuels, Inc. (Details) (USD $) | 6 Months Ended |
In Millions, unless otherwise specified | Jun. 30, 2014 |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ' |
Expected cash proceeds from sale | $296 |
Loss on disposal, after tax | 20 |
Change in working capital | 24 |
Expected Gross Sales Proceeds | 320 |
Transaction costs associated with disposal | 10 |
Accounts Receivable | 13.1 |
Coal Inventory | 40.4 |
Materials & Supplies | 13.2 |
Other Current Assets | 1.8 |
Property and Equipment | 277.1 |
Non-current assets | 2.7 |
Total assets held for sale | 348.3 |
Accounts Payable | 10.9 |
Other Current Liabilities | 14.9 |
Noncurrent liabilities | 12.2 |
Total liabilities held for sale | 38 |
Net assets held for sale | $310.30 |
Financing_Activities_Details
Financing Activities (Details) (Fixed Rate Senior Unsecured Notes 2014637 [Member], Vectren Capital [Member], Unsecured Debt [Member], USD $) | 6 Months Ended |
In Millions, unless otherwise specified | Jun. 30, 2014 |
Fixed Rate Senior Unsecured Notes 2014637 [Member] | Vectren Capital [Member] | Unsecured Debt [Member] | ' |
Debt Instrument [Line Items] | ' |
Long-term Debt, Current Maturities | $30 |
Stated percentage rate (in hundredths) | 6.37% |
Maturity date | 11-Mar-14 |
Debt Instrument, Offering Date | 11-Mar-09 |
Commitments_and_Contingencies_
Commitments and Contingencies (Details) (USD $) | 0 Months Ended | 6 Months Ended | 6 Months Ended | ||||
In Millions, unless otherwise specified | Apr. 01, 2014 | Jun. 30, 2014 | Jun. 30, 2014 | Jun. 30, 2014 | Jun. 30, 2014 | Jun. 30, 2014 | Jun. 30, 2014 |
Guarantees for ESG [Member] | Performance Guarantee [Member] | Other Guarantees Outstanding [Member] | Other Guarantees Outstanding [Member] | Financial Standby Letter of Credit [Member] | Energy Performance Guarantee [Member] | ||
Guarantees for ESG [Member] | Guarantees for ESG [Member] | Guarantees for Other Unconsolidated Affiliates [Member] | Guarantees for Other Unconsolidated Affiliates [Member] | Guarantees for ESG [Member] | |||
Guarantor Obligations [Line Items] | ' | ' | ' | ' | ' | ' | ' |
Letter of Credit, Gross Amount | ' | $8 | ' | ' | ' | ' | ' |
Letters of Credit Outstanding, Amount | ' | 3.4 | ' | ' | ' | ' | ' |
Corporate Guarantees [Abstract] | ' | ' | ' | ' | ' | ' | ' |
Maximum exposure by parent company on guarantees | ' | ' | 25 | 45 | 24 | 18 | 140 |
Effective Date of Acquisition | 1-Apr-14 | ' | ' | ' | ' | ' | 1-Apr-14 |
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) | ' | ' | 53 | ' | ' | ' | ' |
Average face amount of surety bonds wholly owned subsidiary has outstanding | ' | ' | 5.5 | ' | ' | ' | ' |
Maximum face amount of surety bond wholly owned subsidiary has outstanding | ' | ' | $57.30 | ' | ' | ' | ' |
Percentage of work completed on projects covered by open surety bonds (in hundredths) | ' | ' | 42.00% | ' | ' | ' | ' |
Timeframe when significant portion of performance guarantee commitments will be fulfilled | ' | ' | '1 | ' | ' | ' | ' |
Rate_Regulatory_Matters_Detail
Rate & Regulatory Matters (Details) (USD $) | 6 Months Ended | 12 Months Ended | 6 Months Ended | 6 Months Ended | ||||||||
Jun. 30, 2014 | Dec. 31, 2012 | Dec. 31, 2011 | Feb. 01, 2014 | Jun. 30, 2014 | Dec. 31, 2013 | Jun. 30, 2014 | Jun. 30, 2014 | Dec. 31, 2013 | Jun. 30, 2014 | Jun. 30, 2014 | Jun. 30, 2014 | |
INDIANA | INDIANA | INDIANA | Ohio [Member] | Ohio [Member] | SIGECO [Member] | Indiana Gas [Member] | INDIANA | |||||
Indiana Recovery and Deferral Mechanisms [Member] | Indiana Recovery and Deferral Mechanisms [Member] | Pipeline Safety Law [Member] | Ohio Recovery and Deferral Mechanisms [Member] | Ohio Recovery and Deferral Mechanisms [Member] | INDIANA | INDIANA | Pipeline Safety Law [Member] | |||||
Indiana Recovery and Deferral Mechanisms [Member] | Indiana 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 | ' | ' | ' | ' | ' | ' | ' | $118,000,000 | ' | ' | ' | ' |
Regulatory Asset associated with DRR deferrals of depreciation and post in-service carrying costs | ' | ' | ' | ' | ' | ' | ' | 11,200,000 | 9,300,000 | ' | ' | ' |
Initial DRR term | ' | ' | ' | ' | ' | ' | ' | 5 | ' | ' | ' | ' |
Period of extended DRR term | ' | ' | ' | ' | ' | ' | ' | 5 | ' | ' | ' | ' |
Amount of Capital Investment Expected Over Next Five Years Recoverable Under DRR | ' | ' | ' | ' | ' | ' | ' | 187,000,000 | ' | ' | ' | ' |
Time period (in months) included in VEDO application | ' | ' | ' | ' | ' | ' | ' | '15 | ' | ' | ' | ' |
Bill impact per customer per month | ' | ' | ' | ' | ' | ' | ' | 1.5 | ' | ' | ' | ' |
Allowable capital expenditures under Vectren programs | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3,000,000 | 20,000,000 | ' |
Limitations of deferrals of debt-related post in service carrying costs | ' | ' | ' | ' | ' | ' | ' | ' | ' | '3 | '4 | ' |
Regulatory Assset balance associated with Vectren north and south programs | ' | ' | ' | ' | 14,300,000 | 12,100,000 | ' | ' | ' | ' | ' | ' |
Expected Seven Year Period Modernization Investment | ' | ' | ' | ' | ' | ' | 865,000,000 | ' | ' | ' | ' | ' |
Upper range of expected annual operating costs associated with new pipeline safety regulations | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 30,000,000 |
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 | ' | ' | ' | ' | ' |
FERC approved ROE in NETO case | 10.57% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
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 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Period Of Coal Purchase Commitment | '4 years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Coal Procurement Procedures [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Number of years for recovery of coal costs | '6 years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Cumulative total deferrals related to coal purchases | 38,900,000 | ' | ' | 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 | 4,400,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Percent of industrial load opt out of applicable energy efficiency programs | 71.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
FERC Return On Equity Complaint [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Reduced return on equity percentage sought by third party | 9.15% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Equity component, upper limit, as a percentage, sought by third party | 50.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Gross Investment In Qualifying Transmission Projects | 157,600,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Net Investment in Qualifying Transmission Projects | $145,200,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Percentage return recommended by FERC on ROE complaint against NETO | 9.70% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Incentive return granted on qualifying investments in NETO | 11.14% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Current return on equity used in MISO transmission owners rates | 12.38% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Environmental_Matters_Details
Environmental Matters (Details) (USD $) | 6 Months Ended | 12 Months Ended |
In Millions, unless otherwise specified | Jun. 30, 2014 | Dec. 31, 2013 |
MW | T | |
Site Contingency [Line Items] | ' | ' |
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] | ' | ' |
Potential capital investment of using 'best technology available' (BTA) to minimize adverse impacts in a body of water - lower range | 4 | ' |
Potential capital investment of using 'best technology available' (BTA) to minimize adverse impacts in a body of water - upper range | 8 | ' |
Coal Ash Waste Disposal and Ash Ponds [Abstract] | ' | ' |
Estimated capital expenditures to comply with ash pond and coal ash disposal regulations | 30 | ' |
Potential estimated capital expenditures to comply with ash pond and coal ash disposal regulations with stringent alternative | 100 | ' |
Estimated annual compliance costs maximum with ash pond and coal ash disposal regulation | 5 | ' |
Climate Changes [Abstract] | ' | ' |
Maximum level of greenhouse gas emissions that prompts requirement to obtain permit for facilities to construct new facility of significant modification to existing facility (in tons) | 75,000 | ' |
Vectren's share of Indiana's total CO2 emmisions in 2013 (in tons) | ' | 6,300,000 |
Vectren's share of Indiana's CO2 emissions in 2013 (as a percent) | ' | 6.00% |
Percent reduction of Vectren's CO2 emissions since 2005 | 23.00% | ' |
Vectren's emission rate (as measured in lbs CO2/MWh) prior to installation of new technology | 1,967 | ' |
Vectren's emission rate (as measured in lbs CO2/MWh) after installation of new technology | 1,922 | ' |
Percentage reduction of lbs CO2/MWh since 2005 | 3.00% | ' |
Indiana Senate Bill 251 [Abstract] | ' | ' |
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) | 4.00% | ' |
Manufactured Gas Plants | ' | ' |
Site contingency, accrual, undiscounted amount | 43.4 | ' |
Accrual for Environmental Loss Contingencies | 4.6 | 5.7 |
Indiana Gas [Member] | ' | ' |
Manufactured Gas Plants | ' | ' |
Site contingency, accrual, undiscounted amount | 23.2 | ' |
Number of sites identified with potential remedial responsibility for entity (in number of sites) | 26 | ' |
Environmental cost recognized, recover from insurance carriers credited to expense | 20.8 | ' |
SIGECO [Member] | ' | ' |
Manufactured Gas Plants | ' | ' |
Site contingency, accrual, undiscounted amount | 20.2 | ' |
Number of sites identified with potential remedial responsibility for entity (in number of sites) | 5 | ' |
Environmental cost recognized, recover from insurance carriers credited to expense | 14.3 | ' |
Expected Site Contingency Recovery from Insurance Carriers of Environmental Remediation Costs | $15.80 | ' |
Fair_Value_Measurements_Detail
Fair Value Measurements (Details) (USD $) | 6 Months Ended | ||||
In Millions, unless otherwise specified | Jun. 30, 2014 | Jun. 30, 2014 | Dec. 31, 2013 | Jun. 30, 2014 | Dec. 31, 2013 |
Estimated Fair Value [Member] | Estimated Fair Value [Member] | Carrying Amount [Member] | Carrying Amount [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ' | ' | ' | ' | ' |
Long-term debt | ' | $1,960.10 | $1,895.20 | $1,777.20 | $1,807.10 |
Short-term Debt, Fair Value | ' | 79.1 | 68.6 | 79.1 | 68.6 |
Cash and cash equivalents | ' | 8.4 | 21.5 | 8.4 | 21.5 |
Recovery period for call premiums on reacquisition of utility long-term debt (in years) | '15 | ' | ' | ' | ' |
Notes Receivable, Fair Value Disclosure | $10.40 | ' | ' | ' | ' |
Segment_Reporting_Details
Segment Reporting (Details) (USD $) | 3 Months Ended | 6 Months Ended | ||
In Millions, unless otherwise specified | Jun. 30, 2014 | Jun. 30, 2013 | Jun. 30, 2014 | Jun. 30, 2013 |
Segment Reporting [Abstract] | ' | ' | ' | ' |
Portion of Indiana that is provided natural gas distribution and transportation services by the Gas Utility Services segment (in hundredths) | 66.67% | ' | 66.67% | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' |
Revenues | $542.50 | $531 | $1,339.30 | $1,231.60 |
Net income (loss) | 11.9 | -5.8 | 63.1 | 44 |
Utility Group [Member] | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' |
Revenues | 284.5 | 292.8 | 891.1 | 758.3 |
Net income (loss) | 22.9 | 24.2 | 84.2 | 79.3 |
Number of reportable segments | ' | ' | 3 | ' |
Utility Group [Member] | Gas Utility Services [Member] | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' |
Revenues | 132.4 | 138 | 576 | 453.9 |
Net income (loss) | 0.7 | 2.9 | 39 | 41 |
Utility Group [Member] | Electric Utility Services [Member] | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' |
Revenues | 152 | 154.7 | 315 | 304.2 |
Net income (loss) | 19.9 | 18.9 | 39.2 | 33.5 |
Utility Group [Member] | Other Segments [Member] | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' |
Revenues | 9.5 | 9.5 | 19.1 | 19 |
Net income (loss) | 2.3 | 2.4 | 6 | 4.8 |
Utility Group [Member] | Intersegment Eliminations [Member] | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' |
Revenues | -9.4 | -9.4 | -19 | -18.8 |
Nonutility Group [Member] | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' |
Revenues | 296.3 | 270.4 | 518.3 | 525.8 |
Net income (loss) | -10.8 | -29.7 | -20.5 | -35.1 |
Number of reportable segments | ' | ' | 5 | ' |
Nonutility Group [Member] | Infrastructure Services [Member] | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' |
Revenues | 178 | 174.4 | 301 | 346.2 |
Net income (loss) | 9.4 | 7.9 | 4.1 | 14.8 |
Nonutility Group [Member] | Energy Services [Member] | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' |
Revenues | 32.7 | 23.9 | 50.2 | 44.4 |
Net income (loss) | -1.8 | -0.8 | -4.8 | -2.2 |
Nonutility Group [Member] | Coal Mining [Member] | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' |
Revenues | 85.6 | 72.1 | 167.1 | 135.2 |
Net income (loss) | -18.2 | -3.7 | -19.3 | -9.7 |
Nonutility Group [Member] | Energy Marketing [Member] | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' |
Net income (loss) | 0 | -32.9 | 0 | -37.5 |
Nonutility Group [Member] | Other Businesses [Member] | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' |
Net income (loss) | -0.2 | -0.2 | -0.5 | -0.5 |
Corporate and Other [Member] | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' |
Revenues | 0.2 | 0 | 0.5 | 0 |
Net income (loss) | -0.2 | -0.3 | -0.6 | -0.2 |
Number of reportable segments | ' | ' | 1 | ' |
Consolidation, Eliminations [Member] | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' |
Revenues | ($38.50) | ($32.20) | ($70.60) | ($52.50) |