Document_and_Entity_Informatio
Document and Entity Information | 3 Months Ended | |
Mar. 31, 2014 | Apr. 30, 2014 | |
Entity Information [Line Items] | ' | ' |
Entity Registrant Name | 'VECTREN UTILITY HOLDINGS INC | ' |
Entity Central Index Key | '0001129542 | ' |
Current Fiscal Year End Date | '--12-31 | ' |
Entity Filer Category | 'Non-accelerated Filer | ' |
Entity Common Stock, Shares Outstanding | ' | 10 |
Document Fiscal Year Focus | '2014 | ' |
Document Fiscal Period Focus | 'Q1 | ' |
Document Type | '10-Q | ' |
Amendment Flag | 'false | ' |
Document Period End Date | 31-Mar-14 | ' |
CONSOLIDATED_CONDENSED_BALANCE
CONSOLIDATED CONDENSED BALANCE SHEETS (Unaudited) (USD $) | Mar. 31, 2014 | Dec. 31, 2013 |
In Millions, unless otherwise specified | ||
Assets, Current [Abstract] | ' | ' |
Cash & cash equivalents | $52.60 | $8.60 |
Accounts receivable - less reserves of $6.3 & $5.0, respectively | 160.1 | 112.1 |
Accrued unbilled revenues | 98.1 | 113.5 |
Inventories | 54.3 | 89.9 |
Recoverable fuel & natural gas costs | 27.1 | 5.5 |
Prepayments & other current assets | 10 | 42.4 |
Total current assets | 402.2 | 372 |
Utility Plant [Abstract] | ' | ' |
Original cost | 5,439 | 5,389.60 |
Less: accumulated depreciation & amortization | 2,198.80 | 2,165.30 |
Net utility plant | 3,240.20 | 3,224.30 |
Investments in unconsolidated affiliates | 0.2 | 0.2 |
Other Investments | 26.1 | 27.3 |
Nonutility plant - net | 150.7 | 150.5 |
Goodwill - net | 205 | 205 |
Regulatory assets | 114.4 | 136.2 |
Other assets | 23.7 | 25.3 |
TOTAL ASSETS | 4,162.50 | 4,140.80 |
Current Liabilities [Abstract] | ' | ' |
Accounts payable | 151.3 | 172.1 |
Payables to other Vectren companies | 26.5 | 24.6 |
Accrued liabilities | 164.5 | 127.4 |
Short-term borrowings | 0 | 28.6 |
Current maturities of long-term debt | 5 | 0 |
Total current liabilities | 347.3 | 352.7 |
Long-Term Debt - Net of Current Maturities | 1,252.20 | 1,257.10 |
Deferred Credits & Other Liabilities [Abstract] | ' | ' |
Deferred income taxes | 619.7 | 627.4 |
Regulatory liabilities | 393.4 | 387.3 |
Deferred credits & other liabilities | 81.3 | 83.5 |
Total deferred credits and other liabilities | 1,094.40 | 1,098.20 |
Commitments & Contingencies (Notes 7 - 9) | ' | ' |
Common Shareholder's Equity [Abstract] | ' | ' |
Common stock (no par value) | 789.3 | 787.7 |
Retained earnings | 679.3 | 645.1 |
Total common shareholders' equity | 1,468.60 | 1,432.80 |
TOTAL LIABILITIES and SHAREHOLDERS' EQUITY | $4,162.50 | $4,140.80 |
CONSOLIDATED_CONDENSED_BALANCE1
CONSOLIDATED CONDENSED BALANCE SHEETS (Unaudited) (Parenthetical) (USD $) | Mar. 31, 2014 | Dec. 31, 2013 |
In Millions, unless otherwise specified | ||
Assets, Current [Abstract] | ' | ' |
Allowance for Doubtful Accounts Receivable, Current | $6.30 | $5 |
CONSOLIDATED_CONDENSED_STATEME
CONSOLIDATED CONDENSED STATEMENTS OF INCOME (Unaudited) (USD $) | 3 Months Ended | |
In Millions, unless otherwise specified | Mar. 31, 2014 | Mar. 31, 2013 |
OPERATING REVENUES [Abstract] | ' | ' |
Gas utility | $443.60 | $315.90 |
Electric utility | 163 | 149.5 |
Other | 0 | 0.1 |
Total operating revenues | 606.6 | 465.5 |
OPERATING EXPENSES [Abstract] | ' | ' |
Cost of gas sold | 270.9 | 157.2 |
Cost of fuel & purchased power | 57 | 50.2 |
Other operating | 98.3 | 86.8 |
Depreciation & Amortization | 49.9 | 48.4 |
Taxes other than income taxes | 20.1 | 17.5 |
Total operating expenses | 496.2 | 360.1 |
OPERATING INCOME | 110.4 | 105.4 |
Nonoperating Income (Expense) [Abstract] | ' | ' |
Other income - net | 3.9 | 1.8 |
Interest Expense | 16.7 | 17.9 |
INCOME BEFORE INCOME TAXES | 97.6 | 89.3 |
Income taxes | 36.3 | 34.2 |
NET INCOME | $61.30 | $55.10 |
CONSOLIDATED_CONDENSED_STATEME1
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS (Unaudited) (USD $) | 3 Months Ended | |
In Millions, unless otherwise specified | Mar. 31, 2014 | Mar. 31, 2013 |
CASH FLOWS FROM OPERATING ACTIVITIES [Abstract] | ' | ' |
Profitability Measure - Net income (loss) | $61.30 | $55.10 |
Adjustments to Reconcile Net Income to Cash from Operating Activities [Abstract] | ' | ' |
Depreciation & Amortization | 49.9 | 48.4 |
Deferred income taxes & investment tax credits | 5 | 10.2 |
Expense portion of pension & postretirement periodic benefit cost | 1.2 | 1.4 |
Provision for uncollectible accounts | 1.6 | 2.4 |
Other non-cash expense - net | 0.9 | 1.9 |
Changes in working capital accounts [Abstract] | ' | ' |
Accounts receivable & accrued unbilled revenue | -34.1 | -31 |
Inventories | 35.6 | 32.3 |
Recoverable/refundable fuel & natural gas costs | -24.2 | 15.1 |
Prepayments & other current assets | 26.8 | 30.1 |
Accounts payable, including to Vectren companies & affiliated companies | -18.4 | -28.9 |
Accrued liabilities | 39.7 | 18.3 |
Changes in noncurrent ssets | 13.3 | 6.8 |
Changes in noncurrent liabilities | -2.6 | -0.8 |
Net cash provided by operating activities | 156 | 161.3 |
Proceeds from: | ' | ' |
Additional capital contribution | 1.6 | 1.5 |
Requirements for: | ' | ' |
Dividends to parent | -27.1 | -26.3 |
Net change in short-term borrowings | -28.6 | -89.6 |
Net cash used in financing activities | -54.1 | -114.4 |
CASH FLOWS FROM INVESTING ACTIVITIES [Abstract] | ' | ' |
Proceeds from other investing activities | 0.1 | 0.1 |
Requirements for: | ' | ' |
Capital expenditures, excluding AFUDC equity | -58 | -50.5 |
Net cash used in investing activities | -57.9 | -50.4 |
Net change in cash and cash equivalents | 44 | -3.5 |
Cash and cash equivalents at beginning of period | 8.6 | 13.3 |
Cash and cash equivalents at end of period | $52.60 | $9.80 |
Organization_and_Nature_of_Ope
Organization and Nature of Operations | 3 Months Ended |
Mar. 31, 2014 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | ' |
Organization and Nature of Operations | ' |
Organization and Nature of Operations | |
Vectren Utility Holdings, Inc. (the Company, Utility Holdings or VUHI), an Indiana corporation, was formed on March 31, 2000 to serve as the intermediate holding company for Vectren Corporation’s (Vectren) three operating public utilities: Indiana Gas Company, Inc. (Indiana Gas or Vectren North), Southern Indiana Gas and Electric Company (SIGECO or Vectren South), and Vectren Energy Delivery of Ohio, Inc. (VEDO). Utility Holdings also has other assets that provide information technology and other services to the three utilities. Vectren, an Indiana corporation, is an energy holding company headquartered in Evansville, Indiana and was organized on June 10, 1999. Both Vectren and Utility Holdings are holding companies as defined by the Energy Policy Act of 2005 (Energy Act). | |
Indiana Gas provides energy delivery services to approximately 581,000 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 316,000 natural gas customers located near Dayton in west central Ohio. |
Basis_of_Presentation
Basis of Presentation | 3 Months Ended |
Mar. 31, 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 March 5, 2014, on Form 10-K. Because of the seasonal nature of the Company’s utility 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. |
Subsidiary_Guarantor_and_Conso
Subsidiary Guarantor and Consolidating Information | 3 Months Ended | |||||||||||||||
Mar. 31, 2014 | ||||||||||||||||
Subsidiary Guarantor and Consolidating Information [Abstract] | ' | |||||||||||||||
Subsidiary Guarantor and Consolidating Information [Text Block] | ' | |||||||||||||||
Subsidiary Guarantor and Consolidating Information | ||||||||||||||||
The Company’s three operating utility companies, SIGECO, Indiana Gas, and VEDO are guarantors of Utility Holdings’ $350 million in short-term credit facilities, of which none was outstanding at March 31, 2014, and Utility Holdings’ has unsecured senior notes with a par value of $875 million outstanding at March 31, 2014. The guarantees are full and unconditional and joint and several, and Utility Holdings has no direct subsidiaries other than the subsidiary guarantors. However, Utility Holdings does have operations other than those of the subsidiary guarantors. Pursuant to Item 3-10 of Regulation S-X, disclosure of the results of operations and balance sheets of the subsidiary guarantors, which are 100 percent owned, separate from the parent company’s operations is required. Following are consolidating financial statements including information on the combined operations of the subsidiary guarantors separate from the other operations of the parent company. Pursuant to a tax sharing agreement, consolidating tax effects, which are calculated on a separate return basis, are reflected at the parent level. | ||||||||||||||||
Condensed Consolidating Balance Sheet as of March 31, 2014 (in millions): | ||||||||||||||||
ASSETS | Subsidiary | Parent | Eliminations & | |||||||||||||
Guarantors | Company | Reclassifications | Consolidated | |||||||||||||
Current Assets | ||||||||||||||||
Cash & cash equivalents | $ | 35.8 | $ | 16.8 | $ | — | $ | 52.6 | ||||||||
Accounts receivable - less reserves | 160.1 | — | — | 160.1 | ||||||||||||
Intercompany receivables | 85.9 | 14.1 | (100.0 | ) | — | |||||||||||
Accrued unbilled revenues | 98.1 | — | — | 98.1 | ||||||||||||
Inventories | 54.3 | — | — | 54.3 | ||||||||||||
Recoverable fuel & natural gas costs | 27.1 | — | — | 27.1 | ||||||||||||
Prepayments & other current assets | 11.2 | 34.8 | (36.0 | ) | 10 | |||||||||||
Total current assets | 472.5 | 65.7 | (136.0 | ) | 402.2 | |||||||||||
Utility Plant | ||||||||||||||||
Original cost | 5,439.00 | — | — | 5,439.00 | ||||||||||||
Less: accumulated depreciation & amortization | 2,198.80 | — | — | 2,198.80 | ||||||||||||
Net utility plant | 3,240.20 | — | — | 3,240.20 | ||||||||||||
Investments in consolidated subsidiaries | — | 1,409.60 | (1,409.6 | ) | — | |||||||||||
Notes receivable from consolidated subsidiaries | — | 820.6 | (820.6 | ) | — | |||||||||||
Investments in unconsolidated affiliates | 0.2 | — | — | 0.2 | ||||||||||||
Other investments | 21.7 | 4.4 | — | 26.1 | ||||||||||||
Nonutility property - net | 2.1 | 148.6 | — | 150.7 | ||||||||||||
Goodwill - net | 205 | — | — | 205 | ||||||||||||
Regulatory assets | 91.9 | 22.5 | — | 114.4 | ||||||||||||
Other assets | 31 | 1.1 | (8.4 | ) | 23.7 | |||||||||||
TOTAL ASSETS | $ | 4,064.60 | $ | 2,472.50 | $ | (2,374.6 | ) | $ | 4,162.50 | |||||||
LIABILITIES & SHAREHOLDER'S EQUITY | Subsidiary | Parent | Eliminations & | |||||||||||||
Guarantors | Company | Reclassifications | Consolidated | |||||||||||||
Current Liabilities | ||||||||||||||||
Accounts payable | $ | 146.8 | $ | 4.5 | $ | — | $ | 151.3 | ||||||||
Intercompany payables | 14.1 | — | (14.1 | ) | — | |||||||||||
Payables to other Vectren companies | 26.5 | — | — | 26.5 | ||||||||||||
Accrued liabilities | 181.6 | 18.9 | (36.0 | ) | 164.5 | |||||||||||
Intercompany short-term borrowings | — | 85.9 | (85.9 | ) | — | |||||||||||
Current maturities of long-term debt | 5 | — | — | 5 | ||||||||||||
Total current liabilities | 374 | 109.3 | (136.0 | ) | 347.3 | |||||||||||
Long-Term Debt | ||||||||||||||||
Long-term debt | 377.6 | 874.6 | — | 1,252.20 | ||||||||||||
Long-term debt due to VUHI | 820.6 | — | (820.6 | ) | — | |||||||||||
Total long-term debt - net | 1,198.20 | 874.6 | (820.6 | ) | 1,252.20 | |||||||||||
Deferred Credits & Other Liabilities | ||||||||||||||||
Deferred income taxes | 605.5 | 14.2 | — | 619.7 | ||||||||||||
Regulatory liabilities | 391.8 | 1.6 | — | 393.4 | ||||||||||||
Deferred credits & other liabilities | 85.5 | 4.2 | (8.4 | ) | 81.3 | |||||||||||
Total deferred credits & other liabilities | 1,082.80 | 20 | (8.4 | ) | 1,094.40 | |||||||||||
Common Shareholder's Equity | ||||||||||||||||
Common stock (no par value) | 802.5 | 789.3 | (802.5 | ) | 789.3 | |||||||||||
Retained earnings | 607.1 | 679.3 | (607.1 | ) | 679.3 | |||||||||||
Total common shareholder's equity | 1,409.60 | 1,468.60 | (1,409.6 | ) | 1,468.60 | |||||||||||
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY | $ | 4,064.60 | $ | 2,472.50 | $ | (2,374.6 | ) | $ | 4,162.50 | |||||||
Condensed Consolidating Balance Sheet as of December 31, 2013 (in millions): | ||||||||||||||||
ASSETS | Subsidiary | Parent | Eliminations & | |||||||||||||
Guarantors | Company | Reclassifications | Consolidated | |||||||||||||
Current Assets | ||||||||||||||||
Cash & cash equivalents | $ | 8.2 | $ | 0.4 | $ | — | $ | 8.6 | ||||||||
Accounts receivable - less reserves | 112.1 | — | — | 112.1 | ||||||||||||
Intercompany receivables | 0.3 | 84.8 | (85.1 | ) | — | |||||||||||
Accrued unbilled revenues | 113.5 | — | — | 113.5 | ||||||||||||
Inventories | 89.9 | — | — | 89.9 | ||||||||||||
Recoverable fuel & natural gas costs | 5.5 | — | — | 5.5 | ||||||||||||
Prepayments & other current assets | 37.3 | 40.1 | (35.0 | ) | 42.4 | |||||||||||
Total current assets | 366.8 | 125.3 | (120.1 | ) | 372 | |||||||||||
Utility Plant | ||||||||||||||||
Original cost | 5,389.60 | — | — | 5,389.60 | ||||||||||||
Less: accumulated depreciation & amortization | 2,165.30 | — | — | 2,165.30 | ||||||||||||
Net utility plant | 3,224.30 | — | — | 3,224.30 | ||||||||||||
Investments in consolidated subsidiaries | — | 1,375.80 | (1,375.8 | ) | — | |||||||||||
Notes receivable from consolidated subsidiaries | — | 696.4 | (696.4 | ) | — | |||||||||||
Investments in unconsolidated affiliates | 0.2 | — | — | 0.2 | ||||||||||||
Other investments | 22.8 | 4.5 | — | 27.3 | ||||||||||||
Nonutility property - net | 2.2 | 148.3 | — | 150.5 | ||||||||||||
Goodwill - net | 205 | — | — | 205 | ||||||||||||
Regulatory assets | 113.4 | 22.8 | — | 136.2 | ||||||||||||
Other assets | 32.2 | 1 | (7.9 | ) | 25.3 | |||||||||||
TOTAL ASSETS | $ | 3,966.90 | $ | 2,374.10 | $ | (2,200.2 | ) | $ | 4,140.80 | |||||||
LIABILITIES & SHAREHOLDER'S EQUITY | Subsidiary | Parent | Eliminations & | |||||||||||||
Guarantors | Company | Reclassifications | Consolidated | |||||||||||||
Current Liabilities | ||||||||||||||||
Accounts payable | $ | 161.6 | $ | 10.5 | $ | — | $ | 172.1 | ||||||||
Intercompany payables | 11.7 | — | (11.7 | ) | — | |||||||||||
Payables to other Vectren companies | 24.6 | — | — | 24.6 | ||||||||||||
Accrued liabilities | 150.3 | 12.1 | (35.0 | ) | 127.4 | |||||||||||
Short-term borrowings | — | 28.6 | — | 28.6 | ||||||||||||
Intercompany short-term borrowings | 73.1 | 0.3 | (73.4 | ) | — | |||||||||||
Total current liabilities | 421.3 | 51.5 | (120.1 | ) | 352.7 | |||||||||||
Long-Term Debt | ||||||||||||||||
Long-term debt - net of current maturities & | ||||||||||||||||
debt subject to tender | 382.5 | 874.6 | — | 1,257.10 | ||||||||||||
Long-term debt due to VUHI | 696.4 | — | (696.4 | ) | — | |||||||||||
Total long-term debt - net | 1,078.90 | 874.6 | (696.4 | ) | 1,257.10 | |||||||||||
Deferred Credits & Other Liabilities | ||||||||||||||||
Deferred income taxes | 616.9 | 10.5 | — | 627.4 | ||||||||||||
Regulatory liabilities | 385.7 | 1.6 | — | 387.3 | ||||||||||||
Deferred credits & other liabilities | 88.3 | 3.1 | (7.9 | ) | 83.5 | |||||||||||
Total deferred credits & other liabilities | 1,090.90 | 15.2 | (7.9 | ) | 1,098.20 | |||||||||||
Common Shareholder's Equity | ||||||||||||||||
Common stock (no par value) | 800.9 | 787.7 | (800.9 | ) | 787.7 | |||||||||||
Retained earnings | 574.9 | 645.1 | (574.9 | ) | 645.1 | |||||||||||
Total common shareholder's equity | 1,375.80 | 1,432.80 | (1,375.8 | ) | 1,432.80 | |||||||||||
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY | $ | 3,966.90 | $ | 2,374.10 | $ | (2,200.2 | ) | $ | 4,140.80 | |||||||
Condensed Consolidating Statement of Income for the three months ended March 31, 2014 (in millions): | ||||||||||||||||
Subsidiary | Parent | Eliminations & | Consolidated | |||||||||||||
Guarantors | Company | Reclassifications | ||||||||||||||
OPERATING REVENUES | ||||||||||||||||
Gas utility | $ | 443.6 | $ | — | $ | — | $ | 443.6 | ||||||||
Electric utility | 163 | — | — | 163 | ||||||||||||
Other | — | 9.6 | (9.6 | ) | — | |||||||||||
Total operating revenues | 606.6 | 9.6 | (9.6 | ) | 606.6 | |||||||||||
OPERATING EXPENSES | ||||||||||||||||
Cost of gas sold | 270.9 | — | — | 270.9 | ||||||||||||
Cost of fuel & purchased power | 57 | — | — | 57 | ||||||||||||
Other operating | 107.5 | — | (9.2 | ) | 98.3 | |||||||||||
Depreciation & amortization | 44.4 | 5.4 | 0.1 | 49.9 | ||||||||||||
Taxes other than income taxes | 19.6 | 0.4 | 0.1 | 20.1 | ||||||||||||
Total operating expenses | 499.4 | 5.8 | (9.0 | ) | 496.2 | |||||||||||
OPERATING INCOME | 107.2 | 3.8 | (0.6 | ) | 110.4 | |||||||||||
Other income - net | 3 | 10.7 | (9.8 | ) | 3.9 | |||||||||||
Interest expense | 15.8 | 11.3 | (10.4 | ) | 16.7 | |||||||||||
INCOME BEFORE INCOME TAXES | 94.4 | 3.2 | — | 97.6 | ||||||||||||
Income taxes | 36.8 | (0.5 | ) | — | 36.3 | |||||||||||
Equity in earnings of consolidated companies, net of tax | — | 57.6 | (57.6 | ) | — | |||||||||||
NET INCOME | $ | 57.6 | $ | 61.3 | $ | (57.6 | ) | $ | 61.3 | |||||||
Condensed Consolidating Statement of Income for the three months ended March 31, 2013 (in millions): | ||||||||||||||||
Subsidiary | Parent | Eliminations & | Consolidated | |||||||||||||
Guarantors | Company | Reclassifications | ||||||||||||||
OPERATING REVENUES | ||||||||||||||||
Gas utility | $ | 315.9 | $ | — | $ | — | $ | 315.9 | ||||||||
Electric utility | 149.5 | — | — | 149.5 | ||||||||||||
Other | — | 9.5 | (9.4 | ) | 0.1 | |||||||||||
Total operating revenues | 465.4 | 9.5 | (9.4 | ) | 465.5 | |||||||||||
OPERATING EXPENSES | ||||||||||||||||
Cost of gas sold | 157.2 | — | — | 157.2 | ||||||||||||
Cost of fuel & purchased power | 50.2 | — | — | 50.2 | ||||||||||||
Other operating | 96 | — | (9.2 | ) | 86.8 | |||||||||||
Depreciation & amortization | 43.1 | 5.2 | 0.1 | 48.4 | ||||||||||||
Taxes other than income taxes | 17.1 | 0.4 | — | 17.5 | ||||||||||||
Total operating expenses | 363.6 | 5.6 | (9.1 | ) | 360.1 | |||||||||||
OPERATING INCOME | 101.8 | 3.9 | (0.3 | ) | 105.4 | |||||||||||
Other income - net | 1.9 | 9.7 | (9.8 | ) | 1.8 | |||||||||||
Interest expense | 16.2 | 11.8 | (10.1 | ) | 17.9 | |||||||||||
INCOME BEFORE INCOME TAXES | 87.5 | 1.8 | — | 89.3 | ||||||||||||
Income taxes | 34.8 | (0.6 | ) | — | 34.2 | |||||||||||
Equity in earnings of consolidated companies, net of tax | — | 52.7 | (52.7 | ) | — | |||||||||||
NET INCOME | $ | 52.7 | $ | 55.1 | $ | (52.7 | ) | $ | 55.1 | |||||||
Condensed Consolidating Statement of Cash Flows for the three months ended March 31, 2014 (in millions): | ||||||||||||||||
Subsidiary | Parent | Eliminations | Consolidated | |||||||||||||
Guarantors | Company | |||||||||||||||
NET CASH PROVIDED BY OPERATING ACTIVITIES | $ | 137.2 | $ | 18.8 | $ | — | $ | 156 | ||||||||
CASH FLOWS FROM FINANCING ACTIVITIES | ||||||||||||||||
Proceeds from | ||||||||||||||||
Long-term debt - net of issuance costs | 124.2 | — | (124.2 | ) | — | |||||||||||
Additional capital contribution from parent | 1.6 | 1.6 | (1.6 | ) | 1.6 | |||||||||||
Requirements for: | ||||||||||||||||
Dividends to parent | (25.4 | ) | (27.1 | ) | 25.4 | (27.1 | ) | |||||||||
Net change in intercompany short-term borrowings | (73.1 | ) | 85.6 | (12.5 | ) | — | ||||||||||
Net change in short-term borrowings | — | (28.6 | ) | — | (28.6 | ) | ||||||||||
Net cash used in financing activities | 27.3 | 31.5 | (112.9 | ) | (54.1 | ) | ||||||||||
CASH FLOWS FROM INVESTING ACTIVITIES | ||||||||||||||||
Proceeds from: | ||||||||||||||||
Consolidated subsidiary distributions | — | 25.4 | (25.4 | ) | — | |||||||||||
Other investing activities | — | 0.1 | — | 0.1 | ||||||||||||
Requirements for: | ||||||||||||||||
Capital expenditures, excluding AFUDC equity | (51.3 | ) | (6.7 | ) | — | (58.0 | ) | |||||||||
Consolidated subsidiary investments | — | (1.6 | ) | 1.6 | — | |||||||||||
Net change in long-term intercompany notes receivable | — | (124.2 | ) | 124.2 | — | |||||||||||
Net change in short-term intercompany notes receivable | (85.6 | ) | 73.1 | 12.5 | — | |||||||||||
Net cash used in investing activities | (136.9 | ) | (33.9 | ) | 112.9 | (57.9 | ) | |||||||||
Net change in cash & cash equivalents | 27.6 | 16.4 | — | 44 | ||||||||||||
Cash & cash equivalents at beginning of period | 8.2 | 0.4 | — | 8.6 | ||||||||||||
Cash & cash equivalents at end of period | $ | 35.8 | $ | 16.8 | $ | — | $ | 52.6 | ||||||||
Condensed Consolidating Statement of Cash Flows for the three months ended March 31, 2013 (in millions): | ||||||||||||||||
Subsidiary | Parent | Eliminations | Consolidated | |||||||||||||
Guarantors | Company | |||||||||||||||
NET CASH PROVIDED BY OPERATING ACTIVITIES | $ | 168.5 | $ | (7.0 | ) | $ | (0.2 | ) | $ | 161.3 | ||||||
CASH FLOWS FROM FINANCING ACTIVITIES | ||||||||||||||||
Proceeds from: | ||||||||||||||||
Additional capital contribution to parent | 8.5 | 1.5 | (8.5 | ) | 1.5 | |||||||||||
Requirements for: | ||||||||||||||||
Dividends to parent | (24.5 | ) | (26.3 | ) | 24.5 | (26.3 | ) | |||||||||
Net change in intercompany short-term borrowings | (83.1 | ) | 28.9 | 54.2 | — | |||||||||||
Net change in short-term borrowings | — | (89.6 | ) | — | (89.6 | ) | ||||||||||
Net cash used in financing activities | (99.1 | ) | (85.5 | ) | 70.2 | (114.4 | ) | |||||||||
CASH FLOWS FROM INVESTING ACTIVITIES | ||||||||||||||||
Proceeds from: | ||||||||||||||||
Consolidated subsidiary distributions | — | 24.5 | (24.5 | ) | — | |||||||||||
Other investing activities | — | 0.1 | — | 0.1 | ||||||||||||
Requirements for: | ||||||||||||||||
Capital expenditures, excluding AFUDC equity | (47.3 | ) | (3.4 | ) | 0.2 | (50.5 | ) | |||||||||
Consolidated subsidiary investments | — | (8.5 | ) | 8.5 | — | |||||||||||
Net change in short-term intercompany notes receivable | (28.9 | ) | 83.1 | (54.2 | ) | — | ||||||||||
Net cash used in investing activities | (76.2 | ) | 95.8 | (70.0 | ) | (50.4 | ) | |||||||||
Net change in cash & cash equivalents | (6.8 | ) | 3.3 | — | (3.5 | ) | ||||||||||
Cash & cash equivalents at beginning of period | 12.5 | 0.8 | — | 13.3 | ||||||||||||
Cash & cash equivalents at end of period | $ | 5.7 | $ | 4.1 | $ | — | $ | 9.8 | ||||||||
Excise_and_Utility_Receipts_Ta
Excise and Utility Receipts Taxes | 3 Months Ended |
Mar. 31, 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 $12.9 million and $10.7 million in the three months ended March 31, 2014 and 2013 respectively, as a component of operating revenues. Expense associated with excise and utility receipts taxes are recorded as a component of Taxes other than income taxes. |
Accruals_for_Utility_and_NonUt
Accruals for Utility and NonUtility Plant | 3 Months Ended |
Mar. 31, 2014 | |
Accruals for Utility & Nonutility Plant [Abstract] | ' |
Accruals for Utility and NonUtility Plant [Text Block] | ' |
As of March 31, 2014 and December 31, 2013, the Company has accruals related to utility and nonutility plant purchases totaling approximately $13.0 million and $13.1 million, respectively. |
Transactions_with_Other_Vectre
Transactions with Other Vectren Companies and Affiliates | 3 Months Ended |
Mar. 31, 2014 | |
Transactions with Other Vectren Companies and Affiliates [Abstract] | ' |
Transactions With Other Vectren Companies and Affiliates [Text Block] | ' |
Transactions with Other Vectren Companies and Affiliates | |
Vectren Fuels, Inc. (Vectren Fuels) | |
Vectren Fuels, a wholly owned subsidiary of Vectren, owns coal mines from which SIGECO purchases coal used for electric generation. The price of coal that is charged by Vectren Fuels to SIGECO is priced consistent with contracts reviewed by the OUCC and on file with the IURC. Amounts purchased for the three months ended March 31, 2014 and 2013 totaled $30.8 million and $19.9 million, respectively. Amounts owed to Vectren Fuels at March 31, 2014 and December 31, 2013 are included in Payables to other Vectren companies in the Condensed Consolidated Balance Sheets. | |
Vectren Infrastructure Services Corporation (VISCO) | |
VISCO, a wholly owned subsidiary of Vectren, performs natural gas and water distribution, transmission, and construction repair and rehabilitation primarily in the Midwest and the repair and rehabilitation of gas, water, and wastewater facilities nationwide. In addition, VISCO also provides transmission pipeline construction and maintenance; pump station, compressor station, terminal and refinery construction; and hydrostatic testing to customers generally in the northern Midwest region. VISCO's customers include Utility Holdings’ utilities. Fees incurred by Utility Holdings and its subsidiaries totaled $11.4 million and $10.4 million for the three months ended March 31, 2014 and 2013, respectively. Amounts owed to VISCO at March 31, 2014 and December 31, 2013 are included in Payables to other Vectren companies in the Condensed Consolidated Balance Sheets. | |
ProLiance Holdings, LLC (ProLiance) | |
Vectren 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 of its energy marketing business, ProLiance Energy, LLC (ProLiance Energy). ProLiance Energy provided services to a broad range of municipalities, utilities, industrial operations, schools, and healthcare institutions located throughout the Midwest and Southeast United States. ProLiance Energy’s customers included, among others, Vectren’s Indiana utilities as well as Citizens’ utilities. | |
Purchases from ProLiance for resale and for injections into storage for the three months ended March 31, 2013 totaled $107.6 million. The Company had no purchases during 2014 as a result of Proliance exiting the natural gas marketing business. The Company did not have any amounts owed to ProLiance for purchases at March 31, 2014 and at December 31, 2013. Amounts charged by ProLiance for gas supply services were established by supply agreements with each utility. After the exit of the energy marketing business by ProLiance, the Company purchases gas supply from third parties and 83 percent is from a single third party. | |
Support Services & Purchases | |
Vectren provides corporate and general and administrative services to the Company and allocates certain costs to the Company, including costs for share-based compensation and for pension and other postretirement benefits that are not directly charged to subsidiaries. These costs are allocated using various allocators, including number of employees, number of customers and/or the level of payroll, revenue contribution and capital expenditures. Allocations are at cost. For the three months ended March 31, 2014 and 2013, Utility Holdings received corporate allocations totaling $14.7 million and $14.9 million, respectively. | |
The Company does not have share-based compensation plans and pension and other postretirement plans separate from Vectren and allocated costs include participation in Vectren's plans. The allocation methodology for retirement costs is consistent with FASB guidance related to “multiemployer” benefit accounting. |
Commitments_and_Contingencies
Commitments and Contingencies | 3 Months Ended |
Mar. 31, 2014 | |
Commitments and Contingencies Disclosure [Abstract] | ' |
Commitments and Contingencies | ' |
Commitments & Contingencies | |
Commitments | |
The Company has 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. | |
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 | 3 Months Ended |
Mar. 31, 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, the primary purpose of which is preventive maintenance and continual renewal and operational improvement. Laws in both Indiana and Ohio were passed that expand the ability of utilities to recover certain costs of federally mandated projects and other infrastructure improvement projects, outside of a base rate proceeding. Utilization of these recovery mechanisms is discussed below. | |
Ohio Recovery and Deferral Mechanisms | |
The PUCO order approving the Company's 2009 base rate case in the Ohio service territory authorized a distribution replacement rider (DRR). The DRR's primary purpose is recovery of investments in utility plant and related operating expenses associated with replacing bare steel and cast iron pipelines and certain other infrastructure. This rider is updated annually for qualifying capital expenditures and allows for a return to be earned on those capital expenditures based on the rate of return approved in the 2009 base rate case. In addition, deferral of depreciation and the ability to accrue debt-related post in service carrying costs is also allowed until the related capital expenditures are 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 $111 million. Regulatory assets associated with post in service carrying costs and depreciation deferrals were $10.1 million and $9.3 million at March 31, 2014 and December 31, 2013, respectively. Due to the expiration of the initial five year term for the DRR in early 2014, the Company filed a request in August 2013 to extend and expand the DRR. On February 19, 2014, the PUCO 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. | |
Regulatory assets are expected to continue to increase in future periods as post in service carrying costs are recognized in the statement of income and operating costs are deferred. Given the extension of the DRR as discussed above and the growth in rate base that has occurred since the last rate case, the expected growth from the capital expenditure plan outlined above and the growth in the regulatory assets balance, it is anticipated that the Company will file a general rate case for the inclusion in rate base 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 five year time frame. | |
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 $23.5 million capital expenditure program covering the fifteen month period ending December 31, 2012. Such capital expenditures include infrastructure expansion and improvements not covered by the DRR as well as expenditures necessary to comply with PUCO rules, regulations, orders, and system expansion to some new customers. The order also established a prospective bill impact evaluation on the cumulative deferrals, limiting the total deferrals at a level which would equal $1.50 per residential and small general service customer per month. 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 annual filing on April 30, 2014. | |
Indiana Recovery and Deferral Mechanisms | |
The Company's Indiana natural gas utilities received orders in 2008 and 2007 associated with the most recent base rate cases. These orders authorized the deferral of financial impacts associated with bare steel and cast iron replacement activities. The orders provide for the deferral of depreciation and post in service carrying costs on qualifying projects totaling $20 million annually at Vectren North and $3 million annually at Vectren South. The debt-related post in service carrying costs are recognized in the 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 Vectren South and four years after being placed into service at Vectren North. At March 31, 2014 and December 31, 2013, the Company has regulatory assets totaling $13.2 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. The adjustment mechanism is capped at an annual increase in retail revenues of no more than two percent. | |
Pipeline Safety Law | |
On January 3, 2012, the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 (Pipeline Safety Law) was signed into law. The Pipeline Safety Law, which reauthorizes federal pipeline safety programs through fiscal year 2015, provides for enhanced safety, reliability, and environmental protection in the transportation of energy products by pipeline. The law increases federal enforcement authority; grants the federal government expanded authority over pipeline safety; provides for new safety regulations and standards; and authorizes or requires the completion of several pipeline safety-related studies. The DOT is required to promulgate a number of new regulatory requirements over the next two years. Those regulations may eventually lead to further regulatory or statutory requirements. | |
While the Company continues to study the impact of the Pipeline Safety Law and potential new regulations associated with its implementation, it is expected that the law will result in further investment in pipeline inspections, and where necessary, additional investments in pipeline infrastructure and, therefore, result in both increased levels of operating expenses and capital expenditures associated with the Company's natural gas distribution businesses. | |
Requests for Recovery Under Indiana Regulatory Mechanisms | |
The Company filed in November 2013 for authority to recover appropriate costs related to its gas infrastructure replacement and improvement programs in Indiana, including costs associated with existing pipeline safety regulations, using the mechanisms allowed under Senate Bill 251 and Senate Bill 560. The combined Vectren South and Vectren North Indiana filing requests recovery of the capital expenditures associated with the infrastructure replacement and improvement plan pursuant to the legislation, estimated to be approximately $865 million combined, 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. An order is expected later in 2014. | |
Vectren South Electric Environmental Compliance Filing | |
On January 17, 2014, Vectren South filed a request with the IURC for approval of capital investments estimated to be between $70 million and $90 million on its coal-fired generation units to comply with new EPA mandates related to mercury and air toxin standards effective in 2016. Roughly half of the investment will be made to control mercury in both air and water emissions. The remaining investment will be made to address EPA concerns on alleged increases in sulfur trioxide emissions. Although the Company believes these investments are recoverable as a federally mandated investment under Senate Bill 251, the Company has requested deferred accounting treatment in lieu of timely recovery to avoid immediate customer impacts. The accounting treatment request seeks deferral of depreciation and property tax expense related to these investments, accrual of post in service carrying costs, and deferral of incremental operating expenses related to compliance with these standards. The Company filed its case-in-chief on March 14, 2014, intervening parties are scheduled to file their testimony on May 21, 2014, and a hearing is scheduled for July 9, 2014. | |
Coal Procurement Procedures | |
Vectren South submitted a request for proposal (RFP) in April 2011 regarding coal purchases for a four year period beginning in 2012. After negotiations with bidders, Vectren South reached an agreement in principle for multi-year purchases with two suppliers, one of which is Vectren Fuels, Inc. Consistent with the IURC direction in the 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 Vectren South’s 2011 RFP process resulted in the lowest fuel cost reasonably possible. The IURC has, and will continue to, regularly monitor Vectren South’s procurement process in future fuel adjustment proceedings. | |
On December 5, 2011 within the quarterly FAC filing, Vectren South submitted a joint proposal with the OUCC to reduce its fuel costs billed to customers by accelerating into 2012 the impact of lower cost coal under 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 $40.6 million remains as of March 31, 2014. | |
Vectren South Electric Demand Side Management Program Filing | |
On August 16, 2010, Vectren South filed a petition with the IURC, seeking approval of its proposed electric Demand Side Management (DSM) Programs, recovery of the costs associated with these programs, recovery of lost margins as a result of implementing these programs for large customers, and recovery of performance incentives linked with specific measurement criteria on all programs. The DSM Programs proposed were consistent with a December 9, 2009 order issued by the IURC, which, among other actions, defined long-term conservation objectives and goals of DSM programs for all Indiana electric utilities under a consistent statewide approach. In order to meet these objectives, the IURC order divided the DSM programs into Core and Core Plus programs. Core programs are joint programs required to be offered by all Indiana electric utilities to all customers, and include some for large industrial customers. Core Plus programs are those programs not required specifically by the IURC, but defined by each utility to meet the overall energy savings targets defined by the IURC. | |
On August 31, 2011 the IURC issued an order approving an initial three year DSM plan in the Vectren South 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 three months ended March 31, 2014, the Company recognized Electric revenue of $1.6 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 future 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 plans to file a request for Commission approval of a new portfolio of DSM programs by May 30, 2014 to be effective in January 2015. | |
Vectren North Pipeline Safety Investigation | |
On April 11, 2012, the IURC's pipeline safety division filed a complaint against Vectren North alleging several violations of safety regulations pertaining to damage that occurred at a residence in Vectren North's service territory during a pipeline replacement project. The Company negotiated a settlement with the IURC's pipeline safety division, agreeing to a fine and several modifications to the Company's operating policies. The amount of the fine was not material to the Company's financial results. The IURC approved the settlement but modified certain terms of the settlement and added a requirement that Company employees conduct inspections of pipeline excavations. The Company sought and was granted a request for rehearing on the sole issue related to the requirement to use Company employees to inspect excavations. A settlement in the case was reached between the IURC's pipeline safety division and Vectren North that allowed Vectren North to continue to use its risk based approach to inspecting excavations and to allow the Company to continue using a mix of highly trained and qualified contractors and employees to perform inspections. On January 15, 2014, the IURC issued a Final Order in the case approving the settlement agreement, without modification. | |
Vectren North & Vectren South Gas Decoupling Extension Filing | |
On August 18, 2011, the IURC issued an order granting the extension of the current decoupling mechanism in place at both gas companies and recovery of new conservation program costs through December 2015. | |
FERC Return on Equity Complaint | |
On November 12, 2013, certain parties representing a group of industrial customers filed a joint complaint with the FERC under Section 206 of the Federal Power Act against MISO and various MISO transmission owners, including SIGECO. The joint parties seek to reduce the 12.38 percent return on equity used in the MISO transmission owners’ rates, including SIGECO’s formula transmission rates, to 9.15 percent, and to set a capital structure in which the equity component does not exceed 50 percent. In the event a refund is required upon resolution of the complaint, the parties are seeking a refund calculated as of the filing date of the complaint. The MISO transmission owners filed their response to the complaint on January 6, 2014, opposing any change to the return. In addition to the group response, the Company filed a supplemental response, stating that if FERC allows the complaint to go forward, the complaint should not be applied to the Company’s recently completed Gibson-Brown-Reid 345 Kv transmission line investment. As of March 31, 2014, the Company had invested approximately $157.6 million in qualifying projects. The net plant balance for these projects totaled $146.1 million at March 31, 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. The FERC has yet to rule on that case. |
Environmental_Matters
Environmental Matters | 3 Months Ended |
Mar. 31, 2014 | |
Environmental Matters Disclosure [Abstract] | ' |
Environmental Matters | ' |
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 is currently evaluating the impact Senate Bill 251 may have on its operations, including applicability of the stricter regulations the EPA is currently considering involving air quality, fly ash disposal, cooling tower intake facilities, waste water discharges, and greenhouse gases. These issues are further discussed below. | |
Air Quality | |
Clean Air Interstate Rule / Cross-State Air Pollution Rule | |
In July 2011, the EPA finalized the Cross-State Air Pollution Rule (CSAPR). CSAPR was the EPA’s response to the US Court of Appeals for the District of Columbia’s (the Court) remand of the Clean Air Interstate Rule (CAIR). CAIR was originally established in 2005 as an allowance cap and trade program that required reductions from coal-burning power plants for NOx emissions beginning January 1, 2009 and SO2 emissions beginning January 1, 2010, with a second phase of reductions in 2015. In an effort to address the Court’s finding that CAIR did not adequately ensure attainment of pollutants in certain downwind states due to unlimited trading of SO2 and NOx allowances, CSAPR reduced the ability of facilities to meet emission reduction targets through allowance trading. Like CAIR, CSAPR set individual state caps for SO2 and NOx emissions. However, unlike CAIR in which states allocated allowances to generating units through state implementation plans, CSAPR allowances were allocated to individual units directly through the federal rule. CSAPR reductions were to be achieved with initial step reductions beginning January 1, 2012, and final compliance to be achieved in 2014. Multiple administrative and judicial challenges were filed. On December 30, 2011, the Court granted a stay of CSAPR and left CAIR in place pending its review. On August 21, 2012, the Court vacated CSAPR and directed the EPA to continue to administer CAIR. In October 2012, the EPA filed its request for a hearing before the full federal appeals court that struck down the CSAPR. EPA's request for rehearing was denied by the Court on January 24, 2013. In March 2013, the EPA filed a petition for review with the US Supreme Court, and in June 2013 the Supreme Court agreed to review the lower court decision. In April 2014, the US Supreme Court upheld the CSAPR. The EPA has yet to state its plans for implementation of the CSAPR since the Court's decision on April 29th. While it is possible that the EPA could revise the rule prior to implementation, the Company does not anticipate a significant impact from the 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 Environmental Regulations"). | |
Mercury and Air Toxics (MATS) Rule | |
On December 21, 2011, the EPA finalized the Utility MATS Rule. The MATS Rule sets emission limits for hazardous air pollutants for existing and new coal-fired power plants and identifies the following broad categories of hazardous air pollutants: mercury, non-mercury hazardous air pollutants (primarily arsenic, chromium, cobalt, and selenium), and acid gases (hydrogen cyanide, hydrogen chloride, and hydrogen fluoride). The rule imposes mercury emission limits for two sub-categories of coal, and proposed surrogate limits for non-mercury and acid gas hazardous air pollutants. The EPA did not grant blanket compliance extensions, but asserted that states have broad authority to grant one year extensions for individual electric generating units where potential reliability impacts have been demonstrated. Reductions are to be achieved within three years of publication of the final rule in the Federal register (April 2015). 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” to minimize adverse environmental impacts in a body of water. More specifically, Section 316(b) is concerned with impingement and entrainment of aquatic species in once-through cooling water intake structures used at electric generating facilities. In April 2009, the U.S. Supreme Court affirmed that the EPA could, but was not required to, consider costs and benefits in making the evaluation as to the best technology available for existing generating facilities. The regulation was remanded back to the EPA for further consideration. In March 2011, the EPA released its proposed Section 316(b) regulations. The EPA did not mandate the retrofitting of cooling towers in the proposed regulation, but if finalized, the regulation will leave it to each state to determine whether cooling towers should be required on a case by case basis. A final rule is expected in May 2014. Depending on the final rule and on the Company’s facts and circumstances, capital investments could approximate $40 million if new infrastructure, such as new cooling water towers, is required. Costs for compliance with these final regulations should qualify as federally mandated regulatory requirements and be 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 from motor vehicles cause or contribute to air pollution that may reasonably be anticipated to endanger public health or welfare. In April 2009, the EPA published its proposed endangerment finding for public comment. The proposed endangerment finding concludes that carbon emissions from mobile sources pose an endangerment to public health and the environment. The endangerment finding was finalized in December 2009, and is the first step toward the EPA regulating carbon emissions through the existing Clean Air Act in the absence of specific carbon legislation from Congress. | |
The EPA has promulgated two GHG regulations that apply to the Company’s generating facilities. In 2009, the EPA finalized a mandatory GHG emissions registry which requires the reporting of emissions. The EPA has also finalized a revision to the Prevention of Significant Deterioration (PSD) and Title V permitting rules which would require facilities that emit 75,000 tons or more of GHG's a year to obtain a PSD permit for new construction or a significant modification of an existing facility. The EPA's PSD and Title V permitting rules for GHG's were upheld by the US Court of Appeals for the District of Columbia. In 2012, the EPA proposed New Source Performance Standards (NSPS) for GHG's for new electric generating facilities under the Clean Air Act Section 111(b). On October 15, 2013, the US Supreme Court agreed to review a focused appeal on the issue of whether the GHG rule applicable to mobile sources triggered PSD permitting for all stationary sources such as Vectren's power plants. A decision is expected in 2014. | |
In July 2013, the President announced a Climate Action Plan, which calls on the EPA to re-propose and finalize the new source rule expeditiously, and by June 2014 propose, and by June 2015 finalize, NSPS standards for GHG's for existing electric generating units which would apply to Vectren's power plants. States must have their implementation plans to the EPA no later than June 2016. The President's Climate Action Plan did not provide any detail as to actual emission targets or compliance requirements. The Company anticipates that these initial standards will focus on power plant efficiency and other coal fleet carbon intensity reduction measures. The Company believes that such additional costs, if necessary, should be recoverable under Indiana Senate Bill 251 referenced above. | |
Numerous competing federal legislative proposals have also been introduced in recent years that involve carbon, energy efficiency, and renewable energy. Comprehensive energy legislation at the federal level continues to be debated, but there has been little progress to date. The progression of regional initiatives throughout the United States has also slowed. On May 6, 2014, the White House released a report on climate change and the impacts it has on regions within the United States, including the Midwest. The Company is currently assessing and evaluating the report to determine its impact to the Company. | |
Impact of Legislative Actions & Other Initiatives is Unknown | |
If regulations are enacted by the EPA or other agencies or if legislation requiring reductions in CO2 and other GHG's or legislation mandating a renewable energy portfolio standard is adopted, such regulation could substantially affect both the costs and operating characteristics of the Company’s fossil fuel generating plants and natural gas distribution businesses. At this time and in the absence of final legislation or rulemaking, compliance costs and other effects associated with reductions in GHG emissions or obtaining renewable energy sources remain uncertain. The Company has gathered preliminary estimates of the costs to control GHG emissions. A preliminary investigation demonstrated costs to comply would be significant, first with regard to operating expenses and later for capital expenditures as technology becomes available to control GHG emissions. However, these compliance cost estimates are based on highly uncertain assumptions, including allowance prices if a cap and trade approach were employed, and energy efficiency targets. Costs to purchase allowances that cap GHG emissions or expenditures made to control emissions should be considered a federally mandated cost of providing electricity, and as such, the Company believes such costs and expenditures should be recoverable from customers through Senate Bill 251 as referenced above. | |
Senate Bill 251 also established a voluntary clean energy portfolio standard that provides incentives to Indiana electricity suppliers participating in the program. The goal of the program is that by 2025, at least 10 percent of the total electricity obtained by the supplier to meet the energy needs of Indiana retail customers will be provided by clean energy sources, as defined. In advance of a federal portfolio standard and Senate Bill 251, SIGECO received regulatory approval to purchase a 3 MW landfill gas generation facility from a related entity. The facility was purchased in 2009 and is directly connected to the Company's distribution system. In 2008 and 2009, the Company executed long-term purchase power commitments for a total of 80 MW of wind energy. The Company currently has approximately 5 percent of its electricity being provided by clean energy sources due to the long-term wind contracts and landfill gas investment. | |
Manufactured Gas Plants | |
In the past, the Company operated facilities to manufacture natural gas. Given the availability of natural gas transported by pipelines, these facilities have not been operated for many years. Under current environmental laws and regulations, those that owned or operated these facilities may now be required to take remedial action if certain contaminants are found above the regulatory thresholds. | |
In the Indiana Gas service territory, the existence, location, and certain general characteristics of 26 gas manufacturing and storage sites have been identified for which the Company may have some remedial responsibility. A remedial investigation/feasibility study (RI/FS) was completed at one of the sites under an agreed order between Indiana Gas and the IDEM, and a Record of Decision was issued by the IDEM in January 2000. The remaining sites have been submitted to the IDEM's Voluntary Remediation Program (VRP). The Company has identified its involvement in five manufactured gas plant sites in SIGECO’s service territory, all of which are currently enrolled in the IDEM’s VRP. The Company is currently conducting some level of remedial activities, including groundwater monitoring at certain sites. | |
The Company has accrued the estimated costs for further investigation, remediation, groundwater monitoring, and related costs for the sites. While the total costs that may be incurred in connection with addressing these sites cannot be determined at this time, the Company has recorded cumulative costs that it has incurred or reasonably expects to incur totaling approximately $43.4 million ($23.2 million at Indiana Gas and $20.2 million at SIGECO). The estimated accrued costs are limited to the Company’s share of the remediation efforts and are therefore net of exposures of other potentially responsible parties (PRP). | |
With respect to insurance coverage, Indiana Gas has received approximately $20.8 million from all known insurance carriers under insurance policies in effect when these plants were in operation. Likewise, SIGECO has settlement agreements with all known insurance carriers and has received to date approximately $14.3 million of the expected $15.8 million in insurance recoveries. | |
The costs the Company expects to incur are estimated by management using assumptions based on actual costs incurred, the timing of expected future payments, and inflation factors, among others. While the Company’s utilities have recorded all costs which they presently expect to incur in connection with activities at these sites, it is possible that future events may require remedial activities which are not presently foreseen and those costs may not be subject to PRP or insurance recovery. As of March 31, 2014 and December 31, 2013, approximately $5.2 million and $5.7 million, respectively, of accrued, but not yet spent, costs are included in Other Liabilities related to the Indiana Gas and SIGECO sites. |
Fair_Value_Measurements
Fair Value Measurements | 3 Months Ended | |||||||||||||||
Mar. 31, 2014 | ||||||||||||||||
Fair Value Disclosures [Abstract] | ' | |||||||||||||||
Fair Value Measurements | ' | |||||||||||||||
Fair Value Measurements | ||||||||||||||||
The carrying values and estimated fair values using primarily Level 2 assumptions of the Company's other financial instruments follow: | ||||||||||||||||
March 31, 2014 | December 31, 2013 | |||||||||||||||
(In millions) | Carrying | Est. Fair | Carrying | Est. Fair | ||||||||||||
Amount | Value | Amount | Value | |||||||||||||
Long-term debt | $ | 1,257.20 | $ | 1,367.30 | $ | 1,257.10 | $ | 1,317.40 | ||||||||
Short-term borrowings | — | — | 28.6 | 28.6 | ||||||||||||
Cash & cash equivalents | 52.6 | 52.6 | 8.6 | 8.6 | ||||||||||||
For the balance sheet dates presented in these financial statements, the Company had no material assets or liabilities recorded at fair value outstanding, and no material assets or liabilities valued using Level 3 inputs. | ||||||||||||||||
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. |
Segment_Reporting
Segment Reporting | 3 Months Ended | |||||||
Mar. 31, 2014 | ||||||||
Segment Reporting [Abstract] | ' | |||||||
Segment Reporting | ' | |||||||
Segment Reporting | ||||||||
The Company’s operations consist of regulated operations and other operations that provide information technology and other support services to those regulated operations. The Company segregates its regulated operations between a Gas Utility Services operating segment and an Electric Utility Services operating segment. The Gas Utility Services segment provides natural gas distribution and transportation services to nearly two-thirds of Indiana and to west central Ohio. The Electric Utility Services segment provides electric distribution services primarily to southwestern Indiana, and includes the Company’s power generating and wholesale power operations. Regulated operations supply natural gas and/or electricity to over one million customers. In total, the Company is comprised of three operating segments: Gas Utility Services, Electric Utility Services, and Other Shared Service operations. Net income is the measure of profitability used by management for all operations. | ||||||||
Information related to the Company’s business segments is summarized below: | ||||||||
Three Months Ended | ||||||||
March 31, | ||||||||
(In millions) | 2014 | 2013 | ||||||
Revenues | ||||||||
Gas Utility Services | $ | 443.6 | $ | 315.9 | ||||
Electric Utility Services | 163 | 149.5 | ||||||
Other Operations | 9.6 | 9.5 | ||||||
Eliminations | (9.6 | ) | (9.4 | ) | ||||
Total revenues | $ | 606.6 | $ | 465.5 | ||||
Profitability Measure - Net Income | ||||||||
Gas Utility Services | $ | 38.3 | $ | 38.1 | ||||
Electric Utility Services | 19.3 | 14.6 | ||||||
Other Operations | 3.7 | 2.4 | ||||||
Total net income | $ | 61.3 | $ | 55.1 | ||||
Subsidiary_Guarantor_and_Conso1
Subsidiary Guarantor and Consolidating Information Subsidiary Guarantor and Consolidating Information(Tables) | 3 Months Ended | |||||||||||||||
Mar. 31, 2014 | ||||||||||||||||
Condensed Financial Information of Parent Company and Subsidiaries [Abstract] | ' | |||||||||||||||
Condensed consolidating balance sheets [Table Text Block] | ' | |||||||||||||||
Condensed Consolidating Balance Sheet as of March 31, 2014 (in millions): | ||||||||||||||||
ASSETS | Subsidiary | Parent | Eliminations & | |||||||||||||
Guarantors | Company | Reclassifications | Consolidated | |||||||||||||
Current Assets | ||||||||||||||||
Cash & cash equivalents | $ | 35.8 | $ | 16.8 | $ | — | $ | 52.6 | ||||||||
Accounts receivable - less reserves | 160.1 | — | — | 160.1 | ||||||||||||
Intercompany receivables | 85.9 | 14.1 | (100.0 | ) | — | |||||||||||
Accrued unbilled revenues | 98.1 | — | — | 98.1 | ||||||||||||
Inventories | 54.3 | — | — | 54.3 | ||||||||||||
Recoverable fuel & natural gas costs | 27.1 | — | — | 27.1 | ||||||||||||
Prepayments & other current assets | 11.2 | 34.8 | (36.0 | ) | 10 | |||||||||||
Total current assets | 472.5 | 65.7 | (136.0 | ) | 402.2 | |||||||||||
Utility Plant | ||||||||||||||||
Original cost | 5,439.00 | — | — | 5,439.00 | ||||||||||||
Less: accumulated depreciation & amortization | 2,198.80 | — | — | 2,198.80 | ||||||||||||
Net utility plant | 3,240.20 | — | — | 3,240.20 | ||||||||||||
Investments in consolidated subsidiaries | — | 1,409.60 | (1,409.6 | ) | — | |||||||||||
Notes receivable from consolidated subsidiaries | — | 820.6 | (820.6 | ) | — | |||||||||||
Investments in unconsolidated affiliates | 0.2 | — | — | 0.2 | ||||||||||||
Other investments | 21.7 | 4.4 | — | 26.1 | ||||||||||||
Nonutility property - net | 2.1 | 148.6 | — | 150.7 | ||||||||||||
Goodwill - net | 205 | — | — | 205 | ||||||||||||
Regulatory assets | 91.9 | 22.5 | — | 114.4 | ||||||||||||
Other assets | 31 | 1.1 | (8.4 | ) | 23.7 | |||||||||||
TOTAL ASSETS | $ | 4,064.60 | $ | 2,472.50 | $ | (2,374.6 | ) | $ | 4,162.50 | |||||||
LIABILITIES & SHAREHOLDER'S EQUITY | Subsidiary | Parent | Eliminations & | |||||||||||||
Guarantors | Company | Reclassifications | Consolidated | |||||||||||||
Current Liabilities | ||||||||||||||||
Accounts payable | $ | 146.8 | $ | 4.5 | $ | — | $ | 151.3 | ||||||||
Intercompany payables | 14.1 | — | (14.1 | ) | — | |||||||||||
Payables to other Vectren companies | 26.5 | — | — | 26.5 | ||||||||||||
Accrued liabilities | 181.6 | 18.9 | (36.0 | ) | 164.5 | |||||||||||
Intercompany short-term borrowings | — | 85.9 | (85.9 | ) | — | |||||||||||
Current maturities of long-term debt | 5 | — | — | 5 | ||||||||||||
Total current liabilities | 374 | 109.3 | (136.0 | ) | 347.3 | |||||||||||
Long-Term Debt | ||||||||||||||||
Long-term debt | 377.6 | 874.6 | — | 1,252.20 | ||||||||||||
Long-term debt due to VUHI | 820.6 | — | (820.6 | ) | — | |||||||||||
Total long-term debt - net | 1,198.20 | 874.6 | (820.6 | ) | 1,252.20 | |||||||||||
Deferred Credits & Other Liabilities | ||||||||||||||||
Deferred income taxes | 605.5 | 14.2 | — | 619.7 | ||||||||||||
Regulatory liabilities | 391.8 | 1.6 | — | 393.4 | ||||||||||||
Deferred credits & other liabilities | 85.5 | 4.2 | (8.4 | ) | 81.3 | |||||||||||
Total deferred credits & other liabilities | 1,082.80 | 20 | (8.4 | ) | 1,094.40 | |||||||||||
Common Shareholder's Equity | ||||||||||||||||
Common stock (no par value) | 802.5 | 789.3 | (802.5 | ) | 789.3 | |||||||||||
Retained earnings | 607.1 | 679.3 | (607.1 | ) | 679.3 | |||||||||||
Total common shareholder's equity | 1,409.60 | 1,468.60 | (1,409.6 | ) | 1,468.60 | |||||||||||
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY | $ | 4,064.60 | $ | 2,472.50 | $ | (2,374.6 | ) | $ | 4,162.50 | |||||||
Condensed Consolidating Balance Sheet as of December 31, 2013 (in millions): | ||||||||||||||||
ASSETS | Subsidiary | Parent | Eliminations & | |||||||||||||
Guarantors | Company | Reclassifications | Consolidated | |||||||||||||
Current Assets | ||||||||||||||||
Cash & cash equivalents | $ | 8.2 | $ | 0.4 | $ | — | $ | 8.6 | ||||||||
Accounts receivable - less reserves | 112.1 | — | — | 112.1 | ||||||||||||
Intercompany receivables | 0.3 | 84.8 | (85.1 | ) | — | |||||||||||
Accrued unbilled revenues | 113.5 | — | — | 113.5 | ||||||||||||
Inventories | 89.9 | — | — | 89.9 | ||||||||||||
Recoverable fuel & natural gas costs | 5.5 | — | — | 5.5 | ||||||||||||
Prepayments & other current assets | 37.3 | 40.1 | (35.0 | ) | 42.4 | |||||||||||
Total current assets | 366.8 | 125.3 | (120.1 | ) | 372 | |||||||||||
Utility Plant | ||||||||||||||||
Original cost | 5,389.60 | — | — | 5,389.60 | ||||||||||||
Less: accumulated depreciation & amortization | 2,165.30 | — | — | 2,165.30 | ||||||||||||
Net utility plant | 3,224.30 | — | — | 3,224.30 | ||||||||||||
Investments in consolidated subsidiaries | — | 1,375.80 | (1,375.8 | ) | — | |||||||||||
Notes receivable from consolidated subsidiaries | — | 696.4 | (696.4 | ) | — | |||||||||||
Investments in unconsolidated affiliates | 0.2 | — | — | 0.2 | ||||||||||||
Other investments | 22.8 | 4.5 | — | 27.3 | ||||||||||||
Nonutility property - net | 2.2 | 148.3 | — | 150.5 | ||||||||||||
Goodwill - net | 205 | — | — | 205 | ||||||||||||
Regulatory assets | 113.4 | 22.8 | — | 136.2 | ||||||||||||
Other assets | 32.2 | 1 | (7.9 | ) | 25.3 | |||||||||||
TOTAL ASSETS | $ | 3,966.90 | $ | 2,374.10 | $ | (2,200.2 | ) | $ | 4,140.80 | |||||||
LIABILITIES & SHAREHOLDER'S EQUITY | Subsidiary | Parent | Eliminations & | |||||||||||||
Guarantors | Company | Reclassifications | Consolidated | |||||||||||||
Current Liabilities | ||||||||||||||||
Accounts payable | $ | 161.6 | $ | 10.5 | $ | — | $ | 172.1 | ||||||||
Intercompany payables | 11.7 | — | (11.7 | ) | — | |||||||||||
Payables to other Vectren companies | 24.6 | — | — | 24.6 | ||||||||||||
Accrued liabilities | 150.3 | 12.1 | (35.0 | ) | 127.4 | |||||||||||
Short-term borrowings | — | 28.6 | — | 28.6 | ||||||||||||
Intercompany short-term borrowings | 73.1 | 0.3 | (73.4 | ) | — | |||||||||||
Total current liabilities | 421.3 | 51.5 | (120.1 | ) | 352.7 | |||||||||||
Long-Term Debt | ||||||||||||||||
Long-term debt - net of current maturities & | ||||||||||||||||
debt subject to tender | 382.5 | 874.6 | — | 1,257.10 | ||||||||||||
Long-term debt due to VUHI | 696.4 | — | (696.4 | ) | — | |||||||||||
Total long-term debt - net | 1,078.90 | 874.6 | (696.4 | ) | 1,257.10 | |||||||||||
Deferred Credits & Other Liabilities | ||||||||||||||||
Deferred income taxes | 616.9 | 10.5 | — | 627.4 | ||||||||||||
Regulatory liabilities | 385.7 | 1.6 | — | 387.3 | ||||||||||||
Deferred credits & other liabilities | 88.3 | 3.1 | (7.9 | ) | 83.5 | |||||||||||
Total deferred credits & other liabilities | 1,090.90 | 15.2 | (7.9 | ) | 1,098.20 | |||||||||||
Common Shareholder's Equity | ||||||||||||||||
Common stock (no par value) | 800.9 | 787.7 | (800.9 | ) | 787.7 | |||||||||||
Retained earnings | 574.9 | 645.1 | (574.9 | ) | 645.1 | |||||||||||
Total common shareholder's equity | 1,375.80 | 1,432.80 | (1,375.8 | ) | 1,432.80 | |||||||||||
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY | $ | 3,966.90 | $ | 2,374.10 | $ | (2,200.2 | ) | $ | 4,140.80 | |||||||
Condensed consolidating statements fo income [Table Text Block] | ' | |||||||||||||||
Condensed Consolidating Statement of Income for the three months ended March 31, 2014 (in millions): | ||||||||||||||||
Subsidiary | Parent | Eliminations & | Consolidated | |||||||||||||
Guarantors | Company | Reclassifications | ||||||||||||||
OPERATING REVENUES | ||||||||||||||||
Gas utility | $ | 443.6 | $ | — | $ | — | $ | 443.6 | ||||||||
Electric utility | 163 | — | — | 163 | ||||||||||||
Other | — | 9.6 | (9.6 | ) | — | |||||||||||
Total operating revenues | 606.6 | 9.6 | (9.6 | ) | 606.6 | |||||||||||
OPERATING EXPENSES | ||||||||||||||||
Cost of gas sold | 270.9 | — | — | 270.9 | ||||||||||||
Cost of fuel & purchased power | 57 | — | — | 57 | ||||||||||||
Other operating | 107.5 | — | (9.2 | ) | 98.3 | |||||||||||
Depreciation & amortization | 44.4 | 5.4 | 0.1 | 49.9 | ||||||||||||
Taxes other than income taxes | 19.6 | 0.4 | 0.1 | 20.1 | ||||||||||||
Total operating expenses | 499.4 | 5.8 | (9.0 | ) | 496.2 | |||||||||||
OPERATING INCOME | 107.2 | 3.8 | (0.6 | ) | 110.4 | |||||||||||
Other income - net | 3 | 10.7 | (9.8 | ) | 3.9 | |||||||||||
Interest expense | 15.8 | 11.3 | (10.4 | ) | 16.7 | |||||||||||
INCOME BEFORE INCOME TAXES | 94.4 | 3.2 | — | 97.6 | ||||||||||||
Income taxes | 36.8 | (0.5 | ) | — | 36.3 | |||||||||||
Equity in earnings of consolidated companies, net of tax | — | 57.6 | (57.6 | ) | — | |||||||||||
NET INCOME | $ | 57.6 | $ | 61.3 | $ | (57.6 | ) | $ | 61.3 | |||||||
Condensed Consolidating Statement of Income for the three months ended March 31, 2013 (in millions): | ||||||||||||||||
Subsidiary | Parent | Eliminations & | Consolidated | |||||||||||||
Guarantors | Company | Reclassifications | ||||||||||||||
OPERATING REVENUES | ||||||||||||||||
Gas utility | $ | 315.9 | $ | — | $ | — | $ | 315.9 | ||||||||
Electric utility | 149.5 | — | — | 149.5 | ||||||||||||
Other | — | 9.5 | (9.4 | ) | 0.1 | |||||||||||
Total operating revenues | 465.4 | 9.5 | (9.4 | ) | 465.5 | |||||||||||
OPERATING EXPENSES | ||||||||||||||||
Cost of gas sold | 157.2 | — | — | 157.2 | ||||||||||||
Cost of fuel & purchased power | 50.2 | — | — | 50.2 | ||||||||||||
Other operating | 96 | — | (9.2 | ) | 86.8 | |||||||||||
Depreciation & amortization | 43.1 | 5.2 | 0.1 | 48.4 | ||||||||||||
Taxes other than income taxes | 17.1 | 0.4 | — | 17.5 | ||||||||||||
Total operating expenses | 363.6 | 5.6 | (9.1 | ) | 360.1 | |||||||||||
OPERATING INCOME | 101.8 | 3.9 | (0.3 | ) | 105.4 | |||||||||||
Other income - net | 1.9 | 9.7 | (9.8 | ) | 1.8 | |||||||||||
Interest expense | 16.2 | 11.8 | (10.1 | ) | 17.9 | |||||||||||
INCOME BEFORE INCOME TAXES | 87.5 | 1.8 | — | 89.3 | ||||||||||||
Income taxes | 34.8 | (0.6 | ) | — | 34.2 | |||||||||||
Equity in earnings of consolidated companies, net of tax | — | 52.7 | (52.7 | ) | — | |||||||||||
NET INCOME | $ | 52.7 | $ | 55.1 | $ | (52.7 | ) | $ | 55.1 | |||||||
Condensed consolidating statements of cash flows [Table Text Block] | ' | |||||||||||||||
Condensed Consolidating Statement of Cash Flows for the three months ended March 31, 2014 (in millions): | ||||||||||||||||
Subsidiary | Parent | Eliminations | Consolidated | |||||||||||||
Guarantors | Company | |||||||||||||||
NET CASH PROVIDED BY OPERATING ACTIVITIES | $ | 137.2 | $ | 18.8 | $ | — | $ | 156 | ||||||||
CASH FLOWS FROM FINANCING ACTIVITIES | ||||||||||||||||
Proceeds from | ||||||||||||||||
Long-term debt - net of issuance costs | 124.2 | — | (124.2 | ) | — | |||||||||||
Additional capital contribution from parent | 1.6 | 1.6 | (1.6 | ) | 1.6 | |||||||||||
Requirements for: | ||||||||||||||||
Dividends to parent | (25.4 | ) | (27.1 | ) | 25.4 | (27.1 | ) | |||||||||
Net change in intercompany short-term borrowings | (73.1 | ) | 85.6 | (12.5 | ) | — | ||||||||||
Net change in short-term borrowings | — | (28.6 | ) | — | (28.6 | ) | ||||||||||
Net cash used in financing activities | 27.3 | 31.5 | (112.9 | ) | (54.1 | ) | ||||||||||
CASH FLOWS FROM INVESTING ACTIVITIES | ||||||||||||||||
Proceeds from: | ||||||||||||||||
Consolidated subsidiary distributions | — | 25.4 | (25.4 | ) | — | |||||||||||
Other investing activities | — | 0.1 | — | 0.1 | ||||||||||||
Requirements for: | ||||||||||||||||
Capital expenditures, excluding AFUDC equity | (51.3 | ) | (6.7 | ) | — | (58.0 | ) | |||||||||
Consolidated subsidiary investments | — | (1.6 | ) | 1.6 | — | |||||||||||
Net change in long-term intercompany notes receivable | — | (124.2 | ) | 124.2 | — | |||||||||||
Net change in short-term intercompany notes receivable | (85.6 | ) | 73.1 | 12.5 | — | |||||||||||
Net cash used in investing activities | (136.9 | ) | (33.9 | ) | 112.9 | (57.9 | ) | |||||||||
Net change in cash & cash equivalents | 27.6 | 16.4 | — | 44 | ||||||||||||
Cash & cash equivalents at beginning of period | 8.2 | 0.4 | — | 8.6 | ||||||||||||
Cash & cash equivalents at end of period | $ | 35.8 | $ | 16.8 | $ | — | $ | 52.6 | ||||||||
Condensed Consolidating Statement of Cash Flows for the three months ended March 31, 2013 (in millions): | ||||||||||||||||
Subsidiary | Parent | Eliminations | Consolidated | |||||||||||||
Guarantors | Company | |||||||||||||||
NET CASH PROVIDED BY OPERATING ACTIVITIES | $ | 168.5 | $ | (7.0 | ) | $ | (0.2 | ) | $ | 161.3 | ||||||
CASH FLOWS FROM FINANCING ACTIVITIES | ||||||||||||||||
Proceeds from: | ||||||||||||||||
Additional capital contribution to parent | 8.5 | 1.5 | (8.5 | ) | 1.5 | |||||||||||
Requirements for: | ||||||||||||||||
Dividends to parent | (24.5 | ) | (26.3 | ) | 24.5 | (26.3 | ) | |||||||||
Net change in intercompany short-term borrowings | (83.1 | ) | 28.9 | 54.2 | — | |||||||||||
Net change in short-term borrowings | — | (89.6 | ) | — | (89.6 | ) | ||||||||||
Net cash used in financing activities | (99.1 | ) | (85.5 | ) | 70.2 | (114.4 | ) | |||||||||
CASH FLOWS FROM INVESTING ACTIVITIES | ||||||||||||||||
Proceeds from: | ||||||||||||||||
Consolidated subsidiary distributions | — | 24.5 | (24.5 | ) | — | |||||||||||
Other investing activities | — | 0.1 | — | 0.1 | ||||||||||||
Requirements for: | ||||||||||||||||
Capital expenditures, excluding AFUDC equity | (47.3 | ) | (3.4 | ) | 0.2 | (50.5 | ) | |||||||||
Consolidated subsidiary investments | — | (8.5 | ) | 8.5 | — | |||||||||||
Net change in short-term intercompany notes receivable | (28.9 | ) | 83.1 | (54.2 | ) | — | ||||||||||
Net cash used in investing activities | (76.2 | ) | 95.8 | (70.0 | ) | (50.4 | ) | |||||||||
Net change in cash & cash equivalents | (6.8 | ) | 3.3 | — | (3.5 | ) | ||||||||||
Cash & cash equivalents at beginning of period | 12.5 | 0.8 | — | 13.3 | ||||||||||||
Cash & cash equivalents at end of period | $ | 5.7 | $ | 4.1 | $ | — | $ | 9.8 | ||||||||
Fair_Value_Measurements_Tables
Fair Value Measurements (Tables) | 3 Months Ended | |||||||||||||||
Mar. 31, 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: | ||||||||||||||||
March 31, 2014 | December 31, 2013 | |||||||||||||||
(In millions) | Carrying | Est. Fair | Carrying | Est. Fair | ||||||||||||
Amount | Value | Amount | Value | |||||||||||||
Long-term debt | $ | 1,257.20 | $ | 1,367.30 | $ | 1,257.10 | $ | 1,317.40 | ||||||||
Short-term borrowings | — | — | 28.6 | 28.6 | ||||||||||||
Cash & cash equivalents | 52.6 | 52.6 | 8.6 | 8.6 | ||||||||||||
Segment_Reporting_Tables
Segment Reporting (Tables) | 3 Months Ended | |||||||
Mar. 31, 2014 | ||||||||
Segment Reporting [Abstract] | ' | |||||||
Schedule of Segment Reporting Information, by Segment [Table Text Block] | ' | |||||||
Information related to the Company’s business segments is summarized below: | ||||||||
Three Months Ended | ||||||||
March 31, | ||||||||
(In millions) | 2014 | 2013 | ||||||
Revenues | ||||||||
Gas Utility Services | $ | 443.6 | $ | 315.9 | ||||
Electric Utility Services | 163 | 149.5 | ||||||
Other Operations | 9.6 | 9.5 | ||||||
Eliminations | (9.6 | ) | (9.4 | ) | ||||
Total revenues | $ | 606.6 | $ | 465.5 | ||||
Profitability Measure - Net Income | ||||||||
Gas Utility Services | $ | 38.3 | $ | 38.1 | ||||
Electric Utility Services | 19.3 | 14.6 | ||||||
Other Operations | 3.7 | 2.4 | ||||||
Total net income | $ | 61.3 | $ | 55.1 | ||||
Organization_and_Nature_of_Ope1
Organization and Nature of Operations (Details) | 3 Months Ended |
Mar. 31, 2014 | |
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) | 581,000 |
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) | 316,000 |
Subsidiary_Guarantor_and_Conso2
Subsidiary Guarantor and Consolidating Information Subsidiary Guarantor and Consolidating Information Balance Sheet (Details) (USD $) | 3 Months Ended | |||
In Millions, unless otherwise specified | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2013 | Dec. 31, 2012 |
ASSETS | ' | ' | ' | ' |
Cash & cash equivalents | $52.60 | $8.60 | $9.80 | $13.30 |
Accounts receivable - less reserves | 160.1 | 112.1 | ' | ' |
Accrued unbilled revenues | 98.1 | 113.5 | ' | ' |
Inventories | 54.3 | 89.9 | ' | ' |
Recoverable fuel & natural gas costs | 27.1 | 5.5 | ' | ' |
Prepayments & other current assets | 10 | 42.4 | ' | ' |
Total current assets | 402.2 | 372 | ' | ' |
Original cost | 5,439 | 5,389.60 | ' | ' |
Less: accumulated depreciation & amortization | 2,198.80 | 2,165.30 | ' | ' |
Net utility plant | 3,240.20 | 3,224.30 | ' | ' |
Investments in unconsolidated affiliates | 0.2 | 0.2 | ' | ' |
Nonutility property - net | 150.7 | 150.5 | ' | ' |
Goodwill - net | 205 | 205 | ' | ' |
Regulatory assets | 114.4 | 136.2 | ' | ' |
Other assets | 23.7 | 25.3 | ' | ' |
TOTAL ASSETS | 4,162.50 | 4,140.80 | ' | ' |
LIABILITIES & SHAREHOLDERS' EQUITY | ' | ' | ' | ' |
Accounts payable | 151.3 | 172.1 | ' | ' |
Payables to other Vectren companies | 26.5 | 24.6 | ' | ' |
Accrued liabilities | 164.5 | 127.4 | ' | ' |
Short-term borrowings | 0 | 28.6 | ' | ' |
Current maturities of long-term debt | 5 | 0 | ' | ' |
Total current liabilities | 347.3 | 352.7 | ' | ' |
Long-Term Debt - Net of Current Maturities | 1,252.20 | 1,257.10 | ' | ' |
Deferred income taxes | 619.7 | 627.4 | ' | ' |
Regulatory liabilities | 393.4 | 387.3 | ' | ' |
Deferred Credits and Other Liabilities | 81.3 | 83.5 | ' | ' |
Total deferred credits and other liabilities | 1,094.40 | 1,098.20 | ' | ' |
Common stock (no par value) | 789.3 | 787.7 | ' | ' |
Retained earnings | 679.3 | 645.1 | ' | ' |
Total common shareholders' equity | 1,468.60 | 1,432.80 | ' | ' |
TOTAL LIABILITIES and SHAREHOLDERS' EQUITY | 4,162.50 | 4,140.80 | ' | ' |
Subsidiary Guarantors [Member] | ' | ' | ' | ' |
ASSETS | ' | ' | ' | ' |
Cash & cash equivalents | 35.8 | 8.2 | 5.7 | 12.5 |
Accounts receivable - less reserves | 160.1 | 112.1 | ' | ' |
Intercompany Receivables | 85.9 | 0.3 | ' | ' |
Accrued unbilled revenues | 98.1 | 113.5 | ' | ' |
Inventories | 54.3 | 89.9 | ' | ' |
Recoverable fuel & natural gas costs | 27.1 | 5.5 | ' | ' |
Prepayments & other current assets | 11.2 | 37.3 | ' | ' |
Total current assets | 472.5 | 366.8 | ' | ' |
Original cost | 5,439 | 5,389.60 | ' | ' |
Less: accumulated depreciation & amortization | 2,198.80 | 2,165.30 | ' | ' |
Net utility plant | 3,240.20 | 3,224.30 | ' | ' |
Investments in consolidated subsidiaries | 0 | 0 | ' | ' |
Notes receivable from consolidated subsidiaries | 0 | 0 | ' | ' |
Investments in unconsolidated affiliates | 0.2 | 0.2 | ' | ' |
Other investments | 21.7 | 22.8 | ' | ' |
Nonutility property - net | 2.1 | 2.2 | ' | ' |
Goodwill - net | 205 | 205 | ' | ' |
Regulatory assets | 91.9 | 113.4 | ' | ' |
Other assets | 31 | 32.2 | ' | ' |
TOTAL ASSETS | 4,064.60 | 3,966.90 | ' | ' |
LIABILITIES & SHAREHOLDERS' EQUITY | ' | ' | ' | ' |
Accounts payable | 146.8 | 161.6 | ' | ' |
Intercompany payables | 14.1 | 11.7 | ' | ' |
Payables to other Vectren companies | 26.5 | 24.6 | ' | ' |
Accrued liabilities | 181.6 | 150.3 | ' | ' |
Short-term borrowings | ' | 0 | ' | ' |
Intercompany short-term borrowings | 0 | 73.1 | ' | ' |
Current maturities of long-term debt | 5 | ' | ' | ' |
Total current liabilities | 374 | 421.3 | ' | ' |
Long-Term Debt - Net of Current Maturities | 377.6 | 382.5 | ' | ' |
Long-term debt due to VUHI | 820.6 | 696.4 | ' | ' |
Total long-term debt - net | 1,198.20 | 1,078.90 | ' | ' |
Deferred income taxes | 605.5 | 616.9 | ' | ' |
Regulatory liabilities | 391.8 | 385.7 | ' | ' |
Deferred Credits and Other Liabilities | 85.5 | 88.3 | ' | ' |
Total deferred credits and other liabilities | 1,082.80 | 1,090.90 | ' | ' |
Common stock (no par value) | 802.5 | 800.9 | ' | ' |
Retained earnings | 607.1 | 574.9 | ' | ' |
Total common shareholders' equity | 1,409.60 | 1,375.80 | ' | ' |
TOTAL LIABILITIES and SHAREHOLDERS' EQUITY | 4,064.60 | 3,966.90 | ' | ' |
Parent Company [Member] | ' | ' | ' | ' |
ASSETS | ' | ' | ' | ' |
Cash & cash equivalents | 16.8 | 0.4 | 4.1 | 0.8 |
Accounts receivable - less reserves | 0 | 0 | ' | ' |
Intercompany Receivables | 14.1 | 84.8 | ' | ' |
Accrued unbilled revenues | 0 | 0 | ' | ' |
Inventories | 0 | 0 | ' | ' |
Recoverable fuel & natural gas costs | 0 | 0 | ' | ' |
Prepayments & other current assets | 34.8 | 40.1 | ' | ' |
Total current assets | 65.7 | 125.3 | ' | ' |
Original cost | 0 | 0 | ' | ' |
Less: accumulated depreciation & amortization | 0 | 0 | ' | ' |
Net utility plant | 0 | 0 | ' | ' |
Investments in consolidated subsidiaries | 1,409.60 | 1,375.80 | ' | ' |
Notes receivable from consolidated subsidiaries | 820.6 | 696.4 | ' | ' |
Investments in unconsolidated affiliates | 0 | 0 | ' | ' |
Other investments | 4.4 | 4.5 | ' | ' |
Nonutility property - net | 148.6 | 148.3 | ' | ' |
Goodwill - net | 0 | 0 | ' | ' |
Regulatory assets | 22.5 | 22.8 | ' | ' |
Other assets | 1.1 | 1 | ' | ' |
TOTAL ASSETS | 2,472.50 | 2,374.10 | ' | ' |
LIABILITIES & SHAREHOLDERS' EQUITY | ' | ' | ' | ' |
Accounts payable | 4.5 | 10.5 | ' | ' |
Intercompany payables | 0 | 0 | ' | ' |
Payables to other Vectren companies | 0 | 0 | ' | ' |
Accrued liabilities | 18.9 | 12.1 | ' | ' |
Short-term borrowings | ' | 28.6 | ' | ' |
Intercompany short-term borrowings | 85.9 | 0.3 | ' | ' |
Current maturities of long-term debt | 0 | ' | ' | ' |
Total current liabilities | 109.3 | 51.5 | ' | ' |
Long-Term Debt - Net of Current Maturities | 874.6 | 874.6 | ' | ' |
Long-term debt due to VUHI | 0 | 0 | ' | ' |
Total long-term debt - net | 874.6 | 874.6 | ' | ' |
Deferred income taxes | 14.2 | 10.5 | ' | ' |
Regulatory liabilities | 1.6 | 1.6 | ' | ' |
Deferred Credits and Other Liabilities | 4.2 | 3.1 | ' | ' |
Total deferred credits and other liabilities | 20 | 15.2 | ' | ' |
Common stock (no par value) | 789.3 | 787.7 | ' | ' |
Retained earnings | 679.3 | 645.1 | ' | ' |
Total common shareholders' equity | 1,468.60 | 1,432.80 | ' | ' |
TOTAL LIABILITIES and SHAREHOLDERS' EQUITY | 2,472.50 | 2,374.10 | ' | ' |
Line of Credit Facility, Maximum Borrowing Capacity | 350 | ' | ' | ' |
Line of Credit Facility, Amount Outstanding | 0 | ' | ' | ' |
Unsecured Debt | 875 | ' | ' | ' |
Subsidiary Ownership Percentage | 100.00% | ' | ' | ' |
Consolidation, Eliminations [Member] | ' | ' | ' | ' |
ASSETS | ' | ' | ' | ' |
Cash & cash equivalents | 0 | 0 | 0 | 0 |
Accounts receivable - less reserves | 0 | 0 | ' | ' |
Intercompany Receivables | -100 | -85.1 | ' | ' |
Accrued unbilled revenues | 0 | 0 | ' | ' |
Inventories | 0 | 0 | ' | ' |
Recoverable fuel & natural gas costs | 0 | 0 | ' | ' |
Prepayments & other current assets | -36 | -35 | ' | ' |
Total current assets | -136 | -120.1 | ' | ' |
Original cost | 0 | 0 | ' | ' |
Less: accumulated depreciation & amortization | 0 | 0 | ' | ' |
Net utility plant | 0 | 0 | ' | ' |
Investments in consolidated subsidiaries | -1,409.60 | -1,375.80 | ' | ' |
Notes receivable from consolidated subsidiaries | -820.6 | -696.4 | ' | ' |
Investments in unconsolidated affiliates | 0 | 0 | ' | ' |
Other investments | 0 | 0 | ' | ' |
Nonutility property - net | 0 | 0 | ' | ' |
Goodwill - net | 0 | 0 | ' | ' |
Regulatory assets | 0 | 0 | ' | ' |
Other assets | -8.4 | -7.9 | ' | ' |
TOTAL ASSETS | -2,374.60 | -2,200.20 | ' | ' |
LIABILITIES & SHAREHOLDERS' EQUITY | ' | ' | ' | ' |
Accounts payable | 0 | 0 | ' | ' |
Intercompany payables | -14.1 | -11.7 | ' | ' |
Payables to other Vectren companies | 0 | 0 | ' | ' |
Accrued liabilities | -36 | -35 | ' | ' |
Short-term borrowings | ' | 0 | ' | ' |
Intercompany short-term borrowings | -85.9 | -73.4 | ' | ' |
Current maturities of long-term debt | 0 | ' | ' | ' |
Total current liabilities | -136 | -120.1 | ' | ' |
Long-Term Debt - Net of Current Maturities | 0 | 0 | ' | ' |
Long-term debt due to VUHI | -820.6 | -696.4 | ' | ' |
Total long-term debt - net | -820.6 | -696.4 | ' | ' |
Deferred income taxes | 0 | 0 | ' | ' |
Regulatory liabilities | 0 | 0 | ' | ' |
Deferred Credits and Other Liabilities | -8.4 | -7.9 | ' | ' |
Total deferred credits and other liabilities | -8.4 | -7.9 | ' | ' |
Common stock (no par value) | -802.5 | -800.9 | ' | ' |
Retained earnings | -607.1 | -574.9 | ' | ' |
Total common shareholders' equity | -1,409.60 | -1,375.80 | ' | ' |
TOTAL LIABILITIES and SHAREHOLDERS' EQUITY | -2,374.60 | -2,200.20 | ' | ' |
Consolidated Entities [Member] | ' | ' | ' | ' |
ASSETS | ' | ' | ' | ' |
Cash & cash equivalents | 52.6 | 8.6 | 9.8 | 13.3 |
Accounts receivable - less reserves | 160.1 | 112.1 | ' | ' |
Intercompany Receivables | 0 | 0 | ' | ' |
Accrued unbilled revenues | 98.1 | 113.5 | ' | ' |
Inventories | 54.3 | 89.9 | ' | ' |
Recoverable fuel & natural gas costs | 27.1 | 5.5 | ' | ' |
Prepayments & other current assets | 10 | 42.4 | ' | ' |
Total current assets | 402.2 | 372 | ' | ' |
Original cost | 5,439 | 5,389.60 | ' | ' |
Less: accumulated depreciation & amortization | 2,198.80 | 2,165.30 | ' | ' |
Net utility plant | 3,240.20 | 3,224.30 | ' | ' |
Investments in consolidated subsidiaries | 0 | 0 | ' | ' |
Notes receivable from consolidated subsidiaries | 0 | 0 | ' | ' |
Investments in unconsolidated affiliates | 0.2 | 0.2 | ' | ' |
Other investments | 26.1 | 27.3 | ' | ' |
Nonutility property - net | 150.7 | 150.5 | ' | ' |
Goodwill - net | 205 | 205 | ' | ' |
Regulatory assets | 114.4 | 136.2 | ' | ' |
Other assets | 23.7 | 25.3 | ' | ' |
TOTAL ASSETS | 4,162.50 | 4,140.80 | ' | ' |
LIABILITIES & SHAREHOLDERS' EQUITY | ' | ' | ' | ' |
Accounts payable | 151.3 | 172.1 | ' | ' |
Intercompany payables | 0 | 0 | ' | ' |
Payables to other Vectren companies | 26.5 | 24.6 | ' | ' |
Accrued liabilities | 164.5 | 127.4 | ' | ' |
Short-term borrowings | ' | 28.6 | ' | ' |
Intercompany short-term borrowings | 0 | 0 | ' | ' |
Current maturities of long-term debt | 5 | ' | ' | ' |
Total current liabilities | 347.3 | 352.7 | ' | ' |
Long-Term Debt - Net of Current Maturities | 1,252.20 | 1,257.10 | ' | ' |
Long-term debt due to VUHI | 0 | 0 | ' | ' |
Total long-term debt - net | 1,252.20 | 1,257.10 | ' | ' |
Deferred income taxes | 619.7 | 627.4 | ' | ' |
Regulatory liabilities | 393.4 | 387.3 | ' | ' |
Deferred Credits and Other Liabilities | 81.3 | 83.5 | ' | ' |
Total deferred credits and other liabilities | 1,094.40 | 1,098.20 | ' | ' |
Common stock (no par value) | 789.3 | 787.7 | ' | ' |
Retained earnings | 679.3 | 645.1 | ' | ' |
Total common shareholders' equity | 1,468.60 | 1,432.80 | ' | ' |
TOTAL LIABILITIES and SHAREHOLDERS' EQUITY | $4,162.50 | $4,140.80 | ' | ' |
Subsidiary_Guarantor_and_Conso3
Subsidiary Guarantor and Consolidating Information Subsidiary Guarantor and Consolidating Information Income Statement (Details) (USD $) | 3 Months Ended | |
In Millions, unless otherwise specified | Mar. 31, 2014 | Mar. 31, 2013 |
OPERATING REVENUES [Abstract] | ' | ' |
Gas utility | $443.60 | $315.90 |
Electric utility | 163 | 149.5 |
Other | 0 | 0.1 |
Total operating revenues | 606.6 | 465.5 |
OPERATING EXPENSES [Abstract] | ' | ' |
Cost of gas sold | 270.9 | 157.2 |
Cost of fuel & purchased power | 57 | 50.2 |
Other operating | 98.3 | 86.8 |
Depreciation & Amortization | 49.9 | 48.4 |
Taxes other than income taxes | 20.1 | 17.5 |
Total operating expenses | 496.2 | 360.1 |
OPERATING INCOME | 110.4 | 105.4 |
Other income - net | 3.9 | 1.8 |
Interest Expense | 16.7 | 17.9 |
INCOME BEFORE INCOME TAXES | 97.6 | 89.3 |
Income taxes | 36.3 | 34.2 |
NET INCOME | 61.3 | 55.1 |
Subsidiary Guarantors [Member] | ' | ' |
OPERATING REVENUES [Abstract] | ' | ' |
Gas utility | 443.6 | 315.9 |
Electric utility | 163 | 149.5 |
Other | 0 | 0 |
Total operating revenues | 606.6 | 465.4 |
OPERATING EXPENSES [Abstract] | ' | ' |
Cost of gas sold | 270.9 | 157.2 |
Cost of fuel & purchased power | 57 | 50.2 |
Other operating | 107.5 | 96 |
Depreciation & Amortization | 44.4 | 43.1 |
Taxes other than income taxes | 19.6 | 17.1 |
Total operating expenses | 499.4 | 363.6 |
OPERATING INCOME | 107.2 | 101.8 |
Other income - net | 3 | 1.9 |
Interest Expense | 15.8 | 16.2 |
INCOME BEFORE INCOME TAXES | 94.4 | 87.5 |
Income taxes | 36.8 | 34.8 |
Equity in earnings of consolidated companies, net of tax | 0 | 0 |
NET INCOME | 57.6 | 52.7 |
Parent Company [Member] | ' | ' |
OPERATING REVENUES [Abstract] | ' | ' |
Gas utility | 0 | 0 |
Electric utility | 0 | 0 |
Other | 9.6 | 9.5 |
Total operating revenues | 9.6 | 9.5 |
OPERATING EXPENSES [Abstract] | ' | ' |
Cost of gas sold | 0 | 0 |
Cost of fuel & purchased power | 0 | 0 |
Other operating | 0 | 0 |
Depreciation & Amortization | 5.4 | 5.2 |
Taxes other than income taxes | 0.4 | 0.4 |
Total operating expenses | 5.8 | 5.6 |
OPERATING INCOME | 3.8 | 3.9 |
Other income - net | 10.7 | 9.7 |
Interest Expense | 11.3 | 11.8 |
INCOME BEFORE INCOME TAXES | 3.2 | 1.8 |
Income taxes | -0.5 | -0.6 |
Equity in earnings of consolidated companies, net of tax | 57.6 | 52.7 |
NET INCOME | 61.3 | 55.1 |
Consolidation, Eliminations [Member] | ' | ' |
OPERATING REVENUES [Abstract] | ' | ' |
Gas utility | 0 | 0 |
Electric utility | 0 | 0 |
Other | -9.6 | -9.4 |
Total operating revenues | -9.6 | -9.4 |
OPERATING EXPENSES [Abstract] | ' | ' |
Cost of gas sold | 0 | 0 |
Cost of fuel & purchased power | 0 | 0 |
Other operating | -9.2 | -9.2 |
Depreciation & Amortization | 0.1 | 0.1 |
Taxes other than income taxes | 0.1 | 0 |
Total operating expenses | -9 | -9.1 |
OPERATING INCOME | -0.6 | -0.3 |
Other income - net | -9.8 | -9.8 |
Interest Expense | -10.4 | -10.1 |
INCOME BEFORE INCOME TAXES | 0 | 0 |
Income taxes | 0 | 0 |
Equity in earnings of consolidated companies, net of tax | -57.6 | -52.7 |
NET INCOME | -57.6 | -52.7 |
Consolidated Entities [Member] | ' | ' |
OPERATING REVENUES [Abstract] | ' | ' |
Gas utility | 443.6 | 315.9 |
Electric utility | 163 | 149.5 |
Other | 0 | 0.1 |
Total operating revenues | 606.6 | 465.5 |
OPERATING EXPENSES [Abstract] | ' | ' |
Cost of gas sold | 270.9 | 157.2 |
Cost of fuel & purchased power | 57 | 50.2 |
Other operating | 98.3 | 86.8 |
Depreciation & Amortization | 49.9 | 48.4 |
Taxes other than income taxes | 20.1 | 17.5 |
Total operating expenses | 496.2 | 360.1 |
OPERATING INCOME | 110.4 | 105.4 |
Other income - net | 3.9 | 1.8 |
Interest Expense | 16.7 | 17.9 |
INCOME BEFORE INCOME TAXES | 97.6 | 89.3 |
Income taxes | 36.3 | 34.2 |
Equity in earnings of consolidated companies, net of tax | 0 | 0 |
NET INCOME | $61.30 | $55.10 |
Subsidiary_Guarantor_and_Conso4
Subsidiary Guarantor and Consolidating Information Subsidiary Guarantor and Consolidating Information Cash Flows (Details) (USD $) | 3 Months Ended | |||
In Millions, unless otherwise specified | Mar. 31, 2014 | Mar. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2012 |
Net cash provided by operating activities | $156 | $161.30 | ' | ' |
Long-term debt - net of issuance costs | 0 | ' | ' | ' |
Additional capital contribution from parent | 1.6 | 1.5 | ' | ' |
Dividends to parent | -27.1 | -26.3 | ' | ' |
Net change in intercompany short-term borrowings | 0 | ' | ' | ' |
Net change in short-term borrowings | -28.6 | -89.6 | ' | ' |
Net cash used in financing activities | -54.1 | -114.4 | ' | ' |
Consolidated subsidiary distributions | 0 | ' | ' | ' |
Proceeds from other investing activities | 0.1 | 0.1 | ' | ' |
Capital expenditures, excluding AFUDC equity | -58 | -50.5 | ' | ' |
Consolidated subsidiary investments | 0 | ' | ' | ' |
Net change in long-term intercompany notes receivable | 0 | ' | ' | ' |
Net change in short term intercompany notes receivable | 0 | ' | ' | ' |
Net cash used in investing activities | -57.9 | -50.4 | ' | ' |
Net change in cash and cash equivalents | 44 | -3.5 | ' | ' |
Cash & cash equivalents | 52.6 | 9.8 | 8.6 | 13.3 |
Subsidiary Guarantors [Member] | ' | ' | ' | ' |
Net cash provided by operating activities | 137.2 | 168.5 | ' | ' |
Long-term debt - net of issuance costs | 124.2 | ' | ' | ' |
Additional capital contribution from parent | 1.6 | 8.5 | ' | ' |
Dividends to parent | -25.4 | -24.5 | ' | ' |
Net change in intercompany short-term borrowings | -73.1 | -83.1 | ' | ' |
Net change in short-term borrowings | 0 | 0 | ' | ' |
Net cash used in financing activities | 27.3 | -99.1 | ' | ' |
Consolidated subsidiary distributions | 0 | 0 | ' | ' |
Proceeds from other investing activities | 0 | 0 | ' | ' |
Capital expenditures, excluding AFUDC equity | -51.3 | -47.3 | ' | ' |
Consolidated subsidiary investments | 0 | 0 | ' | ' |
Net change in long-term intercompany notes receivable | 0 | ' | ' | ' |
Net change in short term intercompany notes receivable | -85.6 | -28.9 | ' | ' |
Net cash used in investing activities | -136.9 | -76.2 | ' | ' |
Net change in cash and cash equivalents | 27.6 | -6.8 | ' | ' |
Cash & cash equivalents | 35.8 | 5.7 | 8.2 | 12.5 |
Parent Company [Member] | ' | ' | ' | ' |
Net cash provided by operating activities | 18.8 | -7 | ' | ' |
Long-term debt - net of issuance costs | 0 | ' | ' | ' |
Additional capital contribution from parent | 1.6 | 1.5 | ' | ' |
Dividends to parent | -27.1 | -26.3 | ' | ' |
Net change in intercompany short-term borrowings | 85.6 | 28.9 | ' | ' |
Net change in short-term borrowings | -28.6 | -89.6 | ' | ' |
Net cash used in financing activities | 31.5 | -85.5 | ' | ' |
Consolidated subsidiary distributions | 25.4 | 24.5 | ' | ' |
Proceeds from other investing activities | 0.1 | 0.1 | ' | ' |
Capital expenditures, excluding AFUDC equity | -6.7 | -3.4 | ' | ' |
Consolidated subsidiary investments | -1.6 | -8.5 | ' | ' |
Net change in long-term intercompany notes receivable | -124.2 | ' | ' | ' |
Net change in short term intercompany notes receivable | 73.1 | 83.1 | ' | ' |
Net cash used in investing activities | -33.9 | 95.8 | ' | ' |
Net change in cash and cash equivalents | 16.4 | 3.3 | ' | ' |
Cash & cash equivalents | 16.8 | 4.1 | 0.4 | 0.8 |
Consolidation, Eliminations [Member] | ' | ' | ' | ' |
Net cash provided by operating activities | 0 | -0.2 | ' | ' |
Long-term debt - net of issuance costs | -124.2 | ' | ' | ' |
Additional capital contribution from parent | -1.6 | -8.5 | ' | ' |
Dividends to parent | 25.4 | 24.5 | ' | ' |
Net change in intercompany short-term borrowings | -12.5 | 54.2 | ' | ' |
Net change in short-term borrowings | 0 | 0 | ' | ' |
Net cash used in financing activities | -112.9 | 70.2 | ' | ' |
Consolidated subsidiary distributions | -25.4 | -24.5 | ' | ' |
Proceeds from other investing activities | 0 | 0 | ' | ' |
Capital expenditures, excluding AFUDC equity | 0 | 0.2 | ' | ' |
Consolidated subsidiary investments | 1.6 | 8.5 | ' | ' |
Net change in long-term intercompany notes receivable | 124.2 | ' | ' | ' |
Net change in short term intercompany notes receivable | 12.5 | -54.2 | ' | ' |
Net cash used in investing activities | 112.9 | -70 | ' | ' |
Net change in cash and cash equivalents | 0 | 0 | ' | ' |
Cash & cash equivalents | 0 | 0 | 0 | 0 |
Consolidated Entities [Member] | ' | ' | ' | ' |
Net cash provided by operating activities | ' | 161.3 | ' | ' |
Additional capital contribution from parent | ' | 1.5 | ' | ' |
Dividends to parent | ' | -26.3 | ' | ' |
Net change in intercompany short-term borrowings | ' | 0 | ' | ' |
Net change in short-term borrowings | ' | -89.6 | ' | ' |
Net cash used in financing activities | ' | -114.4 | ' | ' |
Consolidated subsidiary distributions | ' | 0 | ' | ' |
Proceeds from other investing activities | ' | 0.1 | ' | ' |
Capital expenditures, excluding AFUDC equity | ' | -50.5 | ' | ' |
Consolidated subsidiary investments | ' | 0 | ' | ' |
Net change in short term intercompany notes receivable | ' | 0 | ' | ' |
Net cash used in investing activities | ' | -50.4 | ' | ' |
Net change in cash and cash equivalents | ' | -3.5 | ' | ' |
Cash & cash equivalents | $52.60 | $9.80 | $8.60 | $13.30 |
Excise_and_Utility_Receipts_Ta1
Excise and Utility Receipts Taxes (Details) (USD $) | 3 Months Ended | |
In Millions, unless otherwise specified | Mar. 31, 2014 | Mar. 31, 2013 |
Excise and Utility Receipts Taxes [Abstract] | ' | ' |
Excise and utility taxes collected and reported in operating revenue | $12.90 | $10.70 |
Accruals_for_Utility_and_NonUt1
Accruals for Utility and NonUtility Plant Accruals for Utility and NonUtility Plant (Details) (USD $) | Mar. 31, 2014 | Dec. 31, 2013 |
In Millions, unless otherwise specified | ||
Accruals for Utility & Nonutility Plant [Abstract] | ' | ' |
Public Utilities Accruals For Purchase Of Utility And Non Utility Plant Assets | $13 | $13.10 |
Transactions_with_Other_Vectre1
Transactions with Other Vectren Companies and Affiliates Transactions with Other Vectren Companies and Afffiliates (Details) (USD $) | 3 Months Ended | |
In Millions, unless otherwise specified | Mar. 31, 2014 | Mar. 31, 2013 |
Vectren Fuels Inc. [Member] | ' | ' |
Transactions with Other Vectren Companies and Affiliates [Line Items] | ' | ' |
Expenses from transactions with related party | $30.80 | $19.90 |
Vectren Infrastructure Services Corporation [Member] | ' | ' |
Transactions with Other Vectren Companies and Affiliates [Line Items] | ' | ' |
Expenses from transactions with related party | 11.4 | 10.4 |
ProLiance [Member] | ' | ' |
Transactions with Other Vectren Companies and Affiliates [Line Items] | ' | ' |
Expenses from transactions with related party | 0 | 107.6 |
Percentage of purchases from single third party | 83.00% | ' |
Date equity method investment disposed of a group of assets | 18-Jun-13 | ' |
Support Services & Purchases [Member] | ' | ' |
Transactions with Other Vectren Companies and Affiliates [Line Items] | ' | ' |
Cost of corporate and general and administrative services | $14.70 | $14.90 |
Rate_Regulatory_Matters_Detail
Rate & Regulatory Matters (Details) (USD $) | 3 Months Ended | 12 Months Ended | 3 Months Ended | 3 Months Ended | 3 Months Ended | ||||||
Mar. 31, 2014 | Dec. 31, 2012 | Dec. 31, 2011 | Feb. 01, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | |
Ohio [Member] | Ohio [Member] | Indiana [Member] | Indiana [Member] | Indiana [Member] | SIGECO [Member] | Indiana Gas [Member] | |||||
Ohio Recovery and Deferral Mechanisms [Member] | Ohio Recovery and Deferral Mechanisms [Member] | Indiana Recovery and Deferral Mechanisms [Member] | Indiana Recovery and Deferral Mechanisms [Member] | Pipeline Safety Law [Member] | Indiana [Member] | Indiana [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 | ' | ' | ' | ' | $111,000,000 | ' | ' | ' | ' | ' | ' |
Regulatory Asset associated with DRR deferrals of depreciation and post in-service carrying costs | ' | ' | ' | ' | 10,100,000 | 9,300,000 | ' | ' | ' | ' | ' |
Period of extended DRR term | ' | ' | ' | ' | 5 | ' | ' | ' | ' | ' | ' |
Amount of Capital Investment Expected Over Next Five Years Recoverable Under DRR | ' | ' | ' | ' | 187,000,000 | ' | ' | ' | ' | ' | ' |
Estimated budget related to Ohio capital expenditure program | ' | ' | ' | ' | 23,500,000 | ' | ' | ' | ' | ' | ' |
Time period (in months) included in VEDO application | ' | ' | ' | ' | '15 | ' | ' | ' | ' | ' | ' |
Bill impact per customer per month | ' | ' | ' | ' | 1.5 | ' | ' | ' | ' | ' | ' |
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 | ' | ' | ' | ' | ' | ' | 13,200,000 | 12,100,000 | ' | ' | ' |
Percentage of project costs to be deferred for future recovery | ' | ' | ' | ' | ' | ' | 20.00% | ' | ' | ' | ' |
Length of project plan required for recovery under new legislation | ' | ' | ' | ' | ' | ' | 7 | ' | ' | ' | ' |
Expected Seven Year Period Modernization Investment | ' | ' | ' | ' | ' | ' | ' | ' | 865,000,000 | ' | ' |
Amount of economic development expenditures | ' | ' | ' | ' | ' | ' | ' | ' | 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 | ' | ' |
Adjustment mechanism cap % based on annual retail revenue increase | ' | ' | ' | ' | ' | ' | 2.00% | ' | ' | ' | ' |
Percentage of costs eligible for recovery using periodic rate recovery mechanism | ' | ' | ' | ' | ' | ' | 80.00% | ' | ' | ' | ' |
Initial DRR term | ' | ' | ' | ' | 5 | ' | ' | ' | ' | ' | ' |
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 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Coal Procurement Procedures [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Number of years for recovery of coal costs | 6 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Cumulative total deferrals related to coal purchases | 40,600,000 | ' | ' | 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 | 1,600,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
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 | $146,100,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
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 $) | 3 Months Ended | |
In Millions, unless otherwise specified | Mar. 31, 2014 | Dec. 31, 2013 |
MW | ||
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 | ' |
Indiana Senate Bill 1 [Abstract] | ' | ' |
Total rate reduction as a result of new legislation | 1.60% | ' |
Annual Phase in Percentage for First 5 Years | 0.25% | ' |
Phase in period of new legislation | 6 | ' |
Annual Phase in Percentage for Year 6 | 0.35% | ' |
Final tax rate after legislation phase in | 4.90% | ' |
Indiana Senate Bill 251 [Abstract] | ' | ' |
Percentage of total electricity obtained by supplier to meet customer needs | 10.00% | ' |
Power generation capacity for acquired landfill gas generations facility (in megawatts) | 3 | ' |
Long term contract for purchase of electric power generated by wind energy (in megawatts) | 80 | ' |
Percentage of total electricity obtained by the supplier to meet the energy needs of its retail customers provided by clean energy sources (in hundredths) | 5.00% | ' |
Clean Water Act [Abstract] | ' | ' |
Estimated capital expenditures related to Clean Water Act | 40 | ' |
Coal Ash Waste Disposal and Ash Ponds [Abstract] | ' | ' |
Estimated capital expenditures to comply with ash pond and coal ash disposal regulations | 30 | ' |
Potential estimated capital expenditures to comply with ash pond and coal ash disposal regulations with stringent alternative | 100 | ' |
Estimated annual compliance costs maximum with ash pond and coal ash disposal regulation | 5 | ' |
Climate Changes [Abstract] | ' | ' |
Maximum level of greenhouse gas emissions that prompts requirement to obtain permit for facilities to construct new facility of significant modification to existing facility (in tons) | 75,000 | ' |
Manufactured Gas Plants | ' | ' |
Site contingency, accrual, undiscounted amount | 43.4 | ' |
Accrual for Environmental Loss Contingencies | 5.2 | 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 $) | 3 Months Ended | |||
In Millions, unless otherwise specified | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2013 | Dec. 31, 2012 |
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ' | ' | ' | ' |
Period over which call premium on reacquisition of long-term debt | '15 | ' | ' | ' |
Short-term borrowings | $0 | $28.60 | ' | ' |
Cash and Cash Equivalents, at Carrying Value | 52.6 | 8.6 | 9.8 | 13.3 |
Carrying Amount [Member] | ' | ' | ' | ' |
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ' | ' | ' | ' |
Long-term Debt, Fair Value | 1,257.20 | 1,257.10 | ' | ' |
Short-term Debt, Fair Value | 0 | 28.6 | ' | ' |
Cash and cash equivalents | 52.6 | 8.6 | ' | ' |
Estimated Fair Value [Member] | ' | ' | ' | ' |
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ' | ' | ' | ' |
Long-term Debt, Fair Value | 1,367.30 | 1,317.40 | ' | ' |
Short-term Debt, Fair Value | 0 | 28.6 | ' | ' |
Cash and cash equivalents | $52.60 | $8.60 | ' | ' |
Segment_Reporting_Details
Segment Reporting (Details) (USD $) | 3 Months Ended | |
In Millions, unless otherwise specified | Mar. 31, 2014 | Mar. 31, 2013 |
Segment Reporting Information [Line Items] | ' | ' |
Portion of Indiana that is provided natural gas distribution and transportation services by the Gas Utility Services segment (in hundredths) | 66.67% | ' |
Revenues | $606.60 | $465.50 |
Profitability Measure - Net income (loss) | 61.3 | 55.1 |
Utility Group [Member] | ' | ' |
Segment Reporting Information [Line Items] | ' | ' |
Number of Reportable Segments | 3 | ' |
Utility Group [Member] | Gas Utility Services [Member] | ' | ' |
Segment Reporting Information [Line Items] | ' | ' |
Revenues | 443.6 | 315.9 |
Profitability Measure - Net income (loss) | 38.3 | 38.1 |
Utility Group [Member] | Electric Utility Services [Member] | ' | ' |
Segment Reporting Information [Line Items] | ' | ' |
Revenues | 163 | 149.5 |
Profitability Measure - Net income (loss) | 19.3 | 14.6 |
Utility Group [Member] | Other Segments [Member] | ' | ' |
Segment Reporting Information [Line Items] | ' | ' |
Revenues | 9.6 | 9.5 |
Profitability Measure - Net income (loss) | 3.7 | 2.4 |
Utility Group [Member] | Intersegment Eliminations [Member] | ' | ' |
Segment Reporting Information [Line Items] | ' | ' |
Revenues | ($9.60) | ($9.40) |