Vectren Utility 10-Q 12 Aug 16 2016 Q2 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2016	Jul. 29, 2016
Document and Entity Information [Abstract]
Entity Registrant Name	VECTREN UTILITY HOLDINGS INC
Entity Central Index Key	1,129,542
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		10
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	Q2
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2016

CONSOLIDATED CONDENSED BALANCE

CONSOLIDATED CONDENSED BALANCE SHEETS (Unaudited) - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Assets, Current [Abstract]
Cash & cash equivalents	$ 4.6	$ 6.2
Accounts receivable - less reserves of $4.1 & $3.0, respectively	66.7	92.3
Accrued unbilled revenues	45.5	85.7
Inventories	115.4	125.3
Recoverable fuel & natural gas costs	18.4	0
Prepayments & other current assets	35.8	49
Total current assets	286.4	358.5
Utility Plant [Abstract]
Original cost	6,298.5	6,090.4
Less: accumulated depreciation & amortization	2,493	2,415.5
Net utility plant	3,805.5	3,674.9
Investments in unconsolidated affiliates	0.2	0.2
Other Investments	20.8	20.1
Nonutility plant - net	154.1	149.7
Goodwill	205	205
Regulatory assets	177.1	152.1
Other assets	48	32.2
TOTAL ASSETS	4,697.1	4,592.7
Current Liabilities [Abstract]
Accounts payable	138.2	168.5
Payables to other Vectren companies	27.3	25.7
Accrued liabilities	123.7	128.4
Short-term borrowings	38.9	14.5
Current maturities of long-term debt	0	13
Total current liabilities	328.1	350.1
Long-Term Debt - Net of Current Maturities	1,379.7	1,379.2
Deferred Credits & Other Liabilities [Abstract]
Deferred income taxes	802.5	758.4
Regulatory liabilities	448.2	433.9
Deferred credits & other liabilities	146	135.9
Total deferred credits & other liabilities	1,396.7	1,328.2
Commitments & Contingencies (Notes 7 - 10)
Common Shareholder's Equity [Abstract]
Common stock (no par value)	827.9	799.9
Retained earnings	764.7	735.3
Total common shareholders' equity	1,592.6	1,535.2
TOTAL LIABILITIES & SHAREHOLDERS' EQUITY	$ 4,697.1	$ 4,592.7

CONSOLIDATED CONDENSED BALANCE3

CONSOLIDATED CONDENSED BALANCE SHEETS (Unaudited) (Parenthetical) - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Assets, Current [Abstract]
Allowance for Doubtful Accounts Receivable, Current	$ 4.1	$ 3

CONSOLIDATED CONDENSED STATEMEN

CONSOLIDATED CONDENSED STATEMENTS OF INCOME (Unaudited) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
OPERATING REVENUES [Abstract]
Gas utility	$ 132	$ 128.6	$ 413.1	$ 481.5
Electric utility	147.7	147.8	289.8	301.7
Other	0.1	0.1	0.2	0.2
Total operating revenues	279.8	276.5	703.1	783.4
OPERATING EXPENSES [Abstract]
Cost of gas sold	34	36.4	145.5	208.4
Cost of fuel & purchased power	45.2	47	89.4	97
Other operating	81.3	78.5	171.4	181.3
Depreciation & Amortization	54	52	107.6	104.2
Taxes other than income taxes	13.1	12.1	30.2	31.2
Total operating expenses	227.6	226	544.1	622.1
OPERATING INCOME	52.2	50.5	159	161.3
Nonoperating Income (Expense) [Abstract]
Other income - net	7	4.3	13.3	9.2
Interest Expense	17.5	16.4	35	33
INCOME BEFORE INCOME TAXES	41.7	38.4	137.3	137.5
Income taxes	15.4	14	49.9	50.1
NET INCOME	$ 26.3	$ 24.4	$ 87.4	$ 87.4

CONSOLIDATED CONDENSED STATEME5

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
CASH FLOWS FROM OPERATING ACTIVITIES [Abstract]
NET INCOME	$ 87.4	$ 87.4
Adjustments to Reconcile Net Income to Cash from Operating Activities [Abstract]
Depreciation & Amortization	107.6	104.2
Deferred income taxes & investment tax credits	44.1	23.2
Expense portion of pension & postretirement periodic benefit cost	2	2.4
Provision for uncollectible accounts	3.8	4.1
Other non-cash expense - net	1.4	3.4
Changes in working capital accounts [Abstract]
Accounts receivable & accrued unbilled revenue	62	115.8
Inventories	9.9	9.2
Recoverable/refundable fuel & natural gas costs	(26.3)	30
Prepayments & other current assets	13	50.6
Accounts payable, including to Vectren companies & affiliated companies	(43.3)	(89)
Accrued liabilities	3.2	5.6
Changes in noncurrent ssets	(34.1)	(5.7)
Changes in noncurrent liabilities	2.1	(4.4)
Net cash provided by operating activities	232.8	336.8
Proceeds from:
Additional capital contribution	28	3
Requirements for:
Dividends to parent	(58)	(55.2)
Retirement of long-term debt	(13)	(5)
Net change in short-term borrowings	24.4	(129.1)
Net cash used in financing activities	(18.6)	(186.3)
CASH FLOWS FROM INVESTING ACTIVITIES [Abstract]
Proceeds from other investing activities	0	0.1
Requirements for:
Capital expenditures, excluding AFUDC equity	(215.9)	(163.2)
Increase (Decrease) in Restricted Cash	(0.1)	0
Net cash used in investing activities	(215.8)	(163.1)
Net change in cash & cash equivalents	(1.6)	(12.6)
Cash & cash equivalents at beginning of period	6.2	19.3
Cash & cash equivalents at end of period	$ 4.6	$ 6.7

Organization and Nature of Oper

Organization and Nature of Operations	6 Months Ended
	Jun. 30, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization and Nature of Operations	Organization and Nature of Operations Vectren Utility Holdings, Inc. (the Company, Utility Holdings or VUHI), an Indiana corporation, was formed on March 31, 2000 to serve as the intermediate holding company for Vectren Corporation’s (Vectren) three operating public utilities: Indiana Gas Company, Inc. (Indiana Gas or Vectren Energy Delivery of Indiana - North), Southern Indiana Gas and Electric Company (SIGECO or Vectren Energy Delivery of Indiana - South), and Vectren Energy Delivery of Ohio, Inc. (VEDO). 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 588,000 natural gas customers located in central and southern Indiana. SIGECO provides energy delivery services to approximately 144,000 electric customers and approximately 111,000 gas customers located near Evansville in southwestern Indiana. SIGECO also owns and operates electric generation assets to serve its electric customers and optimizes those assets in the wholesale power market. Indiana Gas and SIGECO generally do business as Vectren Energy Delivery of Indiana. VEDO provides energy delivery services to approximately 318,000 natural gas customers located near Dayton in west central Ohio.

Basis of Presentation

Basis of Presentation	6 Months Ended
	Jun. 30, 2016
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 interim 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, 2015 , filed with the Securities and Exchange Commission on March 9, 2016, 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 Consol

Subsidiary Guarantor and Consolidating Information	6 Months Ended
	Jun. 30, 2016
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 $39 million was outstanding at June 30, 2016 . The operating utility companies are also guarantors of Utility Holdings’ unsecured senior notes with a par value of $995 million outstanding at June 30, 2016 . 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 condensed 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 June 30, 2016 (in millions): ASSETS Subsidiary Parent Eliminations & Guarantors Company Reclassifications Consolidated Current Assets Cash & cash equivalents $ 3.4 $ 1.2 $ — $ 4.6 Accounts receivable - less reserves 66.6 0.1 — 66.7 Intercompany receivables 37.4 39.6 (77.0 ) — Accrued unbilled revenues 45.5 — — 45.5 Inventories 115.3 0.1 — 115.4 Recoverable fuel & natural gas costs 18.4 — — 18.4 Prepayments & other current assets 35.0 2.6 (1.8 ) 35.8 Total current assets 321.6 43.6 (78.8 ) 286.4 Utility Plant Original cost 6,298.5 — — 6,298.5 Less: accumulated depreciation & amortization 2,493.0 — — 2,493.0 Net utility plant 3,805.5 — — 3,805.5 Investments in consolidated subsidiaries — 1,530.3 (1,530.3 ) — Notes receivable from consolidated subsidiaries — 945.4 (945.4 ) — Investments in unconsolidated affiliates 0.2 — — 0.2 Other investments 20.4 0.4 — 20.8 Nonutility plant - net 1.7 152.4 — 154.1 Goodwill - net 205.0 — — 205.0 Regulatory assets 160.5 16.6 — 177.1 Other assets 54.9 1.0 (7.9 ) 48.0 TOTAL ASSETS $ 4,569.8 $ 2,689.7 $ (2,562.4 ) $ 4,697.1 LIABILITIES & SHAREHOLDER'S EQUITY Subsidiary Parent Eliminations & Guarantors Company Reclassifications Consolidated Current Liabilities Accounts payable $ 130.8 $ 7.4 $ — $ 138.2 Intercompany payables 16.1 — (16.1 ) — Payables to other Vectren companies 26.1 1.2 — 27.3 Accrued liabilities 112.3 13.2 (1.8 ) 123.7 Short-term borrowings — 38.9 — 38.9 Intercompany short-term borrowings 23.5 37.4 (60.9 ) — Total current liabilities 308.8 98.1 (78.8 ) 328.1 Long-Term Debt Long-term debt 384.2 995.5 — 1,379.7 Long-term debt due to VUHI 945.4 — (945.4 ) — Total long-term debt - net 1,329.6 995.5 (945.4 ) 1,379.7 Deferred Credits & Other Liabilities Deferred income taxes 805.3 (2.8 ) — 802.5 Regulatory liabilities 446.8 1.4 — 448.2 Deferred credits & other liabilities 149.0 4.9 (7.9 ) 146.0 Total deferred credits & other liabilities 1,401.1 3.5 (7.9 ) 1,396.7 Common Shareholder's Equity Common stock (no par value) 841.0 827.9 (841.0 ) 827.9 Retained earnings 689.3 764.7 (689.3 ) 764.7 Total common shareholder's equity 1,530.3 1,592.6 (1,530.3 ) 1,592.6 TOTAL LIABILITIES & SHAREHOLDER'S EQUITY $ 4,569.8 $ 2,689.7 $ (2,562.4 ) $ 4,697.1 Condensed Consolidating Balance Sheet as of December 31, 2015 (in millions): ASSETS Subsidiary Parent Eliminations & Guarantors Company Reclassifications Consolidated Current Assets Cash & cash equivalents $ 5.5 $ 0.7 $ — $ 6.2 Accounts receivable - less reserves 92.3 — — 92.3 Intercompany receivables 51.2 142.9 (194.1 ) — Accrued unbilled revenues 85.7 — — 85.7 Inventories 125.3 — — 125.3 Prepayments & other current assets 49.3 4.1 (4.4 ) 49.0 Total current assets 409.3 147.7 (198.5 ) 358.5 Utility Plant Original cost 6,090.4 — — 6,090.4 Less: accumulated depreciation & amortization 2,415.5 — — 2,415.5 Net utility plant 3,674.9 — — 3,674.9 Investments in consolidated subsidiaries — 1,467.0 (1,467.0 ) — Notes receivable from consolidated subsidiaries — 836.0 (836.0 ) — Investments in unconsolidated affiliates 0.2 — — 0.2 Other investments 19.7 0.4 — 20.1 Nonutility plant - net 1.7 148.0 — 149.7 Goodwill - net 205.0 — — 205.0 Regulatory assets 135.2 16.9 — 152.1 Other assets 39.6 1.3 (8.7 ) 32.2 TOTAL ASSETS $ 4,485.6 $ 2,617.3 $ (2,510.2 ) $ 4,592.7 LIABILITIES & SHAREHOLDER'S EQUITY Subsidiary Parent Eliminations & Guarantors Company Reclassifications Consolidated Current Liabilities Accounts payable $ 161.1 $ 7.4 $ — $ 168.5 Intercompany payables 12.4 — (12.4 ) — Payables to other Vectren companies 25.7 — — 25.7 Accrued liabilities 120.2 12.6 (4.4 ) 128.4 Short-term borrowings — 14.5 — 14.5 Intercompany short-term borrowings 130.5 51.2 (181.7 ) — Current maturities of long-term debt 13.0 — — 13.0 Total current liabilities 462.9 85.7 (198.5 ) 350.1 Long-Term Debt Long-term debt - net of current maturities & debt subject to tender 383.9 995.3 — 1,379.2 Long-term debt due to VUHI 836.0 — (836.0 ) — Total long-term debt - net 1,219.9 995.3 (836.0 ) 1,379.2 Deferred Credits & Other Liabilities Deferred income taxes 763.7 (5.3 ) — 758.4 Regulatory liabilities 432.5 1.4 — 433.9 Deferred credits & other liabilities 139.6 5.0 (8.7 ) 135.9 Total deferred credits & other liabilities 1,335.8 1.1 (8.7 ) 1,328.2 Common Shareholder's Equity Common stock (no par value) 813.1 799.9 (813.1 ) 799.9 Retained earnings 653.9 735.3 (653.9 ) 735.3 Total common shareholder's equity 1,467.0 1,535.2 (1,467.0 ) 1,535.2 TOTAL LIABILITIES & SHAREHOLDER'S EQUITY $ 4,485.6 $ 2,617.3 $ (2,510.2 ) $ 4,592.7 Condensed Consolidating Statement of Income for the three months ended June 30, 2016 (in millions): Subsidiary Guarantors Parent Company Eliminations & Reclassifications Consolidated OPERATING REVENUES Gas utility $ 132.0 $ — $ — $ 132.0 Electric utility 147.7 — — 147.7 Other — 10.6 (10.5 ) 0.1 Total operating revenues 279.7 10.6 (10.5 ) 279.8 OPERATING EXPENSES Cost of gas sold 34.0 — — 34.0 Cost of fuel & purchased power 45.2 — — 45.2 Other operating 91.5 — (10.2 ) 81.3 Depreciation & amortization 48.0 6.0 — 54.0 Taxes other than income taxes 12.7 0.4 — 13.1 Total operating expenses 231.4 6.4 (10.2 ) 227.6 OPERATING INCOME 48.3 4.2 (0.3 ) 52.2 Other income - net 6.9 11.7 (11.6 ) 7.0 Interest expense 16.9 12.5 (11.9 ) 17.5 INCOME BEFORE INCOME TAXES 38.3 3.4 — 41.7 Income taxes 14.4 1.0 — 15.4 Equity in earnings of consolidated companies, net of tax — 23.9 (23.9 ) — NET INCOME $ 23.9 $ 26.3 $ (23.9 ) $ 26.3 Condensed Consolidating Statement of Income for the three months ended June 30, 2015 (in millions): Subsidiary Guarantors Parent Company Eliminations & Reclassifications Consolidated OPERATING REVENUES Gas utility $ 128.6 $ — $ — $ 128.6 Electric utility 147.8 — — 147.8 Other — 10.2 (10.1 ) 0.1 Total operating revenues 276.4 10.2 (10.1 ) 276.5 OPERATING EXPENSES Cost of gas sold 36.4 — — 36.4 Cost of fuel & purchased power 47.0 — — 47.0 Other operating 87.9 — (9.4 ) 78.5 Depreciation & amortization 45.5 6.4 0.1 52.0 Taxes other than income taxes 11.7 0.4 — 12.1 Total operating expenses 228.5 6.8 (9.3 ) 226.0 OPERATING INCOME 47.9 3.4 (0.8 ) 50.5 Other income - net 4.3 9.9 (9.9 ) 4.3 Interest expense 15.8 11.3 (10.7 ) 16.4 INCOME BEFORE INCOME TAXES 36.4 2.0 — 38.4 Income taxes 13.3 0.7 — 14.0 Equity in earnings of consolidated companies, net of tax — 23.1 (23.1 ) — NET INCOME $ 23.1 $ 24.4 $ (23.1 ) $ 24.4 Condensed Consolidating Statement of Income for the six months ended June 30, 2016 (in millions): Subsidiary Guarantors Parent Company Eliminations & Reclassifications Consolidated OPERATING REVENUES Gas utility $ 413.1 $ — $ — $ 413.1 Electric utility 289.8 — — 289.8 Other — 21.1 (20.9 ) 0.2 Total operating revenues 702.9 21.1 (20.9 ) 703.1 OPERATING EXPENSES Cost of gas sold 145.5 — — 145.5 Cost of fuel & purchased power 89.4 — — 89.4 Other operating 191.6 — (20.2 ) 171.4 Depreciation & amortization 95.5 12.0 0.1 107.6 Taxes other than income taxes 29.3 0.9 — 30.2 Total operating expenses 551.3 12.9 (20.1 ) 544.1 OPERATING INCOME 151.6 8.2 (0.8 ) 159.0 Other income - net 12.2 24.0 (22.9 ) 13.3 Interest expense 33.8 24.9 (23.7 ) 35.0 INCOME BEFORE INCOME TAXES 130.0 7.3 — 137.3 Income taxes 49.1 0.8 — 49.9 Equity in earnings of consolidated companies, net of tax — 80.9 (80.9 ) — NET INCOME $ 80.9 $ 87.4 $ (80.9 ) $ 87.4 Condensed Consolidating Statement of Income for the six months ended June 30, 2015 (in millions): Subsidiary Guarantors Parent Company Eliminations & Reclassifications Consolidated OPERATING REVENUES $ 481.5 $ — $ — $ 481.5 Electric utility 301.7 — — 301.7 Other — 20.4 (20.2 ) 0.2 Total operating revenues 783.2 20.4 (20.2 ) 783.4 OPERATING EXPENSES Cost of gas sold 208.4 — — 208.4 Cost of fuel & purchased power 97.0 — — 97.0 Other operating 200.3 — (19.0 ) 181.3 Depreciation & amortization 91.2 12.8 0.2 104.2 Taxes other than income taxes 30.3 0.9 — 31.2 Total operating expenses 627.2 13.7 (18.8 ) 622.1 OPERATING INCOME 156.0 6.7 (1.4 ) 161.3 Other income - net 8.4 20.7 (19.9 ) 9.2 Interest expense 31.7 22.6 (21.3 ) 33.0 INCOME BEFORE INCOME TAXES 132.7 4.8 — 137.5 Income taxes 50.1 — — 50.1 Equity in earnings of consolidated companies, net of tax — 82.6 (82.6 ) — NET INCOME $ 82.6 $ 87.4 $ (82.6 ) $ 87.4 Condensed Consolidating Statement of Cash Flows for the six months ended June 30, 2016 (in millions): Subsidiary Guarantors Parent Company Eliminations Consolidated NET CASH PROVIDED BY OPERATING ACTIVITIES $ 210.8 $ 22.0 $ — $ 232.8 CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from Long-term debt - net of issuance costs 109.4 — (109.4 ) — Additional capital contribution from parent 28.0 28.0 (28.0 ) 28.0 Requirements for: Dividends to parent (45.5 ) (58.0 ) 45.5 (58.0 ) Retirement of long term debt (13.0 ) — — (13.0 ) Net change in intercompany short-term borrowings (106.9 ) (13.8 ) 120.7 — Net change in short-term borrowings — 24.4 — 24.4 Net cash used in financing activities (28.0 ) (19.4 ) 28.8 (18.6 ) CASH FLOWS FROM INVESTING ACTIVITIES Proceeds from: Consolidated subsidiary distributions — 45.5 (45.5 ) — Requirements for: Capital expenditures, excluding AFUDC equity (198.8 ) (17.1 ) — (215.9 ) Consolidated subsidiary investments — (28.0 ) 28.0 — Changes in restricted cash 0.1 — — 0.1 Net change in long-term intercompany notes receivable — (109.4 ) 109.4 — Net change in short-term intercompany notes receivable 13.8 106.9 (120.7 ) — Net cash used in investing activities (184.9 ) (2.1 ) (28.8 ) (215.8 ) Net change in cash & cash equivalents (2.1 ) 0.5 — (1.6 ) Cash & cash equivalents at beginning of period 5.5 0.7 — 6.2 Cash & cash equivalents at end of period $ 3.4 $ 1.2 $ — $ 4.6 Condensed Consolidating Statement of Cash Flows for the six months ended June 30, 2015 (in millions): Subsidiary Guarantors Parent Company Eliminations Consolidated NET CASH PROVIDED BY OPERATING ACTIVITIES $ 317.7 $ 19.1 $ — $ 336.8 CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from: Additional capital contribution from parent 3.0 3.0 (3.0 ) 3.0 Requirements for: Dividends to parent (51.6 ) (55.2 ) 51.6 (55.2 ) Retirement of long term debt (5.0 ) — — (5.0 ) Net change in intercompany short-term borrowings (48.2 ) 62.6 (14.4 ) — Net change in short-term borrowings — (129.1 ) — (129.1 ) Net cash used in financing activities (101.8 ) (118.7 ) 34.2 (186.3 ) CASH FLOWS FROM INVESTING ACTIVITIES Proceeds from: Consolidated subsidiary distributions — 51.6 (51.6 ) — Other investing activities — 0.1 — 0.1 Requirements for: Capital expenditures, excluding AFUDC equity (153.8 ) (9.4 ) — (163.2 ) Consolidated subsidiary investments — (3.0 ) 3.0 — Net change in short-term intercompany notes receivable (62.6 ) 48.2 14.4 — Net cash used in investing activities (216.4 ) 87.5 (34.2 ) (163.1 ) Net change in cash & cash equivalents (0.5 ) (12.1 ) — (12.6 ) Cash & cash equivalents at beginning of period 6.9 12.4 — 19.3 Cash & cash equivalents at end of period $ 6.4 $ 0.3 $ — $ 6.7

Excise and Utility Receipts Tax

Excise and Utility Receipts Taxes	6 Months Ended
	Jun. 30, 2016
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 as a component of operating revenues, which totaled $5.5 million and $5.4 million in the three months ended June 30, 2016 and 2015 , respectively. For the six months ended June 30, 2016 and 2015 , these taxes totaled $14.9 million and $17.1 million , respectively. Expenses associated with excise and utility receipts taxes are recorded as a component of Taxes other than income taxes .

Supplemental Cash Flow Informat

Supplemental Cash Flow Information	6 Months Ended
	Jun. 30, 2016
Accruals for Utility & Nonutility Plant [Abstract]
Accruals for Utility and NonUtility Plant [Text Block]	Supplemental Cash Flow Information As of June 30, 2016 and December 31, 2015 , the Company has accruals related to utility and nonutility plant purchases totaling approximately $30.9 million and $18.1 million , respectively.

Transactions with Other Vectren

Transactions with Other Vectren Companies and Affiliates	6 Months Ended
	Jun. 30, 2016
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 Infrastructure Services Corporation (VISCO) VISCO, a wholly owned subsidiary of Vectren, provides underground pipeline construction and repair services. VISCO's customers include Utility Holdings’ utilities and fees incurred by Utility Holdings and its subsidiaries totaled $37.2 million and $31.6 million for the three months ended June 30, 2016 and 2015 , respectively, and for the six months ended June 30, 2016 and 2015 totaled $56.8 million and $49.3 million , respectively. Amounts owed to VISCO at June 30, 2016 and December 31, 2015 are included in Payables to other Vectren companies in the Condensed Consolidated Balance Sheets. 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 June 30, 2016 and 2015 , Utility Holdings received corporate allocations totaling $14.8 million and $11.9 million , respectively. For the six months ended June 30, 2016 and 2015 , Utility Holdings received corporate allocations totaling $32.7 million and $27.5 million , respectively. The increase in corporate allocations in 2016 compared to 2015 is driven by higher performance-based compensation primarily due to the increase in Vectren's stock price. 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	6 Months Ended
	Jun. 30, 2016
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments & Contingencies Commitments The Company has both firm and non-firm commitments, some of which are five and ten year agreements, to purchase natural gas, electricity, and coal as well as certain transportation and storage rights. 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 condition, results of operations or cash flows.

Gas Rate & Regulatory Matters

Gas Rate & Regulatory Matters	6 Months Ended
	Jun. 30, 2016
Public Utilities, General Disclosures [Abstract]
Gas Rate and Regulatory Matters	Gas Rate & Regulatory Matters Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement The Company monitors and maintains its natural gas distribution system to ensure natural gas is delivered in a safe and efficient manner. The Company's natural gas utilities are currently engaged in programs to replace bare steel and cast iron infrastructure and other activities in both Indiana and Ohio to mitigate risk, improve the system, and comply with applicable regulations, many of which are a result of federal pipeline safety requirements. Laws passed in both Indiana and Ohio provide utilities the opportunity to timely recover costs of federally mandated projects and other infrastructure improvement projects outside of a base rate proceeding. In April 2011, Indiana Senate Bill 251 (Senate Bill 251) was signed into Indiana law. The law provides a framework to recover 80 percent of federally mandated costs through a periodic rate adjustment mechanism outside of a general rate case. Such costs include a return on the federally mandated capital investment, based on the overall rate of return most recently approved by the IURC, along with recovery of depreciation and other operating costs associated with these mandates. The remaining 20 percent of those costs is deferred for future recovery in the utility's next general rate case. In April 2013, Indiana Senate Bill 560 (Senate Bill 560) was signed into Indiana law. This legislation supplements Senate Bill 251 described above, and provides for cost recovery outside of a base rate proceeding for projects that either improve electric and gas system reliability and safety or are economic development projects that provide rural areas with access to gas service. Provisions of the legislation require that, among other things, requests for recovery include a seven-year project plan. Once the plan is approved by the IURC, 80 percent of such costs are eligible for current recovery using a periodic rate adjustment mechanism. Recoverable costs include a return on the investment that reflects the current capital structure and associated costs, with the exception of the rate of return on equity, which remains fixed at the rate determined in the Company's last rate case. Recoverable costs also include recovery of depreciation and other operating expenses. The remaining 20 percent of project costs are deferred and recovered in the utility’s next general rate case, which must be filed before the expiration of the seven-year plan. The adjustment mechanism is capped at an annual increase in retail revenues of no more than two percent. In June 2011, Ohio House Bill 95 (House Bill 95) was signed into law. Outside of a base rate proceeding, this legislation permits a natural gas utility to apply for recovery of much of its capital expenditure program. The legislation also allows for the deferral of costs, such as depreciation, property taxes, and debt-related post-in-service carrying costs until recovery is approved by the PUCO. Indiana Recovery and Deferral Mechanisms The Company's Indiana natural gas utilities received Orders in 2008 and 2007 associated with the most recent base rate cases. These Orders authorized the deferral of financial impacts associated with bare steel and cast iron replacement activities. The Orders provide for the deferral of depreciation and post-in-service carrying costs on qualifying projects totaling $20 million annually at Indiana Gas and $3 million annually at SIGECO. The debt-related post-in-service carrying costs are currently recognized in the Condensed Consolidated Statements of Income . The recording of post-in-service carrying costs and depreciation deferral is limited by individual qualifying project to three years after being placed into service at SIGECO and four years after being placed into service at Indiana Gas. At June 30, 2016 and December 31, 2015 , the Company has regulatory assets totaling $21.2 million and $19.9 million , respectively, associated with the deferral of depreciation and debt-related post-in-service carrying cost activities. Beginning in 2014, all bare steel and cast iron replacement activities are now part of the Company’s seven -year capital investment plan discussed further below. Requests for Recovery under Indiana Regulatory Mechanisms On August 27, 2014, the IURC issued an Order (August 2014 Order) approving the Company’s seven-year capital infrastructure replacement and improvement plan (the Plan), beginning in 2014, and the proposed accounting authority and recovery. Compliance projects and other infrastructure improvement projects were approved pursuant to Senate Bill 251 and 560, respectively. As provided in the two laws, the Order approved semi-annual filings for rate recovery of 100 percent of the costs, inclusive of return, related to these capital investments and operating expenses, with 80 percent of the costs, including a return, recovered currently via an approved tracking mechanism and 20 percent of the costs deferred and recovered in the Company’s next base rate proceeding. In addition, the Order established guidelines to annually update the seven-year capital investment plan. Finally, the Order approved the Company’s proposal to recover eligible costs via a fixed monthly charge per residential customer. Subsequent to the August 2014 Order, the Company filed and received Orders on each of its semi-annual updates, which recover in rates investments associated with the approved programs. In October 2015, the Company submitted its third semi-annual filing, seeking approval of the recovery in rates of investments made through June 30, 2015, and updates to the approved seven-year capital investment plan. On March 30, 2016, the IURC issued an Order (March 2016 Order) re-approving approximately $890 million of the Company’s gas infrastructure modernization projects requested in the third update of the Plan, and approving the inclusion in rates of actual investments made through June 30, 2015. While most of the proposed capital spend has been approved as proposed, approximately $80 million of projects were not approved for recovery through the mechanisms pursuant to these filings. Specifically, one project totaling about $65 million involving a 20-mile transmission line and other related investments required to support industrial customer growth and ongoing system reliability in the Lafayette, Indiana area was excluded for recovery under the Plan. The IURC stated because the project was not in the original plan filed in 2013, it does not qualify for cost recovery under this law. In the March 2016 Order, the IURC did pre-approve the project for rate base inclusion upon the filing of the next base rate case. The Company believes that such plan updates should be expected to accommodate new projects that emerge during the term of the plan as ongoing risk assessments determine that new projects are required. The Company filed an appeal of the March 2016 Order on April 29, 2016 to challenge the IURC's finding which limits the scope of the Plan updates. The outcome of the appeal is expected in 2017. On June 29, 2016, the IURC issued an Order (June 2016 Order) approving the inclusion in rates of investments made from July 2015 to December 2015. Through the June 2016 Order, approximately $262 million of the Plan's $890 million total has been spent and included for recovery as of December 31, 2015. At June 30, 2016 and December 31, 2015 , the Company has regulatory assets related to the Plan totaling $46.7 million and $28.6 million , respectively, associated with the return on investment as well as the deferral of depreciation and other operating expenses. 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 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. Due to the expiration of the initial five -year term for the DRR in early 2014, the Company filed a request in August 2013 to extend and expand the DRR. On February 19, 2014, the PUCO issued an Order approving a Stipulation entered into by the PUCO Staff and the Company which provided for the extension of the DRR for the recovery of costs incurred through 2017 and expanded the types of investment covered by the DRR to include recovery of certain other infrastructure investments. The Order limits the resulting DRR fixed charge per month for residential and small general service customers to specific graduated levels over the next five years. The capital expenditure plan is subject to the graduated caps on the fixed DRR monthly charge applicable to residential and small general service customers approved in the Order. In the event the Company exceeds these caps, amounts in excess can be deferred for future recovery; however, the remaining capital expenditure plan, estimated to be approximately $90 million for the remainder of 2016 and 2017, is not expected to exceed those caps. The Order also approved the Company's commitment that the DRR can only be further extended as part of a base rate case. In total, the Company has made capital investments under the DRR totaling $220.7 million as of June 30, 2016 . Regulatory assets associated with post-in-service carrying costs and depreciation deferrals were $21.3 million and $18.2 million at June 30, 2016 and December 31, 2015 , respectively. On May 2, 2016, the Company filed its annual request to adjust the DRR for recovery of costs incurred through December 31, 2015. A procedural schedule has been set in this proceeding and the Company expects an order by September 2016. Given the extension of the DRR through 2017, as discussed above, and the continued ability to defer other capital expenses under House Bill 95, it is anticipated that the Company will not file a general rate case for the inclusion in rate base of the above costs until the expiration of the DRR. As such, the bill impact limits discussed below are not expected to be reached given the Company's capital expenditure plan during the remaining two-year time frame. The PUCO has also issued Orders approving the Company's filings under Ohio House Bill 95. These Orders approve deferral of the Company’s Ohio capital expenditure program for items not covered by the DRR as well as expenditures necessary to comply with PUCO rules, regulations, orders, and system expansion to some new customers. Ohio House Bill 95 Orders also have established a prospective bill impact evaluation on the cumulative deferrals, limiting the total deferrals at a level which would equal $1.50 per residential and small general service customer per month. As of June 30, 2016 , the Company's deferrals have not reached this bill impact cap. On May 2, 2016, the Company submitted its most recent annual report required under its House Bill 95 Order. This report covers the Company's capital expenditure program through calendar year 2016. Pipeline and Hazardous Materials Safety Administration (PHMSA) On March 18, 2016, PHMSA published a notice of proposed rulemaking (NPRM) on the safety of gas transmission and gathering lines. The proposed rule addresses many of the remaining requirements from the 2011 Pipeline Safety Act and sets out more stringent requirements than anticipated. The Company is evaluating the impact the proposed rules would have on the Company's transmission integrity management program and the design, construction, and repair of transmission pipeline assets, including the potential for additional capital expenditures and increase in operation and maintenance expense. The Company believes that such compliance costs would be considered federally mandated costs and therefore should be recoverable from customers using the regulatory recovery mechanisms referenced above.

Electric Rate and Regulatory Ma

Electric Rate and Regulatory Matters	6 Months Ended
	Jun. 30, 2016
Public Utilities, General Disclosures [Abstract]
Electric Rate and Regulatory Matters	Electric Rate & Regulatory Matters SIGECO Electric Environmental Compliance Filing On January 28, 2015, the IURC issued an Order (January Order) approving the Company’s request for approval of capital investments in its coal-fired generation units to comply with new EPA mandates related to mercury and air toxic standards (MATS) effective in 2015 and to address an outstanding Notice of Violation (NOV) related to sulfur trioxide emissions from the EPA. As of June 30, 2016 , approximately $31 million has been spent on equipment to control mercury in both air and water emissions, and $37 million to address the issues raised in the NOV. The total investment is estimated to be between $70 million and $75 million . The Order approved the Company’s request for deferred accounting treatment, as supported by provisions under Indiana Senate Bill 29 (Senate Bill 29) and Senate Bill 251. The accounting treatment includes the deferral of depreciation and property tax expense related to these investments, accrual of post-in-service carrying costs, and deferral of incremental operating expenses related to compliance with these standards. The initial phase of the projects went into service in 2014, with the remaining investment occurring in 2015 and 2016. As of June 30, 2016 , the Company has approximately $4.6 million deferred related to depreciation, property tax, and operating expense, and $1.9 million deferred related to post-in-service carrying costs. In June 2015, Joint Appellants’ Citizens Action Coalition of Indiana, Inc., Sierra Club, Inc., and Valley Watch, Inc. (the appellants) challenged the IURC's January Order. On October 29, 2015, the Indiana Court of Appeals issued an opinion that affirmed the IURC’s findings with regard to equipment required to comply with MATS and certain national pollutant discharge elimination system rules (approximately $35 million ) but remanded the case back to the IURC to determine whether a certificate of public convenience and necessity (CPCN) should be issued for the equipment required by the NOV (approximately $40 million ). On June 22, 2016, the IURC issued an Order granting Vectren a CPCN for the NOV-required equipment. On July 21, 2016, the appellants initiated an appeal of the IURC's June 22, 2016 Order. The basis for the appeal will not be known until the appeal brief is filed later this year. The Company believes the IURC decision is well founded and will ultimately be upheld. SIGECO Electric Demand Side Management (DSM) Program Filing On August 31, 2011, the IURC issued an Order approving an initial three -year DSM plan in the SIGECO electric service territory that complied with the IURC’s energy saving targets. Consistent with the Company’s proposal, the Order approved, among other items, the following: 1) recovery of costs associated with implementing the DSM Plan; 2) the recovery of a performance incentive mechanism based on measured savings related to certain DSM programs; and 3) lost margin recovery associated with the implementation of DSM programs for large customers. On June 20, 2012, the IURC issued an Order approving a small customer lost margin recovery mechanism, inclusive of all previous deferrals. For the six months ended June 30, 2016 and 2015 , the Company recognized electric utility revenue of $5.4 million and $4.8 million , respectively, associated with this approved lost margin recovery mechanism. On March 28, 2014, Indiana Senate Bill 340 was signed into law. This legislation ended electric DSM programs on December 31, 2014 that had been conducted to meet the energy savings requirements established by the IURC in 2009. The legislation also allows for industrial customers to opt out of participating in energy efficiency programs. As of January 1, 2015, approximately 80 percent of the Company’s eligible industrial load has opted out of participation in the applicable energy efficiency programs. The Company filed a request for IURC approval of a new portfolio of DSM programs on May 29, 2014 to be offered in 2015. On October 15, 2014, the IURC issued an Order approving a Settlement between the OUCC and the Company regarding the new portfolio of DSM programs effective January 2015, and new programs for 2015 were implemented during the first quarter of 2015. On May 6, 2015, Indiana's governor signed Indiana Senate Bill 412 (Senate Bill 412) into law requiring electricity suppliers to submit energy efficiency plans to the IURC at least once every three years. Senate Bill 412 also permits the recovery of all program costs, including lost revenues and financial incentives associated with those plans and approved by the IURC. The Company made its first filing pursuant to this bill in June 2015, which proposed energy efficiency programs for calendar years 2016 and 2017. In September 2015, the Company received an Order to continue offering and recovering the associated cost of its 2015 programs until March 31, 2016. In October 2015, the OUCC and Citizens Action Coalition of Indiana filed testimony recommending the rejection of the Company’s plan, contending it was not reasonable under the terms of Senate Bill 412 due to the program design and the Company’s proposal to recover lost revenues and incentives associated with the measures. The Company filed rebuttal testimony in October 2015 defending the plan’s compliance with Senate Bill 412. On March 23, 2016, the IURC issued an Order approving the Company’s 2016-2017 energy efficiency programs. The Order provides for cost recovery of program and administrative expenses and includes performance incentives for reaching energy savings goals. The Order also included a lost margin recovery mechanism that now limits that recovery related to new programs to the shorter of four years or the life of the installed energy efficiency measure. Prior electric energy efficiency orders did not limit lost margin recovery in this manner. This ruling follows three other recent IURC decisions implementing the same lost margin recovery limitation with respect to other electric utilities in Indiana. The Company is committed to continuing to promote and drive participation in its 2016-2017 energy efficiency programs and beyond and has therefore appealed this lost margin recovery restriction. FERC Return on Equity (ROE) Complaints On November 12, 2013, certain parties representing a group of industrial customers filed a joint complaint with the FERC under Section 206 of the Federal Power Act against the MISO and various MISO transmission owners, including SIGECO. The joint parties seek to reduce the 12.38 percent ROE 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 . A second customer complaint case was filed on February 11, 2015 as the maximum FERC-allowed refund period for the November 12, 2013 case ended February 11, 2015. This second complaint covers the period February 12, 2015 through May 11, 2016. As of June 30, 2016 , the Company had invested approximately $157.7 million in qualifying projects. The net plant balance for these projects totaled $138.5 million at June 30, 2016 . These joint complaints are similar to a complaint against the New England Transmission Owners (NETO) filed in September 2011, which requested that the 11.14 percent incentive return granted on qualifying investments in NETO be lowered. On October 16, 2014, the FERC issued an Order in the NETO case approving a 10.57 percent return on equity and a new calculation methodology. The new methodology is based on a two-step discounted cash flow analysis that uses short-term and long-term growth projections in calculating ROE rates for a proxy group of electric utilities. The FERC has stated that it expects future decisions on pending complaints related to similar ROE issues to be guided by the New England transmission decision. The FERC acknowledged that the pending complaint raised against the MISO transmission owners is reasonable but denied the portion of the complaint addressing the equity component of the capital structure. An initial decision from its administrative law judge was received on December 22, 2015, authorizing the transmission owners to collect a Base ROE of 10.32 percent from November 12, 2013 through February 11, 2015 (the “first refund period”). The FERC is expected to rule on the proposed order in late 2016. An initial decision from the FERC administrative law judge in the second complaint case was received on June 30, 2016, authorizing the transmission owners to collect a Base ROE of 9.70 percent from February 12, 2015 through May 11, 2016 (the “second refund period”). The FERC is expected to rule on the proposed order in the second complaint case in 2017. Separately, on January 6, 2015, the FERC approved a MISO transmission owner joint request for an adder to the approved ROE. Under FERC regulations, transmission owners that are part of a Regional Transmission Organization (RTO) such as the MISO are authorized to earn an incentive of 50 basis points above the FERC approved ROE. The FERC deferred the implementation of this adder until the pending complaint is resolved. Once the FERC sets a new ROE in the complaint case, this adder will be applied to that ROE, with retroactive billing to occur back to January 7, 2015. The Company has established a reserve considering the initial decisions and the approved 50 basis points adder.

Environmental Matters

Environmental Matters	6 Months Ended
	Jun. 30, 2016
Environmental Matters Disclosure [Abstract]
Environmental Matters	Environmental Matters The Company's utility operations and properties are subject to extensive environmental regulation pursuant to a variety of federal, state, and municipal laws and regulations. These environmental regulations impose, among other things, restrictions, liabilities, and obligations in connection with the storage, transportation, treatment, and disposal of hazardous substances and limit airborne emissions from electric generating facilities including particulate matter, sulfur dioxide (SO2), nitrogen oxide (NOx), and mercury, among others. Environmental legislation and regulation also requires that facilities, sites, and other properties associated with the Company's operations be operated, maintained, abandoned, and reclaimed to the satisfaction of applicable regulatory authorities. The Company's current costs to comply with these laws and regulations are significant to its results of operations and financial condition. With the trend toward stricter standards, greater regulation, and more extensive permit requirements, the Company's investment in compliant infrastructure, and the associated operating costs have increased and are expected to increase in the future. Similar to the costs associated with federal mandates in the Pipeline Safety Law, Senate Bill 251 is also applicable to federal environmental mandates impacting SIGECO's electric operations. Air Quality Mercury and Air Toxics (MATS) Rule On December 21, 2011, the EPA finalized the utility MATS rule. The MATS rule sets emission limits for hazardous air pollutants for existing and new coal-fired power plants and identifies the following broad categories of hazardous air pollutants: mercury, non-mercury hazardous air pollutants (primarily arsenic, chromium, cobalt, and selenium), and acid gases (hydrogen cyanide, hydrogen chloride, and hydrogen fluoride). The rule imposes mercury emission limits for two sub-categories of coal and proposed surrogate limits for non-mercury and acid gas hazardous air pollutants. In July 2014, a coalition of twenty-one states, including Indiana, filed a petition with the U.S. Supreme Court seeking review of the decision of the appellate court that found the EPA appropriately based its decision to list coal and oil fired generation units as a source of the pollutants at issue solely on those pollutants’ impact on public health. On June 29, 2015, the U.S. Supreme Court reversed the appellate court decision on the basis of the EPA’s failure to consider costs before determining whether it was appropriate and necessary to regulate steam electric generating units under Section 112 of the Clean Air Act. The Court did not vacate the rule, but remanded the MATS rule back to the appellate court for further proceedings consistent with the opinion. In April 2016, in response to the Court's remand, the EPA affirmed its earlier conclusion in a Supplemental Finding. MATS compliance was required to commence April 16, 2015, and the Company continues to operate in full compliance with the MATS rule. Notice of Violation for A.B. Brown Power Plant The Company received a NOV from the EPA in November 2011 pertaining to its A.B. Brown generating station. The NOV asserts when the facility was equipped with Selective Catalytic Reduction (SCR) systems, the correct permits were not obtained or the best available control technology to control incidental sulfuric acid mist was not installed. While the Company did not agree with the notice, it reached a final settlement with the EPA to resolve the NOV in December 2015. As noted previously, on January 28, 2015, the IURC issued an Order approving the Company’s request for approval of capital investments on its coal-fired generation units to comply with new EPA mandates related to MATS effective in 2015 and to address the outstanding NOV. The total investment is estimated to be between $70 million and $75 million , roughly half of which has been spent to control mercury in both air and water emissions, and the remaining investment has been made to address the issues raised in the NOV. In June 2015, Joint Appellants’ Citizens Action Coalition of Indiana, Inc., Sierra Club, Inc., and Valley Watch, Inc. (the appellants) challenged the IURC's January Order. On October 29, 2015, the Indiana Court of Appeals issued an opinion that affirmed the IURC’s findings with regard to equipment required to comply with MATS and certain national pollutant discharge elimination system rules (approximately $35 million ) but remanded the case back to the IURC to determine whether a certificate of public convenience and necessity (CPCN) should be issued for the equipment required by the NOV (approximately $40 million ). On June 22, 2016, the IURC issued an Order granting the Company a CPCN for the equipment required for the resolution of the NOV. On July 21, 2016, the appellants initiated an appeal of the IURC's June 22, 2016 Order. The basis for the appeal will not be known until the appeal brief is filed later this year. The Company believes the IURC decision is well founded and will ultimately be upheld. Ozone NAAQS On November 26, 2014, the EPA proposed to tighten the current National Ambient Air Quality Standard (NAAQS) for ozone from the current standard of 75 parts per billion (ppb) to a level with the range of 65 to 70 ppb. On October 1, 2015, the EPA finalized a new NAAQS for ozone at the high end of the range, or 70 ppb. The EPA is expected to make final determinations as to whether a region is in attainment for the new NAAQS in 2018 based upon monitoring data from 2014-2016. While it is possible that counties in southwest Indiana could be declared in non-attainment with the new standard, and thus could have an effect on future economic development activities in the Company's service territory, the Company does not anticipate any significant compliance cost impacts from the determination given its previous investment in SCR technology for NOx control on its units. In December of 2015, the EPA proposed a supplement to the current Cross State Air Pollution Rule (CSAPR) that would require further NOx reductions during the ozone season (May - September). The Company is positioned to comply with these NOx reduction requirements through its current investment in SCR technology. One Hour SO2 NAAQS On February 16, 2016, the EPA notified states of the commencement of a 120 day consultation period between the state and the EPA with respect to the EPA's recommendations for new non-attainment designations for the 2010 One Hour SO2 NAAQS. Identified on the list was Posey County, Indiana, where the Company's A.B. Brown Generating Station is located. While the Company is in compliance with all applicable SO2 limits in its permits, the Company reached an agreement with the state of Indiana on voluntary measures that the Company was able to implement without significant incremental costs to ensure that Posey County remains in attainment with the 2010 One Hour SO2 NAAQS. The Company's coal-fired generating fleet is 100 percent scrubbed for SO2 and 90 percent controlled for NOx. Coal Ash Waste Disposal, Ash Ponds and Water Coal Combustion Residuals Rule In December 2014, the EPA released its final Coal Combustion Residuals (CCR) rule which regulates ash as non-hazardous material under Subtitle D of the Resource Conservation and Recovery Act (RCRA). On April 17, 2015, the final rule was published in the Federal Register. The final rule allows beneficial reuse of ash and the majority of the ash generated by the Company’s generating plants will continue to be reused. As it relates to the CCR rule, legislation is currently being considered by Congress that would provide for enforcement of the federal program by states rather than through citizen suits. Additionally, the CCR rule is currently being challenged by multiple parties in judicial review proceedings. Under the final CCR rule, the Company is required to complete a series of integrity assessments, including seismic modeling given the Company’s facilities are located within two seismic zones, and groundwater monitoring studies to determine the remaining service life of the ponds and whether a pond must be retrofitted with liners or closed in place, with bottom ash handling conversions completed. In late 2015, using general utility industry data, the Company prepared cost estimates for the retirement of the ash ponds at the end of their useful lives, based on its interpretation of the closure alternatives contemplated in the final rule. The resulting estimates ranged from approximately $35 million to $80 million . These estimates contemplated final capping and monitoring costs of the ponds at both F.B. Culley and A.B. Brown generating stations. These rules have not been applicable to the Company's Warrick generating unit, as this unit has historically been part of a larger generating station that predominantly serves an adjacent industrial facility. The Company is in the process of preparing site specific estimates, using engineering analyses and alternative methods of closure. Significant factors impacting the resulting cost estimates include the closure time frame and the method of closure. The ongoing analysis and the refinement of assumptions may result in estimated costs that could be in excess of the current range of $35 million to $80 million. At September 30, 2015, the Company recorded an approximate $25 million asset retirement obligation (ARO) and that amount is unchanged at June 30, 2016. The recorded ARO reflected the present value of the approximate $35 million in estimated costs in the range above. These assumptions and estimations are subject to change in the future and could materially impact the amount of the estimated ARO. In order to maintain current operations of the ponds, the Company anticipates spending approximately $12 million on the reinforcement of the ash pond dams and other operational changes in 2016 to meet the more stringent 2,500 year seismic event structural and safety standard in the CCR rule. Effluent Limitation Guidelines (ELGs) Under the Clean Water Act, the EPA sets technology-based guidelines for water discharges from new and existing facilities. On September 30, 2015, the EPA released final revisions to the existing steam electric ELGs setting stringent technology- based water discharge limits for the electric power industry. The EPA focused this rulemaking on wastewater generated primarily by pollution control equipment necessitated by the comprehensive air regulations, specifically setting strict water discharge limits for arsenic, mercury and selenium for scrubber waste waters. The ELGs will be implemented when existing water discharge permits for the plants are renewed, with compliance activities expected to commence within the 2018-2023 time frame. Current wastewater discharge permits for the Brown and Culley power plants expire in October and December 2016, respectively. The Company is working with Indiana regulators on permit renewals which will include a compliance schedule for ELGs. In no event will compliance with the ELGs be required prior to November 2018. The ELGs work in tandem with the recently released CCR requirements, effectively prohibiting the use of less costly lined sediment basin options for disposal of coal combustion residuals, and virtually mandate conversions to dry bottom ash handling. Cooling Water Intake Structures Section 316(b) of the Clean Water Act requires that generating facilities use the “best technology available” (BTA) to minimize adverse environmental impacts on a body of water. More specifically, Section 316(b) is concerned with impingement and entrainment of aquatic species in once-through cooling water intake structures used at electric generating facilities. A final rule was issued by the EPA on May 19, 2014. The final rule does not mandate cooling water tower retrofits but requires a state level case-by-case assessment of BTA for each facility. The final rule lists seven presumptive technologies which would qualify as BTA. These technologies range from intake screen modifications to cooling water tower retrofits. Ecological and technology assessment studies must be completed prior to determining BTA for the Company’s facilities. The Company is currently undertaking the required ecological studies and anticipates timely compliance in 2020-2021. To comply, the Company believes that capital investments will likely be in the range of $4 million to $8 million . Climate Change On August 3, 2015, the EPA released its final Clean Power Plan (CPP) rule which requires a 32 percent reduction in carbon emissions from 2005 levels. This results in a final emission rate goal for Indiana of 1,242 lb CO2/MWh to be achieved by 2030. The new rule gives states the option of seeking a two-year extension from the deadline of September 2016 to submit a final state implementation plan (SIP). Under the CPP, states have the flexibility to include energy efficiency and other measures should they choose to implement a SIP as provided in the final rule. While states are given an interim goal (1,451 lb CO2/MWh for Indiana), the final rule gives states the flexibility to shape their own emissions reduction over the 2022-2029 time period. The final rule was published in the Federal Register on October 23, 2015 and that action was immediately followed by litigation initiated by Indiana and 23 other states as a coalition challenging the rule. In January of 2016, the reviewing court denied the states’ and other parties requests to stay the implementation of the CPP pending completion of judicial review. On January 26, 2016, 29 states and state agencies, including the 24 state coalition referenced above, filed a request for immediate stay with the U.S. Supreme Court. On February 9, 2016, the U.S. Supreme Court granted a stay to delay the regulation while being challenged in court. The stay will remain in place while the lower court concludes its review. Among other things, the stay delays the requirement to submit a final SIP by the September 2016 deadline and could extend implementation to 2024. In the event that a state does not submit a SIP, the EPA also released a proposed federal implementation plan (FIP), which would be imposed on those states without an approved SIP. The proposed FIP would apply an emission rate requirement directly on generating units. Under the proposed FIP, the CO2 emission rate limit for coal-fired units would start at 1,671 lbs CO2/MWh in 2022 and decrease to a final emission rate cap of 1,305 lbs CO2/MWh by 2030. While the FIP emission rate cap appears to be slightly less stringent than the state reduction goal for Indiana, the cap would apply directly to generating units and these units would not have the benefit of averaging emission rates with rates from zero-carbon sources as would be available in a SIP. Purchases of emission credits from zero-carbon sources can be made for compliance. The FIP will be subject to extensive public comments prior to finalization. Whether Indiana will file a SIP has yet to be determined. Pending that determination, the electric utilities in Indiana will continue to encourage the state's designated agency to analyze various compliance options and the possible integration into a state plan submittal. At the time of release of the CPP, Indiana was the 5th largest carbon emitter in the nation in tons of CO2 produced from electric generation. The Company’s share of total tons of CO2 generated by Indiana's electric utilities has historically been less than 6 percent . Since 2005, the Company has achieved a reduction in emissions of CO2 of 31 percent (on a tonnage basis) through the retirement of F.B. Culley Unit 1, expiration of municipal contracts, electric conservation, the addition of renewable generation, and the installation of more efficient dense pack turbine technology. Since emissions are further impacted by coal burn reductions and energy efficiency programs, the Company's emissions of CO2 can vary year to year. With respect to renewable generation, in 2008 and 2009, the Company executed long-term purchase power commitments for a total of 80 MW of wind energy. The Company currently has approximately 4 percent of its electricity being provided by energy sources other than coal and natural gas, due to the long-term wind contracts and landfill gas investment. With respect to CO2 emission rate, since 2005 the Company has lowered its CO2 emission rate (as measured in lbs CO2/MWh) from 1,967 lbs CO2/MWh to 1,922 lbs CO2/MWh, for a reduction of 3 percent . The Company’s CO2 emission rate of 1,922 lbs CO2/MWh is basically the same as Indiana's average CO2 emission rate of 1,923 lbs CO2/MWh. The Company plans to consider these reductions in CO2 emissions and renewable generation in future discussions with the state to develop a possible state implementation plan. Impact of Legislative Actions & Other Initiatives is Unknown At this time, compliance costs and other effects associated with reductions in GHG emissions or obtaining renewable energy sources remain uncertain. The Company has gathered preliminary estimates of the costs to control GHG emissions. A preliminary investigation demonstrated costs to comply would be significant, first with regard to operating expenses and later for capital expenditures as technology becomes available to control GHG emissions. However, these compliance cost estimates were based on highly uncertain assumptions, including allowance prices if a cap and trade approach were employed, and energy efficiency targets. The Company is undertaking a detailed review of the requirements of the CPP and the proposed FIP and a review of potential compliance options. The Company will also continue to remain engaged with the Indiana legislators and regulators to assess the final rule and to develop a plan that is the least cost to its customers. In addition to the federal programs, the United States and 194 other countries agreed by consensus to limit GHG emissions beginning after 2020 in the 2015 United Nations Framework Convention on Climate Change Paris Agreement. The United States has proposed a 26-28% GHG emission reduction from 2005 levels by 2025. As previously noted, since 2005, the Company has achieved reduced emissions of CO2 by 31 percent (on a tonnage basis). While the legislative outcome of the CPP rules remains uncertain, the Company will continue to monitor regulatory activity regarding GHG emission standards that may affect its electric generating units. Integrated Resource Planning Process As required by the state of Indiana, the Company is currently in the process of completing its 2016 Integrated Resource Plan (IRP). The state requires each electric utility to perform and submit an IRP that uses economic modeling to consider the costs and risks associated with available resource options to provide reliable electric service for the next twenty year period. During 2016, the Company will hold three public stakeholder meetings to gather input and feedback as well as communicate results of the IRP process as it progresses. Two of the three public meetings were held in April and July. A final IRP report is expected to be submitted to the IURC for review in November 2016. While the IURC reviews these reports, it does not formally approve or reject the plans. In developing its IRP, the Company will consider both the cost to continue operating its existing generation units in a manner that complies with current and anticipated future environmental requirements, as well as various resource alternatives, such as the use of energy efficiency programs and renewable resources as part of its overall generation portfolio. Due to the Company continuing to study compliance requirements and as the IRP will be used to drive future resource decisions, the Company cannot reasonably estimate the total cost it will incur to comply with the CCR, ELG, and CPP regulations. Further, the 2016 IRP will also evaluate the ongoing operation of the 300 MW unit at the Warrick Power Plant (Warrick Unit 4) that SIGECO and Alcoa Generating Corporation (AGC), a subsidiary of Alcoa, Inc. (Alcoa), own as tenants in common. SIGECO's proportionate cost of the unit is included in rate base. In the first quarter of 2016, Alcoa closed its smelter operations. Historically, on-site generation owned and operated by AGC has been used to provide power to the smelter, as well as other mill operations, which will continue. Generation from Alcoa's share of Warrick Unit 4 has historically been sold into the MISO market. Alcoa's operational changes, as described above, lead to a number of uncertainties including its plans regarding the future ownership and operation of Warrick Unit 4 as well as potential environmental regulation implications under the CCR and ELG regulations. The Company is actively working with Alcoa on plans related to continued operation of their generation and what operating scenarios to consider in the IRP. The 2016 IRP will produce a variety of resource options to be considered, including a preferred resource plan. Based on the resulting analysis, the Company will develop an overall strategy that may include compliance projects on some units, possible replacement of other units, and the opportunity for the use of renewable sources. While the cost of compliance with CCR, ELG, and CPP could be significant, the Company anticipates compliance costs associated with ELG and CCR will likely be the most significant. The Company believes that all compliance costs would be considered a federally mandated cost of providing electricity, and therefore if incurred, should be recoverable either from customers through Senate Bill 251 as referenced above, Senate Bill 29, which was used by the Company to recover its initial pollution control investments as clean coal environmental expenditures, or through other forms of rate recovery. Manufactured Gas Plants In the past, the Company operated facilities to manufacture natural gas. Given the availability of natural gas transported by pipelines, these facilities have not been operated for many years. Under current environmental laws and regulations, those that owned or operated these facilities may now be required to take remedial action if certain contaminants are found above the regulatory thresholds. In the Indiana Gas service territory, the existence, location, and certain general characteristics of 26 gas manufacturing and storage sites have been identified for which the Company may have some remedial responsibility. A remedial investigation/ feasibility study (RI/FS) was completed at one of the sites under an agreed upon order between Indiana Gas and the IDEM, and a Record of Decision was issued by the IDEM in January 2000. The remaining sites have been submitted to the IDEM's Voluntary Remediation Program (VRP). The Company has identified its involvement in five manufactured gas plant sites in SIGECO’s service territory, all of which are currently enrolled in the IDEM’s VRP. The Company is currently conducting some level of remedial activities, including groundwater monitoring at certain sites. The Company has accrued the estimated costs for further investigation, remediation, groundwater monitoring, and related costs for the sites. While the total costs that may be incurred in connection with addressing these sites cannot be determined at this time, the Company has recorded cumulative costs that it has incurred or reasonably expects to incur totaling approximately $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 approximately $14.8 million of the expected $15.8 million in insurance recoveries. The costs the Company expects to incur are estimated by management using assumptions based on actual costs incurred, the timing of expected future payments, and inflation factors, among others. While the Company’s utilities have recorded all costs which they presently expect to incur in connection with activities at these sites, it is possible that future events may require remedial activities which are not presently foreseen and those costs may not be subject to PRP or insurance recovery. As of June 30, 2016 and December 31, 2015 , approximately $2.8 million and $3.3 million , respectively, of accrued, but not yet spent, costs are included in Other Liabilities related to the Indiana Gas and SIGECO sites.

Fair Value Measurements

Fair Value Measurements	6 Months Ended
	Jun. 30, 2016
Fair Value Disclosures [Abstract]
Fair Value Measurements	Fair Value Measurements The carrying values and estimated fair values using primarily Level 2 assumptions of the Company's other financial instruments follow: June 30, 2016 December 31, 2015 (In millions) Carrying Amount Est. Fair Value Carrying Amount Est. Fair Value Long-term debt $ 1,379.7 $ 1,549.5 $ 1,392.2 $ 1,495.0 Short-term borrowings 38.9 38.9 14.5 14.5 Cash & cash equivalents 4.6 4.6 6.2 6.2 Restricted Cash 5.8 5.8 5.9 5.9 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. Accordingly, any reacquisition of this debt would not be expected to have a material effect on the Company's results of operations. The Company has reclassified its debt issuance costs, in accordance with ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs. The adoption of the accounting standard update changes the presentation of debt issuance costs in financial statements by requiring an entity to present such costs in the balance sheet as a direct deduction from the related debt liability rather than as an asset. Amortization of the costs will continue to be reported as interest expense. The guidance was adopted as of January 1, 2016, and has been applied retrospectively to all periods presented. The effect of the change on the December 31, 2015 balance sheet was the reclassification of $8.6 million from Regulatory assets to Long-term Debt . The adoption of the standard had no material impact on the Company's financial condition, results of operations, or cash flows.

Impact of Recently Issued Accou

Impact of Recently Issued Accounting Guidance	6 Months Ended
	Jun. 30, 2016
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
Impact of Recently Issued Accounting Principles	Impact of Recently Issued Accounting Principles Revenue Recognition Guidance In May 2014, the FASB issued new accounting guidance to clarify the principles for recognizing revenue and to develop a common revenue standard for GAAP. The amendments in this guidance state that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This new guidance requires improved disclosures to help users of financial statements better understand the nature, amount, timing, and uncertainty of revenue that is recognized. On July 9, 2015, the FASB approved a one year deferral that became effective through an ASU in August and changed the effective date to annual reporting periods beginning after December 15, 2017, including interim periods, with early adoption permitted, but not before the original effective date of December 15, 2016. The Company is currently evaluating the standard to determine application date, transition method, and impact the standard will have on the financial statements. Simplifying the Presentation of Debt Issuance Costs In April 2015, the FASB issued new accounting guidance on accounting for debt issuance costs which changes the presentation of debt issuance costs in financial statements. This ASU requires an entity to present such costs in the balance sheet as a direct reduction from the related debt liability rather than as an asset. Amortization of the costs will continue to be reported as interest expense. This ASU is effective for annual reporting periods beginning after December 15, 2015. The guidance was adopted as of January 1, 2016, and has been applied retrospectively to all periods presented. The effect of the change on the December 31, 2015 balance sheet was the reclassification of $8.6 million from Regulatory assets to Long-term Debt . The reclassification had no material impact on the Company's financial condition, results of operations, or cash flows as a result of the adoption. Leases In February 2016, the FASB issued new accounting guidance for the recognition, measurement, presentation and disclosure of leasing arrangements. This ASU requires the recognition of lease assets and liabilities for those leases currently classified as operating leases while also refining the definition of a lease. In addition, lessees will be required to disclose key information about the amount, timing, and uncertainty of cash flows arising from leasing arrangements. This ASU is effective for the interim and annual reporting periods beginning January 1, 2019, although it can be early adopted, with a modified retrospective approach for leases that commenced prior to the date of adoption. The Company is currently evaluating the standard to determine the impact it will have on the financial statements. Stock Compensation In March 2016, the FASB issued new accounting guidance which is intended to simplify several aspects of accounting for share-based payment transactions, including the income tax consequences. This ASU is effective for annual periods beginning after December 15, 2016, and interim periods therein. Early application is permitted. The Company is currently evaluating the standard to determine the impact it will have on the financial statements, if any. Management believes other recently issued standards, which are not yet effective, will not have a material impact on the Company's financial condition, results of operations, or cash flows upon adoption.

Segment Reporting

Segment Reporting	6 Months Ended
	Jun. 30, 2016
Segment Reporting [Abstract]
Segment Reporting	Segment Reporting The Company’s operations consist of regulated operations and other operations that provide information technology and other support services to those regulated operations. The Company segregates its regulated operations between a Gas Utility Services operating segment and an Electric Utility Services operating segment. The Gas Utility Services segment provides natural gas distribution and transportation services to nearly two-thirds of Indiana and about twenty percent of Ohio, primarily in the west-central area. The Electric Utility Services segment provides electric transmission and distribution services primarily to southwestern Indiana, and includes the Company’s power generating and wholesale power operations. These regulated operations supply natural gas and/or electricity to over one million customers. In total, the Company reports 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 reportable segments is summarized as follows. Three Months Ended Six Months Ended June 30, June 30, (In millions) 2016 2015 2016 2015 Revenues Gas Utility Services $ 132.0 $ 128.6 $ 413.1 $ 481.5 Electric Utility Services 147.7 147.8 289.8 301.7 Other Operations 10.5 10.2 21.1 20.4 Eliminations (10.4 ) (10.1 ) (20.9 ) (20.2 ) Total Revenues $ 279.8 $ 276.5 $ 703.1 $ 783.4 Profitability Measure - Net Income Gas Utility Services $ 4.7 $ 3.4 $ 45.1 $ 43.8 Electric Utility Services 19.2 19.7 35.8 38.9 Other Operations 2.4 1.3 6.5 4.7 Total Net Income $ 26.3 $ 24.4 $ 87.4 $ 87.4

Subsidiary Guarantor and Cons19

Subsidiary Guarantor and Consolidating Information(Tables)	6 Months Ended
	Jun. 30, 2016
Subsidiary Guarantor and Consolidating Information [Abstract]
Condensed consolidating balance sheets [Table Text Block]	Condensed Consolidating Balance Sheet as of June 30, 2016 (in millions): ASSETS Subsidiary Parent Eliminations & Guarantors Company Reclassifications Consolidated Current Assets Cash & cash equivalents $ 3.4 $ 1.2 $ — $ 4.6 Accounts receivable - less reserves 66.6 0.1 — 66.7 Intercompany receivables 37.4 39.6 (77.0 ) — Accrued unbilled revenues 45.5 — — 45.5 Inventories 115.3 0.1 — 115.4 Recoverable fuel & natural gas costs 18.4 — — 18.4 Prepayments & other current assets 35.0 2.6 (1.8 ) 35.8 Total current assets 321.6 43.6 (78.8 ) 286.4 Utility Plant Original cost 6,298.5 — — 6,298.5 Less: accumulated depreciation & amortization 2,493.0 — — 2,493.0 Net utility plant 3,805.5 — — 3,805.5 Investments in consolidated subsidiaries — 1,530.3 (1,530.3 ) — Notes receivable from consolidated subsidiaries — 945.4 (945.4 ) — Investments in unconsolidated affiliates 0.2 — — 0.2 Other investments 20.4 0.4 — 20.8 Nonutility plant - net 1.7 152.4 — 154.1 Goodwill - net 205.0 — — 205.0 Regulatory assets 160.5 16.6 — 177.1 Other assets 54.9 1.0 (7.9 ) 48.0 TOTAL ASSETS $ 4,569.8 $ 2,689.7 $ (2,562.4 ) $ 4,697.1 LIABILITIES & SHAREHOLDER'S EQUITY Subsidiary Parent Eliminations & Guarantors Company Reclassifications Consolidated Current Liabilities Accounts payable $ 130.8 $ 7.4 $ — $ 138.2 Intercompany payables 16.1 — (16.1 ) — Payables to other Vectren companies 26.1 1.2 — 27.3 Accrued liabilities 112.3 13.2 (1.8 ) 123.7 Short-term borrowings — 38.9 — 38.9 Intercompany short-term borrowings 23.5 37.4 (60.9 ) — Total current liabilities 308.8 98.1 (78.8 ) 328.1 Long-Term Debt Long-term debt 384.2 995.5 — 1,379.7 Long-term debt due to VUHI 945.4 — (945.4 ) — Total long-term debt - net 1,329.6 995.5 (945.4 ) 1,379.7 Deferred Credits & Other Liabilities Deferred income taxes 805.3 (2.8 ) — 802.5 Regulatory liabilities 446.8 1.4 — 448.2 Deferred credits & other liabilities 149.0 4.9 (7.9 ) 146.0 Total deferred credits & other liabilities 1,401.1 3.5 (7.9 ) 1,396.7 Common Shareholder's Equity Common stock (no par value) 841.0 827.9 (841.0 ) 827.9 Retained earnings 689.3 764.7 (689.3 ) 764.7 Total common shareholder's equity 1,530.3 1,592.6 (1,530.3 ) 1,592.6 TOTAL LIABILITIES & SHAREHOLDER'S EQUITY $ 4,569.8 $ 2,689.7 $ (2,562.4 ) $ 4,697.1 Condensed Consolidating Balance Sheet as of December 31, 2015 (in millions): ASSETS Subsidiary Parent Eliminations & Guarantors Company Reclassifications Consolidated Current Assets Cash & cash equivalents $ 5.5 $ 0.7 $ — $ 6.2 Accounts receivable - less reserves 92.3 — — 92.3 Intercompany receivables 51.2 142.9 (194.1 ) — Accrued unbilled revenues 85.7 — — 85.7 Inventories 125.3 — — 125.3 Prepayments & other current assets 49.3 4.1 (4.4 ) 49.0 Total current assets 409.3 147.7 (198.5 ) 358.5 Utility Plant Original cost 6,090.4 — — 6,090.4 Less: accumulated depreciation & amortization 2,415.5 — — 2,415.5 Net utility plant 3,674.9 — — 3,674.9 Investments in consolidated subsidiaries — 1,467.0 (1,467.0 ) — Notes receivable from consolidated subsidiaries — 836.0 (836.0 ) — Investments in unconsolidated affiliates 0.2 — — 0.2 Other investments 19.7 0.4 — 20.1 Nonutility plant - net 1.7 148.0 — 149.7 Goodwill - net 205.0 — — 205.0 Regulatory assets 135.2 16.9 — 152.1 Other assets 39.6 1.3 (8.7 ) 32.2 TOTAL ASSETS $ 4,485.6 $ 2,617.3 $ (2,510.2 ) $ 4,592.7 LIABILITIES & SHAREHOLDER'S EQUITY Subsidiary Parent Eliminations & Guarantors Company Reclassifications Consolidated Current Liabilities Accounts payable $ 161.1 $ 7.4 $ — $ 168.5 Intercompany payables 12.4 — (12.4 ) — Payables to other Vectren companies 25.7 — — 25.7 Accrued liabilities 120.2 12.6 (4.4 ) 128.4 Short-term borrowings — 14.5 — 14.5 Intercompany short-term borrowings 130.5 51.2 (181.7 ) — Current maturities of long-term debt 13.0 — — 13.0 Total current liabilities 462.9 85.7 (198.5 ) 350.1 Long-Term Debt Long-term debt - net of current maturities & debt subject to tender 383.9 995.3 — 1,379.2 Long-term debt due to VUHI 836.0 — (836.0 ) — Total long-term debt - net 1,219.9 995.3 (836.0 ) 1,379.2 Deferred Credits & Other Liabilities Deferred income taxes 763.7 (5.3 ) — 758.4 Regulatory liabilities 432.5 1.4 — 433.9 Deferred credits & other liabilities 139.6 5.0 (8.7 ) 135.9 Total deferred credits & other liabilities 1,335.8 1.1 (8.7 ) 1,328.2 Common Shareholder's Equity Common stock (no par value) 813.1 799.9 (813.1 ) 799.9 Retained earnings 653.9 735.3 (653.9 ) 735.3 Total common shareholder's equity 1,467.0 1,535.2 (1,467.0 ) 1,535.2 TOTAL LIABILITIES & SHAREHOLDER'S EQUITY $ 4,485.6 $ 2,617.3 $ (2,510.2 ) $ 4,592.7
Condensed consolidating statements fo income [Table Text Block]	Subsidiary Guarantors Parent Company Eliminations & Reclassifications Consolidated OPERATING REVENUES Gas utility $ 132.0 $ — $ — $ 132.0 Electric utility 147.7 — — 147.7 Other — 10.6 (10.5 ) 0.1 Total operating revenues 279.7 10.6 (10.5 ) 279.8 OPERATING EXPENSES Cost of gas sold 34.0 — — 34.0 Cost of fuel & purchased power 45.2 — — 45.2 Other operating 91.5 — (10.2 ) 81.3 Depreciation & amortization 48.0 6.0 — 54.0 Taxes other than income taxes 12.7 0.4 — 13.1 Total operating expenses 231.4 6.4 (10.2 ) 227.6 OPERATING INCOME 48.3 4.2 (0.3 ) 52.2 Other income - net 6.9 11.7 (11.6 ) 7.0 Interest expense 16.9 12.5 (11.9 ) 17.5 INCOME BEFORE INCOME TAXES 38.3 3.4 — 41.7 Income taxes 14.4 1.0 — 15.4 Equity in earnings of consolidated companies, net of tax — 23.9 (23.9 ) — NET INCOME $ 23.9 $ 26.3 $ (23.9 ) $ 26.3 Condensed Consolidating Statement of Income for the three months ended June 30, 2015 (in millions): Subsidiary Guarantors Parent Company Eliminations & Reclassifications Consolidated OPERATING REVENUES Gas utility $ 128.6 $ — $ — $ 128.6 Electric utility 147.8 — — 147.8 Other — 10.2 (10.1 ) 0.1 Total operating revenues 276.4 10.2 (10.1 ) 276.5 OPERATING EXPENSES Cost of gas sold 36.4 — — 36.4 Cost of fuel & purchased power 47.0 — — 47.0 Other operating 87.9 — (9.4 ) 78.5 Depreciation & amortization 45.5 6.4 0.1 52.0 Taxes other than income taxes 11.7 0.4 — 12.1 Total operating expenses 228.5 6.8 (9.3 ) 226.0 OPERATING INCOME 47.9 3.4 (0.8 ) 50.5 Other income - net 4.3 9.9 (9.9 ) 4.3 Interest expense 15.8 11.3 (10.7 ) 16.4 INCOME BEFORE INCOME TAXES 36.4 2.0 — 38.4 Income taxes 13.3 0.7 — 14.0 Equity in earnings of consolidated companies, net of tax — 23.1 (23.1 ) — NET INCOME $ 23.1 $ 24.4 $ (23.1 ) $ 24.4 Condensed Consolidating Statement of Income for the six months ended June 30, 2016 (in millions): Subsidiary Guarantors Parent Company Eliminations & Reclassifications Consolidated OPERATING REVENUES Gas utility $ 413.1 $ — $ — $ 413.1 Electric utility 289.8 — — 289.8 Other — 21.1 (20.9 ) 0.2 Total operating revenues 702.9 21.1 (20.9 ) 703.1 OPERATING EXPENSES Cost of gas sold 145.5 — — 145.5 Cost of fuel & purchased power 89.4 — — 89.4 Other operating 191.6 — (20.2 ) 171.4 Depreciation & amortization 95.5 12.0 0.1 107.6 Taxes other than income taxes 29.3 0.9 — 30.2 Total operating expenses 551.3 12.9 (20.1 ) 544.1 OPERATING INCOME 151.6 8.2 (0.8 ) 159.0 Other income - net 12.2 24.0 (22.9 ) 13.3 Interest expense 33.8 24.9 (23.7 ) 35.0 INCOME BEFORE INCOME TAXES 130.0 7.3 — 137.3 Income taxes 49.1 0.8 — 49.9 Equity in earnings of consolidated companies, net of tax — 80.9 (80.9 ) — NET INCOME $ 80.9 $ 87.4 $ (80.9 ) $ 87.4 Condensed Consolidating Statement of Income for the six months ended June 30, 2015 (in millions): Subsidiary Guarantors Parent Company Eliminations & Reclassifications Consolidated OPERATING REVENUES $ 481.5 $ — $ — $ 481.5 Electric utility 301.7 — — 301.7 Other — 20.4 (20.2 ) 0.2 Total operating revenues 783.2 20.4 (20.2 ) 783.4 OPERATING EXPENSES Cost of gas sold 208.4 — — 208.4 Cost of fuel & purchased power 97.0 — — 97.0 Other operating 200.3 — (19.0 ) 181.3 Depreciation & amortization 91.2 12.8 0.2 104.2 Taxes other than income taxes 30.3 0.9 — 31.2 Total operating expenses 627.2 13.7 (18.8 ) 622.1 OPERATING INCOME 156.0 6.7 (1.4 ) 161.3 Other income - net 8.4 20.7 (19.9 ) 9.2 Interest expense 31.7 22.6 (21.3 ) 33.0 INCOME BEFORE INCOME TAXES 132.7 4.8 — 137.5 Income taxes 50.1 — — 50.1 Equity in earnings of consolidated companies, net of tax — 82.6 (82.6 ) — NET INCOME $ 82.6 $ 87.4 $ (82.6 ) $ 87.4
Condensed consolidating statements of cash flows [Table Text Block]	Condensed Consolidating Statement of Cash Flows for the six months ended June 30, 2016 (in millions): Subsidiary Guarantors Parent Company Eliminations Consolidated NET CASH PROVIDED BY OPERATING ACTIVITIES $ 210.8 $ 22.0 $ — $ 232.8 CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from Long-term debt - net of issuance costs 109.4 — (109.4 ) — Additional capital contribution from parent 28.0 28.0 (28.0 ) 28.0 Requirements for: Dividends to parent (45.5 ) (58.0 ) 45.5 (58.0 ) Retirement of long term debt (13.0 ) — — (13.0 ) Net change in intercompany short-term borrowings (106.9 ) (13.8 ) 120.7 — Net change in short-term borrowings — 24.4 — 24.4 Net cash used in financing activities (28.0 ) (19.4 ) 28.8 (18.6 ) CASH FLOWS FROM INVESTING ACTIVITIES Proceeds from: Consolidated subsidiary distributions — 45.5 (45.5 ) — Requirements for: Capital expenditures, excluding AFUDC equity (198.8 ) (17.1 ) — (215.9 ) Consolidated subsidiary investments — (28.0 ) 28.0 — Changes in restricted cash 0.1 — — 0.1 Net change in long-term intercompany notes receivable — (109.4 ) 109.4 — Net change in short-term intercompany notes receivable 13.8 106.9 (120.7 ) — Net cash used in investing activities (184.9 ) (2.1 ) (28.8 ) (215.8 ) Net change in cash & cash equivalents (2.1 ) 0.5 — (1.6 ) Cash & cash equivalents at beginning of period 5.5 0.7 — 6.2 Cash & cash equivalents at end of period $ 3.4 $ 1.2 $ — $ 4.6 Condensed Consolidating Statement of Cash Flows for the six months ended June 30, 2015 (in millions): Subsidiary Guarantors Parent Company Eliminations Consolidated NET CASH PROVIDED BY OPERATING ACTIVITIES $ 317.7 $ 19.1 $ — $ 336.8 CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from: Additional capital contribution from parent 3.0 3.0 (3.0 ) 3.0 Requirements for: Dividends to parent (51.6 ) (55.2 ) 51.6 (55.2 ) Retirement of long term debt (5.0 ) — — (5.0 ) Net change in intercompany short-term borrowings (48.2 ) 62.6 (14.4 ) — Net change in short-term borrowings — (129.1 ) — (129.1 ) Net cash used in financing activities (101.8 ) (118.7 ) 34.2 (186.3 ) CASH FLOWS FROM INVESTING ACTIVITIES Proceeds from: Consolidated subsidiary distributions — 51.6 (51.6 ) — Other investing activities — 0.1 — 0.1 Requirements for: Capital expenditures, excluding AFUDC equity (153.8 ) (9.4 ) — (163.2 ) Consolidated subsidiary investments — (3.0 ) 3.0 — Net change in short-term intercompany notes receivable (62.6 ) 48.2 14.4 — Net cash used in investing activities (216.4 ) 87.5 (34.2 ) (163.1 ) Net change in cash & cash equivalents (0.5 ) (12.1 ) — (12.6 ) Cash & cash equivalents at beginning of period 6.9 12.4 — 19.3 Cash & cash equivalents at end of period $ 6.4 $ 0.3 $ — $ 6.7

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	6 Months Ended
	Jun. 30, 2016
Fair Value Disclosures [Abstract]
Fair Value, by Balance Sheet Grouping [Table Text Block]	The carrying values and estimated fair values using primarily Level 2 assumptions of the Company's other financial instruments follow: June 30, 2016 December 31, 2015 (In millions) Carrying Amount Est. Fair Value Carrying Amount Est. Fair Value Long-term debt $ 1,379.7 $ 1,549.5 $ 1,392.2 $ 1,495.0 Short-term borrowings 38.9 38.9 14.5 14.5 Cash & cash equivalents 4.6 4.6 6.2 6.2 Restricted Cash 5.8 5.8 5.9 5.9

Segment Reporting (Tables)

Segment Reporting (Tables)	6 Months Ended
	Jun. 30, 2016
Segment Reporting [Abstract]
Schedule of Segment Reporting Information, by Segment [Table Text Block]	Three Months Ended Six Months Ended June 30, June 30, (In millions) 2016 2015 2016 2015 Revenues Gas Utility Services $ 132.0 $ 128.6 $ 413.1 $ 481.5 Electric Utility Services 147.7 147.8 289.8 301.7 Other Operations 10.5 10.2 21.1 20.4 Eliminations (10.4 ) (10.1 ) (20.9 ) (20.2 ) Total Revenues $ 279.8 $ 276.5 $ 703.1 $ 783.4 Profitability Measure - Net Income Gas Utility Services $ 4.7 $ 3.4 $ 45.1 $ 43.8 Electric Utility Services 19.2 19.7 35.8 38.9 Other Operations 2.4 1.3 6.5 4.7 Total Net Income $ 26.3 $ 24.4 $ 87.4 $ 87.4

Organization and Nature of Op22

Organization and Nature of Operations (Details)	6 Months Ended
	Jun. 30, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of public utility subsidiaries owned by wholly owned subsidiary, Vectren Utility Holdings, Inc. (in number of subsidiaries)	3
Estimated number of natural gas customers located in central and southern Indiana serviced by Indiana Gas Company, Inc. (in number of customers)	588,000
Estimated number of electric customers located near Evansville in southwestern Indiana serviced by Southern Indiana Gas and Electric Company (in number of customers)	144,000
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)	318,000

Subsidiary Guarantor and Cons23

Subsidiary Guarantor and Consolidating Information Balance Sheet (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2016	Dec. 31, 2015	Jun. 30, 2015	Dec. 31, 2014
ASSETS
Cash & cash equivalents	$ 4.6	$ 6.2	$ 6.7	$ 19.3
Accounts receivable - less reserves	66.7	92.3
Accrued unbilled revenues	45.5	85.7
Inventories	115.4	125.3
Recoverable fuel & natural gas costs	18.4	0
Prepayments & other current assets	35.8	49
Total current assets	286.4	358.5
Original cost	6,298.5	6,090.4
Less: accumulated depreciation & amortization	2,493	2,415.5
Net utility plant	3,805.5	3,674.9
Investments in unconsolidated affiliates	0.2	0.2
Other investments	20.8	20.1
Nonutility plant - net	154.1	149.7
Goodwill	205	205
Regulatory assets	177.1	152.1
Other assets	48	32.2
TOTAL ASSETS	4,697.1	4,592.7
LIABILITIES & SHAREHOLDERS' EQUITY
Accounts payable	138.2	168.5
Payables to other Vectren companies	27.3	25.7
Accrued liabilities	123.7	128.4
Short-term borrowings	38.9	14.5
Current maturities of long-term debt	0	13
Total current liabilities	328.1	350.1
Long-term debt	1,379.7	1,379.2
Deferred income taxes	802.5	758.4
Regulatory liabilities	448.2	433.9
Deferred credits & other liabilities	146	135.9
Total deferred credits & other liabilities	1,396.7	1,328.2
Common stock (no par value)	827.9	799.9
Retained earnings	764.7	735.3
Total common shareholders' equity	1,592.6	1,535.2
TOTAL LIABILITIES & SHAREHOLDERS' EQUITY	4,697.1	4,592.7
Consolidation, Eliminations [Member]
ASSETS
Cash & cash equivalents	0	0	0	0
Accounts receivable - less reserves	0	0
Intercompany Receivables	(77)	(194.1)
Accrued unbilled revenues	0	0
Inventories	0	0
Recoverable fuel & natural gas costs	0
Prepayments & other current assets	(1.8)	(4.4)
Total current assets	(78.8)	(198.5)
Original cost	0	0
Less: accumulated depreciation & amortization	0	0
Net utility plant	0	0
Investments in consolidated subsidiaries	(1,530.3)	(1,467)
Notes receivable from consolidated subsidiaries	(945.4)	(836)
Investments in unconsolidated affiliates	0	0
Other investments	0	0
Nonutility plant - net	0	0
Goodwill	0	0
Regulatory assets	0	0
Other assets	(7.9)	(8.7)
TOTAL ASSETS	(2,562.4)	(2,510.2)
LIABILITIES & SHAREHOLDERS' EQUITY
Accounts payable	0	0
Intercompany payables	(16.1)	(12.4)
Payables to other Vectren companies	0	0
Accrued liabilities	(1.8)	(4.4)
Short-term borrowings	0	0
Intercompany short-term borrowings	(60.9)	(181.7)
Current maturities of long-term debt		0
Total current liabilities	(78.8)	(198.5)
Long-term debt	0	0
Long-term debt due to VUHI	(945.4)	(836)
Total long-term debt - net	(945.4)	(836)
Deferred income taxes	0	0
Regulatory liabilities	0	0
Deferred credits & other liabilities	(7.9)	(8.7)
Total deferred credits & other liabilities	(7.9)	(8.7)
Common stock (no par value)	(841)	(813.1)
Retained earnings	(689.3)	(653.9)
Total common shareholders' equity	(1,530.3)	(1,467)
TOTAL LIABILITIES & SHAREHOLDERS' EQUITY	(2,562.4)	(2,510.2)
Consolidated Entities [Member]
ASSETS
Cash & cash equivalents	4.6	6.2	6.7	19.3
Accounts receivable - less reserves	66.7	92.3
Intercompany Receivables	0	0
Accrued unbilled revenues	45.5	85.7
Inventories	115.4	125.3
Recoverable fuel & natural gas costs	18.4
Prepayments & other current assets	35.8	49
Total current assets	286.4	358.5
Original cost	6,298.5	6,090.4
Less: accumulated depreciation & amortization	2,493	2,415.5
Net utility plant	3,805.5	3,674.9
Investments in consolidated subsidiaries	0	0
Notes receivable from consolidated subsidiaries	0	0
Investments in unconsolidated affiliates	0.2	0.2
Other investments	20.8	20.1
Nonutility plant - net	154.1	149.7
Goodwill	205	205
Regulatory assets	177.1	152.1
Other assets	48	32.2
TOTAL ASSETS	4,697.1	4,592.7
LIABILITIES & SHAREHOLDERS' EQUITY
Accounts payable	138.2	168.5
Intercompany payables	0	0
Payables to other Vectren companies	27.3	25.7
Accrued liabilities	123.7	128.4
Short-term borrowings	38.9	14.5
Intercompany short-term borrowings	0	0
Current maturities of long-term debt		13
Total current liabilities	328.1	350.1
Long-term debt	1,379.7	1,379.2
Long-term debt due to VUHI	0	0
Total long-term debt - net	1,379.7	1,379.2
Deferred income taxes	802.5	758.4
Regulatory liabilities	448.2	433.9
Deferred credits & other liabilities	146	135.9
Total deferred credits & other liabilities	1,396.7	1,328.2
Common stock (no par value)	827.9	799.9
Retained earnings	764.7	735.3
Total common shareholders' equity	1,592.6	1,535.2
TOTAL LIABILITIES & SHAREHOLDERS' EQUITY	4,697.1	4,592.7
Guarantor Subsidiaries [Member]
ASSETS
Cash & cash equivalents	3.4	5.5	6.4	6.9
Accounts receivable - less reserves	66.6	92.3
Intercompany Receivables	37.4	51.2
Accrued unbilled revenues	45.5	85.7
Inventories	115.3	125.3
Recoverable fuel & natural gas costs	18.4
Prepayments & other current assets	35	49.3
Total current assets	321.6	409.3
Original cost	6,298.5	6,090.4
Less: accumulated depreciation & amortization	2,493	2,415.5
Net utility plant	3,805.5	3,674.9
Investments in consolidated subsidiaries	0	0
Notes receivable from consolidated subsidiaries	0	0
Investments in unconsolidated affiliates	0.2	0.2
Other investments	20.4	19.7
Nonutility plant - net	1.7	1.7
Goodwill	205	205
Regulatory assets	160.5	135.2
Other assets	54.9	39.6
TOTAL ASSETS	4,569.8	4,485.6
LIABILITIES & SHAREHOLDERS' EQUITY
Accounts payable	130.8	161.1
Intercompany payables	16.1	12.4
Payables to other Vectren companies	26.1	25.7
Accrued liabilities	112.3	120.2
Short-term borrowings	0	0
Intercompany short-term borrowings	23.5	130.5
Current maturities of long-term debt		13
Total current liabilities	308.8	462.9
Long-term debt	384.2	383.9
Long-term debt due to VUHI	945.4	836
Total long-term debt - net	1,329.6	1,219.9
Deferred income taxes	805.3	763.7
Regulatory liabilities	446.8	432.5
Deferred credits & other liabilities	149	139.6
Total deferred credits & other liabilities	1,401.1	1,335.8
Common stock (no par value)	841	813.1
Retained earnings	689.3	653.9
Total common shareholders' equity	1,530.3	1,467
TOTAL LIABILITIES & SHAREHOLDERS' EQUITY	$ 4,569.8	4,485.6
Subsidiary Ownership Percentage	100.00%
Parent Company [Member]
ASSETS
Cash & cash equivalents	$ 1.2	0.7	$ 0.3	$ 12.4
Accounts receivable - less reserves	0.1	0
Intercompany Receivables	39.6	142.9
Accrued unbilled revenues	0	0
Inventories	0.1	0
Recoverable fuel & natural gas costs	0
Prepayments & other current assets	2.6	4.1
Total current assets	43.6	147.7
Original cost	0	0
Less: accumulated depreciation & amortization	0	0
Net utility plant	0	0
Investments in consolidated subsidiaries	1,530.3	1,467
Notes receivable from consolidated subsidiaries	945.4	836
Investments in unconsolidated affiliates	0	0
Other investments	0.4	0.4
Nonutility plant - net	152.4	148
Goodwill	0	0
Regulatory assets	16.6	16.9
Other assets	1	1.3
TOTAL ASSETS	2,689.7	2,617.3
LIABILITIES & SHAREHOLDERS' EQUITY
Accounts payable	7.4	7.4
Intercompany payables	0	0
Payables to other Vectren companies	1.2	0
Accrued liabilities	13.2	12.6
Short-term borrowings	38.9	14.5
Intercompany short-term borrowings	37.4	51.2
Current maturities of long-term debt		0
Total current liabilities	98.1	85.7
Long-term debt	995.5	995.3
Long-term debt due to VUHI	0	0
Total long-term debt - net	995.5	995.3
Deferred income taxes	(2.8)	(5.3)
Regulatory liabilities	1.4	1.4
Deferred credits & other liabilities	4.9	5
Total deferred credits & other liabilities	3.5	1.1
Common stock (no par value)	827.9	799.9
Retained earnings	764.7	735.3
Total common shareholders' equity	1,592.6	1,535.2
TOTAL LIABILITIES & SHAREHOLDERS' EQUITY	2,689.7	$ 2,617.3
Line of Credit Facility, Maximum Borrowing Capacity	350
Unsecured Debt	$ 995

Subsidiary Guarantor and Cons24

Subsidiary Guarantor and Consolidating Information Income Statement (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
OPERATING REVENUES [Abstract]
Gas utility	$ 132	$ 128.6	$ 413.1	$ 481.5
Electric utility	147.7	147.8	289.8	301.7
Other	0.1	0.1	0.2	0.2
Total operating revenues	279.8	276.5	703.1	783.4
OPERATING EXPENSES [Abstract]
Cost of gas sold	34	36.4	145.5	208.4
Cost of fuel & purchased power	45.2	47	89.4	97
Other operating	81.3	78.5	171.4	181.3
Depreciation & Amortization	54	52	107.6	104.2
Taxes other than income taxes	13.1	12.1	30.2	31.2
Total operating expenses	227.6	226	544.1	622.1
OPERATING INCOME	52.2	50.5	159	161.3
Other income - net	7	4.3	13.3	9.2
Interest Expense	17.5	16.4	35	33
INCOME BEFORE INCOME TAXES	41.7	38.4	137.3	137.5
Income taxes	15.4	14	49.9	50.1
NET INCOME	26.3	24.4	87.4	87.4
Consolidated Entities [Member]
OPERATING REVENUES [Abstract]
Gas utility	132	128.6	413.1	481.5
Electric utility	147.7	147.8	289.8	301.7
Other	0.1	0.1	0.2	0.2
Total operating revenues	279.8	276.5	703.1	783.4
OPERATING EXPENSES [Abstract]
Cost of gas sold	34	36.4	145.5	208.4
Cost of fuel & purchased power	45.2	47	89.4	97
Other operating	81.3	78.5	171.4	181.3
Depreciation & Amortization	54	52	107.6	104.2
Taxes other than income taxes	13.1	12.1	30.2	31.2
Total operating expenses	227.6	226	544.1	622.1
OPERATING INCOME	52.2	50.5	159	161.3
Other income - net	7	4.3	13.3	9.2
Interest Expense	17.5	16.4	35	33
INCOME BEFORE INCOME TAXES	41.7	38.4	137.3	137.5
Income taxes	15.4	14	49.9	50.1
Equity in earnings of consolidated companies, net of tax	0	0	0	0
NET INCOME	26.3	24.4	87.4	87.4
Guarantor Subsidiaries [Member]
OPERATING REVENUES [Abstract]
Gas utility	132	128.6	413.1	481.5
Electric utility	147.7	147.8	289.8	301.7
Other	0	0	0	0
Total operating revenues	279.7	276.4	702.9	783.2
OPERATING EXPENSES [Abstract]
Cost of gas sold	34	36.4	145.5	208.4
Cost of fuel & purchased power	45.2	47	89.4	97
Other operating	91.5	87.9	191.6	200.3
Depreciation & Amortization	48	45.5	95.5	91.2
Taxes other than income taxes	12.7	11.7	29.3	30.3
Total operating expenses	231.4	228.5	551.3	627.2
OPERATING INCOME	48.3	47.9	151.6	156
Other income - net	6.9	4.3	12.2	8.4
Interest Expense	16.9	15.8	33.8	31.7
INCOME BEFORE INCOME TAXES	38.3	36.4	130	132.7
Income taxes	14.4	13.3	49.1	50.1
Equity in earnings of consolidated companies, net of tax	0	0	0	0
NET INCOME	23.9	23.1	80.9	82.6
Parent Company [Member]
OPERATING REVENUES [Abstract]
Gas utility	0	0	0	0
Electric utility	0	0	0	0
Other	10.6	10.2	21.1	20.4
Total operating revenues	10.6	10.2	21.1	20.4
OPERATING EXPENSES [Abstract]
Cost of gas sold	0	0	0	0
Cost of fuel & purchased power	0	0	0	0
Other operating	0	0	0	0
Depreciation & Amortization	6	6.4	12	12.8
Taxes other than income taxes	0.4	0.4	0.9	0.9
Total operating expenses	6.4	6.8	12.9	13.7
OPERATING INCOME	4.2	3.4	8.2	6.7
Other income - net	11.7	9.9	24	20.7
Interest Expense	12.5	11.3	24.9	22.6
INCOME BEFORE INCOME TAXES	3.4	2	7.3	4.8
Income taxes	1	0.7	0.8	0
Equity in earnings of consolidated companies, net of tax	23.9	23.1	80.9	82.6
NET INCOME	26.3	24.4	87.4	87.4
Consolidation, Eliminations [Member]
OPERATING REVENUES [Abstract]
Gas utility	0	0	0	0
Electric utility	0	0	0	0
Other	(10.5)	(10.1)	(20.9)	(20.2)
Total operating revenues	(10.5)	(10.1)	(20.9)	(20.2)
OPERATING EXPENSES [Abstract]
Cost of gas sold	0	0	0	0
Cost of fuel & purchased power	0	0	0	0
Other operating	(10.2)	(9.4)	(20.2)	(19)
Depreciation & Amortization	0	0.1	0.1	0.2
Taxes other than income taxes	0	0	0	0
Total operating expenses	(10.2)	(9.3)	(20.1)	(18.8)
OPERATING INCOME	(0.3)	(0.8)	(0.8)	(1.4)
Other income - net	(11.6)	(9.9)	(22.9)	(19.9)
Interest Expense	(11.9)	(10.7)	(23.7)	(21.3)
INCOME BEFORE INCOME TAXES	0	0	0	0
Income taxes	0	0	0	0
Equity in earnings of consolidated companies, net of tax	(23.9)	(23.1)	(80.9)	(82.6)
NET INCOME	$ (23.9)	$ (23.1)	$ (80.9)	$ (82.6)

Subsidiary Guarantor and Cons25

Subsidiary Guarantor and Consolidating Information Cash Flows (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015	Dec. 31, 2014
Net cash provided by operating activities	$ 232.8	$ 336.8
Additional capital contribution from parent	28	3
Dividends to parent	(58)	(55.2)
Retirement of long term debt	(13)	(5)
Net change in short-term borrowings	24.4	(129.1)
Net cash used in financing activities	(18.6)	(186.3)
Proceeds from other investing activities	0	0.1
Capital expenditures, excluding AFUDC equity	(215.9)	(163.2)
Changes in Restricted Cash	0.1	0
Net cash used in investing activities	(215.8)	(163.1)
Net change in cash & cash equivalents	(1.6)	(12.6)
Cash & cash equivalents	4.6	6.7	$ 6.2	$ 19.3
Consolidation, Eliminations [Member]
Net cash provided by operating activities	0	0
Long-term debt - net of issuance costs	(109.4)
Additional capital contribution from parent	(28)	(3)
Dividends to parent	45.5	51.6
Retirement of long term debt	0	0
Net change in intercompany short-term borrowings	120.7	(14.4)
Net change in short-term borrowings	0	0
Net cash used in financing activities	28.8	34.2
Consolidated subsidiary distributions	(45.5)	(51.6)
Proceeds from other investing activities		0
Capital expenditures, excluding AFUDC equity	0	0
Consolidated subsidiary investments	28	3
Changes in Restricted Cash	0
Net change in long-term intercompany notes receivable	109.4
Net change in short term intercompany notes receivable	(120.7)	14.4
Net cash used in investing activities	(28.8)	(34.2)
Net change in cash & cash equivalents	0	0
Cash & cash equivalents	0	0	0	0
Consolidated Entities [Member]
Net cash provided by operating activities	232.8	336.8
Long-term debt - net of issuance costs	0
Additional capital contribution from parent	28	3
Dividends to parent	(58)	(55.2)
Retirement of long term debt	(13)	(5)
Net change in intercompany short-term borrowings	0	0
Net change in short-term borrowings	24.4	(129.1)
Net cash used in financing activities	(18.6)	(186.3)
Consolidated subsidiary distributions	0	0
Proceeds from other investing activities		0.1
Capital expenditures, excluding AFUDC equity	(215.9)	(163.2)
Consolidated subsidiary investments	0	0
Changes in Restricted Cash	0.1
Net change in long-term intercompany notes receivable	0
Net change in short term intercompany notes receivable	0	0
Net cash used in investing activities	(215.8)	(163.1)
Net change in cash & cash equivalents	(1.6)	(12.6)
Cash & cash equivalents	4.6	6.7	6.2	19.3
Guarantor Subsidiaries [Member]
Net cash provided by operating activities	210.8	317.7
Long-term debt - net of issuance costs	109.4
Additional capital contribution from parent	28	3
Dividends to parent	(45.5)	(51.6)
Retirement of long term debt	(13)	(5)
Net change in intercompany short-term borrowings	(106.9)	(48.2)
Net change in short-term borrowings	0	0
Net cash used in financing activities	(28)	(101.8)
Consolidated subsidiary distributions	0	0
Proceeds from other investing activities		0
Capital expenditures, excluding AFUDC equity	(198.8)	(153.8)
Consolidated subsidiary investments	0	0
Changes in Restricted Cash	0.1
Net change in long-term intercompany notes receivable	0
Net change in short term intercompany notes receivable	13.8	(62.6)
Net cash used in investing activities	(184.9)	(216.4)
Net change in cash & cash equivalents	(2.1)	(0.5)
Cash & cash equivalents	3.4	6.4	5.5	6.9
Parent Company [Member]
Net cash provided by operating activities	22	19.1
Long-term debt - net of issuance costs	0
Additional capital contribution from parent	28	3
Dividends to parent	(58)	(55.2)
Retirement of long term debt	0	0
Net change in intercompany short-term borrowings	(13.8)	62.6
Net change in short-term borrowings	24.4	(129.1)
Net cash used in financing activities	(19.4)	(118.7)
Consolidated subsidiary distributions	45.5	51.6
Proceeds from other investing activities		0.1
Capital expenditures, excluding AFUDC equity	(17.1)	(9.4)
Consolidated subsidiary investments	(28)	(3)
Changes in Restricted Cash	0
Net change in long-term intercompany notes receivable	(109.4)
Net change in short term intercompany notes receivable	106.9	48.2
Net cash used in investing activities	(2.1)	87.5
Net change in cash & cash equivalents	0.5	(12.1)
Cash & cash equivalents	$ 1.2	$ 0.3	$ 0.7	$ 12.4

Excise and Utility Receipts T26

Excise and Utility Receipts Taxes (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Excise and Utility Receipts Taxes [Abstract]
Excise and utility taxes collected and reported in operating revenue	$ 5.5	$ 5.4	$ 14.9	$ 17.1

Supplemental Cash Flow Inform27

Supplemental Cash Flow Information (Details) - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Accruals for Utility & Nonutility Plant [Abstract]
Public Utilities Accruals For Purchase Of Utility And Non Utility Plant Assets	$ 30.9	$ 18.1

Transactions with Other Vectr28

Transactions with Other Vectren Companies and Affiliates Transactions with Other Vectren Companies and Afffiliates (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Vectren Infrastructure Services Corporation [Member]
Transactions with Other Vectren Companies and Affiliates [Line Items]
Expenses from transactions with related party	$ 37.2	$ 31.6	$ 56.8	$ 49.3
Support Services & Purchases [Member]
Transactions with Other Vectren Companies and Affiliates [Line Items]
Cost of corporate and general and administrative services	$ 14.8	$ 11.9	$ 32.7	$ 27.5

Gas Rate & Regulatory Matters (

Gas Rate & Regulatory Matters (Details) - USD ($)	6 Months Ended
	Jun. 30, 2016	Dec. 31, 2015
INDIANA | Indiana Recovery and Deferral Mechanisms [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Asset balance associated with Vectren north and south programs	$ 21,200,000	$ 19,900,000
Length of project plan required for recovery under new legislation	7 years
INDIANA | Senate Bill 251 and 560 [Member]
Public Utilities, General Disclosures [Line Items]
Amount of projects not approved for recovery	$ 80,000,000
Amount of single project excluded from recovery	$ 65,000,000
Percentage of costs eligible for recovery using periodic rate recovery mechanism	80.00%
Percentage of project costs to be deferred for future recovery	20.00%
Project spend life to date	$ 262,000,000
Capital Expenditure Increases	890,000,000
Regulatory Asset associated with DRR deferrals of depreciation and post in-service carrying costs	46,700,000	28,600,000
INDIANA | SIGECO [Member] | Indiana Recovery and Deferral Mechanisms [Member]
Public Utilities, General Disclosures [Line Items]
Allowable capital expenditures under Vectren programs	$ 3,000,000
Limitations of deferrals of debt-related post in service carrying costs	P3Y
INDIANA | Indiana Gas [Member] | Indiana Recovery and Deferral Mechanisms [Member]
Public Utilities, General Disclosures [Line Items]
Allowable capital expenditures under Vectren programs	$ 20,000,000
Limitations of deferrals of debt-related post in service carrying costs	P4Y
OHIO | Ohio Recovery and Deferral Mechanisms [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Asset associated with DRR deferrals of depreciation and post in-service carrying costs	$ 21,300,000	$ 18,200,000
Initial distribution replacement rider mechanism term.	5 years
Amount of Capital Investment Expected Over Next Five Years Recoverable Under DRR	$ 90,000,000
Cumulative gross plant invesment made under Distribution Replacement Rider	220,700,000
OHIO | Ohio House Bill95 [Member]
Public Utilities, General Disclosures [Line Items]
Bill impact per customer per month	$ 1.50

Electric Rate and Regulatory 30

Electric Rate and Regulatory Matters (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
Vectren South Electric Environmental Compliance Filing [Abstract]
Amount of capital investments to date in equipment for mercury control	$ 31
Amount of capital investments to date in equipment to control sulfur trioxide emissions	37
Lower range of request for approval of capital investments on coal-fired generation units	70
Upper range of request for approval of capital investments on coal-fired generation units	75
Amount of deferred costs to date related to depreciation, property tax, and operating expenses under Senate Bill 29 and Senate Bill 251	4.6
Amount of deferred costs to date related to post in-service carrying costs under Senate Bill 29 and Senate Bill 251.	1.9
Estimated cost of equipment to comply with MATS	35
Estimated cost of equipment required by the NOV	$ 40
Vectren South Electric Demand Side Management Program Filing [Abstract]
Number of Years in Initial Demand Side Management Program	3 years
Electric revenue recognized associated with lost margin recovery	$ 5.4	$ 4.8
Percent of industrial load opt out of applicable energy efficiency programs	80.00%
Maximum period for recovery under energy efficiency program	4 years
FERC Return On Equity Complaint [Abstract]
Current return on equity used in MISO transmission owners rates	12.38%
Reduced return on equity percentage sought by third party through joint complaint	9.15%
Equity component, upper limit, as a percentage, sought by third party through joint complaint	50.00%
Gross Investment In Qualifying Transmission Projects	$ 157.7
Net Investment in Qualifying Transmission Projects	$ 138.5
Incentive return granted on qualifying investments in NETO	11.14%
Percentage return approved by FERC on ROE complaint against NETO	10.57%
FERC authorized base ROE percentage for first refund period	10.32%
FERC authorized base ROE percentage for second refund period	9.70%
Number of incentive basis point above and beyond approved FERC approved ROE	50

Environmental Matters (Details)

Environmental Matters (Details) $ in Millions	6 Months Ended
	Jun. 30, 2016USD ($)MW	Dec. 31, 2015USD ($)
Air Quality [Abstract]
Percentage of coal fired generating fleet currently controlled for NOx (in hundredths)	90.00%
Percentage of coal fired generating fleet currently being scrubbed for SO2 (in hundredths)	100.00%
Coal Ash Waste Disposal, Ash Ponds and Water [Abstract]
Estimated Capital Expenditures to Comply With Ash Pond and Coal Ash Disposal Regulations - Lower Range	$ 35
Estimated Capital Expenditures to Comply With Ash Pond and Coal Ash Disposal Regulations - Upper Range	80
Asset Retirement Obligation	25
Estimated capital expenditures to comply with Clean Water Act (Lower Range)	4
Estimated capital expenditures to comply with Clean Water Act (Upper Range)	8
Estimated spend for ash pond dam reinforcement and other operational changes	$ 12
Climate Changes [Abstract]
Vectren's share of Indiana's CO2 emissions in 2013 (as a percent)	6.00%
Percent reduction of Vectren's CO2 emissions since 2005	31.00%
Long term contract for purchase of electric power generated by wind energy (in megawatts) | MW	80
Percentage of total electricity obtained by the supplier to meet the energy needs of its retail customers provided by clean energy sources (in hundredths)	4.00%
Vectren's emission rate (as measured in lbs CO2/MWh) prior to installation of new technology	1,967
Vectren's emission rate (as measured in lbs CO2/MWh) after installation of new technology	1,922
Percentage reduction of lbs CO2/MWh since 2005	3.00%
Manufactured Gas Plants
Site contingency, accrual, undiscounted amount	$ 43.4
Accrual for Environmental Loss Contingencies	$ 2.8	$ 3.3
Indiana Gas [Member]
Manufactured Gas Plants
Number of sites identified with potential remedial responsibility for entity (in number of sites)	26
Site contingency, accrual, undiscounted amount	$ 23.2
Environmental cost recognized, recover from insurance carriers credited to expense	$ 20.8
SIGECO [Member]
Manufactured Gas Plants
Number of sites identified with potential remedial responsibility for entity (in number of sites)	5
Site contingency, accrual, undiscounted amount	$ 20.2
Environmental cost recognized, recover from insurance carriers credited to expense	14.8
Expected Site Contingency Recovery from Insurance Carriers of Environmental Remediation Costs	$ 15.8

Fair Value Measurements (Detail

Fair Value Measurements (Details) - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Estimated Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt	$ 1,549.5	$ 1,495
Short-term Debt	38.9	14.5
Cash and cash equivalents	4.6	6.2
Restricted Cash	5.8	5.9
Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt	1,379.7	1,392.2
Short-term Debt	38.9	14.5
Cash and cash equivalents	4.6	6.2
Restricted Cash	$ 5.8	$ 5.9

Impact of Recently Issued Acc33

Impact of Recently Issued Accounting Guidance (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)
Accounting Standards Update 2015-03 [Member] | Impact on Regulatory Assets [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification	$ 8.6

Segment Reporting (Details)

Segment Reporting (Details) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016USD ($)	Jun. 30, 2015USD ($)	Jun. 30, 2016USD ($)	Jun. 30, 2015USD ($)
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)	66.66667%		66.66667%
Number of Reportable Segments			3
Revenues	$ 279.8	$ 276.5	$ 703.1	$ 783.4
NET INCOME	26.3	24.4	87.4	87.4
Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues	(10.4)	(10.1)	(20.9)	(20.2)
Other Segments [Member]
Segment Reporting Information [Line Items]
Revenues	10.5	10.2	21.1	20.4
NET INCOME	2.4	1.3	6.5	4.7
Electric Utility Services [Member]
Segment Reporting Information [Line Items]
Revenues	147.7	147.8	289.8	301.7
NET INCOME	19.2	19.7	35.8	38.9
Gas Utility Services [Member]
Segment Reporting Information [Line Items]
Revenues	132	128.6	413.1	481.5
NET INCOME	$ 4.7	$ 3.4	$ 45.1	$ 43.8