10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

ý QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2014

OR

[_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from __________________ to __________________

Commission file number:   1-16739

VECTREN UTILITY HOLDINGS, INC.

(Exact name of registrant as specified in its charter)

INDIANA	35-2104850
(State or other jurisdiction of incorporation or organization)	(IRS Employer Identification No.)

One Vectren Square, Evansville, IN 47708

(Address of principal executive offices)

(Zip Code)

812-491-4000

(Registrant's telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. ý Yes  o No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

ý Yes   o No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.  (Check one):

Large accelerated filer o                                                                                                        Accelerated filer o

Non-accelerated filer ý (Do not check if a smaller reporting company)                               Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

o Yes     ý No

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date.

Common Stock- Without Par Value	10	October 31, 2014
Class	Number of Shares	Date

Access to Information

Vectren Corporation makes available all SEC filings and recent annual reports, including those of its wholly owned subsidiaries, free of charge through its website at www.vectren.com as soon as reasonably practicable after electronically filing or furnishing the reports to the SEC, or by request, directed to Investor Relations at the mailing address, phone number, or email address that follows:

Mailing Address: One Vectren Square Evansville, Indiana  47708 Phone Number: (812) 491-4000 Investor Relations Contact: Robert L. Goocher Treasurer and Vice President, Investor Relations vvcir@vectren.com

Definitions

AFUDC:  allowance for funds used during construction	MDth / MMDth: thousands / millions of dekatherms
DOT: Department of Transportation	MISO: Midcontinent Independent System Operator (formerly Midwest Independent System Operator)
EPA:  Environmental Protection Agency	MMBTU:  millions of British thermal units
FAC:  Fuel Adjustment Clause	MW:  megawatts
FASB:  Financial Accounting Standards Board	MWh / GWh:  megawatt hours / thousands of megawatt hours (gigawatt hours)
FERC:  Federal Energy Regulatory Commission	OCC:  Ohio Office of the Consumer Counselor
IDEM:  Indiana Department of Environmental Management	OUCC:  Indiana Office of the Utility Consumer Counselor
IURC:  Indiana Utility Regulatory Commission	PUCO:  Public Utilities Commission of Ohio
Kv: Kilovolt	Throughput:  combined gas sales and gas transportation volumes
MCF / BCF:  thousands / billions of cubic feet	XBRL:  eXtensible Business Reporting Language

Table of Contents

Item Number		Page Number
	PART I.  FINANCIAL INFORMATION
1	Financial Statements (Unaudited)
	Vectren Utility Holdings, Inc. and Subsidiary Companies
	Condensed Consolidated Balance Sheets	3- 4
	Condensed Consolidated Statements of Income	5
	Condensed Consolidated Statements of Cash Flows	6
	Notes to Unaudited Condensed Consolidated Financial Statements	7
2	Management’s Discussion and Analysis of Financial Condition and Results of Operations	26
3	Quantitative and Qualitative Disclosures About Market Risk	43
4	Controls and Procedures	44
	PART II.  OTHER INFORMATION
1	Legal Proceedings	45
1A	Risk Factors	45
2	Unregistered Sales of Equity Securities and Use of Proceeds	45
3	Defaults Upon Senior Securities	45
4	Mine Safety Disclosures	45
5	Other Information	45
6	Exhibits	46
	Signatures	47

2

PART I.  FINANCIAL INFORMATION

ITEM 1.  FINANCIAL STATEMENTS

VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited – In millions)

	September 30, 2014		December 31, 2013
ASSETS
Current Assets
Cash & cash equivalents	$	5.4	$	8.6
Accounts receivable - less reserves of $3.4 & $5.0, respectively	68.8		112.1
Accrued unbilled revenues	41.8		113.5
Inventories	109.7		89.9
Recoverable fuel & natural gas costs	25.5		5.5
Prepayments & other current assets	47.7		42.4
Total current assets	298.9		372.0
Utility Plant
Original cost	5,599.2		5,389.6
Less:  accumulated depreciation & amortization	2,250.3		2,165.3
Net utility plant	3,348.9		3,224.3
Investments in unconsolidated affiliates	0.2		0.2
Other investments	25.1		27.3
Nonutility plant - net	148.8		150.5
Goodwill - net	205.0		205.0
Regulatory assets	131.6		136.2
Other assets	20.2		25.3
TOTAL ASSETS	$	4,178.7	$	4,140.8

The accompanying notes are an integral part of these condensed consolidated financial statements.

3

VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited – In millions)

	September 30, 2014		December 31, 2013
LIABILITIES & SHAREHOLDER'S EQUITY
Current Liabilities
Accounts payable	$	110.1	$	172.1
Payables to other Vectren companies	50.6		24.6
Accrued liabilities	118.1		127.4
Short-term borrowings	60.1		28.6
Current maturities of long-term debt	5.0		—
Total current liabilities	343.9		352.7
Long-Term Debt - Net of Current Maturities	1,252.3		1,257.1
Deferred Credits & Other Liabilities
Deferred income taxes	625.0		627.4
Regulatory liabilities	404.8		387.3
Deferred credits & other liabilities	88.2		83.5
Total deferred credits & other liabilities	1,118.0		1,098.2
Commitments & Contingencies (Notes 8 - 10)
Common Shareholder's Equity
Common stock (no par value)	792.3		787.7
Retained earnings	672.2		645.1
Total common shareholder's equity	1,464.5		1,432.8
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	$	4,178.7	$	4,140.8

The accompanying notes are an integral part of these condensed consolidated financial statements.

4

VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Unaudited – In millions)

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2014		2013		2014		2013
OPERATING REVENUES
Gas utility	$	105.1	$	101.9	$	681.1	$	555.8
Electric utility	165.9		165.8		480.9		470.0
Other	0.1		—		0.2		0.2
Total operating revenues	271.1		267.7		1,162.2		1,026.0
OPERATING EXPENSES
Cost of gas sold	28.8		27.5		343.4		235.4
Cost of fuel & purchased power	50.3		50.4		155.4		154.5
Other operating	79.9		74.0		259.7		236.9
Depreciation & amortization	51.0		49.7		151.5		146.8
Taxes other than income taxes	11.7		11.6		44.3		41.3
Total operating expenses	221.7		213.2		954.3		814.9
OPERATING INCOME	49.4		54.5		207.9		211.1
Other income - net	4.8		2.0		12.4		6.8
Interest expense	16.6		15.6		50.0		49.2
INCOME BEFORE INCOME TAXES	37.6		40.9		170.3		168.7
Income taxes	13.3		15.6		61.8		64.1
NET INCOME	$	24.3	$	25.3	$	108.5	$	104.6

The accompanying notes are an integral part of these condensed consolidated financial statements.

5

VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited – In millions)

	Nine Months Ended
	September 30,
	2014			2013
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	108.5		$	104.6
Adjustments to reconcile net income to cash from operating activities:
Depreciation & amortization	151.5			146.8
Deferred income taxes & investment tax credits	19.8			27.9
Expense portion of pension & postretirement periodic benefit cost	3.5			4.2
Provision for uncollectible accounts	3.7			4.8
Other non-cash expense - net	2.3			4.7
Changes in working capital accounts:
Accounts receivable & accrued unbilled revenue	111.3			67.7
Inventories	(19.8		)	15.5
Recoverable/refundable fuel & natural gas costs	(22.6		)	5.8
Prepayments & other current assets	(9.6		)	4.3
Accounts payable, including to Vectren companies                     & affiliated companies	(42.2		)	(64.0		)
Accrued liabilities	(15.8		)	(16.5		)
Changes in noncurrent assets	0.9			(6.5		)
Changes in noncurrent liabilities	(9.1		)	(3.9		)
Net cash provided by operating activities	282.4			295.4
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from:
Long-term debt - net of issuance costs	63.0			232.7
Additional capital contribution	4.6			4.5
Requirements for:
Dividends to parent	(81.4		)	(78.8		)
Retirement of long-term debt	(63.6		)	(337.5		)
Net change in short-term borrowings	31.5			59.4
Net cash used in financing activities	(45.9		)	(119.7		)
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from other investing activities	0.3			0.8
Requirements for:
Capital expenditures, excluding AFUDC equity	(240.0		)	(183.6		)
Net cash used in investing activities	(239.7		)	(182.8		)
Net change in cash & cash equivalents	(3.2		)	(7.1		)
Cash & cash equivalents at beginning of period	8.6			13.3
Cash & cash equivalents at end of period	$	5.4		$	6.2

The accompanying notes are an integral part of these condensed consolidated financial statements.

6

VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

1. 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), Southern Indiana Gas and Electric Company (SIGECO), and Vectren Energy Delivery of Ohio, Inc. (VEDO).  Utility Holdings also has other assets that provide information technology and other services to the three utilities.  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 574,000 natural gas customers located in central and southern Indiana. SIGECO provides energy delivery services to approximately 143,000 electric customers and approximately 110,000 gas customers located near Evansville in southwestern Indiana.  SIGECO also owns and operates electric generation assets to serve its electric customers and optimizes those assets in the wholesale power market.  Indiana Gas and SIGECO generally do business as Vectren Energy Delivery of Indiana.  VEDO provides energy delivery services to approximately 313,000 natural gas customers located near Dayton in west central Ohio.

2. Basis of Presentation

The interim condensed consolidated financial statements included in this report have been prepared by the Company, without audit, as provided in the rules and regulations of the Securities and Exchange Commission and include a review of subsequent events through the date the financial statements were issued.  Certain information and note disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States have been omitted as provided in such rules and regulations.  The information in this report reflects all adjustments which are, in the opinion of management, necessary to fairly state the interim periods presented, inclusive of adjustments that are normal and recurring in nature.  These condensed consolidated financial statements and related notes should be read in conjunction with the Company’s audited annual consolidated financial statements for the year ended December 31, 2013, filed with the Securities and Exchange Commission on March 5, 2014, on Form 10-K.  Because of the seasonal nature of the Company’s utility operations, the results shown on a quarterly basis are not necessarily indicative of annual results.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the statements and the reported amounts of revenues and expenses during the reporting periods.  Actual results could differ from those estimates.

3. 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 approximately $60 million was outstanding at September 30, 2014, and Utility Holdings’ has unsecured senior notes with a par value of $875 million outstanding at September 30, 2014.  The guarantees are full and unconditional and joint and several, and Utility Holdings has no direct subsidiaries other than the subsidiary guarantors.   However, Utility Holdings does have operations other than those of the subsidiary guarantors.  Pursuant to Item 3-10 of Regulation S-X, disclosure of the results of operations and balance sheets of the subsidiary guarantors, which are 100 percent owned, separate from the parent company’s operations is required.  Following are consolidating financial statements including information on the combined operations of the subsidiary guarantors separate from the other operations of the parent company.  Pursuant to a tax sharing agreement, consolidating tax effects, which are calculated on a separate return basis, are reflected at the parent level.

7

Condensed Consolidating Balance Sheet as of September 30, 2014 (in millions):

ASSETS	Subsidiary		Parent		Eliminations &
	Guarantors		Company		Reclassifications			Consolidated
Current Assets
Cash & cash equivalents	$	3.9	$	1.5	$	—		$	5.4
Accounts receivable - less reserves	68.8		—		—			68.8
Intercompany receivables	29.0		64.0		(93.0		)	—
Accrued unbilled revenues	41.8		—		—			41.8
Inventories	109.7		—		—			109.7
Recoverable fuel & natural gas costs	25.5		—		—			25.5
Prepayments & other current assets	55.7		26.8		(34.8		)	47.7
Total current assets	334.4		92.3		(127.8		)	298.9
Utility Plant
Original cost	5,599.2		—		—			5,599.2
Less:  accumulated depreciation & amortization	2,250.3		—		—			2,250.3
Net utility plant	3,348.9		—		—			3,348.9
Investments in consolidated subsidiaries	—		1,404.0		(1,404.0		)	—
Notes receivable from consolidated subsidiaries	—		820.6		(820.6		)	—
Investments in unconsolidated affiliates	0.2		—		—			0.2
Other investments	20.9		4.2		—			25.1
Nonutility property - net	1.8		147.0		—			148.8
Goodwill - net	205.0		—		—			205.0
Regulatory assets	109.7		21.9		—			131.6
Other assets	30.1		0.6		(10.5		)	20.2
TOTAL ASSETS	$	4,051.0	$	2,490.6	$	(2,362.9	)	$	4,178.7
LIABILITIES & SHAREHOLDER'S EQUITY	Subsidiary		Parent		Eliminations &
	Guarantors		Company		Reclassifications			Consolidated
Current Liabilities
Accounts payable	$	104.2	$	5.9	$	—		$	110.1
Intercompany payables	23.5		—		(23.5		)	—
Payables to other Vectren companies	50.6		—		—			50.6
Accrued liabilities	130.9		22.0		(34.8		)	118.1
Short-term borrowings	—		60.1		—			60.1
Intercompany short-term borrowings	40.5		29.0		(69.5		)	—
Current maturities of long-term debt	5.0		—		—			5.0
Total current liabilities	354.7		117.0		(127.8		)	343.9
Long-Term Debt
Long-term debt	377.6		874.7		—			1,252.3
Long-term debt due to VUHI	820.6		—		(820.6		)	—
Total long-term debt - net	1,198.2		874.7		(820.6		)	1,252.3
Deferred Credits & Other Liabilities
Deferred income taxes	596.8		28.2		—			625.0
Regulatory liabilities	403.3		1.5		—			404.8
Deferred credits & other liabilities	94.0		4.7		(10.5		)	88.2
Total deferred credits & other liabilities	1,094.1		34.4		(10.5		)	1,118.0
Common Shareholder's Equity
Common stock (no par value)	805.5		792.3		(805.5		)	792.3
Retained earnings	598.5		672.2		(598.5		)	672.2
Total common shareholder's equity	1,404.0		1,464.5		(1,404.0		)	1,464.5
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	$	4,051.0	$	2,490.6	$	(2,362.9	)	$	4,178.7

8

Condensed Consolidating Balance Sheet as of December 31, 2013 (in millions):

ASSETS	Subsidiary		Parent		Eliminations &
	Guarantors		Company		Reclassifications			Consolidated
Current Assets
Cash & cash equivalents	$	8.2	$	0.4	$	—		$	8.6
Accounts receivable - less reserves	112.1		—		—			112.1
Intercompany receivables	0.3		84.8		(85.1		)	—
Accrued unbilled revenues	113.5		—		—			113.5
Inventories	89.9		—		—			89.9
Recoverable fuel & natural gas costs	5.5		—		—			5.5
Prepayments & other current assets	37.3		40.1		(35.0		)	42.4
Total current assets	366.8		125.3		(120.1		)	372.0
Utility Plant
Original cost	5,389.6		—		—			5,389.6
Less:  accumulated depreciation & amortization	2,165.3		—		—			2,165.3
Net utility plant	3,224.3		—		—			3,224.3
Investments in consolidated subsidiaries	—		1,375.8		(1,375.8		)	—
Notes receivable from consolidated subsidiaries	—		696.4		(696.4		)	—
Investments in unconsolidated affiliates	0.2		—		—			0.2
Other investments	22.8		4.5		—			27.3
Nonutility property - net	2.2		148.3		—			150.5
Goodwill - net	205.0		—		—			205.0
Regulatory assets	113.4		22.8		—			136.2
Other assets	32.2		1.0		(7.9		)	25.3
TOTAL ASSETS	$	3,966.9	$	2,374.1	$	(2,200.2	)	$	4,140.8
LIABILITIES & SHAREHOLDER'S EQUITY	Subsidiary		Parent		Eliminations &
	Guarantors		Company		Reclassifications			Consolidated
Current Liabilities
Accounts payable	$	161.6	$	10.5	$	—		$	172.1
Intercompany payables	11.7		—		(11.7		)	—
Payables to other Vectren companies	24.6		—		—			24.6
Accrued liabilities	150.3		12.1		(35.0		)	127.4
Short-term borrowings	—		28.6		—			28.6
Intercompany short-term borrowings	73.1		0.3		(73.4		)	—
Total current liabilities	421.3		51.5		(120.1		)	352.7
Long-Term Debt
Long-term debt - net of current maturities &
debt subject to tender	382.5		874.6		—			1,257.1
Long-term debt due to VUHI	696.4		—		(696.4		)	—
Total long-term debt - net	1,078.9		874.6		(696.4		)	1,257.1
Deferred Credits & Other Liabilities
Deferred income taxes	616.9		10.5		—			627.4
Regulatory liabilities	385.7		1.6		—			387.3
Deferred credits & other liabilities	88.3		3.1		(7.9		)	83.5
Total deferred credits & other liabilities	1,090.9		15.2		(7.9		)	1,098.2
Common Shareholder's Equity
Common stock (no par value)	800.9		787.7		(800.9		)	787.7
Retained earnings	574.9		645.1		(574.9		)	645.1
Total common shareholder's equity	1,375.8		1,432.8		(1,375.8		)	1,432.8
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	$	3,966.9	$	2,374.1	$	(2,200.2	)	$	4,140.8

9

Condensed Consolidating Statement of Income for the three months ended September 30, 2014 (in millions):

	Subsidiary Guarantors		Parent Company			Eliminations & Reclassifications			Consolidated
OPERATING REVENUES
Gas utility	$	105.1	$	—		$	—		$	105.1
Electric utility	165.9		—			—			165.9
Other	—		9.6			(9.5		)	0.1
Total operating revenues	271.0		9.6			(9.5		)	271.1
OPERATING EXPENSES
Cost of gas sold	28.8		—			—			28.8
Cost of fuel & purchased power	50.3		—			—			50.3
Other operating	88.6		—			(8.7		)	79.9
Depreciation & amortization	44.8		6.1			0.1			51.0
Taxes other than income taxes	11.2		0.5			—			11.7
Total operating expenses	223.7		6.6			(8.6		)	221.7
OPERATING INCOME	47.3		3.0			(0.9		)	49.4
Other income - net	3.9		10.8			(9.9		)	4.8
Interest expense	16.1		11.3			(10.8		)	16.6
INCOME BEFORE INCOME TAXES	35.1		2.5			—			37.6
Income taxes	13.5		(0.2		)	—			13.3
Equity in earnings of consolidated companies, net of tax	—		21.6			(21.6		)	—
NET INCOME	$	21.6	$	24.3		$	(21.6	)	$	24.3

Condensed Consolidating Statement of Income for the three months ended September 30, 2013 (in millions):

	Subsidiary Guarantors		Parent Company		Eliminations & Reclassifications			Consolidated
OPERATING REVENUES
Gas utility	$	101.9	$	—	$	—		$	101.9
Electric utility	165.8		—		—			165.8
Other	—		9.4		(9.4		)	—
Total operating revenues	267.7		9.4		(9.4		)	267.7
OPERATING EXPENSES
Cost of gas sold	27.5		—		—			27.5
Cost of fuel & purchased power	50.4		—		—			50.4
Other operating	83.1		—		(9.1		)	74.0
Depreciation & amortization	44.1		5.4		0.2			49.7
Taxes other than income taxes	11.2		0.4		—			11.6
Total operating expenses	216.3		5.8		(8.9		)	213.2
OPERATING INCOME	51.4		3.6		(0.5		)	54.5
Other income - net	1.2		9.8		(9.0		)	2.0
Interest expense	14.7		10.4		(9.5		)	15.6
INCOME BEFORE INCOME TAXES	37.9		3.0		—			40.9
Income taxes	15.0		0.6		—			15.6
Equity in earnings of consolidated companies, net of tax	—		22.9		(22.9		)	—
NET INCOME	$	22.9	$	25.3	$	(22.9	)	$	25.3

10

Condensed Consolidating Statement of Income for the nine months endedSeptember 30, 2014 (in millions):

	Subsidiary Guarantors		Parent Company			Eliminations & Reclassifications			Consolidated
OPERATING REVENUES
Gas utility	$	681.1	$	—		$	—		$	681.1
Electric utility	480.9		—			—			480.9
Other	—		28.7			(28.5		)	0.2
Total operating revenues	1,162.0		28.7			(28.5		)	1,162.2
OPERATING EXPENSES
Cost of gas sold	343.4		—			—			343.4
Cost of fuel & purchased power	155.4		—			—			155.4
Other operating	286.4		—			(26.7		)	259.7
Depreciation & amortization	133.8		17.4			0.3			151.5
Taxes other than income taxes	42.9		1.3			0.1			44.3
Total operating expenses	961.9		18.7			(26.3		)	954.3
OPERATING INCOME	200.1		10.0			(2.2		)	207.9
Other income - net	9.7		32.4			(29.7		)	12.4
Interest expense	48.0		33.9			(31.9		)	50.0
INCOME BEFORE INCOME TAXES	161.8		8.5			—			170.3
Income taxes	62.0		(0.2		)	—			61.8
Equity in earnings of consolidated companies, net of tax	—		99.8			(99.8		)	—
NET INCOME	$	99.8	$	108.5		$	(99.8	)	$	108.5

Condensed Consolidating Statement of Income for the nine months endedSeptember 30, 2013 (in millions):

	Subsidiary Guarantors		Parent Company		Eliminations & Reclassifications			Consolidated
OPERATING REVENUES
Gas utility	$	555.8	$	—	$	—		$	555.8
Electric utility	470.0		—		—			470.0
Other	—		28.4		(28.2		)	0.2
Total operating revenues	1,025.8		28.4		(28.2		)	1,026.0
OPERATING EXPENSES
Cost of gas sold	235.4		—		—			235.4
Cost of fuel & purchased power	154.5		—		—			154.5
Other operating	264.3		—		(27.4		)	236.9
Depreciation & amortization	130.5		15.9		0.4			146.8
Taxes other than income taxes	40.1		1.2		—			41.3
Total operating expenses	824.8		17.1		(27.0		)	814.9
OPERATING INCOME	201.0		11.3		(1.2		)	211.1
Other income - net	4.9		28.6		(26.7		)	6.8
Interest expense	44.7		32.4		(27.9		)	49.2
INCOME BEFORE INCOME TAXES	161.2		7.5		—			168.7
Income taxes	63.8		0.3		—			64.1
Equity in earnings of consolidated companies, net of tax	—		97.4		(97.4		)	—
NET INCOME	$	97.4	$	104.6	$	(97.4	)	$	104.6

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Condensed Consolidating Statement of Cash Flows for the nine months endedSeptember 30, 2014 (in millions):

	Subsidiary Guarantors			Parent Company			Eliminations			Consolidated
NET CASH PROVIDED BY OPERATING ACTIVITIES	$	226.3		$	56.1		$	—		$	282.4
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from
Long-term debt - net of issuance costs	187.2			—			(124.2		)	63.0
Additional capital contribution from parent	4.6			4.6			(4.6		)	4.6
Requirements for:
Dividends to parent	(76.2		)	(81.4		)	76.2			(81.4		)
Retirement of long term debt	(63.6		)	—			—			(63.6		)
Net change in intercompany short-term borrowings	(32.5		)	28.6			3.9			—
Net change in short-term borrowings	—			31.5			—			31.5
Net cash used in financing activities	19.5			(16.7		)	(48.7		)	(45.9		)
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from:
Consolidated subsidiary distributions	—			76.2			(76.2		)	—
Other investing activities	—			0.3			—			0.3
Requirements for:
Capital expenditures, excluding AFUDC equity	(221.4		)	(18.6		)	—			(240.0		)
Consolidated subsidiary investments	—			(4.6		)	4.6			—
Net change in long-term intercompany notes receivable	—			(124.2		)	124.2			—
Net change in short-term intercompany notes receivable	(28.7		)	32.6			(3.9		)	—
Net cash used in investing activities	(250.1		)	(38.3		)	48.7			(239.7		)
Net change in cash & cash equivalents	(4.3		)	1.1			—			(3.2		)
Cash & cash equivalents at beginning of period	8.2			0.4			—			8.6
Cash & cash equivalents at end of period	$	3.9		$	1.5		$	—		$	5.4

Condensed Consolidating Statement of Cash Flows for the nine months endedSeptember 30, 2013 (in millions):

	Subsidiary Guarantors			Parent Company			Eliminations			Consolidated
NET CASH PROVIDED BY OPERATING ACTIVITIES	$	276.1		$	19.3		$	—		$	295.4
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from:
Long-term debt, net of issuance costs	232.7			124.4			(124.4		)	232.7
Additional capital contribution from parent	11.5			4.5			(11.5		)	4.5
Requirements for:
Dividends to parent	(73.5		)	(78.8		)	73.5			(78.8		)
Retirement of long term debt	(223.6		)	(221.6		)	107.7			(337.5		)
Net change in intercompany short-term borrowings	(61.5		)	—			61.5			—
Net change in short-term borrowings	—			59.4			—			59.4
Net cash used in financing activities	(114.4		)	(112.1		)	106.8			(119.7		)
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from:
Consolidated subsidiary distributions	—			73.5			(73.5		)	—
Other investing activities	0.6			0.2			—			0.8
Requirements for:
Capital expenditures, excluding AFUDC equity	(169.4		)	(14.2		)	—			(183.6		)
Consolidated subsidiary investments	—			(11.5		)	11.5			—
Net change in long-term intercompany notes receivable	—			(16.7		)	16.7			—
Net change in short-term intercompany notes receivable	—			61.5			(61.5		)	—
Net cash used in investing activities	(168.8		)	92.8			(106.8		)	(182.8		)
Net change in cash & cash equivalents	(7.1		)	—			—			(7.1		)
Cash & cash equivalents at beginning of period	12.5			0.8			—			13.3
Cash & cash equivalents at end of period	$	5.4		$	0.8		$	—		$	6.2

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4. 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 $4.9 million and $4.8 million in the three months ended September 30, 2014 and 2013, respectively. For the nine months ended September 30, 2014 and 2013, these taxes totaled $23.3 million and $20.9 million, respectively.  Expense associated with excise and utility receipts taxes are recorded as a component of Taxes other than income taxes.

5. Supplemental Cash Flow Information

As of September 30, 2014 and December 31, 2013, the Company has accruals related to utility and nonutility plant purchases totaling approximately $19.3 million and $13.1 million, respectively.

6. Transactions with Other Vectren Companies and Affiliates

Vectren Fuels, Inc. (Vectren Fuels)

On August 29, 2014, Vectren closed on a transaction to sell its wholly-owned coal mining subsidiary, Vectren Fuels, to Sunrise Coal, LLC (Sunrise), an Indiana-based wholly-owned subsidiary of Hallador Energy Company. Prior to the sale date, SIGECO purchased coal used for electric generation from Vectren Fuels.  Amounts purchased for the three months ended September 30, 2014 and 2013 totaled $30.0 million and $24.5 million, respectively, and for the nine months ended September 30, 2014 and 2013 totaled $98.6 million and $76.1 million, respectively.  Amounts owed to Vectren Fuels at September 30, 2014 and December 31, 2013 are included in Payables to other Vectren companies in the Condensed Consolidated Balance Sheets.

Vectren Infrastructure Services Corporation (VISCO)

VISCO, a wholly owned subsidiary of Vectren, performs natural gas and water distribution, transmission, and construction repair and rehabilitation primarily in the Midwest and the repair and rehabilitation of gas, water, and wastewater facilities nationwide. In addition, VISCO also provides transmission pipeline construction and maintenance; pump station, compressor station, terminal and refinery construction; and hydrostatic testing to customers generally in the northern Midwest region. VISCO's customers include Utility Holdings’ utilities. Fees incurred by Utility Holdings and its subsidiaries totaled $30.1 million and $15.9 million for the three months ended September 30, 2014 and 2013, respectively, and for the nine months ended September 30, 2014 and 2013 totaled $63.5 million and $39.5 million, respectively. Amounts owed to VISCO at September 30, 2014 and December 31, 2013 are included in Payables to other Vectren companies in the Condensed Consolidated Balance Sheets.

ProLiance Holdings, LLC (ProLiance)

Vectren has an investment in ProLiance, a nonutility affiliate of Vectren and Citizens Energy Group (Citizens). On June 18, 2013, ProLiance exited the natural gas marketing business through the disposition of certain of the net assets of its energy marketing business, ProLiance Energy, LLC (ProLiance Energy). ProLiance Energy provided services to a broad range of municipalities, utilities, industrial operations, schools, and healthcare institutions located throughout the Midwest and Southeast United States.  ProLiance Energy’s customers included, among others, Vectren’s Indiana utilities as well as Citizens’ utilities. 

The Company had no purchases from ProLiance for resale and for injections into storage for the three and nine months ended September 30, 2014, as a result of ProLiance exiting the natural gas marketing business. For the three months ended September 30, 2013, the Company had no purchases, and for the nine months ended September 30, 2013 purchases totaled $200.5 million. The Company did not have any amounts owed to ProLiance for purchases at September 30, 2014 and at December 31, 2013.  Amounts charged by ProLiance for gas supply services were established by supply agreements with each utility. After the exit of the energy marketing business by ProLiance, the Company purchases gas supply from third parties and 83 percent is from a single third party for the three and nine month periods ended September 30, 2014.

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

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months ended September 30, 2014 and 2013, Utility Holdings received corporate allocations totaling $13.0 million and $10.4 million, respectively. For the nine months ending September 30, 2014 and 2013, Utility Holdings received corporate allocations totaling $41.7 million and $36.7 million, respectively.

The Company does not have share-based compensation plans and pension and other postretirement plans separate from Vectren and allocated costs include participation in Vectren's plans.  The allocation methodology for retirement costs is consistent with FASB guidance related to “multiemployer” benefit accounting.

7.    Financing Activities

SIGECO Debt Refund and Issuance

On September 24, 2014, SIGECO issued two new series of tax-exempt debt totaling $63.6 million.  Proceeds from the issuance were used to retire three series of tax-exempt bonds aggregating $63.6 million at a redemption price of par plus accrued interest.  The principal terms of the two new series of tax-exempt debt are:  (i) $22.3 million sold in a public offering and bear interest at 4.00 percent per annum, due September 1, 2044 and (ii) $41.3 million, due July 1, 2025, sold in a private placement at variable rates through September 2019.

Short-term Credit Facilities

On October 31, 2014, Utility Holdings’ short-term credit facility, which totals $350 million in borrowing capacity, was amended to extend its maturity until October 31, 2019.

8. Commitments & Contingencies

Commitments

The Company has both firm and non-firm commitments to purchase natural gas, electricity, and coal as well as certain transportation and storage rights and certain contracts are firm commitments under five and ten year arrangements. Costs arising from these commitments, while significant, are pass-through costs, generally collected dollar-for-dollar from retail customers through regulator-approved cost recovery mechanisms.

Legal & Regulatory Proceedings

The Company is party to various legal proceedings, audits, and reviews by taxing authorities and other government agencies arising in the normal course of business.  In the opinion of management, there are no legal proceedings or other regulatory reviews or audits pending against the Company that are likely to have a material adverse effect on its financial position, results of operations or cash flows.

9. Rate & Regulatory Matters

Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement

The Company monitors and maintains its natural gas distribution system to ensure that natural gas is delivered in a safe and efficient manner. The Company's natural gas utilities are currently engaged in replacement programs in both Indiana and Ohio to mitigate risk, improve the system, and comply with applicable regulations. Laws in both Indiana and Ohio were passed that provide utilities the opportunity to timely recover costs of federally mandated projects and other infrastructure improvement projects outside of a base rate proceeding.

Ohio Recovery and Deferral Mechanisms

The PUCO Order approving the Company's 2009 base rate case in the Ohio service territory authorized a distribution replacement rider (DRR). The DRR's primary purpose is recovery of investments in utility plant and related operating expenses associated with replacing bare steel and cast iron pipelines and certain other infrastructure. This rider is updated annually for qualifying capital expenditures and allows for a return to be earned on those capital expenditures based on the rate of return approved in the 2009 base rate case. In addition, deferral of depreciation and the ability to accrue debt-related post in service carrying costs is also allowed until the related capital expenditures are included in the DRR. The Order also initially established a prospective bill impact evaluation on the annual deferrals. To date, the Company has made capital investments under this rider totaling $132.9 million. Regulatory assets associated with post in service carrying costs and depreciation deferrals were $12.1 million and $9.3 million at

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September 30, 2014 and December 31, 2013, respectively. Due to the expiration of the initial five year term for the DRR in early 2014, the Company filed a request in August 2013 to extend and expand the DRR. On February 19, 2014, the PUCO approved a Stipulation entered into by the PUCO Staff and the Company which provided for the extension of the DRR for the recovery of costs incurred through 2017 and expanded the types of investment covered by the DRR to include recovery of other infrastructure investments. The Order also approved an adjustment to the bill impact evaluation, limiting the resulting DRR rate per month for residential and small general service customers to specific graduated levels over the next five years. The Company's five year capital expenditure plan related to these infrastructure investments for calendar years 2013 through 2017 totals approximately $200 million, subject to the DRR rate caps approved in the Order. In addition, the Order approved the Company's commitment that the DRR can only be further extended as part of a base rate case. On May 1, 2014, the Company filed its annual request to adjust the DRR for recovery of costs incurred through December 31, 2013. On August 27, 2014 the PUCO issued an Order approving the Company’s revised DRR rate, effective September 1, 2014.

In June 2011, Ohio House Bill 95 was signed into law. Outside of a base rate proceeding, this legislation permits a natural gas company to apply for recovery of much of its capital expenditure program. The legislation also allows for the deferral of costs, such as depreciation, property taxes, and debt-related post in service carrying costs. On December 12, 2012, the PUCO issued an Order approving the Company's initial deferral application under this law, reflecting its capital expenditure program covering the fifteen month period ending December 31, 2012. Such capital expenditures include infrastructure expansion and improvements not covered by the DRR as well as expenditures necessary to comply with PUCO rules, regulations, orders, and system expansion to some new customers. The Order also established a prospective bill impact evaluation on the cumulative deferrals, limiting the total deferrals at a level which would equal $1.50 per residential and small general service customer per month. In addition, the Order approved the Company's proposal that subsequent requests for accounting authority will be filed annually in April. The Company submitted its most recent annual filing on April 30, 2014, which covers the Company’s capital expenditure program through calendar year 2014.

Given the extension of the DRR through 2017 as discussed above and the continued ability to defer other capital expenses under House Bill 95, it is anticipated that the Company will file a general rate case for the inclusion in rate base of the above costs near the expiration of the DRR. As such, the bill impact limits discussed above are not expected to be reached given the Company's capital expenditure plan during the remaining four year time frame.

Indiana Recovery and Deferral Mechanisms

The Company's Indiana natural gas utilities received Orders in 2008 and 2007 associated with the most recent base rate cases. These Orders authorized the deferral of financial impacts associated with bare steel and cast iron replacement activities. The Orders provide for the deferral of depreciation and post in service carrying costs on qualifying projects totaling $20 million annually at Indiana Gas and $3 million annually at SIGECO. The debt-related post in service carrying costs are recognized in the Condensed Consolidated Statements of Income currently. The recording of post in service carrying costs and depreciation deferral is limited by individual qualifying project to three years after being placed into service at SIGECO and four years after being placed into service at Indiana Gas. At September 30, 2014 and December 31, 2013, the Company has regulatory assets totaling $15.3 million and $12.1 million, respectively, associated with the deferral of depreciation and debt-related post in service carrying cost activities.

In April 2011, Senate Bill 251 was signed into Indiana law. The law provides a framework to recover 80 percent of federally mandated costs through a periodic rate adjustment mechanism outside of a general rate case. Such costs include a return on the federally mandated capital investment, along with recovery of depreciation and other operating costs associated with these mandates. The remaining 20 percent of those costs are to be deferred for future recovery in the utility's next general rate case.

In April 2013, Senate Bill 560 was signed into law.  This legislation supplements Senate Bill 251 described above, which addressed federally mandated investment, and provides for cost recovery outside of a base rate proceeding for projects that either improve electric and gas system reliability and safety or are economic development projects that provide rural areas with access to gas service.  Provisions of the legislation require that, among other things, requests for recovery include a seven year project plan.  Once the plan is approved by the IURC, 80 percent of such costs are eligible for current recovery using a periodic rate adjustment mechanism.  Recoverable costs include a return on and of the investment, as well as property taxes and operating expenses.  The remaining 20 percent of project costs are to be deferred and recovered in the Company'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.

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Pipeline Safety Law

On January 3, 2012, the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 (Pipeline Safety Law) was signed into law. The Pipeline Safety Law, which reauthorizes federal pipeline safety programs through fiscal year 2015, provides for enhanced safety, reliability, and environmental protection in the transportation of energy products by pipeline. The law increases federal enforcement authority; grants the federal government expanded authority over pipeline safety; provides for new safety regulations and standards; and authorizes or requires the completion of several pipeline safety-related studies. The DOT is required to promulgate a number of new regulatory requirements over the next two years. Those regulations may eventually lead to further regulatory or statutory requirements.

While the Company continues to study the impact of the Pipeline Safety Law and potential new regulations associated with its implementation, it is expected that the law will result in further investment in pipeline inspections, and where necessary, additional investments in pipeline infrastructure and, therefore, result in both increased levels of operating expenses and capital expenditures associated with the Company's natural gas distribution businesses.

Requests for Recovery Under Indiana Regulatory Mechanisms

The Company filed in November 2013 for authority to recover costs related to its gas infrastructure replacement and improvement programs in Indiana, including costs associated with existing pipeline safety regulations, using the mechanisms allowed under Senate Bill 251 and Senate Bill 560. On August 27, 2014, the Commission issued an Order approving the Company’s seven year capital infrastructure replacement and improvement plan, beginning in 2014, and the proposed accounting authority and recovery, pursuant to the legislation. As provided in the two laws, the Order approved semi-annual filings for rate recovery of 100 percent of the costs, inclusive of return, related to these capital investments and operating expenses associated with pipeline safety rules, with 80 percent of the costs recovered currently via an approved tracking mechanism and 20 percent of the costs deferred and recovered in the Company’s next base rate proceeding. In addition, the Order established guidelines for the Company to update its seven year capital investment plan annually, with detailed estimates provided for the upcoming calendar year. Finally, the Order approved the Company’s proposal to recover eligible costs via a fixed monthly rate per residential customer. On September 26, 2014, the Indiana Office of Utility Consumer Counselor (OUCC) filed a Notice of Appeal with the Indiana Court of Appeals in response to the IURC's Order. The specific issues raised by the OUCC have not yet been identified. An appeal was filed in response to the IURC's Order in Northern Indiana Public Service Company's (NIPSCO) Senate Bill 560 electric infrastructure proceeding, pertaining to certain issues regarding the Commission's authority to approve NIPSCO's infrastructure plan. The outcome of the NIPSCO appeal and its implications to the Company’s Order, if any, cannot be determined.

On October 1, 2014, the Company filed its initial request for approval of the revenue requirement associated with capital investment through June 30, 2014 as part of its approved infrastructure improvement plan. As the next step of the recovery process as outlined in the legislation, this filing, once approved, will initiate the rates necessary to begin cash recovery of 80 percent of the revenue requirement, with the remaining 20 percent deferred for recovery in the Company's next rate cases. Also in this filing, consistent with the guidelines set forth in the Order, the Company submitted an update to its seven year plan, to reflect changes to project prioritization as a result of both additional risk modeling and cost increases. The updated plan reflects capital expenditures of approximately $900 million, inclusive of an estimated $30 million of economic development related expenditures, over the seven year period beginning in 2014. The plan also includes approximately $15 million of annual operating costs associated with pipeline safety rules. Pursuant to Senate Bill 560, the Company expects an order by the end of 2014.

Indiana Gas GCA Cost Recovery Issue

On July 1, 2014, Indiana Gas filed its recurring quarterly Gas Cost Adjustment (GCA) mechanism, which included recovery of gas cost variances incurred for the period January through March 2014.  In August 2014, the Indiana Office of Utility Consumer Counselor (OUCC) filed testimony opposing the recovery of approximately $3.9 million of natural gas commodity purchases incurred during this period on the basis that a gas cost incentive calculation had not been properly performed. The calculation at issue is performed by the Company's supply administrator. In the winter period at issue, a pipeline force majeure event caused the gas to be priced at a location that was impacted by the extreme winter temperatures. After further review, the OUCC has modified its position in testimony filed on November 5, 2014, and now supports a reduced disallowance of $3.0 million. The Company believes that the costs are either recoverable in its GCA, or that if the incentive mechanism calculation is found to

16

create a cost disallowance, any such loss would be allocated to its supply administrator. An order is expected in November 2014.

SIGECO Electric Environmental Compliance Filing

On January 17, 2014, SIGECO filed a request with the IURC for approval of capital investments estimated to be between $70 and $90 million on its coal-fired generation units to comply with new EPA mandates related to mercury and air toxin standards effective in 2015 and to address an outstanding Notice of Violation (NOV) from the EPA. Roughly half of the investment will be made to control mercury in both air and water emissions. The remaining investment will be made to address the NOV on alleged increases in sulfur trioxide emissions. Although the Company believes these investments are recoverable as clean coal technology under Senate Bill 29 and federal mandated investments under Senate Bill 251, the Company has requested deferred accounting treatment in lieu of timely recovery to avoid immediate customer bill impacts. The accounting treatment request seeks deferral of depreciation and property tax expense related to these investments, accrual of post in service carrying costs, and deferral of incremental operating expenses related to compliance with these standards. The Company filed its case-in-chief on March 14, 2014. Intervening parties filed their testimony on May 28, 2014, to which the Company responded with rebuttal testimony on June 20, 2014. A hearing was held beginning on July 30, 2014. The case has been fully briefed as of October 2, 2014, and the Company is awaiting a Commission order.

Coal Procurement Procedures

SIGECO annually submits its coal procurement plan for IURC review in a sub docket proceeding.  Entering 2014,  SIGECO had in place staggered term coal contracts with Vectren Fuels and one other supplier to provide supply for its generating units.  During 2014, SIGECO entered into separate negotiations with Vectren Fuels and Sunrise Coal to modify its existing contracts as well as enter into new long-term contracts in order to secure supply of coal with specifications that support its compliance with the Mercury and Air Toxins Rule. Subsequent to the sale of Vectren Fuels to an affiliate of Sunrise Coal, all such contracts have been assigned to Sunrise Coal. Those contracts were submitted to the IURC for review as part of the 2014 annual sub docket proceeding.  The OUCC filed testimony in September 2014 in support of the reasonableness of these contracts. A hearing was held in October 2014 and the Company is awaiting an order from the Commission.  

On December 5, 2011 within the quarterly FAC filing, SIGECO submitted a joint proposal with the OUCC to reduce its fuel costs billed to customers by accelerating into 2012 the impact of lower cost coal under new term contracts effective after 2012. The cost difference was deferred to a regulatory asset and is being recovered over a six year period without interest beginning in 2014.  The IURC approved this proposal on January 25, 2012, with the reduction to customer’s rates effective February 1, 2012.  The total balance deferred for recovery through the Company’s FAC, starting February 2014, was $42.4 million, of which $37.1 million remains as of September 30, 2014.

SIGECO Electric Demand Side Management Program Filing

On August 16, 2010, SIGECO filed a petition with the IURC, seeking approval of its proposed electric Demand Side Management (DSM) Programs, recovery of the costs associated with these programs, recovery of lost margins as a result of implementing these programs for large customers, and recovery of performance incentives linked with specific measurement criteria on all programs.  The DSM Programs proposed were consistent with a December 9, 2009 Order issued by the IURC, which, among other actions, defined long-term conservation objectives and goals of DSM programs for all Indiana electric utilities under a consistent statewide approach.  In order to meet these objectives, the IURC Order divided the DSM programs into Core and Core Plus programs.  Core programs are joint programs required to be offered by all Indiana electric utilities to all customers, and include some for large industrial customers.  Core Plus programs are those programs not required specifically by the IURC, but defined by each utility to meet the overall energy savings targets defined by the IURC.

On August 31, 2011 the IURC issued an Order approving an initial three year DSM plan in the SIGECO electric service territory that complied with the IURC’s energy saving targets.  Consistent with the Company’s proposal, the Order approved, among other items, the following: 1) recovery of costs associated with implementing the DSM Plan; 2) the recovery of a performance incentive mechanism based on measured savings related to certain DSM programs; 3) lost margin recovery associated with the implementation of DSM programs for large customers; and 4) deferral of lost margin up to $3 million in 2012 and $1 million in 2011 associated with small customer DSM programs for subsequent recovery under a tracking mechanism to be proposed by the Company.  On June 20, 2012, the IURC issued an Order approving a small customer lost margin recovery mechanism, inclusive of all previous deferrals. This mechanism is an alternative to the electric decoupling proposal that was denied by the IURC in the

17

Company's last base rate proceeding.  For the nine months endedSeptember 30, 2014 and September 30, 2013, the Company recognized Electric revenue of $6.6 million and $3.5 million, respectively, associated with this approved lost margin recovery mechanism.

On March 28, 2014, Senate Bill 340 was signed into law. This legislation ends electric DSM programs on December 31, 2014 that have been conducted to meet the energy savings requirements established in the Commission's December 2009 Order. The legislation also allows for industrial customers to opt out of participating in energy efficiency programs. As of July 1, 2014, approximately 71 percent of the Company’s eligible industrial load has opted out of participation in the applicable energy efficiency programs. Indiana's governor has requested that the Commission make new recommendations for energy efficiency programs to be proposed for 2015 and beyond, and has also asked the legislature to consider further legislation requiring some level of utility sponsored energy efficiency programs. The Company filed a request for Commission approval of a new portfolio of DSM programs on May 29, 2014 to be offered in 2015. On October 15, 2014, the Commission issued an Order approving a Settlement between the OUCC and the Company regarding the new portfolio of DSM programs effective January 2015.

Indiana Gas Pipeline Safety Investigation

On April 11, 2012, the IURC's pipeline safety division filed a complaint against Indiana Gas alleging several violations of safety regulations pertaining to damage that occurred at a residence in Indiana Gas's service territory during a pipeline replacement project. The Company negotiated a settlement with the IURC's pipeline safety division, agreeing to a fine and several modifications to the Company's operating policies. The amount of the fine was not material to the Company's financial results. The IURC approved the settlement but modified certain terms of the settlement and added a requirement that Company employees conduct inspections of pipeline excavations. The Company sought and was granted a request for rehearing on the sole issue related to the requirement to use Company employees to inspect excavations. A settlement in the case was reached between the IURC's pipeline safety division and Indiana Gas that allowed Indiana Gas to continue to use its risk based approach to inspecting excavations and to allow the Company to continue using a mix of highly trained and qualified contractors and employees to perform inspections. On January 15, 2014, the IURC issued a Final Order in the case approving the settlement agreement, without modification.

Indiana Gas & SIGECO Gas Decoupling Extension Filing

On August 18, 2011, the IURC issued an Order granting the extension of the current decoupling mechanism in place at both gas companies and recovery of new conservation program costs through December 2015. The Order provides that the companies must submit an extension proposal no later than March 1, 2015.

FERC Return on Equity Complaint

On November 12, 2013, certain parties representing a group of industrial customers filed a joint complaint with the FERC under Section 206 of the Federal Power Act against MISO and various MISO transmission owners, including SIGECO. The joint parties seek to reduce the 12.38 percent return on equity used in the MISO transmission owners’ rates, including SIGECO’s formula transmission rates, to 9.15 percent, and to set a capital structure in which the equity component does not exceed 50 percent. The MISO transmission owners filed their response to the complaint on January 6, 2014, opposing any change to the return. As of September 30, 2014, the Company had invested approximately $157.7 million in qualifying projects. The net plant balance for these projects totaled $144.5 million at September 30, 2014.

This joint complaint is similar to a complaint against the New England Transmission Owners (NETO) filed in September 2011, which requested that the 11.14 percent incentive return granted on qualifying investments in NETO be lowered. On October 16, 2014, the FERC issued an Order in the NETO case approving the 10.57 percent return on equity and the methodology set out in its June 19, 2014 decision.

In addition to the NETO ruling, the FERC acknowledged that the pending complaint raised against the MISO transmission owners is reasonable, and ordered the initiation of a formal settlement discussion, mediated by a FERC appointed judge, in November 2014. If a settlement is not reached, the case will move to a formal evidentiary hearing before the FERC. The Company has established a reserve pending the outcome of this complaint.

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10. Legislative & Environmental Matters

Indiana Senate Bill 1

In March 2014, Indiana Senate Bill 1 was signed into law.  This legislation phases in a 1.6 percent rate reduction to the Indiana Adjusted Gross Income Tax Rate for corporations over a six year period. Pursuant to this legislation, the tax rate will be lowered by 0.25 percent each year for the first five years and 0.35 percent in year six beginning on July 1, 2016 to the final rate of 4.9 percent effective July 1, 2021. Pursuant to FASB guidance, the Company accounted for the effect of the change in tax law on its deferred taxes in the first quarter of 2014, the period of enactment. The impact was not material to results of operations.

Indiana Senate Bill 251

Indiana Senate Bill 251 is also applicable to federal environmental mandates impacting Vectren South's electric operations. The Company continues with its ongoing evaluation of the impact Senate Bill 251 may have on its operations, including applicability of the stricter regulations the EPA is currently considering involving air quality, fly ash disposal, cooling tower intake facilities, waste water discharges, and greenhouse gases. These issues are further discussed below.

Air Quality

Clean Air Interstate Rule / Cross-State Air Pollution Rule

In July 2011, the EPA finalized the Cross-State Air Pollution Rule (CSAPR).  CSAPR was the EPA’s response to the US Court of Appeals for the District of Columbia’s (the Court) remand of the Clean Air Interstate Rule (CAIR). CAIR was originally established in 2005 as an allowance cap and trade program that required reductions from coal-burning power plants for NOX emissions beginning January 1, 2009 and SO2 emissions beginning January 1, 2010, with a second phase of reductions in 2015. In an effort to address the Court’s finding that CAIR did not adequately ensure attainment of pollutants in certain downwind states due to unlimited trading of SO2and NOX allowances, CSAPR reduced the ability of facilities to meet emission reduction targets through allowance trading.  CSAPR reductions were to be achieved with initial step reductions beginning January 1, 2012, and final compliance to be achieved in 2014.  On December 30, 2011, a reviewing court granted a stay of CSAPR and left CAIR in place pending its review. On August 21, 2012, the court vacated CSAPR and directed the EPA to continue to administer CAIR. In April 2014, the US Supreme Court upheld CSAPR. On June 26, 2014, the EPA asked the federal appeals court to lift the stay of the rule. The EPA also asked the court to approve a new deadline schedule for entities that must comply, with the first phase caps starting in 2015 and 2016, and the second phase in 2017. On October 23, 2014 the Court granted the EPA’s request to lift the CSAPR stay, but did not finalize the new implementation dates. While it is possible that the EPA could further revise the rule prior to implementation, the Company does not anticipate a significant impact from the Supreme Court's decision based upon the investments it has already made in pollution control technology to meet the requirements of CAIR. The Company remains in full compliance with CAIR (see additional information below "Conclusions Regarding Air and Water Regulations").

Mercury and Air Toxics (MATS) Rule

On December 21, 2011, the EPA finalized the utility MATS Rule.  The MATS Rule sets emission limits for hazardous air pollutants for existing and new coal-fired power plants and identifies the following broad categories of hazardous air pollutants:  mercury, non-mercury hazardous air pollutants (primarily arsenic, chromium, cobalt, and selenium), and acid gases (hydrogen cyanide, hydrogen chloride, and hydrogen fluoride).  The rule imposes mercury emission limits for two sub-categories of coal, and proposed surrogate limits for non-mercury and acid gas hazardous air pollutants. The EPA did not grant blanket compliance extensions, but asserted that states have broad authority to grant one year extensions for individual electric generating units where potential reliability impacts have been demonstrated.  Reductions are to be achieved within three years of publication of the final rule in the Federal register (April 2015).  Multiple judicial challenges were filed, and the EPA agreed to reconsider MATS requirements for new construction, as the requirements are more stringent than those for existing plants. Utilities planning new coal-fired generation had argued standards outlined in the MATS could not be attained even using the best available control technology. The EPA issued its revised emission limits for new construction in March 2013. In April 2014, the U.S. Court of Appeals for the D.C. Circuit rejected various challenges to the rule for existing sources that were brought by industry and state petitioners. In July a coalition of twenty-one states, including Indiana, filed a petition for certiorari with the U.S. Supreme Court seeking review of the decision of the appellate court. The Company continues to proceed with its MATS compliance strategy. This plan is currently before the IURC for approval, and the Company anticipates full compliance by the applicable deadlines.

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Notice of Violation for A.B. Brown Power Plant

The Company received a notice of violation (NOV) from the EPA in November 2011 pertaining to its A.B. Brown power plant.  The NOV asserts that when the power plant was equipped with Selective Catalytic Reduction (SCR) systems, the correct permits were not obtained or the best available control technology to control incidental sulfuric acid mist was not installed. The Company reached a settlement in principle with the EPA to resolve the NOV. That settlement was contemplated in the plan filed with the IURC in the SIGECO Electric Environmental Compliance Filing.

Information Request

SIGECO and Alcoa Generating Corporation (AGC), a subsidiary of ALCOA, own a 300 MW Unit 4 at the Warrick Power Plant as tenants in common.  AGC and SIGECO also share equally in the cost of operation and output of the unit.  In January 2013, AGC received an information request from the EPA under Section 114 of the Clean Air Act for historical operational information on the Warrick Power Plant. In April 2013, ALCOA filed a timely response to the information request.

Water

Section 316(b) of the Clean Water Act requires that generating facilities use the “best technology available” (BTA) to minimize adverse environmental impacts in a body of water.  More specifically, Section 316(b) is concerned with impingement and entrainment of aquatic species in once-through cooling water intake structures used at electric generating facilities.  In April 2009, the U.S. Supreme Court affirmed that the EPA could, but was not required to, consider costs and benefits in making the evaluation as to the best technology available for existing generating facilities.  The regulation was remanded to the EPA for further consideration.  In March 2011, the EPA released its proposed Section 316(b) regulations.  The EPA did not mandate the retrofitting of cooling towers in the proposed regulation, but if finalized, the regulation will leave it to each state to determine whether cooling towers should be required on a case by case basis.  A final rule was issued on May 19, 2014. The final rule does not mandate cooling water tower retrofits but requires a case by case assessment of BTA for each facility. The final rule lists seven presumptive technologies which would qualify as BTA. These technologies range from intake screen modifications to cooling water tower retrofits. Ecological and technology assessment studies must be completed prior to determining BTA for the Company’s facilities. The Company believes that capital investments will likely be in the range of $4 million to $8 million.  Costs for compliance with these final regulations should qualify as federally mandated regulatory requirements and be recoverable under Indiana Senate Bill 251 referenced above.

Under the Clean Water Act, the EPA sets technology-based guidelines for water discharges from new and existing facilities. The EPA is currently in the process of revising the existing steam electric effluent limitation guidelines that set the technology-based water discharge limits for the electric power industry. The EPA is focusing its rulemaking on wastewater generated primarily by pollution control equipment necessitated by the comprehensive air regulations. The EPA released proposed rules on April 19, 2013 and the Company is reviewing the proposal. At this time, it is not possible to estimate what potential costs may be required to meet these new water discharge limits, however costs for compliance with these regulations should qualify as federally mandated regulatory requirements and be recoverable under Senate Bill 251 referenced above.

Conclusions Regarding Air and Water Regulations

To comply with Indiana’s implementation plan of the Clean Air Act, and other federal air quality standards, the Company obtained authority from the IURC to invest in clean coal technology.  Using this authorization, the Company invested approximately $411 million starting in 2001 with the last equipment being placed into service on January 1, 2010.  The pollution control equipment included SCR systems, fabric filters, and an SO2 scrubber at its generating facility that is jointly owned with AGC.  SCR technology is the most effective method of reducing NOX emissions where high removal efficiencies are required and fabric filters control particulate matter emissions.  The unamortized portion of the $411 million clean coal technology investment was included in rate base for purposes of determining SIGECO’s electric base rates approved in the latest base rate order obtained April 27, 2011.  SIGECO’s coal-fired generating fleet is 100 percent scrubbed for SO2 and 90 percent controlled for NOX.  

Utilization of the Company’s NOX and SO2 allowances can be impacted as regulations are revised and implemented.  Most of these allowances were granted to the Company at zero cost; therefore, any reduction in carrying value that could result from future changes in regulations would be immaterial.

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The Company continues to review the sufficiency of its existing pollution control equipment in relation to the requirements described in the MATS Rule, the recent renewal of water discharge permits, and the NOV discussed above.  Some operational modifications to the control equipment are likely. The Company is continuing to evaluate potential technologies to address compliance and what the additional costs may be associated with these efforts. Currently, it is expected that the capital costs could be between $70 million and $90 million. Compliance is required by government regulation, and the Company believes that such additional costs, if incurred, should be recoverable under Senate Bill 251 referenced above. On January 17, 2014, the Company filed its request with the IURC seeking approval to upgrade its existing emissions control equipment to comply with the MATS Rule, take steps to address the EPA's allegations in the NOV and comply with new mercury limits to the waste water discharge permits at the Culley and Brown generating stations. In that filing, the Company has proposed to defer recovery of the costs until 2020 in order to mitigate the impact on customer rates in the near term. In July a hearing was held before the IURC in this matter. The case has been fully briefed as of October 2, 2014, and the Company is awaiting a Commission order.

Coal Ash Waste Disposal & Ash Ponds

In June 2010, the EPA issued proposed regulations affecting the management and disposal of coal combustion products, such as ash generated by the Company’s coal-fired power plants.  The proposed rules more stringently regulate these byproducts and would likely increase the cost of operating or expanding existing ash ponds and the development of new ash ponds.  The alternatives include regulating coal combustion by-products that are not being beneficially reused as hazardous waste.  The EPA did not offer a preferred alternative, but took public comment on multiple alternative regulations.  Rules have not been finalized given oversight hearings, congressional interest, and other factors. Recently the EPA entered into a consent decree in which it agreed to finalize by December 2014 its determination whether to regulate ash as hazardous waste, or the less stringent solid waste designation.

At this time, the majority of the Company’s ash is being beneficially reused.  However, the alternatives proposed would require modification to, or closure of, existing ash ponds.  The Company estimates capital expenditures to comply could be as much as $30 million, and such expenditures could exceed $100 million if the most stringent of the alternatives is selected.  Annual compliance costs could increase only slightly or be impacted by as much as $5 million.  Costs for compliance with these regulations should qualify as federally mandated regulatory requirements and be recoverable under Senate Bill 251 referenced above. 

Climate Change

In April 2007, the US Supreme Court determined that greenhouse gases (GHG's) meet the definition of "air pollutant" under the Clean Air Act and ordered the EPA to determine whether GHG emissions cause or contribute to air pollution that may reasonably be anticipated to endanger public health or welfare. The endangerment finding was finalized in December 2009, concluding that carbon emissions pose an endangerment to public health and the environment.

The EPA has finalized two sets of GHG regulations that apply to the Company’s generating facilities.  In 2009, the EPA finalized a mandatory GHG emissions registry which requires the reporting of emissions.  The EPA has also finalized a revision to the Prevention of Significant Deterioration (PSD) and Title V permitting rules which would require facilities that emit 75,000 tons or more of GHG's a year to obtain a PSD permit for new construction or a significant modification of an existing facility.  The EPA's PSD and Title V permitting rules for GHG's were upheld by the US Court of Appeals for the District of Columbia, and in June 2014 the US Supreme Court upheld the regulations with respect to applicability to major sources such as coal-fired power plants that are required to hold PSD construction and Title V air operating permits for other criteria pollutants.

While the Company has no plans to invest in new coal fired generation, there is also a rule making and related legal challenge involving new source performance standards for new construction. This rulemaking must be finalized and withstand legal scrutiny in order for the EPA to implement its proposed new source performance standards for existing units discussed below.

In July 2013, the President announced a Climate Action Plan, which calls on the EPA to finalize the rule for new construction expeditiously, and by June 2014 propose, and by June 2015 finalize, New Source Performance Standards (NSPS) for GHG's for existing electric generating units which would apply to the Company's power plants. States must have their implementation plans to the EPA no later than June 2016. On June 2, 2014, the EPA proposed its rule for states to regulate CO2 emissions from existing electric generating units. The rule, when final, will require states to adopt plans that reduce CO2 emissions by 30 percent from 2005 levels by 2030. Unlike most rulemakings which allow for a 30 day public comment period, the EPA provided

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an initial 120 days from publication of the proposal in the Federal Register, and a subsequent extension of the public comment period was granted to December 1, 2014. The proposal sets state-specific CO2 emission rate-based CO2 goals (measured in lb CO2/MWh or “megawatt hour”) and guidelines for the development, submission and implementation of state plans to achieve the state goals. These state-specific goals are calculated based upon 2012 average emission rates aggregated for all fossil fuel-based units in the state. For Indiana, the proposal uses a 2012 emission rate of 1,923 lb CO2/MWh, and sets an interim goal of 1,607 lb CO2/MWh and a final emission goal of 1,531 lb CO2/MWh that must be met by 2030. Under this proposal, these CO2 emission rate goals do not apply directly to individual units, or generating systems. They are state goals. As such, the state must establish a framework that will guide how compliance will be met on a statewide basis. The state’s interim or “phase in” goal of 1,607 lb CO2/MWh must be met as averaged over a ten year period (2020 - 2029) with progress toward this goal to be demonstrated for every two rolling calendar years starting in 2020, with the first report due in 2022.

Under the proposal all states have unique goals based upon each state’s mix of electric generating assets. The EPA is proposing a 20 percent reduction in Indiana’s total CO2 emission rate compared to 2012. At 20 percent Indiana’s CO2 emission rate reduction requirement is tied with West Virginia as the 9^th lowest reduction requirement in US. This is due in part to the EPA’s attempt to recognize the existing generating resource mix in the state and take into account each state’s ability to cost effectively lower its CO2 emission rate through a portfolio approach including energy efficiency and renewables, improving power plant heat rates, and dispatching lower emitting fuel sources. Each state’s goals were set by taking 2012 emissions data and applying four “building blocks” of emission rate improvements that the EPA asserts can be achieved by that state. These four building blocks constitute the EPA’s determination of “Best System of Emission Reductions that has been adequately demonstrated,” which defines the EPA’s authority under § 111(d) for existing sources. When applied to each state, the portfolio approach leads to significant differences in requirements across state lines. With the exception of building block number 1 (heat rate improvement of 6 percent), other building blocks are tailored to individual states based upon each state’s existing generating mix and what the EPA concluded a state could reasonably accomplish to reduce its CO2 emission rate. Despite having just been recently proposed and not expected to be finalized until June of 2015, legal challenges to the EPA's proposal have begun. On July 31, 2014, litigation was filed by the state of Indiana and other parties challenging the rules which may delay the timing of approval of the various state plans.

With respect to the state of Indiana, the four building blocks that support Indiana’s goal are as follows:

(1) Heat rate (HR) improvements of 6 percent (this is consistently applied to all states).

(2) Increasing the dispatch of existing natural gas baseload generation sources to 70 percent.

(3) Renewable energy portfolio requirements of 5 percent (interim) and 7 percent (final).

(4) Energy efficiency / DSM that results in reductions of 1.5 percent annually starting in 2020, ending at a sustained 11 percent by 2030.

Under the proposal, Indiana may choose to implement a program based upon an annual average emission rate target or convert that target rate to a comparable CO2 emission cap. Indiana is the 5^th largest carbon emitter in the nation in tons of CO2 produced from electric generation. In 2013, Indiana’s electric utilities generated 105.6 million tons of CO2. The Company’s share of that total was 6.3 million, or <6 percent. Since 2005, the Company’s emissions of CO2 have declined 23 percent (on a tonnage basis). These reductions have come from the retirement of FB Culley Unit 1, expiration of municipal contracts, electric conservation and the addition of renewable generation and the installation of more efficient dense pack turbine technology. With respect to CO2 emission rate, since 2005 the Company has lowered its CO2 emission rate (as measured in lbs CO2/MWh) from 1967 lbs CO2/MWh to 1922 lbs CO2/MWh, for a reduction of 3 percent. the Company’s CO2 emission rate of 1922 lbs/MWh is basically the same as the State’s average CO2 emission rate of 1923 lb CO2/MWh.

Impact of Legislative Actions & Other Initiatives is Unknown

If the regulations referenced above are finalized by the EPA, or if legislation requiring reductions in CO2 and other GHG's or legislation mandating a renewable energy portfolio standard is adopted, such regulation could substantially affect both the costs and operating characteristics of the Company’s fossil fuel generating plants and natural gas distribution businesses.  At this time and in the absence of final legislation or rulemaking, compliance costs and other effects associated with reductions in GHG emissions or obtaining renewable energy sources remain uncertain.  The Company has gathered preliminary estimates of the costs to control GHG emissions.  A preliminary investigation demonstrated costs to comply would be significant, first with regard to operating expenses and later for capital expenditures as technology becomes available to control GHG emissions.  However,

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these compliance cost estimates were based on highly uncertain assumptions, including allowance prices if a cap and trade approach were employed, and energy efficiency targets.  As the EPA moves toward finalization of the NSPS for existing sources and the State of Indiana begins formulation of its state implementation plan, the Company will have more information to enable it to better assess potential compliance costs with a final regulation. Costs to purchase allowances that cap GHG emissions or expenditures made to control emissions or lower carbon emission rates should be considered a federally mandated cost of providing electricity, and as such, the Company believes such costs and expenditures should be recoverable from customers through Senate Bill 251 as referenced above or Senate Bill 29, which was used by the Company to recover its initial pollution control investments.

Renewables

Senate Bill 251 also established a voluntary clean energy portfolio standard that provides incentives to Indiana electricity suppliers participating in the program. The goal of the program is that by 2025, at least 10 percent of the total electricity obtained by the supplier to meet the energy needs of Indiana retail customers will be provided by clean energy sources, as defined. In advance of a federal portfolio standard and Senate Bill 251, SIGECO received regulatory approval to purchase a 3 MW landfill gas generation facility from a related entity. The facility was purchased in 2009 and is directly connected to the Company's distribution system. In 2008 and 2009, the Company executed long-term purchase power commitments for a total of 80 MW of wind energy. The Company currently has approximately 4 percent of its electricity being provided by clean energy sources due to the long-term wind contracts and landfill gas investment.

Manufactured Gas Plants

In the past, the Company operated facilities to manufacture natural gas.  Given the availability of natural gas transported by pipelines, these facilities have not been operated for many years.  Under current environmental laws and regulations, those that owned or operated these facilities may now be required to take remedial action if certain contaminants are found above the regulatory thresholds.

In the Indiana Gas service territory, the existence, location, and certain general characteristics of 26 gas manufacturing and storage sites have been identified for which the Company may have some remedial responsibility.  A remedial investigation/feasibility study (RI/FS) was completed at one of the sites under an agreed order between Indiana Gas and the IDEM, and a Record of Decision was issued by the IDEM in January 2000.  The remaining sites have been submitted to the IDEM's Voluntary Remediation Program (VRP).  The Company has identified its involvement in five manufactured gas plant sites in SIGECO’s service territory, all of which are currently enrolled in the IDEM’s VRP.  The Company is currently conducting some level of remedial activities, including groundwater monitoring at certain sites.

The Company has accrued the estimated costs for further investigation, remediation, groundwater monitoring, and related costs for the sites.  While the total costs that may be incurred in connection with addressing these sites cannot be determined at this time, the Company has recorded cumulative costs that it has incurred or reasonably expects to incur totaling approximately $43.4 million ($23.2 million at Indiana Gas and $20.2 million at SIGECO).  The estimated accrued costs are limited to the Company’s share of the remediation efforts and are therefore net of exposures of other potentially responsible parties (PRP).

With respect to insurance coverage, Indiana Gas has received approximately $20.8 million from all known insurance carriers under insurance policies in effect when these plants were in operation.  Likewise, SIGECO has settlement agreements with all known insurance carriers and has received to date approximately $14.3 million of the expected $15.8 million in insurance recoveries.

The costs the Company expects to incur are estimated by management using assumptions based on actual costs incurred, the timing of expected future payments, and inflation factors, among others.  While the Company’s utilities have recorded all costs which they presently expect to incur in connection with activities at these sites, it is possible that future events may require remedial activities which are not presently foreseen and those costs may not be subject to PRP or insurance recovery.  As of September 30, 2014 and December 31, 2013, approximately $4.3 million and $5.7 million, respectively, of accrued, but not yet spent, costs are included in Other Liabilities related to the Indiana Gas and SIGECO sites.

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11. Fair Value Measurements

The carrying values and estimated fair values using primarily Level 2 assumptions of the Company's other financial instruments follow:

	September 30, 2014				December 31, 2013
(In millions)	Carrying Amount		Est. Fair Value		Carrying Amount		Est. Fair Value
Long-term debt	$	1,257.3	$	1,398.2	$	1,257.1	$	1,317.4
Short-term borrowings	60.1		60.1		28.6		28.6
Cash & cash equivalents	5.4		5.4		8.6		8.6

For the balance sheet dates presented in these financial statements, the Company had no material assets or liabilities recorded at fair value outstanding, and no material assets or liabilities valued using Level 3 inputs.

Certain methods and assumptions must be used to estimate the fair value of financial instruments.  The fair value of the Company's long-term debt was estimated based on the quoted market prices for the same or similar issues or on the current rates offered to the Company for instruments with similar characteristics.  Because of the maturity dates and variable interest rates of short-term borrowings and cash & cash equivalents, those carrying amounts approximate fair value.  Because of the inherent difficulty of estimating interest rate and other market risks, the methods used to estimate fair value may not always be indicative of actual realizable value, and different methodologies could produce different fair value estimates at the reporting date.

Under current regulatory treatment, call premiums on reacquisition of utility-related long-term debt are generally recovered in customer rates over the life of the refunding issue or over a 15-year period.  Accordingly, any reacquisition of this debt would not be expected to have a material effect on the Company's results of operations.

12. Impact of Recently Issued Accounting Principles

Revenue Recognition Guidance

In May 2014, the FASB issued new accounting guidance to clarify the principles for recognizing revenue and to develop a common revenue standard for GAAP and IFRS. The amendments in this guidance state that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This new guidance requires improved disclosures to help users of financial statements better understand the nature, amount, timing, and uncertainty of revenue that is recognized. For a public entity, the guidance is effective for annual reporting periods beginning after December 15, 2016, with early adoption not permitted. An entity should apply the amendments in this update retrospectively to each prior reporting period presented or retrospectively with the cumulative effect of initially applying this update recognized at the date of initial application. The Company is currently evaluating the standard to understand the overall impact it will have on the financial statements.

Financial Reporting of Discontinued Operations

In April 2014, the FASB issued new accounting guidance on reporting discontinued operations and disclosures of disposals of a company or entity. The guidance changes the criteria for reporting discontinued operations and provides for enhanced disclosures in this area. Under the new guidance, only disposals representing a strategic shift in operations should be presented as discontinued operations. Those strategic shifts should have a major effect on the organization's operations and financial results. Additionally, the new guidance requires expanded disclosures about discontinued operations to provide more information about the assets, liabilities, income, and expenses of discontinued operations. The new guidance also requires disclosure of the pre-tax income attributable to a disposal of a significant part of an organization that does not qualify for discontinued operations reporting. This guidance is effective for fiscal years beginning on or after December 15, 2014, with early adoption permitted. The Company is currently evaluating the impact of this guidance, if any.

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Financial Reporting of Going Concern

In August 2014, the FASB issued new accounting guidance with respect to reporting on an entity's ability to continue as a going concern. This new guidance requires management to assess an entity's ability to continue as a going concern by incorporating and expanding upon certain principles that are currently in U.S. auditing standards, which requires disclosure surrounding what constitutes substantial doubt for the entity, including disclosure of management's plans to mitigate and alleviate substantial doubt. This guidance is effective for annual periods beginning after December 15, 2016, and for annual and interim periods thereafter, with early application permitted. Adoption of this guidance will not have a material impact on the Company’s financial statements.

13. Segment Reporting

The Company’s operations consist of regulated operations and other operations that provide information technology and other support services to those regulated operations.  The Company segregates its regulated operations between a Gas Utility Services operating segment and an Electric Utility Services operating segment.  The Gas Utility Services segment provides natural gas distribution and transportation services to nearly two-thirds of Indiana and to west central Ohio.  The Electric Utility Services segment provides electric distribution services primarily to southwestern Indiana, and includes the Company’s power generating and wholesale power operations.  Regulated operations supply natural gas and/or electricity to over one million customers.  In total, the Company is comprised of three operating segments:  Gas Utility Services, Electric Utility Services, and Other Shared Service operations.  Net income is the measure of profitability used by management for all operations.

Information related to the Company’s reportable segments is summarized as follows. 

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(In millions)	2014			2013			2014			2013
Revenues
Gas Utility Services	$	105.1		$	101.9		$	681.1		$	555.8
Electric Utility Services	165.9			165.8			480.9			470.0
Other Operations	9.6			9.5			28.7			28.5
Eliminations	(9.5		)	(9.5		)	(28.5		)	(28.3		)
Total revenues	$	271.1		$	267.7		$	1,162.2		$	1,026.0
Profitability Measure - Net Income
Gas Utility Services	$	(5.1	)	$	(3.8	)	$	33.9		$	37.2
Electric Utility Services	26.7			26.6			65.9			60.1
Other Operations	2.7			2.5			8.7			7.3
Total net income	$	24.3		$	25.3		$	108.5		$	104.6

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ITEM 2.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION

Description of the Business

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), Southern Indiana Gas and Electric Company (SIGECO), and Vectren Energy Delivery of Ohio, Inc. (VEDO).  Utility Holdings also earns a return on shared 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 574,000 natural gas customers located in central and southern Indiana.  SIGECO provides energy delivery services to approximately 143,000 electric customers and approximately 110,000 gas customers located near Evansville in southwestern Indiana.  SIGECO also owns and operates electric generation assets to serve its electric customers and optimizes those assets in the wholesale power market.  Indiana Gas and SIGECO generally do business as Vectren Energy Delivery of Indiana.  VEDO provides energy delivery services to approximately 313,000 natural gas customers located near Dayton in west central Ohio. The Company segregates its regulatory utility operations between a Gas Utility Services operating segment and an Electric Utility Services operating segment.

The following discussion and analysis should be read in conjunction with the unaudited condensed consolidated financial statements and notes thereto as well as the Company’s 2013 annual report filed on Form 10-K.

Executive Summary of Consolidated Results of Operations

In the third quarter of 2014, Utility Holdings' earnings were $24.3 million, compared to $25.3 million in 2013. In the nine months endedSeptember 30, 2014, Utility Holdings earned $108.5 million, compared to $104.6 million in 2013. The quarter over quarter decrease was primarily related to higher operating expenses. The year to date increase is driven by increased gas and electric margins offset by higher operating expenses driven by increased performance-based compensation expense as well as weather-related gas system maintenance resulting from the harsh winter.

Gas Utility Services

In the third quarter of 2014, Gas Utility Services reported a seasonal loss of $5.1 million compared to a loss of $3.8 million in the third quarter of 2013. In the nine months endedSeptember 30, 2014, Gas Utility Services earnings were $33.9 million, compared to earnings of $37.2 million in 2013. Though customer margin increased in both quarter and year to date periods in 2014 from the returns from the Ohio infrastructure replacement programs and from small customer growth in the year to date period, the increase in margin was offset by higher operating expenses driven by weather-related maintenance of the gas system in the year to date period and by increased performance-based compensation expense in both quarter and year to date periods.

Electric Utility Services

In the third quarter of 2014, Electric Utility Services' earnings were $26.7 million, compared to $26.6 million in the third quarter of 2013. Electric Utility Services earned $65.9 million year to date in 2014, compared to earnings of $60.1 million for the nine months endedSeptember 30, 2013. The increase in the year to date period is driven by the impact of weather on retail electric margin, which management estimates the after tax impact to be approximately $1.6 million favorable year to date compared to the 2013 period, as well as wholesale margin, which has a favorable after tax impact of $1.2 million. The increase in the quarter and year to date periods is also driven by the Company's lost revenue recovery mechanism which had an after tax favorable impact of $0.5 million and $1.9 million, respectively, related to electric conservation programs. Additionally, increases in both the quarter and year to date periods reflect increased deferral of interest on construction projects, offset by higher operating expenses due to increased performance-based compensation expense.

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Other Utility Operations

In the third quarter of 2014, earnings from Other Utility operations were $2.7 million, compared to $2.5 million in 2013. In the nine months endedSeptember 30, 2014, earnings from these operations were $8.7 million compared to $7.3 million in 2013. The increase in the nine months ended September 30, 2014 is primarily driven by a decrease in net interest expense compared to 2013.

Results of Operations

Margin

Throughout this discussion, the terms Gas Utility margin and Electric Utility margin are used.  Gas Utility margin is calculated as Gas utility revenues less the Cost of gas sold.  Electric Utility margin is calculated as Electric utility revenues less Cost of fuel & purchased power.  The Company believes Gas Utility and Electric Utility margins are better indicators of relative contribution than revenues since gas prices and fuel and purchased power costs can be volatile and are generally collected on a dollar-for-dollar basis from customers. 

In addition, the Company separately reflects regulatory expense recovery mechanisms within Gas Utility margin and Electric Utility margin.  These amounts represent dollar-for-dollar recovery of operating expenses. The Company utilizes these approved regulatory mechanisms to recover variations in operating expenses from the amounts reflected in base rates and are generally expenses that are subject to volatility.  For example, demand side management and conservation expenses for both the gas and electric utilities; MISO administrative expenses for the Company's electric operations; uncollectible expense associated with the Company's Ohio gas customers; and recoveries of state mandated revenue taxes in both Indiana and Ohio are included in these amounts. Following is a discussion and analysis of margin generated from regulated utility operations.

Gas Utility Margin (Gas utility revenues less Cost of gas sold)

Gas utility margin and throughput by customer type follows:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions)	2014		2013		2014		2013
Gas utility revenues	$	105.1	$	101.9	$	681.1	$	555.8
Cost of gas sold	28.8		27.5		343.4		235.4
Total gas utility margin	$	76.3	$	74.4	$	337.7	$	320.4
Margin attributed to:
Residential & commercial customers	$	57.6	$	56.4	$	248.3	$	243.4
Industrial customers	11.8		12.1		42.7		41.9
Other	2.3		2.2		8.7		7.6
Regulatory expense recovery mechanisms	4.6		3.7		38.0		27.5
Total gas utility margin	$	76.3	$	74.4	$	337.7	$	320.4
Sold & transported volumes in MMDth attributed to:
Residential & commercial customers	6.7		6.5		84.3		73.6
Industrial customers	23.5		24.6		83.2		80.7
Total sold & transported volumes	30.2		31.1		167.5		154.3

Gas Utility margins were $76.3 million and $337.7 million for the threeandnine months endedSeptember 30, 2014, and compared to 2013, increased $1.9 million quarter over quarter and $17.3 million year to date. Year to date, customer margin increased $2.9 million compared to 2013 from small customer growth and large customer usage. Additionally, year to date margin was favorably impacted by $2.4 million from the return from infrastructure replacement programs, particularly in Ohio. With rate designs that substantially limit the impact of weather on margin, heating degree days that were 115 percent of normal in Ohio and 110 percent of normal in Indiana during the nine months endedSeptember 30, 2014, compared to 103 percent of normal in Ohio and 100 percent of normal in Indiana during 2013, had a slight favorable impact on small customer margin.

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Weather was also the primary driver in the higher volumetric pass through margin, which increased $10.5 million year to date compared to the prior year.

Electric Utility Margin (Electric utility revenues less Cost of fuel & purchased power)

Electric utility margin and volumes sold by customer type follows:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions)	2014		2013		2014		2013
Electric utility revenues	$	165.9	$	165.8	$	480.9	$	470.0
Cost of fuel & purchased power	50.3		50.4		155.4		154.5
Total electric utility margin	$	115.6	$	115.4	$	325.5	$	315.5
Margin attributed to:
Residential & commercial customers	$	73.0	$	73.8	$	201.7	$	195.0
Industrial customers	29.7		28.6		83.6		82.5
Other	0.9		1.4		2.9		3.1
Regulatory expense recovery mechanisms	2.7		2.2		9.3		6.7
Subtotal: retail	$	106.3	$	106.0	$	297.5	$	287.3
Wholesale power & transmission system margin	9.3		9.4		28.0		28.2
Total electric utility margin	$	115.6	$	115.4	$	325.5	$	315.5
Electric volumes sold in GWh attributed to:
Residential & commercial customers	759.0		769.6		2,136.5		2,072.1
Industrial customers	749.1		729.7		2,101.6		2,087.0
Other customers	5.3		4.9		16.2		15.5
Total retail volumes sold	1,513.4		1,504.2		4,254.3		4,174.6

Retail

Electric retail utility margins were $106.3 million and $297.5 million for the three and nine months endedSeptember 30, 2014, and, compared to 2013, increased by $0.3 million in the quarter and $10.2 million year to date. Electric results, which are not protected by weather normalizing mechanisms, experienced a $0.9 million decrease in the third quarter 2014 in small customer margin related to weather as cooling degree days were 91 percent of normal compared to 99 percent of normal in 2013. For the year to date period, electric results were positively impacted by weather, resulting in a year to date increase of $2.7 million in small customer margin. Margin from regulatory expense recovery mechanisms increased $2.6 million year to date 2014 compared to 2013, driven primarily by a corresponding increase in operating expenses associated with the electric state-mandated conservation programs and MISO costs. As conservation initiatives continue, in the nine months ended September 30, 2014, the Company's lost revenue recovery mechanism contributed increased margin of $3.1 million related to electric conservation programs.

Margin from Wholesale Electric Activities

The Company earns a return on electric transmission projects constructed by the Company in its service territory that meet the criteria of MISO’s regional transmission expansion plans and also markets and sells its generating and transmission capacity to optimize the return on its owned assets.  Substantially all off-system sales are generated in the MISO Day Ahead and Real Time markets when sales into the MISO in a given hour are greater than amounts purchased for native load.  Further detail of MISO off-system margin and transmission system margin follows:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions)	2014		2013		2014		2013
MISO Transmission system margin	$	8.1	$	8.6	$	20.8	$	23.1
MISO Off-system margin	1.2		0.8		7.2		5.1
Total wholesale margin	$	9.3	$	9.4	$	28.0	$	28.2

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Transmission system margin associated with qualifying projects, including the reconciliation of recovery mechanisms, and other transmission system operations, totaled $20.8 million and $23.1 million during the nine months endedSeptember 30, 2014 and 2013, respectively. During the third quarter of 2014, transmission system margin was $8.1 million compared to $8.6 million for the same period in 2013. As of September 30, 2014, the Company had invested approximately $157.7 million in qualifying projects. The net plant balance for these projects totaled $144.5 million at September 30, 2014. These projects include an interstate 345 Kv transmission line that connects the Company’s A.B. Brown Generating Station to a generating station in Indiana owned by Duke Energy to the north and to a generating station in Kentucky owned by Big Rivers Electric Corporation to the south; a substation; and another transmission line. Although the allowed return is currently being challenged as discussed below in Rate and Regulatory Matters, once placed into service, these projects earn a FERC approved equity rate of return of 12.38 percent on the net plant balance. Operating expenses are also recovered. The Company has established a reserve pending the outcome of this complaint. The 345 Kv project is the largest of these qualifying projects, with a cost of $106.8 million that earned the FERC approved equity rate of return, including while under construction. The last segment of that project was placed into service in December 2012.

For the nine months endedSeptember 30, 2014, margin from off-system sales was $7.2 million, compared to $5.1 million in 2013. In the third quarter of 2014 margin from off system sales was $1.2 million compared to $0.8 million in 2013. The base rate changes implemented in May 2011 require that wholesale margin from off-system sales earned above or below $7.5 million per year be shared equally with customers.  Results for the periods presented reflect the impact of that sharing.

Operating Expenses

Other Operating

During the third quarter of 2014, other operating expenses were $79.9 million, an increase of $5.9 million. Excluding costs that are recovered directly in margin, the increase is primarily related to increased performance-based compensation. For the nine months endedSeptember 30, 2014, other operating expenses were $259.7 million, an increase of $22.8 million, compared to 2013. Costs that are recovered directly in margin account for $9.9 million of the year to date increase. Excluding these pass through costs, other operating expenses increased $12.9 million year to date, compared to the same period in 2013, primarily associated with increased energy delivery expenses of $3.8 million due to the harsh winter weather in the first quarter 2014 and an increase in performance-based compensation expense of $5.2 million.

Depreciation & Amortization

In the third quarter of 2014, depreciation and amortization expense was $51.0 million, compared to $49.7 million in 2013. For the nine months endedSeptember 30, 2014, depreciation and amortization expense was $151.5 million, which represents an increase of $4.7 million compared to 2013. Both year to date and quarter periods reflect increased plant placed into service.

Taxes Other Than Income Taxes

Taxes other than income taxes were $11.7 millionfor the third quarter of 2014, an increase of $0.1 million, compared to 2013. Year to date, taxes other than income taxes were $44.3 million compared to $41.3 million for the year to date period in 2013. The increase of $3.0 million is primarily due to higher revenue taxes associated with increased consumption and higher gas costs. These taxes are primarily revenue-related taxes and are offset dollar-for-dollar with higher gas utility and electric utility revenues reflected in margin attributable to regulatory expense recovery mechanisms.

Other Income - Net

Other income-net reflects income of $4.8 million for the third quarter of 2014, an increase of $2.8 million, compared to 2013. Year to date, other income-net reflects income of $12.4 million compared to $6.8 million, compared to 2013. Year to date results include increased AFUDC of approximately $5.5 million, driven primarily by higher capital spending.

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Rate & Regulatory Matters

Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement

The Company monitors and maintains its natural gas distribution system to ensure that natural gas is delivered in a safe and efficient manner. The Company's natural gas utilities are currently engaged in replacement programs in both Indiana and Ohio to mitigate risk, improve the system, and comply with applicable regulations. Laws in both Indiana and Ohio were passed that provide utilities the opportunity to timely recover costs of federally mandated projects and other infrastructure improvement projects outside of a base rate proceeding.

Ohio Recovery and Deferral Mechanisms

The PUCO Order approving the Company's 2009 base rate case in the Ohio service territory authorized a distribution replacement rider (DRR). The DRR's primary purpose is recovery of investments in utility plant and related operating expenses associated with replacing bare steel and cast iron pipelines and certain other infrastructure. This rider is updated annually for qualifying capital expenditures and allows for a return to be earned on those capital expenditures based on the rate of return approved in the 2009 base rate case. In addition, deferral of depreciation and the ability to accrue debt-related post in service carrying costs is also allowed until the related capital expenditures are included in the DRR. The Order also initially established a prospective bill impact evaluation on the annual deferrals. To date, the Company has made capital investments under this rider totaling $132.9 million. Regulatory assets associated with post in service carrying costs and depreciation deferrals were $12.1 million and $9.3 million at September 30, 2014 and December 31, 2013, respectively. Due to the expiration of the initial five year term for the DRR in early 2014, the Company filed a request in August 2013 to extend and expand the DRR. On February 19, 2014, the PUCO approved a Stipulation entered into by the PUCO Staff and the Company which provided for the extension of the DRR for the recovery of costs incurred through 2017 and expanded the types of investment covered by the DRR to include recovery of other infrastructure investments. The Order also approved an adjustment to the bill impact evaluation, limiting the resulting DRR rate per month for residential and small general service customers to specific graduated levels over the next five years. The Company's five year capital expenditure plan related to these infrastructure investments for calendar years 2013 through 2017 totals approximately $200 million, subject to the DRR rate caps approved in the Order. In addition, the Order approved the Company's commitment that the DRR can only be further extended as part of a base rate case. On May 1, 2014, the Company filed its annual request to adjust the DRR for recovery of costs incurred through December 31, 2013. On August 27, 2014 the PUCO issued an Order approving the Company’s revised DRR rate, effective September 1, 2014.

In June 2011, Ohio House Bill 95 was signed into law. Outside of a base rate proceeding, this legislation permits a natural gas company to apply for recovery of much of its capital expenditure program. The legislation also allows for the deferral of costs, such as depreciation, property taxes, and debt-related post in service carrying costs. On December 12, 2012, the PUCO issued an Order approving the Company's initial deferral application under this law, reflecting its capital expenditure program covering the fifteen month period ending December 31, 2012. Such capital expenditures include infrastructure expansion and improvements not covered by the DRR as well as expenditures necessary to comply with PUCO rules, regulations, orders, and system expansion to some new customers. The Order also established a prospective bill impact evaluation on the cumulative deferrals, limiting the total deferrals at a level which would equal $1.50 per residential and small general service customer per month. In addition, the Order approved the Company's proposal that subsequent requests for accounting authority will be filed annually in April. The Company submitted its most recent annual filing on April 30, 2014, which covers the Company’s capital expenditure program through calendar year 2014.

Given the extension of the DRR through 2017 as discussed above and the continued ability to defer other capital expenses under House Bill 95, it is anticipated that the Company will file a general rate case for the inclusion in rate base of the above costs near the expiration of the DRR. As such, the bill impact limits discussed above are not expected to be reached given the Company's capital expenditure plan during the remaining four year time frame.

Indiana Recovery and Deferral Mechanisms

The Company's Indiana natural gas utilities received Orders in 2008 and 2007 associated with the most recent base rate cases. These Orders authorized the deferral of financial impacts associated with bare steel and cast iron replacement activities. The Orders provide for the deferral of depreciation and post in service carrying costs on qualifying projects totaling $20 million annually at Indiana Gas and $3 million annually at SIGECO. The debt-related post in service carrying costs are recognized in

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the Condensed Consolidated Statements of Income currently. The recording of post in service carrying costs and depreciation deferral is limited by individual qualifying project to three years after being placed into service at SIGECO and four years after being placed into service at Indiana Gas. At September 30, 2014 and December 31, 2013, the Company has regulatory assets totaling $15.3 million and $12.1 million, respectively, associated with the deferral of depreciation and debt-related post in service carrying cost activities.

In April 2011, Senate Bill 251 was signed into Indiana law. The law provides a framework to recover 80 percent of federally mandated costs through a periodic rate adjustment mechanism outside of a general rate case. Such costs include a return on the federally mandated capital investment, along with recovery of depreciation and other operating costs associated with these mandates. The remaining 20 percent of those costs are to be deferred for future recovery in the utility's next general rate case.

In April 2013, Senate Bill 560 was signed into law.  This legislation supplements Senate Bill 251 described above, which addressed federally mandated investment, and provides for cost recovery outside of a base rate proceeding for projects that either improve electric and gas system reliability and safety or are economic development projects that provide rural areas with access to gas service.  Provisions of the legislation require that, among other things, requests for recovery include a seven year project plan.  Once the plan is approved by the IURC, 80 percent of such costs are eligible for current recovery using a periodic rate adjustment mechanism.  Recoverable costs include a return on and of the investment, as well as property taxes and operating expenses.  The remaining 20 percent of project costs are to be deferred and recovered in the Company'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.

Pipeline Safety Law

On January 3, 2012, the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 (Pipeline Safety Law) was signed into law. The Pipeline Safety Law, which reauthorizes federal pipeline safety programs through fiscal year 2015, provides for enhanced safety, reliability, and environmental protection in the transportation of energy products by pipeline. The law increases federal enforcement authority; grants the federal government expanded authority over pipeline safety; provides for new safety regulations and standards; and authorizes or requires the completion of several pipeline safety-related studies. The DOT is required to promulgate a number of new regulatory requirements over the next two years. Those regulations may eventually lead to further regulatory or statutory requirements.

While the Company continues to study the impact of the Pipeline Safety Law and potential new regulations associated with its implementation, it is expected that the law will result in further investment in pipeline inspections, and where necessary, additional investments in pipeline infrastructure and, therefore, result in both increased levels of operating expenses and capital expenditures associated with the Company's natural gas distribution businesses.

Requests for Recovery Under Indiana Regulatory Mechanisms

The Company filed in November 2013 for authority to recover costs related to its gas infrastructure replacement and improvement programs in Indiana, including costs associated with existing pipeline safety regulations, using the mechanisms allowed under Senate Bill 251 and Senate Bill 560. On August 27, 2014, the Commission issued an Order approving the Company’s seven year capital infrastructure replacement and improvement plan, beginning in 2014, and the proposed accounting authority and recovery, pursuant to the legislation. As provided in the two laws, the Order approved semi-annual filings for rate recovery of 100 percent of the costs, inclusive of return, related to these capital investments and operating expenses associated with pipeline safety rules, with 80 percent of the costs recovered currently via an approved tracking mechanism and 20 percent of the costs deferred and recovered in the Company’s next base rate proceeding. In addition, the Order established guidelines for the Company to update its seven year capital investment plan annually, with detailed estimates provided for the upcoming calendar year. Finally, the Order approved the Company’s proposal to recover eligible costs via a fixed monthly rate per residential customer. On September 26, 2014, the Indiana Office of Utility Consumer Counselor (OUCC) filed a Notice of Appeal with the Indiana Court of Appeals in response to the IURC's Order. The specific issues raised by the OUCC have not yet been identified. An appeal was filed in response to the IURC's Order in Northern Indiana Public Service Company's (NIPSCO) Senate Bill 560 electric infrastructure proceeding, pertaining to certain issues regarding the Commission's authority to approve NIPSCO's infrastructure plan. The outcome of the NIPSCO appeal and its implications to the Company’s Order, if any, cannot be determined.

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On October 1, 2014, the Company filed its initial request for approval of the revenue requirement associated with capital investment through June 30, 2014 as part of its approved infrastructure improvement plan. As the next step of the recovery process as outlined in the legislation, this filing, once approved, will initiate the rates necessary to begin cash recovery of 80 percent of the revenue requirement, with the remaining 20 percent deferred for recovery in the Company's next rate cases. Also in this filing, consistent with the guidelines set forth in the Order, the Company submitted an update to its seven year plan, to reflect changes to project prioritization as a result of both additional risk modeling and cost increases. The updated plan reflects capital expenditures of approximately $900 million, inclusive of an estimated $30 million of economic development related expenditures, over the seven year period beginning in 2014. The plan also includes approximately $15 million of annual operating costs associated with pipeline safety rules. Pursuant to Senate Bill 560, the Company expects an order by the end of 2014.

Indiana Gas GCA Cost Recovery Issue

On July 1, 2014, Indiana Gas filed its recurring quarterly Gas Cost Adjustment (GCA) mechanism, which included recovery of gas cost variances incurred for the period January through March 2014.  In August 2014, the Indiana Office of Utility Consumer Counselor (OUCC) filed testimony opposing the recovery of approximately $3.9 million of natural gas commodity purchases incurred during this period on the basis that a gas cost incentive calculation had not been properly performed. The calculation at issue is performed by the Company's supply administrator. In the winter period at issue, a pipeline force majeure event caused the gas to be priced at a location that was impacted by the extreme winter temperatures. After further review, the OUCC has modified its position in testimony filed on November 5, 2014, and now supports a reduced disallowance of $3.0 million. The Company believes that the costs are either recoverable in its GCA, or that if the incentive mechanism calculation is found to create a cost disallowance, any such loss would be allocated to its supply administrator. An order is expected in November 2014.

SIGECO Electric Environmental Compliance Filing

On January 17, 2014, SIGECO filed a request with the IURC for approval of capital investments estimated to be between $70 and $90 million on its coal-fired generation units to comply with new EPA mandates related to mercury and air toxin standards effective in 2015 and to address an outstanding Notice of Violation (NOV) from the EPA. Roughly half of the investment will be made to control mercury in both air and water emissions. The remaining investment will be made to address the NOV on alleged increases in sulfur trioxide emissions. Although the Company believes these investments are recoverable as clean coal technology under Senate Bill 29 and federal mandated investments under Senate Bill 251, the Company has requested deferred accounting treatment in lieu of timely recovery to avoid immediate customer bill impacts. The accounting treatment request seeks deferral of depreciation and property tax expense related to these investments, accrual of post in service carrying costs, and deferral of incremental operating expenses related to compliance with these standards. The Company filed its case-in-chief on March 14, 2014. Intervening parties filed their testimony on May 28, 2014, to which the Company responded with rebuttal testimony on June 20, 2014. A hearing was held beginning on July 30, 2014. The case has been fully briefed as of October 2, 2014, and the Company is awaiting a Commission order.

Coal Procurement Procedures

SIGECO annually submits its coal procurement plan for IURC review in a sub docket proceeding.  Entering 2014,  SIGECO had in place staggered term coal contracts with Vectren Fuels and one other supplier to provide supply for its generating units.  During 2014, SIGECO entered into separate negotiations with Vectren Fuels and Sunrise Coal to modify its existing contracts as well as enter into new long-term contracts in order to secure supply of coal with specifications that support its compliance with the Mercury and Air Toxins Rule. Subsequent to the sale of Vectren Fuels to an affiliate of Sunrise Coal, all such contracts have been assigned to Sunrise Coal. Those contracts were submitted to the IURC for review as part of the 2014 annual sub docket proceeding.  The OUCC filed testimony in September 2014 in support of the reasonableness of these contracts. A hearing was held in October 2014 and the Company is awaiting an order from the Commission.  

On December 5, 2011 within the quarterly FAC filing, SIGECO submitted a joint proposal with the OUCC to reduce its fuel costs billed to customers by accelerating into 2012 the impact of lower cost coal under new term contracts effective after 2012. The cost difference was deferred to a regulatory asset and is being recovered over a six year period without interest beginning in 2014.  The IURC approved this proposal on January 25, 2012, with the reduction to customer’s rates effective February 1, 2012.  The total balance deferred for recovery through the Company’s FAC, starting February 2014, was $42.4 million, of which $37.1 million remains as of September 30, 2014.

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SIGECO Electric Demand Side Management Program Filing

On August 16, 2010, SIGECO filed a petition with the IURC, seeking approval of its proposed electric Demand Side Management (DSM) Programs, recovery of the costs associated with these programs, recovery of lost margins as a result of implementing these programs for large customers, and recovery of performance incentives linked with specific measurement criteria on all programs.  The DSM Programs proposed were consistent with a December 9, 2009 Order issued by the IURC, which, among other actions, defined long-term conservation objectives and goals of DSM programs for all Indiana electric utilities under a consistent statewide approach.  In order to meet these objectives, the IURC Order divided the DSM programs into Core and Core Plus programs.  Core programs are joint programs required to be offered by all Indiana electric utilities to all customers, and include some for large industrial customers.  Core Plus programs are those programs not required specifically by the IURC, but defined by each utility to meet the overall energy savings targets defined by the IURC.

On August 31, 2011 the IURC issued an Order approving an initial three year DSM plan in the SIGECO electric service territory that complied with the IURC’s energy saving targets.  Consistent with the Company’s proposal, the Order approved, among other items, the following: 1) recovery of costs associated with implementing the DSM Plan; 2) the recovery of a performance incentive mechanism based on measured savings related to certain DSM programs; 3) lost margin recovery associated with the implementation of DSM programs for large customers; and 4) deferral of lost margin up to $3 million in 2012 and $1 million in 2011 associated with small customer DSM programs for subsequent recovery under a tracking mechanism to be proposed by the Company.  On June 20, 2012, the IURC issued an Order approving a small customer lost margin recovery mechanism, inclusive of all previous deferrals. This mechanism is an alternative to the electric decoupling proposal that was denied by the IURC in the Company's last base rate proceeding.  For the nine months endedSeptember 30, 2014 and September 30, 2013, the Company recognized Electric revenue of $6.6 million and $3.5 million, respectively, associated with this approved lost margin recovery mechanism.

On March 28, 2014, Senate Bill 340 was signed into law. This legislation ends electric DSM programs on December 31, 2014 that have been conducted to meet the energy savings requirements established in the Commission's December 2009 Order. The legislation also allows for industrial customers to opt out of participating in energy efficiency programs. As of July 1, 2014, approximately 71 percent of the Company’s eligible industrial load has opted out of participation in the applicable energy efficiency programs. Indiana's governor has requested that the Commission make new recommendations for energy efficiency programs to be proposed for 2015 and beyond, and has also asked the legislature to consider further legislation requiring some level of utility sponsored energy efficiency programs. The Company filed a request for Commission approval of a new portfolio of DSM programs on May 29, 2014 to be offered in 2015. On October 15, 2014, the Commission issued an Order approving a Settlement between the OUCC and the Company regarding the new portfolio of DSM programs effective January 2015.

Indiana Gas Pipeline Safety Investigation

On April 11, 2012, the IURC's pipeline safety division filed a complaint against Indiana Gas alleging several violations of safety regulations pertaining to damage that occurred at a residence in Indiana Gas's service territory during a pipeline replacement project. The Company negotiated a settlement with the IURC's pipeline safety division, agreeing to a fine and several modifications to the Company's operating policies. The amount of the fine was not material to the Company's financial results. The IURC approved the settlement but modified certain terms of the settlement and added a requirement that Company employees conduct inspections of pipeline excavations. The Company sought and was granted a request for rehearing on the sole issue related to the requirement to use Company employees to inspect excavations. A settlement in the case was reached between the IURC's pipeline safety division and Indiana Gas that allowed Indiana Gas to continue to use its risk based approach to inspecting excavations and to allow the Company to continue using a mix of highly trained and qualified contractors and employees to perform inspections. On January 15, 2014, the IURC issued a Final Order in the case approving the settlement agreement, without modification.

Indiana Gas & SIGECO Gas Decoupling Extension Filing

On August 18, 2011, the IURC issued an Order granting the extension of the current decoupling mechanism in place at both gas companies and recovery of new conservation program costs through December 2015. The Order provides that the companies must submit an extension proposal no later than March 1, 2015.

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FERC Return on Equity Complaint

On November 12, 2013, certain parties representing a group of industrial customers filed a joint complaint with the FERC under Section 206 of the Federal Power Act against MISO and various MISO transmission owners, including SIGECO. The joint parties seek to reduce the 12.38 percent return on equity used in the MISO transmission owners’ rates, including SIGECO’s formula transmission rates, to 9.15 percent, and to set a capital structure in which the equity component does not exceed 50 percent. The MISO transmission owners filed their response to the complaint on January 6, 2014, opposing any change to the return. As of September 30, 2014, the Company had invested approximately $157.7 million in qualifying projects. The net plant balance for these projects totaled $144.5 million at September 30, 2014.

This joint complaint is similar to a complaint against the New England Transmission Owners (NETO) filed in September 2011, which requested that the 11.14 percent incentive return granted on qualifying investments in NETO be lowered. On October 16, 2014, the FERC issued an Order in the NETO case approving the 10.57 percent return on equity and the methodology set out in its June 19, 2014 decision.

In addition to the NETO ruling, the FERC acknowledged that the pending complaint raised against the MISO transmission owners is reasonable, and ordered the initiation of a formal settlement discussion, mediated by a FERC appointed judge, in November 2014. If a settlement is not reached, the case will move to a formal evidentiary hearing before the FERC. The Company has established a reserve pending the outcome of this complaint.

Legislative & Environmental Matters

Indiana Senate Bill 1

In March 2014, Indiana Senate Bill 1 was signed into law.  This legislation phases in a 1.6 percent rate reduction to the Indiana Adjusted Gross Income Tax Rate for corporations over a six year period. Pursuant to this legislation, the tax rate will be lowered by 0.25 percent each year for the first five years and 0.35 percent in year six beginning on July 1, 2016 to the final rate of 4.9 percent effective July 1, 2021. Pursuant to FASB guidance, the Company accounted for the effect of the change in tax law on its deferred taxes in the first quarter of 2014, the period of enactment. The impact was not material to results of operations.

Indiana Senate Bill 251

Indiana Senate Bill 251 is also applicable to federal environmental mandates impacting Vectren South's electric operations. The Company continues with its ongoing evaluation of the impact Senate Bill 251 may have on its operations, including applicability of the stricter regulations the EPA is currently considering involving air quality, fly ash disposal, cooling tower intake facilities, waste water discharges, and greenhouse gases. These issues are further discussed below.

Air Quality

Clean Air Interstate Rule / Cross-State Air Pollution Rule

In July 2011, the EPA finalized the Cross-State Air Pollution Rule (CSAPR).  CSAPR was the EPA’s response to the US Court of Appeals for the District of Columbia’s (the Court) remand of the Clean Air Interstate Rule (CAIR). CAIR was originally established in 2005 as an allowance cap and trade program that required reductions from coal-burning power plants for NOX emissions beginning January 1, 2009 and SO2 emissions beginning January 1, 2010, with a second phase of reductions in 2015. In an effort to address the Court’s finding that CAIR did not adequately ensure attainment of pollutants in certain downwind states due to unlimited trading of SO2and NOX allowances, CSAPR reduced the ability of facilities to meet emission reduction targets through allowance trading.  CSAPR reductions were to be achieved with initial step reductions beginning January 1, 2012, and final compliance to be achieved in 2014.  On December 30, 2011, a reviewing court granted a stay of CSAPR and left CAIR in place pending its review. On August 21, 2012, the court vacated CSAPR and directed the EPA to continue to administer CAIR. In April 2014, the US Supreme Court upheld CSAPR. On June 26, 2014, the EPA asked the federal appeals court to lift the stay of the rule. The EPA also asked the court to approve a new deadline schedule for entities that must comply, with the first phase caps starting in 2015 and 2016, and the second phase in 2017. On October 23, 2014 the Court granted the EPA’s request to lift the CSAPR stay, but did not finalize the new implementation dates. While it is possible that the EPA could further revise the rule prior to implementation, the Company does not anticipate a significant impact from the Supreme Court's decision based upon the investments it has already made in pollution control technology to meet the requirements of CAIR. The Company remains in full compliance with CAIR (see additional information below "Conclusions Regarding Air and Water Regulations").

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Mercury and Air Toxics (MATS) Rule

On December 21, 2011, the EPA finalized the utility MATS Rule.  The MATS Rule sets emission limits for hazardous air pollutants for existing and new coal-fired power plants and identifies the following broad categories of hazardous air pollutants:  mercury, non-mercury hazardous air pollutants (primarily arsenic, chromium, cobalt, and selenium), and acid gases (hydrogen cyanide, hydrogen chloride, and hydrogen fluoride).  The rule imposes mercury emission limits for two sub-categories of coal, and proposed surrogate limits for non-mercury and acid gas hazardous air pollutants. The EPA did not grant blanket compliance extensions, but asserted that states have broad authority to grant one year extensions for individual electric generating units where potential reliability impacts have been demonstrated.  Reductions are to be achieved within three years of publication of the final rule in the Federal register (April 2015).  Multiple judicial challenges were filed, and the EPA agreed to reconsider MATS requirements for new construction, as the requirements are more stringent than those for existing plants. Utilities planning new coal-fired generation had argued standards outlined in the MATS could not be attained even using the best available control technology. The EPA issued its revised emission limits for new construction in March 2013. In April 2014, the U.S. Court of Appeals for the D.C. Circuit rejected various challenges to the rule for existing sources that were brought by industry and state petitioners. In July a coalition of twenty-one states, including Indiana, filed a petition for certiorari with the U.S. Supreme Court seeking review of the decision of the appellate court. The Company continues to proceed with its MATS compliance strategy. This plan is currently before the IURC for approval, and the Company anticipates full compliance by the applicable deadlines.

Notice of Violation for A.B. Brown Power Plant

The Company received a notice of violation (NOV) from the EPA in November 2011 pertaining to its A.B. Brown power plant.  The NOV asserts that when the power plant was equipped with Selective Catalytic Reduction (SCR) systems, the correct permits were not obtained or the best available control technology to control incidental sulfuric acid mist was not installed. The Company reached a settlement in principle with the EPA to resolve the NOV. That settlement was contemplated in the plan filed with the IURC in the SIGECO Electric Environmental Compliance Filing.

Information Request

SIGECO and Alcoa Generating Corporation (AGC), a subsidiary of ALCOA, own a 300 MW Unit 4 at the Warrick Power Plant as tenants in common.  AGC and SIGECO also share equally in the cost of operation and output of the unit.  In January 2013, AGC received an information request from the EPA under Section 114 of the Clean Air Act for historical operational information on the Warrick Power Plant. In April 2013, ALCOA filed a timely response to the information request.

Water

Section 316(b) of the Clean Water Act requires that generating facilities use the “best technology available” (BTA) to minimize adverse environmental impacts in a body of water.  More specifically, Section 316(b) is concerned with impingement and entrainment of aquatic species in once-through cooling water intake structures used at electric generating facilities.  In April 2009, the U.S. Supreme Court affirmed that the EPA could, but was not required to, consider costs and benefits in making the evaluation as to the best technology available for existing generating facilities.  The regulation was remanded to the EPA for further consideration.  In March 2011, the EPA released its proposed Section 316(b) regulations.  The EPA did not mandate the retrofitting of cooling towers in the proposed regulation, but if finalized, the regulation will leave it to each state to determine whether cooling towers should be required on a case by case basis.  A final rule was issued on May 19, 2014. The final rule does not mandate cooling water tower retrofits but requires a case by case assessment of BTA for each facility. The final rule lists seven presumptive technologies which would qualify as BTA. These technologies range from intake screen modifications to cooling water tower retrofits. Ecological and technology assessment studies must be completed prior to determining BTA for the Company’s facilities. The Company believes that capital investments will likely be in the range of $4 million to $8 million.  Costs for compliance with these final regulations should qualify as federally mandated regulatory requirements and be recoverable under Indiana Senate Bill 251 referenced above.

Under the Clean Water Act, the EPA sets technology-based guidelines for water discharges from new and existing facilities. The EPA is currently in the process of revising the existing steam electric effluent limitation guidelines that set the technology-based water discharge limits for the electric power industry. The EPA is focusing its rulemaking on wastewater generated primarily by pollution control equipment necessitated by the comprehensive air regulations. The EPA released proposed rules on April 19, 2013 and the Company is reviewing the proposal. At this time, it is not possible to estimate what potential costs may be

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required to meet these new water discharge limits, however costs for compliance with these regulations should qualify as federally mandated regulatory requirements and be recoverable under Senate Bill 251 referenced above.

Conclusions Regarding Air and Water Regulations

To comply with Indiana’s implementation plan of the Clean Air Act, and other federal air quality standards, the Company obtained authority from the IURC to invest in clean coal technology.  Using this authorization, the Company invested approximately $411 million starting in 2001 with the last equipment being placed into service on January 1, 2010.  The pollution control equipment included SCR systems, fabric filters, and an SO2 scrubber at its generating facility that is jointly owned with AGC.  SCR technology is the most effective method of reducing NOX emissions where high removal efficiencies are required and fabric filters control particulate matter emissions.  The unamortized portion of the $411 million clean coal technology investment was included in rate base for purposes of determining SIGECO’s electric base rates approved in the latest base rate order obtained April 27, 2011.  SIGECO’s coal-fired generating fleet is 100 percent scrubbed for SO2 and 90 percent controlled for NOX.  

Utilization of the Company’s NOX and SO2 allowances can be impacted as regulations are revised and implemented.  Most of these allowances were granted to the Company at zero cost; therefore, any reduction in carrying value that could result from future changes in regulations would be immaterial.

The Company continues to review the sufficiency of its existing pollution control equipment in relation to the requirements described in the MATS Rule, the recent renewal of water discharge permits, and the NOV discussed above.  Some operational modifications to the control equipment are likely. The Company is continuing to evaluate potential technologies to address compliance and what the additional costs may be associated with these efforts. Currently, it is expected that the capital costs could be between $70 million and $90 million. Compliance is required by government regulation, and the Company believes that such additional costs, if incurred, should be recoverable under Senate Bill 251 referenced above. On January 17, 2014, the Company filed its request with the IURC seeking approval to upgrade its existing emissions control equipment to comply with the MATS Rule, take steps to address the EPA's allegations in the NOV and comply with new mercury limits to the waste water discharge permits at the Culley and Brown generating stations. In that filing, the Company has proposed to defer recovery of the costs until 2020 in order to mitigate the impact on customer rates in the near term. In July a hearing was held before the IURC in this matter. The case has been fully briefed as of October 2, 2014, and the Company is awaiting a Commission order.

Coal Ash Waste Disposal & Ash Ponds

In June 2010, the EPA issued proposed regulations affecting the management and disposal of coal combustion products, such as ash generated by the Company’s coal-fired power plants.  The proposed rules more stringently regulate these byproducts and would likely increase the cost of operating or expanding existing ash ponds and the development of new ash ponds.  The alternatives include regulating coal combustion by-products that are not being beneficially reused as hazardous waste.  The EPA did not offer a preferred alternative, but took public comment on multiple alternative regulations.  Rules have not been finalized given oversight hearings, congressional interest, and other factors. Recently the EPA entered into a consent decree in which it agreed to finalize by December 2014 its determination whether to regulate ash as hazardous waste, or the less stringent solid waste designation.

At this time, the majority of the Company’s ash is being beneficially reused.  However, the alternatives proposed would require modification to, or closure of, existing ash ponds.  The Company estimates capital expenditures to comply could be as much as $30 million, and such expenditures could exceed $100 million if the most stringent of the alternatives is selected.  Annual compliance costs could increase only slightly or be impacted by as much as $5 million.  Costs for compliance with these regulations should qualify as federally mandated regulatory requirements and be recoverable under Senate Bill 251 referenced above. 

Climate Change

In April 2007, the US Supreme Court determined that greenhouse gases (GHG's) meet the definition of "air pollutant" under the Clean Air Act and ordered the EPA to determine whether GHG emissions cause or contribute to air pollution that may reasonably be anticipated to endanger public health or welfare. The endangerment finding was finalized in December 2009, concluding that carbon emissions pose an endangerment to public health and the environment.

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The EPA has finalized two sets of GHG regulations that apply to the Company’s generating facilities.  In 2009, the EPA finalized a mandatory GHG emissions registry which requires the reporting of emissions.  The EPA has also finalized a revision to the Prevention of Significant Deterioration (PSD) and Title V permitting rules which would require facilities that emit 75,000 tons or more of GHG's a year to obtain a PSD permit for new construction or a significant modification of an existing facility.  The EPA's PSD and Title V permitting rules for GHG's were upheld by the US Court of Appeals for the District of Columbia, and in June 2014 the US Supreme Court upheld the regulations with respect to applicability to major sources such as coal-fired power plants that are required to hold PSD construction and Title V air operating permits for other criteria pollutants.

While the Company has no plans to invest in new coal fired generation, there is also a rule making and related legal challenge involving new source performance standards for new construction. This rulemaking must be finalized and withstand legal scrutiny in order for the EPA to implement its proposed new source performance standards for existing units discussed below.

In July 2013, the President announced a Climate Action Plan, which calls on the EPA to finalize the rule for new construction expeditiously, and by June 2014 propose, and by June 2015 finalize, New Source Performance Standards (NSPS) for GHG's for existing electric generating units which would apply to the Company's power plants. States must have their implementation plans to the EPA no later than June 2016. On June 2, 2014, the EPA proposed its rule for states to regulate CO2 emissions from existing electric generating units. The rule, when final, will require states to adopt plans that reduce CO2 emissions by 30 percent from 2005 levels by 2030. Unlike most rulemakings which allow for a 30 day public comment period, the EPA provided an initial 120 days from publication of the proposal in the Federal Register, and a subsequent extension of the public comment period was granted to December 1, 2014. The proposal sets state-specific CO2 emission rate-based CO2 goals (measured in lb CO2/MWh or “megawatt hour”) and guidelines for the development, submission and implementation of state plans to achieve the state goals. These state-specific goals are calculated based upon 2012 average emission rates aggregated for all fossil fuel-based units in the state. For Indiana, the proposal uses a 2012 emission rate of 1,923 lb CO2/MWh, and sets an interim goal of 1,607 lb CO2/MWh and a final emission goal of 1,531 lb CO2/MWh that must be met by 2030. Under this proposal, these CO2 emission rate goals do not apply directly to individual units, or generating systems. They are state goals. As such, the state must establish a framework that will guide how compliance will be met on a statewide basis. The state’s interim or “phase in” goal of 1,607 lb CO2/MWh must be met as averaged over a ten year period (2020 - 2029) with progress toward this goal to be demonstrated for every two rolling calendar years starting in 2020, with the first report due in 2022.

Under the proposal all states have unique goals based upon each state’s mix of electric generating assets. The EPA is proposing a 20 percent reduction in Indiana’s total CO2 emission rate compared to 2012. At 20 percent Indiana’s CO2 emission rate reduction requirement is tied with West Virginia as the 9^th lowest reduction requirement in US. This is due in part to the EPA’s attempt to recognize the existing generating resource mix in the state and take into account each state’s ability to cost effectively lower its CO2 emission rate through a portfolio approach including energy efficiency and renewables, improving power plant heat rates, and dispatching lower emitting fuel sources. Each state’s goals were set by taking 2012 emissions data and applying four “building blocks” of emission rate improvements that the EPA asserts can be achieved by that state. These four building blocks constitute the EPA’s determination of “Best System of Emission Reductions that has been adequately demonstrated,” which defines the EPA’s authority under § 111(d) for existing sources. When applied to each state, the portfolio approach leads to significant differences in requirements across state lines. With the exception of building block number 1 (heat rate improvement of 6 percent), other building blocks are tailored to individual states based upon each state’s existing generating mix and what the EPA concluded a state could reasonably accomplish to reduce its CO2 emission rate. Despite having just been recently proposed and not expected to be finalized until June of 2015, legal challenges to the EPA's proposal have begun. On July 31, 2014, litigation was filed by the state of Indiana and other parties challenging the rules which may delay the timing of approval of the various state plans.

With respect to the state of Indiana, the four building blocks that support Indiana’s goal are as follows:

(1) Heat rate (HR) improvements of 6 percent (this is consistently applied to all states).

(2) Increasing the dispatch of existing natural gas baseload generation sources to 70 percent.

(3) Renewable energy portfolio requirements of 5 percent (interim) and 7 percent (final).

(4) Energy efficiency / DSM that results in reductions of 1.5 percent annually starting in 2020, ending at a sustained 11 percent by 2030.

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Under the proposal, Indiana may choose to implement a program based upon an annual average emission rate target or convert that target rate to a comparable CO2 emission cap. Indiana is the 5^th largest carbon emitter in the nation in tons of CO2 produced from electric generation. In 2013, Indiana’s electric utilities generated 105.6 million tons of CO2. The Company’s share of that total was 6.3 million, or <6 percent. Since 2005, the Company’s emissions of CO2 have declined 23 percent (on a tonnage basis). These reductions have come from the retirement of FB Culley Unit 1, expiration of municipal contracts, electric conservation and the addition of renewable generation and the installation of more efficient dense pack turbine technology. With respect to CO2 emission rate, since 2005 the Company has lowered its CO2 emission rate (as measured in lbs CO2/MWh) from 1967 lbs CO2/MWh to 1922 lbs CO2/MWh, for a reduction of 3 percent. the Company’s CO2 emission rate of 1922 lbs/MWh is basically the same as the State’s average CO2 emission rate of 1923 lb CO2/MWh.

Impact of Legislative Actions & Other Initiatives is Unknown

If the regulations referenced above are finalized by the EPA, or if legislation requiring reductions in CO2 and other GHG's or legislation mandating a renewable energy portfolio standard is adopted, such regulation could substantially affect both the costs and operating characteristics of the Company’s fossil fuel generating plants and natural gas distribution businesses.  At this time and in the absence of final legislation or rulemaking, compliance costs and other effects associated with reductions in GHG emissions or obtaining renewable energy sources remain uncertain.  The Company has gathered preliminary estimates of the costs to control GHG emissions.  A preliminary investigation demonstrated costs to comply would be significant, first with regard to operating expenses and later for capital expenditures as technology becomes available to control GHG emissions.  However, these compliance cost estimates were based on highly uncertain assumptions, including allowance prices if a cap and trade approach were employed, and energy efficiency targets.  As the EPA moves toward finalization of the NSPS for existing sources and the State of Indiana begins formulation of its state implementation plan, the Company will have more information to enable it to better assess potential compliance costs with a final regulation. Costs to purchase allowances that cap GHG emissions or expenditures made to control emissions or lower carbon emission rates should be considered a federally mandated cost of providing electricity, and as such, the Company believes such costs and expenditures should be recoverable from customers through Senate Bill 251 as referenced above or Senate Bill 29, which was used by the Company to recover its initial pollution control investments.

Renewables

Senate Bill 251 also established a voluntary clean energy portfolio standard that provides incentives to Indiana electricity suppliers participating in the program. The goal of the program is that by 2025, at least 10 percent of the total electricity obtained by the supplier to meet the energy needs of Indiana retail customers will be provided by clean energy sources, as defined. In advance of a federal portfolio standard and Senate Bill 251, SIGECO received regulatory approval to purchase a 3 MW landfill gas generation facility from a related entity. The facility was purchased in 2009 and is directly connected to the Company's distribution system. In 2008 and 2009, the Company executed long-term purchase power commitments for a total of 80 MW of wind energy. The Company currently has approximately 4 percent of its electricity being provided by clean energy sources due to the long-term wind contracts and landfill gas investment.

Manufactured Gas Plants

In the past, the Company operated facilities to manufacture natural gas.  Given the availability of natural gas transported by pipelines, these facilities have not been operated for many years.  Under current environmental laws and regulations, those that owned or operated these facilities may now be required to take remedial action if certain contaminants are found above the regulatory thresholds.

In the Indiana Gas service territory, the existence, location, and certain general characteristics of 26 gas manufacturing and storage sites have been identified for which the Company may have some remedial responsibility.  A remedial investigation/feasibility study (RI/FS) was completed at one of the sites under an agreed order between Indiana Gas and the IDEM, and a Record of Decision was issued by the IDEM in January 2000.  The remaining sites have been submitted to the IDEM's Voluntary Remediation Program (VRP).  The Company has identified its involvement in five manufactured gas plant sites in SIGECO’s service territory, all of which are currently enrolled in the IDEM’s VRP.  The Company is currently conducting some level of remedial activities, including groundwater monitoring at certain sites.

The Company has accrued the estimated costs for further investigation, remediation, groundwater monitoring, and related costs for the sites.  While the total costs that may be incurred in connection with addressing these sites cannot be determined at this

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time, the Company has recorded cumulative costs that it has incurred or reasonably expects to incur totaling approximately $43.4 million ($23.2 million at Indiana Gas and $20.2 million at SIGECO).  The estimated accrued costs are limited to the Company’s share of the remediation efforts and are therefore net of exposures of other potentially responsible parties (PRP).

With respect to insurance coverage, Indiana Gas has received approximately $20.8 million from all known insurance carriers under insurance policies in effect when these plants were in operation.  Likewise, SIGECO has settlement agreements with all known insurance carriers and has received to date approximately $14.3 million of the expected $15.8 million in insurance recoveries.

The costs the Company expects to incur are estimated by management using assumptions based on actual costs incurred, the timing of expected future payments, and inflation factors, among others.  While the Company’s utilities have recorded all costs which they presently expect to incur in connection with activities at these sites, it is possible that future events may require remedial activities which are not presently foreseen and those costs may not be subject to PRP or insurance recovery.  As of September 30, 2014 and December 31, 2013, approximately $4.3 million and $5.7 million, respectively, of accrued, but not yet spent, costs are included in Other Liabilities related to the Indiana Gas and SIGECO sites.

Impact of Recently Issued Accounting Guidance

Revenue Recognition Guidance

In May 2014, the FASB issued new accounting guidance to clarify the principles for recognizing revenue and to develop a common revenue standard for GAAP and IFRS. The amendments in this guidance state that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This new guidance requires improved disclosures to help users of financial statements better understand the nature, amount, timing, and uncertainty of revenue that is recognized. For a public entity, the guidance is effective for annual reporting periods beginning after December 15, 2016, with early adoption not permitted. An entity should apply the amendments in this update retrospectively to each prior reporting period presented or retrospectively with the cumulative effect of initially applying this update recognized at the date of initial application. The Company is currently evaluating the standard to understand the overall impact it will have on the financial statements.

Financial Reporting of Discontinued Operations

In April 2014, the FASB issued new accounting guidance on reporting discontinued operations and disclosures of disposals of a company or entity. The guidance changes the criteria for reporting discontinued operations and provides for enhanced disclosures in this area. Under the new guidance, only disposals representing a strategic shift in operations should be presented as discontinued operations. Those strategic shifts should have a major effect on the organization's operations and financial results. Additionally, the new guidance requires expanded disclosures about discontinued operations to provide more information about the assets, liabilities, income, and expenses of discontinued operations. The new guidance also requires disclosure of the pre-tax income attributable to a disposal of a significant part of an organization that does not qualify for discontinued operations reporting. This guidance is effective for fiscal years beginning on or after December 15, 2014, with early adoption permitted. The Company is currently evaluating the impact of this guidance, if any.

Financial Reporting of Going Concern

In August 2014, the FASB issued new accounting guidance with respect to reporting on an entity's ability to continue as a going concern. This new guidance requires management to assess an entity's ability to continue as a going concern by incorporating and expanding upon certain principles that are currently in U.S. auditing standards, which requires disclosure surrounding what constitutes substantial doubt for the entity, including disclosure of management's plans to mitigate and alleviate substantial doubt. This guidance is effective for annual periods beginning after December 15, 2016, and for annual and interim periods thereafter, with early application permitted. Adoption of this guidance will not have a material impact on the Company’s financial statements.

Financial Condition

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Utility Holdings funds the short-term and long-term financing needs of its utility subsidiary operations.  Vectren does not guarantee Utility Holdings’ debt.  Utility Holdings’ outstanding long-term and short-term borrowing arrangements are jointly and severally guaranteed by Indiana Gas, SIGECO, and VEDO.  The guarantees are full and unconditional and joint and several, and Utility Holdings has no direct subsidiaries other than the subsidiary guarantors.  Information about the subsidiary guarantors as a group is included in Note 3 to the consolidated financial statements.  Utility Holdings’ long-term debt outstanding at September 30, 2014 approximated $875 million. As of September 30, 2014, Utility Holdings had $60 million in short-term borrowings outstanding. Additionally, prior to Utility Holdings’ formation, Indiana Gas and SIGECO funded their operations separately, and therefore, have long-term debt outstanding funded solely by their operations.  SIGECO will also occasionally issue tax exempt debt to fund qualifying pollution control capital expenditures.  Total Indiana Gas and SIGECO long-term debt, including current maturities, outstanding at September 30, 2014, was approximately $382 million. Utility Holdings’ operations have historically been the primary funding source for Vectren’s common stock dividends.

The credit ratings of the senior unsecured debt of Utility Holdings and Indiana Gas, at September 30, 2014, are A-/A2 as rated by Standard and Poor's Ratings Services (Standard and Poor’s) and Moody’s Investors Service (Moody’s), respectively.  The credit ratings on SIGECO's secured debt are A/Aa3.  Utility Holdings’ commercial paper has a credit rating of A-2/P-1.  The current outlook of both Moody’s and Standard and Poor’s is stable. A security rating is not a recommendation to buy, sell, or hold securities.  The rating is subject to revision or withdrawal at any time, and each rating should be evaluated independently of any other rating.  Standard and Poor’s and Moody’s lowest level investment grade rating is BBB- and Baa3, respectively.

The Company’s consolidated equity capitalization objective is 50-60 percent of long-term capitalization.  This objective may have varied, and will vary, depending on particular business opportunities, capital spending requirements, execution of long-term financing plans, and seasonal factors that affect the Company’s operations.  The Company’s equity component was 54 percent of long-term capitalization at September 30, 2014 and 53 percent at December 31, 2013.  Long-term capitalization includes long-term debt, including current maturities, as well as common shareholder’s equity.

Both long-term and short-term borrowing arrangements contain customary default provisions; restrictions on liens, sale-leaseback transactions, mergers or consolidations, and sales of assets; and restrictions on leverage, among other restrictions.  Multiple debt agreements contain a covenant that the ratio of consolidated total debt to consolidated total capitalization will not exceed 65 percent.  As of September 30, 2014, the Company was in compliance with all debt covenants.

Available Liquidity in Current Credit Conditions

The Company’s A-/A2 investment grade credit ratings have allowed it to access the capital markets as needed, and the Company believes it will have the ability to continue to do so.  Given the Company's intent to maintain a balanced long-term capitalization ratio, it anticipates funding future capital expenditures and dividends principally through internally generated funds and modest amounts of incremental long-term debt. However, the resources required for capital investment remain uncertain for a variety of factors including pending legislative and regulatory initiatives involving gas pipeline infrastructure replacement; and expanded EPA regulations for air, water, and fly ash. These regulations may result in the need to raise additional debt and equity capital in the coming years. The timing and amount of such investments depends on a variety of factors, including available liquidity.

On September 24, 2014, SIGECO issued two new series of tax-exempt debt totaling $63.6 million.  Proceeds from the issuance were used to retire three series of tax-exempt bonds aggregating $63.6 million at a redemption price of par plus accrued interest.  The principal terms of the two new series of tax-exempt debt are:  (i) $22.3 million sold in a public offering and bear interest at 4 percent per annum, due September 1, 2044 and (ii) $41.3 million, due July 1, 2025, sold in a private placement at variable rates through September 2019.

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Consolidated Short-Term Borrowing Arrangements

At September 30, 2014, the Company has $350 million of short-term borrowing capacity.  As reduced by borrowings currently outstanding, approximately $290 million was available at September 30, 2014. This short-term credit facility was amended on October 31, 2014 to, among other things, extend the maturity until October 31, 2019.  The maximum limit of the facility remained unchanged. This facility is used to supplement working capital needs and also to fund capital investments and debt redemptions until financed on a long-term basis. 

The Company has historically funded its short-term borrowing needs through the commercial paper market and expects to use the short-term borrowing facility in instances where the commercial paper market is not efficient. 

Following is certain information regarding these short-term borrowing arrangements.

(In millions)	2014	2013
As of September 30
Balance Outstanding	$60.1	$176.1
Weighted Average Interest Rate	0.31%	0.31%
Nine Months Ended September 30 Average
Balance Outstanding	$15.3	$121.4
Weighted Average Interest Rate	0.28%	0.35%
Maximum Month End Balance Outstanding	$60.1	$176.1
(In millions)	2014	2013
Quarterly Average - September 30
Balance Outstanding	$43.0	$153.8
Weighted Average Interest Rate	0.28%	0.34%
Maximum Month End Balance Outstanding	$60.1	$176.1

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Potential Uses of Liquidity

Pension Funding Obligations

Vectren's management currently anticipates making no contributions to its qualified pension plans in 2014. As such, Utility Holdings will make no funding contribution to Vectren in 2014.

Planned Capital Expenditures

Utility capital expenditures are estimated at $110 million for the remainder of 2014.

Comparison of Historical Sources & Uses of Liquidity

Operating Cash Flow

The Company's primary source of liquidity to fund working capital requirements has been cash generated from operations, which totaled $282.4 million and $295.4 million for the nine months endedSeptember 30, 2014 and 2013, respectively. The decrease is driven primarily by change in certain working capital accounts.  

Financing Cash Flow

Net cash flow required for financing activities was $45.9 million and $119.7 million during the nine months endedSeptember 30, 2014 and 2013, respectively.  Financing activity in both periods presented reflect the payment of dividends. Decrease in cash flow required for financing activities primarily reflects a greater payoff of long term debt in 2013 compared to 2014.

Investing Cash Flow

Cash flow required for investing activities was $239.7 million and $182.8 million during the nine months endedSeptember 30, 2014 and 2013, respectively.  The increase in cash flow required for investing activities is a result of increased capital expenditures related to gas infrastructure programs.

Forward-Looking Information

A “safe harbor” for forward-looking statements is provided by the Private Securities Litigation Reform Act of 1995 (Reform Act of 1995).  The Reform Act of 1995 was adopted to encourage such forward-looking statements without the threat of litigation, provided those statements are identified as forward-looking and are accompanied by meaningful cautionary statements identifying important factors that could cause the actual results to differ materially from those projected in the statement.  Certain matters described in Management’s Discussion and Analysis of Results of Operations and Financial Condition are forward-looking statements.  Such statements are based on management’s beliefs, as well as assumptions made by and information currently available to management.  When used in this filing, the words “believe”, “anticipate”, “endeavor”, “estimate”, “expect”, “objective”, “projection”, “forecast”, “goal”, “likely”, and similar expressions are intended to identify forward-looking statements.  In addition to any assumptions and other factors referred to specifically in connection with such forward-looking statements, factors that could cause the Company’s actual results to differ materially from those contemplated in any forward-looking statements include, among others, the following:

• Factors affecting utility operations such as unusual weather conditions; catastrophic weather-related damage; unusual maintenance or repairs; unanticipated changes to coal and natural gas costs; unanticipated changes to gas transportation and storage costs, or availability due to higher demand, shortages, transportation problems or other developments; environmental or pipeline incidents; transmission or distribution incidents; unanticipated changes to electric energy supply costs, or availability due to demand, shortages, transmission problems or other developments; or electric transmission or gas pipeline system constraints.

• Catastrophic events such as fires, earthquakes, explosions, floods, ice storms, tornadoes, terrorist acts, cyber attacks, or other similar occurrences could adversely affect Vectren’s facilities, operations, financial condition and results of operations.

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• Increased competition in the energy industry, including the effects of industry restructuring, unbundling, and other sources of energy.

• Regulatory factors such as unanticipated changes in rate-setting policies or procedures, recovery of investments and costs made under regulation, and the frequency and timing of rate increases.

• Financial, regulatory or accounting principles or policies imposed by the Financial Accounting Standards Board; the Securities and Exchange Commission; the Federal Energy Regulatory Commission; state public utility commissions; state entities which regulate electric and natural gas transmission and distribution, natural gas gathering and processing, electric power supply; and similar entities with regulatory oversight.

• Economic conditions including the effects of inflation rates, commodity prices, and monetary fluctuations.

• Economic conditions surrounding the current economic uncertainty, including increased potential for lower levels of economic activity; uncertainty regarding energy prices and the capital and commodity markets; volatile changes in the demand for natural gas, and electricity; impacts on both gas and electric large customers; lower residential and commercial customer counts; and higher operating expenses.

• Volatile natural gas and coal commodity prices and the potential impact on customer consumption, uncollectible accounts expense, unaccounted for gas and interest expense.

• Changing market conditions and a variety of other factors associated with physical energy and financial trading activities including, but not limited to, price, basis, credit, liquidity, volatility, capacity, interest rate, and warranty risks.

• Direct or indirect effects on the Company’s business, financial condition, liquidity and results of operations resulting from changes in credit ratings, changes in interest rates, and/or changes in market perceptions of the utility industry and other energy-related industries.

• Employee or contractor workforce factors including changes in key executives, collective bargaining agreements with union employees, aging workforce issues, work stoppages, or pandemic illness.

• Risks associated with material business transactions such as mergers, acquisitions and divestitures, including, without limitation, legal and regulatory delays; the related time and costs of implementing such transactions; integrating operations as part of these transactions; and possible failures to achieve expected gains, revenue growth and/or expense savings from such transactions.

• Costs, fines, penalties and other effects of legal and administrative proceedings, settlements, investigations, claims, including, but not limited to, such matters involving compliance with state and federal laws and interpretations of these laws.

• Changes in or additions to federal, state or local legislative requirements, such as changes in or additions to tax laws or rates, pipeline safety regulations, environmental laws, including laws governing greenhouse gases, mandates of sources of renewable energy, and other regulations.

• The performance of projects undertaken by Vectren's nonutility businesses and the success of efforts to realize value from, invest in and develop new opportunities, including but not limited to, Vectren's infrastructure services, energy services, and remaining energy marketing assets.

The Company undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of changes in actual results, changes in assumptions, or other factors affecting such statements.

ITEM 3.  QUANTITATIVE & QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The Company is exposed to various business risks associated with commodity prices, interest rates, and counter-party credit.  These financial exposures are monitored and managed by the Company as an integral part of its overall risk management program.  The Company’s risk management program includes, among other things, the use of derivatives.  The Company executes derivative contracts in the normal course of operations while buying and selling commodities and occasionally when managing interest rate risk.

The Company has in place a risk management committee that consists of senior management as well as financial and operational management.  The committee is actively involved in identifying risks as well as reviewing and authorizing risk mitigation strategies.

These risks are not significantly different from the information set forth in Item 7A Quantitative and Qualitative Disclosures About Market Risk included in the Vectren Utility Holdings, Inc. 2013 Form 10-K and is therefore not presented herein.

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ITEM 4.  CONTROLS & PROCEDURES

Changes in Internal Controls over Financial Reporting

During the quarter ended September 30, 2014, there have been no changes to the Company’s internal controls over financial reporting that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

As of September 30, 2014, the Company conducted an evaluation under the supervision and with the participation of the Chief Executive Officer and Chief Financial Officer of the effectiveness and the design and operation of the Company's disclosure controls and procedures.  Based on that evaluation, the Chief Executive Officer and the Chief Financial Officer have concluded that the Company's disclosure controls and procedures are effective as of September 30, 2014, to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is:

1) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and

2) accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

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PART II.  OTHER INFORMATION

ITEM 1.  LEGAL PROCEEDINGS

The Company is party to various legal proceedings and audits and reviews by taxing authorities and other government agencies arising in the normal course of business.  In the opinion of management, there are no legal proceedings or other regulatory reviews or audits pending against the Company that are likely to have a material adverse effect on its financial position, results of operations, or cash flows.  See the notes to the consolidated financial statements regarding commitments and contingencies, environmental matters, rate and regulatory matters.  The condensed consolidated financial statements are included in Part 1 Item 1.

ITEM 1A.  RISK FACTORS

Investors should consider carefully factors that may impact the Company’s operating results and financial condition, causing them to be materially adversely affected.  The Company’s risk factors have not materially changed from the information set forth in Item 1A Risk Factors included in the Vectren Utility Holdings 2013 Form 10-K and are therefore not presented herein.

ITEM 2.  UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Not Applicable

ITEM 3.  DEFAULTS UPON SENIOR SECURITIES

Not Applicable

ITEM 4.  MINE SAFETY DISCLOSURES

Not Applicable

ITEM 5.  OTHER INFORMATION

Not Applicable

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ITEM 6.  EXHIBITS

Exhibits and Certifications

3.1	Code of By-Laws of Vectren corporation as Most Recently Amended as of October 1, 2014 (filed and designated in Form 8-K, dated September 29, 2014, File No. 1-16739, as Exhibit 3.1)
4.1	SIGECO Supplemental Indenture dated as of September 1, 2014 (filed and designated in Form 8-K, dated September 25, 2014, File No. 1-16739, as Exhibit 4.1)
10.1	Amendment number two to Vectren Corporation Change in Control Agreement (specimen) (filed and designated in Form 8-K, dated September 29, 2014, File No. 1-16739, as Exhibit 10.1)
10.2	Credit Agreement, dated as of October 31, 2014, among Vectren Utility Holdings, Inc., as borrower (Vectren Utility); certain subsidiaries of Vectren Utility, as guarantors; Bank of America, N.A., as administrative agent, swing line lender and a letter of credit issuer; Wells Fargo Bank, National Association, JPMorgan Chase Bank, N.A. and MUFG Union Bank, N.A., as co-syndication agents and letter of credit issuers; and the other lenders named therein (filed and designated in Form 8-K, dated November 5, 2014, File No. 1-16739, as Exhibit 10.1)
31.1	Certification Pursuant To Section 302 of The Sarbanes-Oxley Act Of 2002- Chief Executive Officer
31.2	Certification Pursuant To Section 302 of The Sarbanes-Oxley Act Of 2002- Chief Financial Officer
32	Certification Pursuant To Section 906 of The Sarbanes-Oxley Act Of 2002
101	Interactive Data File.
101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema
101.CAL	XBRL Taxonomy Extension Calculation Linkbase
101.DEF	XBRL Taxonomy Extension Definition Linkbase
101.LAB	XBRL Taxonomy Extension Labels Linkbase
101.PRE	XBRL Taxonomy Extension Presentation Linkbase

46

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	VECTREN UTILITY HOLDINGS, INC.
	Registrant
November 14, 2014	/s/M. Susan Hardwick
	M. Susan Hardwick
	Senior Vice President and Chief Financial Officer
	(Signing on behalf of the registrant and as Principal Accounting & Financial Officer)

47

EX-31.1

Exhibit 31.1

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

CHIEF EXECUTIVE OFFICER CERTIFICATION

I, Carl L. Chapman, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Vectren Utility Holdings, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions)

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: November 14, 2014

/s/ Carl L. Chapman

Carl L. Chapman

Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

CHIEF FINANCIAL OFFICER CERTIFICATION

I, M. Susan Hardwick, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Vectren Utility Holdings, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions)

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: November 14, 2014

/s/ M. Susan Hardwick

M. Susan Hardwick

Senior Vice President and Chief Financial Officer

EX-32

Exhibit 32

CERTIFICATION PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

CERTIFICATION

By signing below, each of the undersigned officers hereby certifies pursuant to 18 U.S.C. § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his or her knowledge, (i) this report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in this report fairly presents, in all material respects, the financial condition and results of operations of Vectren Utility Holdings, Inc.

Signed this 14th day of November, 2014.

/s/ M. Susan Hardwick	/s/ Carl L. Chapman
(Signature of Authorized Officer)	(Signature of Authorized Officer)
M. Susan Hardwick	Carl L. Chapman
(Typed Name)	(Typed Name)
Senior Vice President and Chief Financial Officer	Chief Executive Officer
(Title)	(Title)

XML

Segment Reporting (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Jun. 30, 2014
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%
Revenues	$ 271.1	$ 267.7	$ 1,162.2	$ 1,026.0
Profitability Measure - Net income (loss)	24.3	25.3	108.5	104.6
Utility Group [Member]
Segment Reporting Information [Line Items]
Number of Reportable Segments			3
Utility Group [Member] | Gas Utility Services [Member]
Segment Reporting Information [Line Items]
Revenues	105.1	101.9	681.1	555.8
Profitability Measure - Net income (loss)	(5.1)	(3.8)	33.9	37.2
Utility Group [Member] | Electric Utility Services [Member]
Segment Reporting Information [Line Items]
Revenues	165.9	165.8	480.9	470.0
Profitability Measure - Net income (loss)	26.7	26.6	65.9	60.1
Utility Group [Member] | Other Segments [Member]
Segment Reporting Information [Line Items]
Revenues	9.6	9.5	28.7	28.5
Profitability Measure - Net income (loss)	2.7	2.5	8.7	7.3
Utility Group [Member] | Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues	$ (9.5)	$ (9.5)	$ (28.5)	$ (28.3)

XML

Subsidiary Guarantor and Consolidating Information Cash Flows (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013	Dec. 31, 2012
Net cash provided by operating activities	$ 282.4	$ 295.4
Long-term debt - net of issuance costs	63.0	232.7
Additional capital contribution from parent	4.6	4.5
Dividends to parent	(81.4)	(78.8)
Retirement of long term debt	(63.6)	(337.5)
Net change in intercompany short-term borrowings	0
Net change in short-term borrowings	31.5	59.4
Net cash used in financing activities	(45.9)	(119.7)
Consolidated subsidiary distributions	0
Proceeds from other investing activities	0.3	0.8
Capital expenditures, excluding AFUDC equity	(240.0)	(183.6)
Consolidated subsidiary investments	0
Net change in long-term intercompany notes receivable	0
Net change in short term intercompany notes receivable	0
Net cash used in investing activities	(239.7)	(182.8)
Net change in cash and cash equivalents	(3.2)	(7.1)
Cash & cash equivalents	5.4	6.2	8.6	13.3
Subsidiary Guarantors [Member]
Net cash provided by operating activities	226.3	276.1
Long-term debt - net of issuance costs	187.2	232.7
Additional capital contribution from parent	4.6	11.5
Dividends to parent	(76.2)	(73.5)
Retirement of long term debt	(63.6)	(223.6)
Net change in intercompany short-term borrowings	(32.5)	(61.5)
Net change in short-term borrowings	0	0
Net cash used in financing activities	19.5	(114.4)
Consolidated subsidiary distributions	0	0
Proceeds from other investing activities	0	0.6
Capital expenditures, excluding AFUDC equity	(221.4)	(169.4)
Consolidated subsidiary investments	0	0
Net change in long-term intercompany notes receivable	0	0
Net change in short term intercompany notes receivable	(28.7)	0
Net cash used in investing activities	(250.1)	(168.8)
Net change in cash and cash equivalents	(4.3)	(7.1)
Cash & cash equivalents	3.9	5.4	8.2	12.5
Parent Company [Member]
Net cash provided by operating activities	56.1	19.3
Long-term debt - net of issuance costs	0	124.4
Additional capital contribution from parent	4.6	4.5
Dividends to parent	(81.4)	(78.8)
Retirement of long term debt	0	(221.6)
Net change in intercompany short-term borrowings	28.6	0
Net change in short-term borrowings	31.5	59.4
Net cash used in financing activities	(16.7)	(112.1)
Consolidated subsidiary distributions	76.2	73.5
Proceeds from other investing activities	0.3	0.2
Capital expenditures, excluding AFUDC equity	(18.6)	(14.2)
Consolidated subsidiary investments	(4.6)	(11.5)
Net change in long-term intercompany notes receivable	(124.2)	(16.7)
Net change in short term intercompany notes receivable	32.6	61.5
Net cash used in investing activities	(38.3)	92.8
Net change in cash and cash equivalents	1.1	0
Cash & cash equivalents	1.5	0.8	0.4	0.8
Consolidation, Eliminations [Member]
Net cash provided by operating activities	0	0
Long-term debt - net of issuance costs	(124.2)	(124.4)
Additional capital contribution from parent	(4.6)	(11.5)
Dividends to parent	76.2	73.5
Retirement of long term debt	0	107.7
Net change in intercompany short-term borrowings	3.9	61.5
Net change in short-term borrowings	0	0
Net cash used in financing activities	(48.7)	106.8
Consolidated subsidiary distributions	(76.2)	(73.5)
Proceeds from other investing activities	0	0
Capital expenditures, excluding AFUDC equity	0	0
Consolidated subsidiary investments	4.6	11.5
Net change in long-term intercompany notes receivable	124.2	16.7
Net change in short term intercompany notes receivable	(3.9)	(61.5)
Net cash used in investing activities	48.7	(106.8)
Net change in cash and cash equivalents	0	0
Cash & cash equivalents	0	0	0	0
Consolidated Entities [Member]
Net cash provided by operating activities		295.4
Long-term debt - net of issuance costs		232.7
Additional capital contribution from parent		4.5
Dividends to parent		(78.8)
Retirement of long term debt		(337.5)
Net change in intercompany short-term borrowings		0
Net change in short-term borrowings		59.4
Net cash used in financing activities		(119.7)
Consolidated subsidiary distributions		0
Proceeds from other investing activities		0.8
Capital expenditures, excluding AFUDC equity		(183.6)
Consolidated subsidiary investments		0
Net change in long-term intercompany notes receivable		0
Net change in short term intercompany notes receivable		0
Net cash used in investing activities		(182.8)
Net change in cash and cash equivalents		(7.1)
Cash & cash equivalents	$ 5.4	$ 6.2	$ 8.6	$ 13.3

XML

Excise and Utility Receipts Taxes

9 Months Ended

Sep. 30, 2014

Excise and Utility Receipts Taxes [Abstract]

Excise and Utility Receipts Taxes

Excise and Utility Receipts Taxes

Excise taxes and a portion of utility receipts taxes are included in rates charged to customers.  Accordingly, the Company records these taxes received as a component of operating revenues, which totaled $4.9 million and $4.8 million in the three months ended September 30, 2014 and 2013, respectively. For the nine months ended September 30, 2014 and 2013, these taxes totaled $23.3 million and $20.9 million, respectively.  Expense associated with excise and utility receipts taxes are recorded as a component of Taxes other than income taxes.

XML

Financing Activities (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2014
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 350
SIGECO [Member] | Bonds [Member] | Tax Exempt Debt 2044400 [Member]
Debt Instrument [Line Items]
Stated percentage rate (in hundredths)	4.00%
Maturity date	Sep. 01, 2044
Debt Instrument, Face Amount	22.3
SIGECO [Member] | Bonds [Member] | Tax Exempt Debt 2025variable [Member]
Debt Instrument [Line Items]
Maturity date	Jul. 01, 2025
Interest Rate Type	variable
Debt Instrument, Face Amount	$ 41.3

XML

Transactions with Other Vectren Companies and Affiliates Transactions with Other Vectren Companies and Afffiliates (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Vectren Fuels Inc. [Member]
Transactions with Other Vectren Companies and Affiliates [Line Items]
Expenses from transactions with related party	$ 30.0	$ 24.5	$ 98.6	$ 76.1
Vectren Infrastructure Services Corporation [Member]
Transactions with Other Vectren Companies and Affiliates [Line Items]
Expenses from transactions with related party	30.1	15.9	63.5	39.5
ProLiance [Member]
Transactions with Other Vectren Companies and Affiliates [Line Items]
Expenses from transactions with related party			0	200.5
Percentage of purchases from single third party	83.00%		83.00%
Support Services & Purchases [Member]
Transactions with Other Vectren Companies and Affiliates [Line Items]
Cost of corporate and general and administrative services	$ 13.0	$ 10.4	$ 41.7	$ 36.7

XML

Rate & Regulatory Matters (Details) (USD $)	9 Months Ended		12 Months Ended			9 Months Ended				9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2012	Dec. 31, 2011	Feb. 01, 2014	Sep. 30, 2014 Ohio [Member] Ohio Recovery and Deferral Mechanisms [Member]	Dec. 31, 2013 Ohio [Member] Ohio Recovery and Deferral Mechanisms [Member]	Sep. 30, 2014 INDIANA Indiana Recovery and Deferral Mechanisms [Member]	Dec. 31, 2013 INDIANA Indiana Recovery and Deferral Mechanisms [Member]	Sep. 30, 2014 INDIANA Pipeline Safety Law [Member]	Sep. 30, 2014 SIGECO [Member] INDIANA Indiana Recovery and Deferral Mechanisms [Member]	Sep. 30, 2014 Indiana Gas [Member] INDIANA Indiana Recovery and Deferral Mechanisms [Member]	Sep. 30, 2014 Indiana Gas [Member] INDIANA Indiana Gas GCA Cost Recovery [Member]
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items]
Cumulative gross plant invesment made under Distribution Replacement Rider						$ 132,900,000
Regulatory Asset associated with DRR deferrals of depreciation and post in-service carrying costs						12,100,000	9,300,000
Period of extended DRR term						5
Amount of Capital Investment Expected Over Next Five Years Recoverable Under DRR						200,000,000
Time period (in months) included in VEDO application						15
Bill impact per customer per month						1.50
Allowable capital expenditures under Vectren programs											3,000,000	20,000,000
Limitations of deferrals of debt-related post in service carrying costs											3	4
Regulatory Assset balance associated with Vectren north and south programs								15,300,000	12,100,000
Expected Seven Year Period Modernization Investment										900,000,000
Amount of economic development expenditures										30,000,000
Expected annual operating costs associated with new pipeline safety regulations										15,000,000
Initial DRR term						5
Original amount of recovery opposed by OUCC													3,900,000
Amount of recovery supported by OUCC													3,000,000
Vectren South Electric Environmental Compliance Filing [Abstract]
Lower range of request for approval of capital investments on coal-fired generation units	70,000,000
Upper range of request for approval of capital investments on coal-fired generation units	90,000,000
Coal Procurement Procedures [Abstract]
Number of years for recovery of coal costs	6 years
Cumulative total deferrals related to coal purchases	37,100,000				42,400,000
Vectren South Electric Demand Side Management Program Filing [Abstract]
Number of years in initial demand side management program approved by the IURC (in years)	3
Maximum Deferral Of Lost Margin Associated With Small Customer DSM Programs			3,000,000	1,000,000
Electric revenue recognized associated with lost margin recovery	6,600,000	3,500,000
Percent of industrial load opt out of applicable energy efficiency programs	71.00%
FERC Return On Equity Complaint [Abstract]
Reduced return on equity percentage sought by third party	9.15%
Equity component, upper limit, as a percentage, sought by third party	50.00%
Gross Investment In Qualifying Transmission Projects	157,700,000
Net Investment in Qualifying Transmission Projects	$ 144,500,000
Incentive return granted on qualifying investments in NETO	11.14%
Current return on equity used in MISO transmission owners rates	12.38%
FERC approved ROE in NETO case	10.57%

XML

Environmental Matters (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2014 T MW	Dec. 31, 2013
Site Contingency [Line Items]
SIGECO investment in Property, Plant and Equipment, Pollution control equipment	$ 411
Property, Plant and Equipment, amount of investment in pollution control equipment included in rate base	411
Percentage of coal fired generating fleet currently being scrubbed for SO2 (in hundredths)	100.00%
Percentage of coal fired generating fleet currently controlled for NOx (in hundredths)	90.00%
Cost of most of the allowances granted to company for NOx and SO2 inventory usage	0
Indiana Senate Bill 251 [Abstract]
Percentage of total electricity obtained by supplier to meet customer needs	10.00%
Power generation capacity for acquired landfill gas generations facility (in megawatts)	3
Long term contract for purchase of electric power generated by wind energy (in megawatts)	80
Percentage of total electricity obtained by the supplier to meet the energy needs of its retail customers provided by clean energy sources (in hundredths)	4.00%
Clean Water Act [Abstract]
Potential capital investment of using 'best technology available' (BTA) to minimize adverse impacts in a body of water - lower range	4
Potential capital investment of using 'best technology available' (BTA) to minimize adverse impacts in a body of water - upper range	8
Coal Ash Waste Disposal and Ash Ponds [Abstract]
Estimated capital expenditures to comply with ash pond and coal ash disposal regulations	30
Potential estimated capital expenditures to comply with ash pond and coal ash disposal regulations with stringent alternative	100
Estimated annual compliance costs maximum with ash pond and coal ash disposal regulation	5
Climate Changes [Abstract]
Maximum level of greenhouse gas emissions that prompts requirement to obtain permit for facilities to construct new facility of significant modification to existing facility (in tons)	75,000
Vectren's share of Indiana's total CO2 emmisions in 2013 (in tons)	6,300,000
Vectren's share of Indiana's total CO2 emissions in 2013 (as a percent)	6.00%
Percent reduction of Vectren's CO2 emissions since 2005	23.00%
Vectren's emission rate (as measured in lbs CO2/MWh) prior to installation of new technology	1,967
Vectren's emission rate (as measured in lbs CO2/MWh) after installation of new technology	1,922
Percentage reduction of lbs CO2/MWh since 2005	3.00%
Manufactured Gas Plants
Site contingency, accrual, undiscounted amount	43.4
Accrual for Environmental Loss Contingencies	4.3	5.7
Indiana Gas [Member]
Manufactured Gas Plants
Site contingency, accrual, undiscounted amount	23.2
Number of sites identified with potential remedial responsibility for entity (in number of sites)	26
Environmental cost recognized, recover from insurance carriers credited to expense	20.8
SIGECO [Member]
Manufactured Gas Plants
Site contingency, accrual, undiscounted amount	20.2
Number of sites identified with potential remedial responsibility for entity (in number of sites)	5
Environmental cost recognized, recover from insurance carriers credited to expense	14.3
Expected Site Contingency Recovery from Insurance Carriers of Environmental Remediation Costs	$ 15.8

XML

Subsidiary Guarantor and Consolidating Information

9 Months Ended

Sep. 30, 2014

Subsidiary Guarantor and Consolidating Information [Abstract]

Subsidiary Guarantor and Consolidating Information [Text Block]

Subsidiary Guarantor and Consolidating Information

The Company’s three operating utility companies, SIGECO, Indiana Gas, and VEDO are guarantors of Utility Holdings’ $350 million in short-term credit facilities, of which approximately $60 million was outstanding at September 30, 2014, and Utility Holdings’ has unsecured senior notes with a par value of $875 million outstanding at September 30, 2014.  The guarantees are full and unconditional and joint and several, and Utility Holdings has no direct subsidiaries other than the subsidiary guarantors.   However, Utility Holdings does have operations other than those of the subsidiary guarantors.  Pursuant to Item 3-10 of Regulation S-X, disclosure of the results of operations and balance sheets of the subsidiary guarantors, which are 100 percent owned, separate from the parent company’s operations is required.  Following are consolidating financial statements including information on the combined operations of the subsidiary guarantors separate from the other operations of the parent company.  Pursuant to a tax sharing agreement, consolidating tax effects, which are calculated on a separate return basis, are reflected at the parent level.

Condensed Consolidating Balance Sheet as of September 30, 2014 (in millions):

ASSETS	Subsidiary		Parent		Eliminations &
	Guarantors		Company		Reclassifications			Consolidated
Current Assets
Cash & cash equivalents	$	3.9	$	1.5	$	—		$	5.4
Accounts receivable - less reserves	68.8		—		—			68.8
Intercompany receivables	29.0		64.0		(93.0		)	—
Accrued unbilled revenues	41.8		—		—			41.8
Inventories	109.7		—		—			109.7
Recoverable fuel & natural gas costs	25.5		—		—			25.5
Prepayments & other current assets	55.7		26.8		(34.8		)	47.7
Total current assets	334.4		92.3		(127.8		)	298.9
Utility Plant
Original cost	5,599.2		—		—			5,599.2
Less:  accumulated depreciation & amortization	2,250.3		—		—			2,250.3
Net utility plant	3,348.9		—		—			3,348.9
Investments in consolidated subsidiaries	—		1,404.0		(1,404.0		)	—
Notes receivable from consolidated subsidiaries	—		820.6		(820.6		)	—
Investments in unconsolidated affiliates	0.2		—		—			0.2
Other investments	20.9		4.2		—			25.1
Nonutility property - net	1.8		147.0		—			148.8
Goodwill - net	205.0		—		—			205.0
Regulatory assets	109.7		21.9		—			131.6
Other assets	30.1		0.6		(10.5		)	20.2
TOTAL ASSETS	$	4,051.0	$	2,490.6	$	(2,362.9	)	$	4,178.7
LIABILITIES & SHAREHOLDER'S EQUITY	Subsidiary		Parent		Eliminations &
	Guarantors		Company		Reclassifications			Consolidated
Current Liabilities
Accounts payable	$	104.2	$	5.9	$	—		$	110.1
Intercompany payables	23.5		—		(23.5		)	—
Payables to other Vectren companies	50.6		—		—			50.6
Accrued liabilities	130.9		22.0		(34.8		)	118.1
Short-term borrowings	—		60.1		—			60.1
Intercompany short-term borrowings	40.5		29.0		(69.5		)	—
Current maturities of long-term debt	5.0		—		—			5.0
Total current liabilities	354.7		117.0		(127.8		)	343.9
Long-Term Debt
Long-term debt	377.6		874.7		—			1,252.3
Long-term debt due to VUHI	820.6		—		(820.6		)	—
Total long-term debt - net	1,198.2		874.7		(820.6		)	1,252.3
Deferred Credits & Other Liabilities
Deferred income taxes	596.8		28.2		—			625.0
Regulatory liabilities	403.3		1.5		—			404.8
Deferred credits & other liabilities	94.0		4.7		(10.5		)	88.2
Total deferred credits & other liabilities	1,094.1		34.4		(10.5		)	1,118.0
Common Shareholder's Equity
Common stock (no par value)	805.5		792.3		(805.5		)	792.3
Retained earnings	598.5		672.2		(598.5		)	672.2
Total common shareholder's equity	1,404.0		1,464.5		(1,404.0		)	1,464.5
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	$	4,051.0	$	2,490.6	$	(2,362.9	)	$	4,178.7

Condensed Consolidating Balance Sheet as of December 31, 2013 (in millions):

ASSETS	Subsidiary		Parent		Eliminations &
	Guarantors		Company		Reclassifications			Consolidated
Current Assets
Cash & cash equivalents	$	8.2	$	0.4	$	—		$	8.6
Accounts receivable - less reserves	112.1		—		—			112.1
Intercompany receivables	0.3		84.8		(85.1		)	—
Accrued unbilled revenues	113.5		—		—			113.5
Inventories	89.9		—		—			89.9
Recoverable fuel & natural gas costs	5.5		—		—			5.5
Prepayments & other current assets	37.3		40.1		(35.0		)	42.4
Total current assets	366.8		125.3		(120.1		)	372.0
Utility Plant
Original cost	5,389.6		—		—			5,389.6
Less:  accumulated depreciation & amortization	2,165.3		—		—			2,165.3
Net utility plant	3,224.3		—		—			3,224.3
Investments in consolidated subsidiaries	—		1,375.8		(1,375.8		)	—
Notes receivable from consolidated subsidiaries	—		696.4		(696.4		)	—
Investments in unconsolidated affiliates	0.2		—		—			0.2
Other investments	22.8		4.5		—			27.3
Nonutility property - net	2.2		148.3		—			150.5
Goodwill - net	205.0		—		—			205.0
Regulatory assets	113.4		22.8		—			136.2
Other assets	32.2		1.0		(7.9		)	25.3
TOTAL ASSETS	$	3,966.9	$	2,374.1	$	(2,200.2	)	$	4,140.8
LIABILITIES & SHAREHOLDER'S EQUITY	Subsidiary		Parent		Eliminations &
	Guarantors		Company		Reclassifications			Consolidated
Current Liabilities
Accounts payable	$	161.6	$	10.5	$	—		$	172.1
Intercompany payables	11.7		—		(11.7		)	—
Payables to other Vectren companies	24.6		—		—			24.6
Accrued liabilities	150.3		12.1		(35.0		)	127.4
Short-term borrowings	—		28.6		—			28.6
Intercompany short-term borrowings	73.1		0.3		(73.4		)	—
Total current liabilities	421.3		51.5		(120.1		)	352.7
Long-Term Debt
Long-term debt - net of current maturities &
debt subject to tender	382.5		874.6		—			1,257.1
Long-term debt due to VUHI	696.4		—		(696.4		)	—
Total long-term debt - net	1,078.9		874.6		(696.4		)	1,257.1
Deferred Credits & Other Liabilities
Deferred income taxes	616.9		10.5		—			627.4
Regulatory liabilities	385.7		1.6		—			387.3
Deferred credits & other liabilities	88.3		3.1		(7.9		)	83.5
Total deferred credits & other liabilities	1,090.9		15.2		(7.9		)	1,098.2
Common Shareholder's Equity
Common stock (no par value)	800.9		787.7		(800.9		)	787.7
Retained earnings	574.9		645.1		(574.9		)	645.1
Total common shareholder's equity	1,375.8		1,432.8		(1,375.8		)	1,432.8
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	$	3,966.9	$	2,374.1	$	(2,200.2	)	$	4,140.8

Condensed Consolidating Statement of Income for the three months ended September 30, 2014 (in millions):

	Subsidiary Guarantors		Parent Company			Eliminations & Reclassifications			Consolidated
OPERATING REVENUES
Gas utility	$	105.1	$	—		$	—		$	105.1
Electric utility	165.9		—			—			165.9
Other	—		9.6			(9.5		)	0.1
Total operating revenues	271.0		9.6			(9.5		)	271.1
OPERATING EXPENSES
Cost of gas sold	28.8		—			—			28.8
Cost of fuel & purchased power	50.3		—			—			50.3
Other operating	88.6		—			(8.7		)	79.9
Depreciation & amortization	44.8		6.1			0.1			51.0
Taxes other than income taxes	11.2		0.5			—			11.7
Total operating expenses	223.7		6.6			(8.6		)	221.7
OPERATING INCOME	47.3		3.0			(0.9		)	49.4
Other income - net	3.9		10.8			(9.9		)	4.8
Interest expense	16.1		11.3			(10.8		)	16.6
INCOME BEFORE INCOME TAXES	35.1		2.5			—			37.6
Income taxes	13.5		(0.2		)	—			13.3
Equity in earnings of consolidated companies, net of tax	—		21.6			(21.6		)	—
NET INCOME	$	21.6	$	24.3		$	(21.6	)	$	24.3

Condensed Consolidating Statement of Income for the three months ended September 30, 2013 (in millions):

	Subsidiary Guarantors		Parent Company		Eliminations & Reclassifications			Consolidated
OPERATING REVENUES
Gas utility	$	101.9	$	—	$	—		$	101.9
Electric utility	165.8		—		—			165.8
Other	—		9.4		(9.4		)	—
Total operating revenues	267.7		9.4		(9.4		)	267.7
OPERATING EXPENSES
Cost of gas sold	27.5		—		—			27.5
Cost of fuel & purchased power	50.4		—		—			50.4
Other operating	83.1		—		(9.1		)	74.0
Depreciation & amortization	44.1		5.4		0.2			49.7
Taxes other than income taxes	11.2		0.4		—			11.6
Total operating expenses	216.3		5.8		(8.9		)	213.2
OPERATING INCOME	51.4		3.6		(0.5		)	54.5
Other income - net	1.2		9.8		(9.0		)	2.0
Interest expense	14.7		10.4		(9.5		)	15.6
INCOME BEFORE INCOME TAXES	37.9		3.0		—			40.9
Income taxes	15.0		0.6		—			15.6
Equity in earnings of consolidated companies, net of tax	—		22.9		(22.9		)	—
NET INCOME	$	22.9	$	25.3	$	(22.9	)	$	25.3

Condensed Consolidating Statement of Income for the nine months endedSeptember 30, 2014 (in millions):

	Subsidiary Guarantors		Parent Company			Eliminations & Reclassifications			Consolidated
OPERATING REVENUES
Gas utility	$	681.1	$	—		$	—		$	681.1
Electric utility	480.9		—			—			480.9
Other	—		28.7			(28.5		)	0.2
Total operating revenues	1,162.0		28.7			(28.5		)	1,162.2
OPERATING EXPENSES
Cost of gas sold	343.4		—			—			343.4
Cost of fuel & purchased power	155.4		—			—			155.4
Other operating	286.4		—			(26.7		)	259.7
Depreciation & amortization	133.8		17.4			0.3			151.5
Taxes other than income taxes	42.9		1.3			0.1			44.3
Total operating expenses	961.9		18.7			(26.3		)	954.3
OPERATING INCOME	200.1		10.0			(2.2		)	207.9
Other income - net	9.7		32.4			(29.7		)	12.4
Interest expense	48.0		33.9			(31.9		)	50.0
INCOME BEFORE INCOME TAXES	161.8		8.5			—			170.3
Income taxes	62.0		(0.2		)	—			61.8
Equity in earnings of consolidated companies, net of tax	—		99.8			(99.8		)	—
NET INCOME	$	99.8	$	108.5		$	(99.8	)	$	108.5

Condensed Consolidating Statement of Income for the nine months endedSeptember 30, 2013 (in millions):

	Subsidiary Guarantors		Parent Company		Eliminations & Reclassifications			Consolidated
OPERATING REVENUES
Gas utility	$	555.8	$	—	$	—		$	555.8
Electric utility	470.0		—		—			470.0
Other	—		28.4		(28.2		)	0.2
Total operating revenues	1,025.8		28.4		(28.2		)	1,026.0
OPERATING EXPENSES
Cost of gas sold	235.4		—		—			235.4
Cost of fuel & purchased power	154.5		—		—			154.5
Other operating	264.3		—		(27.4		)	236.9
Depreciation & amortization	130.5		15.9		0.4			146.8
Taxes other than income taxes	40.1		1.2		—			41.3
Total operating expenses	824.8		17.1		(27.0		)	814.9
OPERATING INCOME	201.0		11.3		(1.2		)	211.1
Other income - net	4.9		28.6		(26.7		)	6.8
Interest expense	44.7		32.4		(27.9		)	49.2
INCOME BEFORE INCOME TAXES	161.2		7.5		—			168.7
Income taxes	63.8		0.3		—			64.1
Equity in earnings of consolidated companies, net of tax	—		97.4		(97.4		)	—
NET INCOME	$	97.4	$	104.6	$	(97.4	)	$	104.6

Condensed Consolidating Statement of Cash Flows for the nine months endedSeptember 30, 2014 (in millions):

	Subsidiary Guarantors			Parent Company			Eliminations			Consolidated
NET CASH PROVIDED BY OPERATING ACTIVITIES	$	226.3		$	56.1		$	—		$	282.4
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from
Long-term debt - net of issuance costs	187.2			—			(124.2		)	63.0
Additional capital contribution from parent	4.6			4.6			(4.6		)	4.6
Requirements for:
Dividends to parent	(76.2		)	(81.4		)	76.2			(81.4		)
Retirement of long term debt	(63.6		)	—			—			(63.6		)
Net change in intercompany short-term borrowings	(32.5		)	28.6			3.9			—
Net change in short-term borrowings	—			31.5			—			31.5
Net cash used in financing activities	19.5			(16.7		)	(48.7		)	(45.9		)
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from:
Consolidated subsidiary distributions	—			76.2			(76.2		)	—
Other investing activities	—			0.3			—			0.3
Requirements for:
Capital expenditures, excluding AFUDC equity	(221.4		)	(18.6		)	—			(240.0		)
Consolidated subsidiary investments	—			(4.6		)	4.6			—
Net change in long-term intercompany notes receivable	—			(124.2		)	124.2			—
Net change in short-term intercompany notes receivable	(28.7		)	32.6			(3.9		)	—
Net cash used in investing activities	(250.1		)	(38.3		)	48.7			(239.7		)
Net change in cash & cash equivalents	(4.3		)	1.1			—			(3.2		)
Cash & cash equivalents at beginning of period	8.2			0.4			—			8.6
Cash & cash equivalents at end of period	$	3.9		$	1.5		$	—		$	5.4

Condensed Consolidating Statement of Cash Flows for the nine months endedSeptember 30, 2013 (in millions):

	Subsidiary Guarantors			Parent Company			Eliminations			Consolidated
NET CASH PROVIDED BY OPERATING ACTIVITIES	$	276.1		$	19.3		$	—		$	295.4
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from:
Long-term debt, net of issuance costs	232.7			124.4			(124.4		)	232.7
Additional capital contribution from parent	11.5			4.5			(11.5		)	4.5
Requirements for:
Dividends to parent	(73.5		)	(78.8		)	73.5			(78.8		)
Retirement of long term debt	(223.6		)	(221.6		)	107.7			(337.5		)
Net change in intercompany short-term borrowings	(61.5		)	—			61.5			—
Net change in short-term borrowings	—			59.4			—			59.4
Net cash used in financing activities	(114.4		)	(112.1		)	106.8			(119.7		)
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from:
Consolidated subsidiary distributions	—			73.5			(73.5		)	—
Other investing activities	0.6			0.2			—			0.8
Requirements for:
Capital expenditures, excluding AFUDC equity	(169.4		)	(14.2		)	—			(183.6		)
Consolidated subsidiary investments	—			(11.5		)	11.5			—
Net change in long-term intercompany notes receivable	—			(16.7		)	16.7			—
Net change in short-term intercompany notes receivable	—			61.5			(61.5		)	—
Net cash used in investing activities	(168.8		)	92.8			(106.8		)	(182.8		)
Net change in cash & cash equivalents	(7.1		)	—			—			(7.1		)
Cash & cash equivalents at beginning of period	12.5			0.8			—			13.3
Cash & cash equivalents at end of period	$	5.4		$	0.8		$	—		$	6.2

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Fair Value Measurements (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2014	Dec. 31, 2013	Sep. 30, 2013	Dec. 31, 2012
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Period over which call premium on reacquisition of long-term debt	15
Short-term borrowings	$ 60.1	$ 28.6
Cash and Cash Equivalents, at Carrying Value	5.4	8.6	6.2	13.3
Estimated Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Fair Value	1,398.2	1,317.4
Short-term Debt, Fair Value	60.1	28.6
Cash and cash equivalents	5.4	8.6
Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Fair Value	1,257.3	1,257.1
Short-term Debt, Fair Value	60.1	28.6
Cash and cash equivalents	$ 5.4	$ 8.6

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CONSOLIDATED CONDENSED BALANCE SHEETS (Unaudited) (USD $) In Millions, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Assets, Current [Abstract]
Cash & cash equivalents	$ 5.4	$ 8.6
Accounts receivable - less reserves of $3.4 & $5.0, respectively	68.8	112.1
Accrued unbilled revenues	41.8	113.5
Inventories	109.7	89.9
Recoverable fuel & natural gas costs	25.5	5.5
Prepayments & other current assets	47.7	42.4
Total current assets	298.9	372.0
Utility Plant [Abstract]
Original cost	5,599.2	5,389.6
Less: accumulated depreciation & amortization	2,250.3	2,165.3
Net utility plant	3,348.9	3,224.3
Investments in unconsolidated affiliates	0.2	0.2
Other Investments	25.1	27.3
Nonutility plant - net	148.8	150.5
Goodwill - net	205.0	205.0
Regulatory assets	131.6	136.2
Other assets	20.2	25.3
TOTAL ASSETS	4,178.7	4,140.8
Current Liabilities [Abstract]
Accounts payable	110.1	172.1
Payables to other Vectren companies	50.6	24.6
Accrued liabilities	118.1	127.4
Short-term borrowings	60.1	28.6
Current maturities of long-term debt	5.0	0
Total current liabilities	343.9	352.7
Long-Term Debt - Net of Current Maturities	1,252.3	1,257.1
Deferred Credits & Other Liabilities [Abstract]
Deferred income taxes	625.0	627.4
Regulatory liabilities	404.8	387.3
Deferred credits & other liabilities	88.2	83.5
Total deferred credits and other liabilities	1,118.0	1,098.2
Commitments & Contingencies (Notes 8 - 10)
Common Shareholder's Equity [Abstract]
Common stock (no par value)	792.3	787.7
Retained earnings	672.2	645.1
Total common shareholders' equity	1,464.5	1,432.8
TOTAL LIABILITIES and SHAREHOLDERS' EQUITY	$ 4,178.7	$ 4,140.8

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Organization and Nature of Operations

9 Months Ended

Sep. 30, 2014

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Organization and Nature of Operations

Organization and Nature of Operations

Vectren Utility Holdings, Inc. (the Company, Utility Holdings or VUHI), an Indiana corporation, was formed on March 31, 2000 to serve as the intermediate holding company for Vectren Corporation’s (Vectren) three operating public utilities:  Indiana Gas Company, Inc. (Indiana Gas), Southern Indiana Gas and Electric Company (SIGECO), and Vectren Energy Delivery of Ohio, Inc. (VEDO).  Utility Holdings also has other assets that provide information technology and other services to the three utilities.  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 574,000 natural gas customers located in central and southern Indiana. SIGECO provides energy delivery services to approximately 143,000 electric customers and approximately 110,000 gas customers located near Evansville in southwestern Indiana.  SIGECO also owns and operates electric generation assets to serve its electric customers and optimizes those assets in the wholesale power market.  Indiana Gas and SIGECO generally do business as Vectren Energy Delivery of Indiana.  VEDO provides energy delivery services to approximately 313,000 natural gas customers located near Dayton in west central Ohio.

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Organization and Nature of Operations (Details)	9 Months Ended
	Sep. 30, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of public utility subsidiaries owned by wholly owned subsidiary, Vectren Utility Holdings, Inc. (in number of subsidiaries)	3
Estimated number of natural gas customers located in central and southern Indiana serviced by Indiana Gas Company, Inc. (in number of customers)	574,000
Estimated number of electric customers located near Evansville in southwestern Indiana serviced by Southern Indiana Gas and Electric Company (in number of customers)	143,000
Estimated number of natural gas customers located near Evansville in southwestern Indiana serviced by Southern Indiana Gas and Electric Company (in number of customers)	110,000
Estimated number of natural gas customers located near Dayton in west central Ohio serviced by the Ohio operations (in number of customers)	313,000

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Subsidiary Guarantor and Consolidating Information Income Statement (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
OPERATING REVENUES [Abstract]
Gas utility	$ 105.1	$ 101.9	$ 681.1	$ 555.8
Electric utility	165.9	165.8	480.9	470.0
Other	0.1	0	0.2	0.2
Total operating revenues	271.1	267.7	1,162.2	1,026.0
OPERATING EXPENSES [Abstract]
Cost of gas sold	28.8	27.5	343.4	235.4
Cost of fuel & purchased power	50.3	50.4	155.4	154.5
Other operating	79.9	74.0	259.7	236.9
Depreciation & Amortization	51.0	49.7	151.5	146.8
Taxes other than income taxes	11.7	11.6	44.3	41.3
Total operating expenses	221.7	213.2	954.3	814.9
OPERATING INCOME	49.4	54.5	207.9	211.1
Other income - net	4.8	2.0	12.4	6.8
Interest Expense	16.6	15.6	50.0	49.2
INCOME BEFORE INCOME TAXES	37.6	40.9	170.3	168.7
Income taxes	13.3	15.6	61.8	64.1
NET INCOME	24.3	25.3	108.5	104.6
Subsidiary Guarantors [Member]
OPERATING REVENUES [Abstract]
Gas utility	105.1	101.9	681.1	555.8
Electric utility	165.9	165.8	480.9	470.0
Other	0	0	0	0
Total operating revenues	271.0	267.7	1,162.0	1,025.8
OPERATING EXPENSES [Abstract]
Cost of gas sold	28.8	27.5	343.4	235.4
Cost of fuel & purchased power	50.3	50.4	155.4	154.5
Other operating	88.6	83.1	286.4	264.3
Depreciation & Amortization	44.8	44.1	133.8	130.5
Taxes other than income taxes	11.2	11.2	42.9	40.1
Total operating expenses	223.7	216.3	961.9	824.8
OPERATING INCOME	47.3	51.4	200.1	201.0
Other income - net	3.9	1.2	9.7	4.9
Interest Expense	16.1	14.7	48.0	44.7
INCOME BEFORE INCOME TAXES	35.1	37.9	161.8	161.2
Income taxes	13.5	15.0	62.0	63.8
Equity in earnings of consolidated companies, net of tax	0	0	0	0
NET INCOME	21.6	22.9	99.8	97.4
Parent Company [Member]
OPERATING REVENUES [Abstract]
Gas utility	0	0	0	0
Electric utility	0	0	0	0
Other	9.6	9.4	28.7	28.4
Total operating revenues	9.6	9.4	28.7	28.4
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	6.1	5.4	17.4	15.9
Taxes other than income taxes	0.5	0.4	1.3	1.2
Total operating expenses	6.6	5.8	18.7	17.1
OPERATING INCOME	3.0	3.6	10.0	11.3
Other income - net	10.8	9.8	32.4	28.6
Interest Expense	11.3	10.4	33.9	32.4
INCOME BEFORE INCOME TAXES	2.5	3.0	8.5	7.5
Income taxes	(0.2)	0.6	(0.2)	0.3
Equity in earnings of consolidated companies, net of tax	21.6	22.9	99.8	97.4
NET INCOME	24.3	25.3	108.5	104.6
Consolidation, Eliminations [Member]
OPERATING REVENUES [Abstract]
Gas utility	0	0	0	0
Electric utility	0	0	0	0
Other	(9.5)	(9.4)	(28.5)	(28.2)
Total operating revenues	(9.5)	(9.4)	(28.5)	(28.2)
OPERATING EXPENSES [Abstract]
Cost of gas sold	0	0	0	0
Cost of fuel & purchased power	0	0	0	0
Other operating	(8.7)	(9.1)	(26.7)	(27.4)
Depreciation & Amortization	0.1	0.2	0.3	0.4
Taxes other than income taxes	0	0	0.1	0
Total operating expenses	(8.6)	(8.9)	(26.3)	(27.0)
OPERATING INCOME	(0.9)	(0.5)	(2.2)	(1.2)
Other income - net	(9.9)	(9.0)	(29.7)	(26.7)
Interest Expense	(10.8)	(9.5)	(31.9)	(27.9)
INCOME BEFORE INCOME TAXES	0	0	0	0
Income taxes	0	0	0	0
Equity in earnings of consolidated companies, net of tax	(21.6)	(22.9)	(99.8)	(97.4)
NET INCOME	(21.6)	(22.9)	(99.8)	(97.4)
Consolidated Entities [Member]
OPERATING REVENUES [Abstract]
Gas utility	105.1	101.9	681.1	555.8
Electric utility	165.9	165.8	480.9	470.0
Other	0.1	0	0.2	0.2
Total operating revenues	271.1	267.7	1,162.2	1,026.0
OPERATING EXPENSES [Abstract]
Cost of gas sold	28.8	27.5	343.4	235.4
Cost of fuel & purchased power	50.3	50.4	155.4	154.5
Other operating	79.9	74.0	259.7	236.9
Depreciation & Amortization	51.0	49.7	151.5	146.8
Taxes other than income taxes	11.7	11.6	44.3	41.3
Total operating expenses	221.7	213.2	954.3	814.9
OPERATING INCOME	49.4	54.5	207.9	211.1
Other income - net	4.8	2.0	12.4	6.8
Interest Expense	16.6	15.6	50.0	49.2
INCOME BEFORE INCOME TAXES	37.6	40.9	170.3	168.7
Income taxes	13.3	15.6	61.8	64.1
Equity in earnings of consolidated companies, net of tax	0	0	0	0
NET INCOME	$ 24.3	$ 25.3	$ 108.5	$ 104.6

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Basis of Presentation

9 Months Ended

Sep. 30, 2014

Basis of Presentation [Abstract]

Basis of Presentation

Basis of Presentation

The interim condensed consolidated financial statements included in this report have been prepared by the Company, without audit, as provided in the rules and regulations of the Securities and Exchange Commission and include a review of subsequent events through the date the financial statements were issued.  Certain information and note disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States have been omitted as provided in such rules and regulations.  The information in this report reflects all adjustments which are, in the opinion of management, necessary to fairly state the interim periods presented, inclusive of adjustments that are normal and recurring in nature.  These condensed consolidated financial statements and related notes should be read in conjunction with the Company’s audited annual consolidated financial statements for the year ended December 31, 2013, filed with the Securities and Exchange Commission on March 5, 2014, on Form 10-K.  Because of the seasonal nature of the Company’s utility operations, the results shown on a quarterly basis are not necessarily indicative of annual results.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the statements and the reported amounts of revenues and expenses during the reporting periods.  Actual results could differ from those estimates.

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CONSOLIDATED CONDENSED BALANCE SHEETS (Unaudited) (Parenthetical) (USD $) In Millions, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Assets, Current [Abstract]
Allowance for Doubtful Accounts Receivable, Current	$ 3.4	$ 5.0

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Impact of Recently Issued Accounting Principles (Notes)

9 Months Ended

Sep. 30, 2014

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

New Accounting Pronouncements and Changes in Accounting Principles [Text Block]

Impact of Recently Issued Accounting Principles

Revenue Recognition Guidance

In May 2014, the FASB issued new accounting guidance to clarify the principles for recognizing revenue and to develop a common revenue standard for GAAP and IFRS. The amendments in this guidance state that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This new guidance requires improved disclosures to help users of financial statements better understand the nature, amount, timing, and uncertainty of revenue that is recognized. For a public entity, the guidance is effective for annual reporting periods beginning after December 15, 2016, with early adoption not permitted. An entity should apply the amendments in this update retrospectively to each prior reporting period presented or retrospectively with the cumulative effect of initially applying this update recognized at the date of initial application. The Company is currently evaluating the standard to understand the overall impact it will have on the financial statements.

Financial Reporting of Discontinued Operations

In April 2014, the FASB issued new accounting guidance on reporting discontinued operations and disclosures of disposals of a company or entity. The guidance changes the criteria for reporting discontinued operations and provides for enhanced disclosures in this area. Under the new guidance, only disposals representing a strategic shift in operations should be presented as discontinued operations. Those strategic shifts should have a major effect on the organization's operations and financial results. Additionally, the new guidance requires expanded disclosures about discontinued operations to provide more information about the assets, liabilities, income, and expenses of discontinued operations. The new guidance also requires disclosure of the pre-tax income attributable to a disposal of a significant part of an organization that does not qualify for discontinued operations reporting. This guidance is effective for fiscal years beginning on or after December 15, 2014, with early adoption permitted. The Company is currently evaluating the impact of this guidance, if any.

Financial Reporting of Going Concern

In August 2014, the FASB issued new accounting guidance with respect to reporting on an entity's ability to continue as a going concern. This new guidance requires management to assess an entity's ability to continue as a going concern by incorporating and expanding upon certain principles that are currently in U.S. auditing standards, which requires disclosure surrounding what constitutes substantial doubt for the entity, including disclosure of management's plans to mitigate and alleviate substantial doubt. This guidance is effective for annual periods beginning after December 15, 2016, and for annual and interim periods thereafter, with early application permitted. Adoption of this guidance will not have a material impact on the Company’s financial statements.

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Document and Entity Information	9 Months Ended
	Sep. 30, 2014	Oct. 31, 2014
Entity Information [Line Items]
Entity Registrant Name	VECTREN UTILITY HOLDINGS INC
Entity Central Index Key	0001129542
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		10
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	Q3
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2014

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Segment Reporting

9 Months Ended

Sep. 30, 2014

Segment Reporting [Abstract]

Segment Reporting

Segment Reporting

The Company’s operations consist of regulated operations and other operations that provide information technology and other support services to those regulated operations.  The Company segregates its regulated operations between a Gas Utility Services operating segment and an Electric Utility Services operating segment.  The Gas Utility Services segment provides natural gas distribution and transportation services to nearly two-thirds of Indiana and to west central Ohio.  The Electric Utility Services segment provides electric distribution services primarily to southwestern Indiana, and includes the Company’s power generating and wholesale power operations.  Regulated operations supply natural gas and/or electricity to over one million customers.  In total, the Company is comprised of three operating segments:  Gas Utility Services, Electric Utility Services, and Other Shared Service operations.  Net income is the measure of profitability used by management for all operations.

Information related to the Company’s reportable segments is summarized as follows. 

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(In millions)	2014			2013			2014			2013
Revenues
Gas Utility Services	$	105.1		$	101.9		$	681.1		$	555.8
Electric Utility Services	165.9			165.8			480.9			470.0
Other Operations	9.6			9.5			28.7			28.5
Eliminations	(9.5		)	(9.5		)	(28.5		)	(28.3		)
Total revenues	$	271.1		$	267.7		$	1,162.2		$	1,026.0
Profitability Measure - Net Income
Gas Utility Services	$	(5.1	)	$	(3.8	)	$	33.9		$	37.2
Electric Utility Services	26.7			26.6			65.9			60.1
Other Operations	2.7			2.5			8.7			7.3
Total net income	$	24.3		$	25.3		$	108.5		$	104.6

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CONSOLIDATED CONDENSED STATEMENTS OF INCOME (Unaudited) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
OPERATING REVENUES [Abstract]
Gas utility	$ 105.1	$ 101.9	$ 681.1	$ 555.8
Electric utility	165.9	165.8	480.9	470.0
Other	0.1	0	0.2	0.2
Total operating revenues	271.1	267.7	1,162.2	1,026.0
OPERATING EXPENSES [Abstract]
Cost of gas sold	28.8	27.5	343.4	235.4
Cost of fuel & purchased power	50.3	50.4	155.4	154.5
Other operating	79.9	74.0	259.7	236.9
Depreciation & Amortization	51.0	49.7	151.5	146.8
Taxes other than income taxes	11.7	11.6	44.3	41.3
Total operating expenses	221.7	213.2	954.3	814.9
OPERATING INCOME	49.4	54.5	207.9	211.1
Nonoperating Income (Expense) [Abstract]
Other income - net	4.8	2.0	12.4	6.8
Interest Expense	16.6	15.6	50.0	49.2
INCOME BEFORE INCOME TAXES	37.6	40.9	170.3	168.7
Income taxes	13.3	15.6	61.8	64.1
NET INCOME	$ 24.3	$ 25.3	$ 108.5	$ 104.6

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Financing Activities

9 Months Ended

Sep. 30, 2014

Debt Disclosure [Abstract]

Financing Activities

 Financing Activities

SIGECO Debt Refund and Issuance

On September 24, 2014, SIGECO issued two new series of tax-exempt debt totaling $63.6 million.  Proceeds from the issuance were used to retire three series of tax-exempt bonds aggregating $63.6 million at a redemption price of par plus accrued interest.  The principal terms of the two new series of tax-exempt debt are:  (i) $22.3 million sold in a public offering and bear interest at 4.00 percent per annum, due September 1, 2044 and (ii) $41.3 million, due July 1, 2025, sold in a private placement at variable rates through September 2019.

Short-term Credit Facilities

On October 31, 2014, Utility Holdings’ short-term credit facility, which totals $350 million in borrowing capacity, was amended to extend its maturity until October 31, 2019.

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Transactions with Other Vectren Companies and Affiliates

9 Months Ended

Sep. 30, 2014

Transactions with Other Vectren Companies and Affiliates [Abstract]

Transactions With Other Vectren Companies and Affiliates [Text Block]

Transactions with Other Vectren Companies and Affiliates

Vectren Fuels, Inc. (Vectren Fuels)

On August 29, 2014, Vectren closed on a transaction to sell its wholly-owned coal mining subsidiary, Vectren Fuels, to Sunrise Coal, LLC (Sunrise), an Indiana-based wholly-owned subsidiary of Hallador Energy Company. Prior to the sale date, SIGECO purchased coal used for electric generation from Vectren Fuels.  Amounts purchased for the three months ended September 30, 2014 and 2013 totaled $30.0 million and $24.5 million, respectively, and for the nine months ended September 30, 2014 and 2013 totaled $98.6 million and $76.1 million, respectively.  Amounts owed to Vectren Fuels at September 30, 2014 and December 31, 2013 are included in Payables to other Vectren companies in the Condensed Consolidated Balance Sheets.

Vectren Infrastructure Services Corporation (VISCO)

VISCO, a wholly owned subsidiary of Vectren, performs natural gas and water distribution, transmission, and construction repair and rehabilitation primarily in the Midwest and the repair and rehabilitation of gas, water, and wastewater facilities nationwide. In addition, VISCO also provides transmission pipeline construction and maintenance; pump station, compressor station, terminal and refinery construction; and hydrostatic testing to customers generally in the northern Midwest region. VISCO's customers include Utility Holdings’ utilities. Fees incurred by Utility Holdings and its subsidiaries totaled $30.1 million and $15.9 million for the three months ended September 30, 2014 and 2013, respectively, and for the nine months ended September 30, 2014 and 2013 totaled $63.5 million and $39.5 million, respectively. Amounts owed to VISCO at September 30, 2014 and December 31, 2013 are included in Payables to other Vectren companies in the Condensed Consolidated Balance Sheets.

ProLiance Holdings, LLC (ProLiance)

Vectren has an investment in ProLiance, a nonutility affiliate of Vectren and Citizens Energy Group (Citizens). On June 18, 2013, ProLiance exited the natural gas marketing business through the disposition of certain of the net assets of its energy marketing business, ProLiance Energy, LLC (ProLiance Energy). ProLiance Energy provided services to a broad range of municipalities, utilities, industrial operations, schools, and healthcare institutions located throughout the Midwest and Southeast United States.  ProLiance Energy’s customers included, among others, Vectren’s Indiana utilities as well as Citizens’ utilities. 

The Company had no purchases from ProLiance for resale and for injections into storage for the three and nine months ended September 30, 2014, as a result of ProLiance exiting the natural gas marketing business. For the three months ended September 30, 2013, the Company had no purchases, and for the nine months ended September 30, 2013 purchases totaled $200.5 million. The Company did not have any amounts owed to ProLiance for purchases at September 30, 2014 and at December 31, 2013.  Amounts charged by ProLiance for gas supply services were established by supply agreements with each utility. After the exit of the energy marketing business by ProLiance, the Company purchases gas supply from third parties and 83 percent is from a single third party for the three and nine month periods ended September 30, 2014.

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 September 30, 2014 and 2013, Utility Holdings received corporate allocations totaling $13.0 million and $10.4 million, respectively. For the nine months ending September 30, 2014 and 2013, Utility Holdings received corporate allocations totaling $41.7 million and $36.7 million, respectively.

The Company does not have share-based compensation plans and pension and other postretirement plans separate from Vectren and allocated costs include participation in Vectren's plans.  The allocation methodology for retirement costs is consistent with FASB guidance related to “multiemployer” benefit accounting.

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Subsidiary Guarantor and Consolidating Information Balance Sheet (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2014	Dec. 31, 2013	Sep. 30, 2013	Dec. 31, 2012
ASSETS
Cash & cash equivalents	$ 5.4	$ 8.6	$ 6.2	$ 13.3
Accounts receivable - less reserves	68.8	112.1
Accrued unbilled revenues	41.8	113.5
Inventories	109.7	89.9
Recoverable fuel & natural gas costs	25.5	5.5
Prepayments & other current assets	47.7	42.4
Total current assets	298.9	372.0
Original cost	5,599.2	5,389.6
Less: accumulated depreciation & amortization	2,250.3	2,165.3
Net utility plant	3,348.9	3,224.3
Investments in unconsolidated affiliates	0.2	0.2
Other investments	25.1	27.3
Nonutility property - net	148.8	150.5
Goodwill - net	205.0	205.0
Regulatory assets	131.6	136.2
Other assets	20.2	25.3
TOTAL ASSETS	4,178.7	4,140.8
LIABILITIES & SHAREHOLDERS' EQUITY
Accounts payable	110.1	172.1
Payables to other Vectren companies	50.6	24.6
Accrued liabilities	118.1	127.4
Short-term borrowings	60.1	28.6
Current maturities of long-term debt	5.0	0
Total current liabilities	343.9	352.7
Long-Term Debt - Net of Current Maturities	1,252.3	1,257.1
Deferred income taxes	625.0	627.4
Regulatory liabilities	404.8	387.3
Deferred Credits and Other Liabilities	88.2	83.5
Total deferred credits and other liabilities	1,118.0	1,098.2
Common stock (no par value)	792.3	787.7
Retained earnings	672.2	645.1
Total common shareholders' equity	1,464.5	1,432.8
TOTAL LIABILITIES and SHAREHOLDERS' EQUITY	4,178.7	4,140.8
Line of Credit Facility, Maximum Borrowing Capacity	350
Subsidiary Guarantors [Member]
ASSETS
Cash & cash equivalents	3.9	8.2	5.4	12.5
Accounts receivable - less reserves	68.8	112.1
Intercompany Receivables	29.0	0.3
Accrued unbilled revenues	41.8	113.5
Inventories	109.7	89.9
Recoverable fuel & natural gas costs	25.5	5.5
Prepayments & other current assets	55.7	37.3
Total current assets	334.4	366.8
Original cost	5,599.2	5,389.6
Less: accumulated depreciation & amortization	2,250.3	2,165.3
Net utility plant	3,348.9	3,224.3
Investments in consolidated subsidiaries	0	0
Notes receivable from consolidated subsidiaries	0	0
Investments in unconsolidated affiliates	0.2	0.2
Other investments	20.9	22.8
Nonutility property - net	1.8	2.2
Goodwill - net	205.0	205.0
Regulatory assets	109.7	113.4
Other assets	30.1	32.2
TOTAL ASSETS	4,051.0	3,966.9
LIABILITIES & SHAREHOLDERS' EQUITY
Accounts payable	104.2	161.6
Intercompany payables	23.5	11.7
Payables to other Vectren companies	50.6	24.6
Accrued liabilities	130.9	150.3
Short-term borrowings	0	0
Intercompany short-term borrowings	40.5	73.1
Current maturities of long-term debt	5.0
Total current liabilities	354.7	421.3
Long-Term Debt - Net of Current Maturities	377.6	382.5
Long-term debt due to VUHI	820.6	696.4
Total long-term debt - net	1,198.2	1,078.9
Deferred income taxes	596.8	616.9
Regulatory liabilities	403.3	385.7
Deferred Credits and Other Liabilities	94.0	88.3
Total deferred credits and other liabilities	1,094.1	1,090.9
Common stock (no par value)	805.5	800.9
Retained earnings	598.5	574.9
Total common shareholders' equity	1,404.0	1,375.8
TOTAL LIABILITIES and SHAREHOLDERS' EQUITY	4,051.0	3,966.9
Parent Company [Member]
ASSETS
Cash & cash equivalents	1.5	0.4	0.8	0.8
Accounts receivable - less reserves	0	0
Intercompany Receivables	64.0	84.8
Accrued unbilled revenues	0	0
Inventories	0	0
Recoverable fuel & natural gas costs	0	0
Prepayments & other current assets	26.8	40.1
Total current assets	92.3	125.3
Original cost	0	0
Less: accumulated depreciation & amortization	0	0
Net utility plant	0	0
Investments in consolidated subsidiaries	1,404.0	1,375.8
Notes receivable from consolidated subsidiaries	820.6	696.4
Investments in unconsolidated affiliates	0	0
Other investments	4.2	4.5
Nonutility property - net	147.0	148.3
Goodwill - net	0	0
Regulatory assets	21.9	22.8
Other assets	0.6	1.0
TOTAL ASSETS	2,490.6	2,374.1
LIABILITIES & SHAREHOLDERS' EQUITY
Accounts payable	5.9	10.5
Intercompany payables	0	0
Payables to other Vectren companies	0	0
Accrued liabilities	22.0	12.1
Short-term borrowings	60.1	28.6
Intercompany short-term borrowings	29.0	0.3
Current maturities of long-term debt	0
Total current liabilities	117.0	51.5
Long-Term Debt - Net of Current Maturities	874.7	874.6
Long-term debt due to VUHI	0	0
Total long-term debt - net	874.7	874.6
Deferred income taxes	28.2	10.5
Regulatory liabilities	1.5	1.6
Deferred Credits and Other Liabilities	4.7	3.1
Total deferred credits and other liabilities	34.4	15.2
Common stock (no par value)	792.3	787.7
Retained earnings	672.2	645.1
Total common shareholders' equity	1,464.5	1,432.8
TOTAL LIABILITIES and SHAREHOLDERS' EQUITY	2,490.6	2,374.1
Line of Credit Facility, Maximum Borrowing Capacity	350
Unsecured Debt	875
Subsidiary Ownership Percentage	100.00%
Consolidation, Eliminations [Member]
ASSETS
Cash & cash equivalents	0	0	0	0
Accounts receivable - less reserves	0	0
Intercompany Receivables	(93.0)	(85.1)
Accrued unbilled revenues	0	0
Inventories	0	0
Recoverable fuel & natural gas costs	0	0
Prepayments & other current assets	(34.8)	(35.0)
Total current assets	(127.8)	(120.1)
Original cost	0	0
Less: accumulated depreciation & amortization	0	0
Net utility plant	0	0
Investments in consolidated subsidiaries	(1,404.0)	(1,375.8)
Notes receivable from consolidated subsidiaries	(820.6)	(696.4)
Investments in unconsolidated affiliates	0	0
Other investments	0	0
Nonutility property - net	0	0
Goodwill - net	0	0
Regulatory assets	0	0
Other assets	(10.5)	(7.9)
TOTAL ASSETS	(2,362.9)	(2,200.2)
LIABILITIES & SHAREHOLDERS' EQUITY
Accounts payable	0	0
Intercompany payables	(23.5)	(11.7)
Payables to other Vectren companies	0	0
Accrued liabilities	(34.8)	(35.0)
Short-term borrowings	0	0
Intercompany short-term borrowings	(69.5)	(73.4)
Current maturities of long-term debt	0
Total current liabilities	(127.8)	(120.1)
Long-Term Debt - Net of Current Maturities	0	0
Long-term debt due to VUHI	(820.6)	(696.4)
Total long-term debt - net	(820.6)	(696.4)
Deferred income taxes	0	0
Regulatory liabilities	0	0
Deferred Credits and Other Liabilities	(10.5)	(7.9)
Total deferred credits and other liabilities	(10.5)	(7.9)
Common stock (no par value)	(805.5)	(800.9)
Retained earnings	(598.5)	(574.9)
Total common shareholders' equity	(1,404.0)	(1,375.8)
TOTAL LIABILITIES and SHAREHOLDERS' EQUITY	(2,362.9)	(2,200.2)
Consolidated Entities [Member]
ASSETS
Cash & cash equivalents	5.4	8.6	6.2	13.3
Accounts receivable - less reserves	68.8	112.1
Intercompany Receivables	0	0
Accrued unbilled revenues	41.8	113.5
Inventories	109.7	89.9
Recoverable fuel & natural gas costs	25.5	5.5
Prepayments & other current assets	47.7	42.4
Total current assets	298.9	372.0
Original cost	5,599.2	5,389.6
Less: accumulated depreciation & amortization	2,250.3	2,165.3
Net utility plant	3,348.9	3,224.3
Investments in consolidated subsidiaries	0	0
Notes receivable from consolidated subsidiaries	0	0
Investments in unconsolidated affiliates	0.2	0.2
Other investments	25.1	27.3
Nonutility property - net	148.8	150.5
Goodwill - net	205.0	205.0
Regulatory assets	131.6	136.2
Other assets	20.2	25.3
TOTAL ASSETS	4,178.7	4,140.8
LIABILITIES & SHAREHOLDERS' EQUITY
Accounts payable	110.1	172.1
Intercompany payables	0	0
Payables to other Vectren companies	50.6	24.6
Accrued liabilities	118.1	127.4
Short-term borrowings	60.1	28.6
Intercompany short-term borrowings	0	0
Current maturities of long-term debt	5.0
Total current liabilities	343.9	352.7
Long-Term Debt - Net of Current Maturities	1,252.3	1,257.1
Long-term debt due to VUHI	0	0
Total long-term debt - net	1,252.3	1,257.1
Deferred income taxes	625.0	627.4
Regulatory liabilities	404.8	387.3
Deferred Credits and Other Liabilities	88.2	83.5
Total deferred credits and other liabilities	1,118.0	1,098.2
Common stock (no par value)	792.3	787.7
Retained earnings	672.2	645.1
Total common shareholders' equity	1,464.5	1,432.8
TOTAL LIABILITIES and SHAREHOLDERS' EQUITY	$ 4,178.7	$ 4,140.8

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Subsidiary Guarantor and Consolidating Information(Tables)

9 Months Ended

Sep. 30, 2014

Subsidiary Guarantor and Consolidating Information [Abstract]

Condensed consolidating balance sheets [Table Text Block]

Condensed Consolidating Balance Sheet as of September 30, 2014 (in millions):

ASSETS	Subsidiary		Parent		Eliminations &
	Guarantors		Company		Reclassifications			Consolidated
Current Assets
Cash & cash equivalents	$	3.9	$	1.5	$	—		$	5.4
Accounts receivable - less reserves	68.8		—		—			68.8
Intercompany receivables	29.0		64.0		(93.0		)	—
Accrued unbilled revenues	41.8		—		—			41.8
Inventories	109.7		—		—			109.7
Recoverable fuel & natural gas costs	25.5		—		—			25.5
Prepayments & other current assets	55.7		26.8		(34.8		)	47.7
Total current assets	334.4		92.3		(127.8		)	298.9
Utility Plant
Original cost	5,599.2		—		—			5,599.2
Less:  accumulated depreciation & amortization	2,250.3		—		—			2,250.3
Net utility plant	3,348.9		—		—			3,348.9
Investments in consolidated subsidiaries	—		1,404.0		(1,404.0		)	—
Notes receivable from consolidated subsidiaries	—		820.6		(820.6		)	—
Investments in unconsolidated affiliates	0.2		—		—			0.2
Other investments	20.9		4.2		—			25.1
Nonutility property - net	1.8		147.0		—			148.8
Goodwill - net	205.0		—		—			205.0
Regulatory assets	109.7		21.9		—			131.6
Other assets	30.1		0.6		(10.5		)	20.2
TOTAL ASSETS	$	4,051.0	$	2,490.6	$	(2,362.9	)	$	4,178.7
LIABILITIES & SHAREHOLDER'S EQUITY	Subsidiary		Parent		Eliminations &
	Guarantors		Company		Reclassifications			Consolidated
Current Liabilities
Accounts payable	$	104.2	$	5.9	$	—		$	110.1
Intercompany payables	23.5		—		(23.5		)	—
Payables to other Vectren companies	50.6		—		—			50.6
Accrued liabilities	130.9		22.0		(34.8		)	118.1
Short-term borrowings	—		60.1		—			60.1
Intercompany short-term borrowings	40.5		29.0		(69.5		)	—
Current maturities of long-term debt	5.0		—		—			5.0
Total current liabilities	354.7		117.0		(127.8		)	343.9
Long-Term Debt
Long-term debt	377.6		874.7		—			1,252.3
Long-term debt due to VUHI	820.6		—		(820.6		)	—
Total long-term debt - net	1,198.2		874.7		(820.6		)	1,252.3
Deferred Credits & Other Liabilities
Deferred income taxes	596.8		28.2		—			625.0
Regulatory liabilities	403.3		1.5		—			404.8
Deferred credits & other liabilities	94.0		4.7		(10.5		)	88.2
Total deferred credits & other liabilities	1,094.1		34.4		(10.5		)	1,118.0
Common Shareholder's Equity
Common stock (no par value)	805.5		792.3		(805.5		)	792.3
Retained earnings	598.5		672.2		(598.5		)	672.2
Total common shareholder's equity	1,404.0		1,464.5		(1,404.0		)	1,464.5
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	$	4,051.0	$	2,490.6	$	(2,362.9	)	$	4,178.7

Condensed Consolidating Balance Sheet as of December 31, 2013 (in millions):

ASSETS	Subsidiary		Parent		Eliminations &
	Guarantors		Company		Reclassifications			Consolidated
Current Assets
Cash & cash equivalents	$	8.2	$	0.4	$	—		$	8.6
Accounts receivable - less reserves	112.1		—		—			112.1
Intercompany receivables	0.3		84.8		(85.1		)	—
Accrued unbilled revenues	113.5		—		—			113.5
Inventories	89.9		—		—			89.9
Recoverable fuel & natural gas costs	5.5		—		—			5.5
Prepayments & other current assets	37.3		40.1		(35.0		)	42.4
Total current assets	366.8		125.3		(120.1		)	372.0
Utility Plant
Original cost	5,389.6		—		—			5,389.6
Less:  accumulated depreciation & amortization	2,165.3		—		—			2,165.3
Net utility plant	3,224.3		—		—			3,224.3
Investments in consolidated subsidiaries	—		1,375.8		(1,375.8		)	—
Notes receivable from consolidated subsidiaries	—		696.4		(696.4		)	—
Investments in unconsolidated affiliates	0.2		—		—			0.2
Other investments	22.8		4.5		—			27.3
Nonutility property - net	2.2		148.3		—			150.5
Goodwill - net	205.0		—		—			205.0
Regulatory assets	113.4		22.8		—			136.2
Other assets	32.2		1.0		(7.9		)	25.3
TOTAL ASSETS	$	3,966.9	$	2,374.1	$	(2,200.2	)	$	4,140.8
LIABILITIES & SHAREHOLDER'S EQUITY	Subsidiary		Parent		Eliminations &
	Guarantors		Company		Reclassifications			Consolidated
Current Liabilities
Accounts payable	$	161.6	$	10.5	$	—		$	172.1
Intercompany payables	11.7		—		(11.7		)	—
Payables to other Vectren companies	24.6		—		—			24.6
Accrued liabilities	150.3		12.1		(35.0		)	127.4
Short-term borrowings	—		28.6		—			28.6
Intercompany short-term borrowings	73.1		0.3		(73.4		)	—
Total current liabilities	421.3		51.5		(120.1		)	352.7
Long-Term Debt
Long-term debt - net of current maturities &
debt subject to tender	382.5		874.6		—			1,257.1
Long-term debt due to VUHI	696.4		—		(696.4		)	—
Total long-term debt - net	1,078.9		874.6		(696.4		)	1,257.1
Deferred Credits & Other Liabilities
Deferred income taxes	616.9		10.5		—			627.4
Regulatory liabilities	385.7		1.6		—			387.3
Deferred credits & other liabilities	88.3		3.1		(7.9		)	83.5
Total deferred credits & other liabilities	1,090.9		15.2		(7.9		)	1,098.2
Common Shareholder's Equity
Common stock (no par value)	800.9		787.7		(800.9		)	787.7
Retained earnings	574.9		645.1		(574.9		)	645.1
Total common shareholder's equity	1,375.8		1,432.8		(1,375.8		)	1,432.8
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	$	3,966.9	$	2,374.1	$	(2,200.2	)	$	4,140.8

Condensed consolidating statements fo income [Table Text Block]

	Subsidiary Guarantors		Parent Company			Eliminations & Reclassifications			Consolidated
OPERATING REVENUES
Gas utility	$	105.1	$	—		$	—		$	105.1
Electric utility	165.9		—			—			165.9
Other	—		9.6			(9.5		)	0.1
Total operating revenues	271.0		9.6			(9.5		)	271.1
OPERATING EXPENSES
Cost of gas sold	28.8		—			—			28.8
Cost of fuel & purchased power	50.3		—			—			50.3
Other operating	88.6		—			(8.7		)	79.9
Depreciation & amortization	44.8		6.1			0.1			51.0
Taxes other than income taxes	11.2		0.5			—			11.7
Total operating expenses	223.7		6.6			(8.6		)	221.7
OPERATING INCOME	47.3		3.0			(0.9		)	49.4
Other income - net	3.9		10.8			(9.9		)	4.8
Interest expense	16.1		11.3			(10.8		)	16.6
INCOME BEFORE INCOME TAXES	35.1		2.5			—			37.6
Income taxes	13.5		(0.2		)	—			13.3
Equity in earnings of consolidated companies, net of tax	—		21.6			(21.6		)	—
NET INCOME	$	21.6	$	24.3		$	(21.6	)	$	24.3

Condensed Consolidating Statement of Income for the three months ended September 30, 2013 (in millions):

	Subsidiary Guarantors		Parent Company		Eliminations & Reclassifications			Consolidated
OPERATING REVENUES
Gas utility	$	101.9	$	—	$	—		$	101.9
Electric utility	165.8		—		—			165.8
Other	—		9.4		(9.4		)	—
Total operating revenues	267.7		9.4		(9.4		)	267.7
OPERATING EXPENSES
Cost of gas sold	27.5		—		—			27.5
Cost of fuel & purchased power	50.4		—		—			50.4
Other operating	83.1		—		(9.1		)	74.0
Depreciation & amortization	44.1		5.4		0.2			49.7
Taxes other than income taxes	11.2		0.4		—			11.6
Total operating expenses	216.3		5.8		(8.9		)	213.2
OPERATING INCOME	51.4		3.6		(0.5		)	54.5
Other income - net	1.2		9.8		(9.0		)	2.0
Interest expense	14.7		10.4		(9.5		)	15.6
INCOME BEFORE INCOME TAXES	37.9		3.0		—			40.9
Income taxes	15.0		0.6		—			15.6
Equity in earnings of consolidated companies, net of tax	—		22.9		(22.9		)	—
NET INCOME	$	22.9	$	25.3	$	(22.9	)	$	25.3

Condensed Consolidating Statement of Income for the nine months endedSeptember 30, 2014 (in millions):

	Subsidiary Guarantors		Parent Company			Eliminations & Reclassifications			Consolidated
OPERATING REVENUES
Gas utility	$	681.1	$	—		$	—		$	681.1
Electric utility	480.9		—			—			480.9
Other	—		28.7			(28.5		)	0.2
Total operating revenues	1,162.0		28.7			(28.5		)	1,162.2
OPERATING EXPENSES
Cost of gas sold	343.4		—			—			343.4
Cost of fuel & purchased power	155.4		—			—			155.4
Other operating	286.4		—			(26.7		)	259.7
Depreciation & amortization	133.8		17.4			0.3			151.5
Taxes other than income taxes	42.9		1.3			0.1			44.3
Total operating expenses	961.9		18.7			(26.3		)	954.3
OPERATING INCOME	200.1		10.0			(2.2		)	207.9
Other income - net	9.7		32.4			(29.7		)	12.4
Interest expense	48.0		33.9			(31.9		)	50.0
INCOME BEFORE INCOME TAXES	161.8		8.5			—			170.3
Income taxes	62.0		(0.2		)	—			61.8
Equity in earnings of consolidated companies, net of tax	—		99.8			(99.8		)	—
NET INCOME	$	99.8	$	108.5		$	(99.8	)	$	108.5

Condensed Consolidating Statement of Income for the nine months endedSeptember 30, 2013 (in millions):

	Subsidiary Guarantors		Parent Company		Eliminations & Reclassifications			Consolidated
OPERATING REVENUES
Gas utility	$	555.8	$	—	$	—		$	555.8
Electric utility	470.0		—		—			470.0
Other	—		28.4		(28.2		)	0.2
Total operating revenues	1,025.8		28.4		(28.2		)	1,026.0
OPERATING EXPENSES
Cost of gas sold	235.4		—		—			235.4
Cost of fuel & purchased power	154.5		—		—			154.5
Other operating	264.3		—		(27.4		)	236.9
Depreciation & amortization	130.5		15.9		0.4			146.8
Taxes other than income taxes	40.1		1.2		—			41.3
Total operating expenses	824.8		17.1		(27.0		)	814.9
OPERATING INCOME	201.0		11.3		(1.2		)	211.1
Other income - net	4.9		28.6		(26.7		)	6.8
Interest expense	44.7		32.4		(27.9		)	49.2
INCOME BEFORE INCOME TAXES	161.2		7.5		—			168.7
Income taxes	63.8		0.3		—			64.1
Equity in earnings of consolidated companies, net of tax	—		97.4		(97.4		)	—
NET INCOME	$	97.4	$	104.6	$	(97.4	)	$	104.6

Condensed consolidating statements of cash flows [Table Text Block]

Condensed Consolidating Statement of Cash Flows for the nine months endedSeptember 30, 2014 (in millions):

	Subsidiary Guarantors			Parent Company			Eliminations			Consolidated
NET CASH PROVIDED BY OPERATING ACTIVITIES	$	226.3		$	56.1		$	—		$	282.4
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from
Long-term debt - net of issuance costs	187.2			—			(124.2		)	63.0
Additional capital contribution from parent	4.6			4.6			(4.6		)	4.6
Requirements for:
Dividends to parent	(76.2		)	(81.4		)	76.2			(81.4		)
Retirement of long term debt	(63.6		)	—			—			(63.6		)
Net change in intercompany short-term borrowings	(32.5		)	28.6			3.9			—
Net change in short-term borrowings	—			31.5			—			31.5
Net cash used in financing activities	19.5			(16.7		)	(48.7		)	(45.9		)
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from:
Consolidated subsidiary distributions	—			76.2			(76.2		)	—
Other investing activities	—			0.3			—			0.3
Requirements for:
Capital expenditures, excluding AFUDC equity	(221.4		)	(18.6		)	—			(240.0		)
Consolidated subsidiary investments	—			(4.6		)	4.6			—
Net change in long-term intercompany notes receivable	—			(124.2		)	124.2			—
Net change in short-term intercompany notes receivable	(28.7		)	32.6			(3.9		)	—
Net cash used in investing activities	(250.1		)	(38.3		)	48.7			(239.7		)
Net change in cash & cash equivalents	(4.3		)	1.1			—			(3.2		)
Cash & cash equivalents at beginning of period	8.2			0.4			—			8.6
Cash & cash equivalents at end of period	$	3.9		$	1.5		$	—		$	5.4

Condensed Consolidating Statement of Cash Flows for the nine months endedSeptember 30, 2013 (in millions):

	Subsidiary Guarantors			Parent Company			Eliminations			Consolidated
NET CASH PROVIDED BY OPERATING ACTIVITIES	$	276.1		$	19.3		$	—		$	295.4
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from:
Long-term debt, net of issuance costs	232.7			124.4			(124.4		)	232.7
Additional capital contribution from parent	11.5			4.5			(11.5		)	4.5
Requirements for:
Dividends to parent	(73.5		)	(78.8		)	73.5			(78.8		)
Retirement of long term debt	(223.6		)	(221.6		)	107.7			(337.5		)
Net change in intercompany short-term borrowings	(61.5		)	—			61.5			—
Net change in short-term borrowings	—			59.4			—			59.4
Net cash used in financing activities	(114.4		)	(112.1		)	106.8			(119.7		)
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from:
Consolidated subsidiary distributions	—			73.5			(73.5		)	—
Other investing activities	0.6			0.2			—			0.8
Requirements for:
Capital expenditures, excluding AFUDC equity	(169.4		)	(14.2		)	—			(183.6		)
Consolidated subsidiary investments	—			(11.5		)	11.5			—
Net change in long-term intercompany notes receivable	—			(16.7		)	16.7			—
Net change in short-term intercompany notes receivable	—			61.5			(61.5		)	—
Net cash used in investing activities	(168.8		)	92.8			(106.8		)	(182.8		)
Net change in cash & cash equivalents	(7.1		)	—			—			(7.1		)
Cash & cash equivalents at beginning of period	12.5			0.8			—			13.3
Cash & cash equivalents at end of period	$	5.4		$	0.8		$	—		$	6.2

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Environmental Matters

9 Months Ended

Sep. 30, 2014

Environmental Matters Disclosure [Abstract]

Environmental Matters

Legislative & Environmental Matters

Indiana Senate Bill 1

In March 2014, Indiana Senate Bill 1 was signed into law.  This legislation phases in a 1.6 percent rate reduction to the Indiana Adjusted Gross Income Tax Rate for corporations over a six year period. Pursuant to this legislation, the tax rate will be lowered by 0.25 percent each year for the first five years and 0.35 percent in year six beginning on July 1, 2016 to the final rate of 4.9 percent effective July 1, 2021. Pursuant to FASB guidance, the Company accounted for the effect of the change in tax law on its deferred taxes in the first quarter of 2014, the period of enactment. The impact was not material to results of operations.

Indiana Senate Bill 251

Indiana Senate Bill 251 is also applicable to federal environmental mandates impacting Vectren South's electric operations. The Company continues with its ongoing evaluation of the impact Senate Bill 251 may have on its operations, including applicability of the stricter regulations the EPA is currently considering involving air quality, fly ash disposal, cooling tower intake facilities, waste water discharges, and greenhouse gases. These issues are further discussed below.

Air Quality

Clean Air Interstate Rule / Cross-State Air Pollution Rule

In July 2011, the EPA finalized the Cross-State Air Pollution Rule (CSAPR).  CSAPR was the EPA’s response to the US Court of Appeals for the District of Columbia’s (the Court) remand of the Clean Air Interstate Rule (CAIR). CAIR was originally established in 2005 as an allowance cap and trade program that required reductions from coal-burning power plants for NOX emissions beginning January 1, 2009 and SO2 emissions beginning January 1, 2010, with a second phase of reductions in 2015. In an effort to address the Court’s finding that CAIR did not adequately ensure attainment of pollutants in certain downwind states due to unlimited trading of SO2and NOX allowances, CSAPR reduced the ability of facilities to meet emission reduction targets through allowance trading.  CSAPR reductions were to be achieved with initial step reductions beginning January 1, 2012, and final compliance to be achieved in 2014.  On December 30, 2011, a reviewing court granted a stay of CSAPR and left CAIR in place pending its review. On August 21, 2012, the court vacated CSAPR and directed the EPA to continue to administer CAIR. In April 2014, the US Supreme Court upheld CSAPR. On June 26, 2014, the EPA asked the federal appeals court to lift the stay of the rule. The EPA also asked the court to approve a new deadline schedule for entities that must comply, with the first phase caps starting in 2015 and 2016, and the second phase in 2017. On October 23, 2014 the Court granted the EPA’s request to lift the CSAPR stay, but did not finalize the new implementation dates. While it is possible that the EPA could further revise the rule prior to implementation, the Company does not anticipate a significant impact from the Supreme Court's decision based upon the investments it has already made in pollution control technology to meet the requirements of CAIR. The Company remains in full compliance with CAIR (see additional information below "Conclusions Regarding Air and Water Regulations").

Mercury and Air Toxics (MATS) Rule

On December 21, 2011, the EPA finalized the utility MATS Rule.  The MATS Rule sets emission limits for hazardous air pollutants for existing and new coal-fired power plants and identifies the following broad categories of hazardous air pollutants:  mercury, non-mercury hazardous air pollutants (primarily arsenic, chromium, cobalt, and selenium), and acid gases (hydrogen cyanide, hydrogen chloride, and hydrogen fluoride).  The rule imposes mercury emission limits for two sub-categories of coal, and proposed surrogate limits for non-mercury and acid gas hazardous air pollutants. The EPA did not grant blanket compliance extensions, but asserted that states have broad authority to grant one year extensions for individual electric generating units where potential reliability impacts have been demonstrated.  Reductions are to be achieved within three years of publication of the final rule in the Federal register (April 2015).  Multiple judicial challenges were filed, and the EPA agreed to reconsider MATS requirements for new construction, as the requirements are more stringent than those for existing plants. Utilities planning new coal-fired generation had argued standards outlined in the MATS could not be attained even using the best available control technology. The EPA issued its revised emission limits for new construction in March 2013. In April 2014, the U.S. Court of Appeals for the D.C. Circuit rejected various challenges to the rule for existing sources that were brought by industry and state petitioners. In July a coalition of twenty-one states, including Indiana, filed a petition for certiorari with the U.S. Supreme Court seeking review of the decision of the appellate court. The Company continues to proceed with its MATS compliance strategy. This plan is currently before the IURC for approval, and the Company anticipates full compliance by the applicable deadlines.

Notice of Violation for A.B. Brown Power Plant

The Company received a notice of violation (NOV) from the EPA in November 2011 pertaining to its A.B. Brown power plant.  The NOV asserts that when the power plant was equipped with Selective Catalytic Reduction (SCR) systems, the correct permits were not obtained or the best available control technology to control incidental sulfuric acid mist was not installed. The Company reached a settlement in principle with the EPA to resolve the NOV. That settlement was contemplated in the plan filed with the IURC in the SIGECO Electric Environmental Compliance Filing.

Information Request

SIGECO and Alcoa Generating Corporation (AGC), a subsidiary of ALCOA, own a 300 MW Unit 4 at the Warrick Power Plant as tenants in common.  AGC and SIGECO also share equally in the cost of operation and output of the unit.  In January 2013, AGC received an information request from the EPA under Section 114 of the Clean Air Act for historical operational information on the Warrick Power Plant. In April 2013, ALCOA filed a timely response to the information request.

Water

Section 316(b) of the Clean Water Act requires that generating facilities use the “best technology available” (BTA) to minimize adverse environmental impacts in a body of water.  More specifically, Section 316(b) is concerned with impingement and entrainment of aquatic species in once-through cooling water intake structures used at electric generating facilities.  In April 2009, the U.S. Supreme Court affirmed that the EPA could, but was not required to, consider costs and benefits in making the evaluation as to the best technology available for existing generating facilities.  The regulation was remanded to the EPA for further consideration.  In March 2011, the EPA released its proposed Section 316(b) regulations.  The EPA did not mandate the retrofitting of cooling towers in the proposed regulation, but if finalized, the regulation will leave it to each state to determine whether cooling towers should be required on a case by case basis.  A final rule was issued on May 19, 2014. The final rule does not mandate cooling water tower retrofits but requires a case by case assessment of BTA for each facility. The final rule lists seven presumptive technologies which would qualify as BTA. These technologies range from intake screen modifications to cooling water tower retrofits. Ecological and technology assessment studies must be completed prior to determining BTA for the Company’s facilities. The Company believes that capital investments will likely be in the range of $4 million to $8 million.  Costs for compliance with these final regulations should qualify as federally mandated regulatory requirements and be recoverable under Indiana Senate Bill 251 referenced above.

Under the Clean Water Act, the EPA sets technology-based guidelines for water discharges from new and existing facilities. The EPA is currently in the process of revising the existing steam electric effluent limitation guidelines that set the technology-based water discharge limits for the electric power industry. The EPA is focusing its rulemaking on wastewater generated primarily by pollution control equipment necessitated by the comprehensive air regulations. The EPA released proposed rules on April 19, 2013 and the Company is reviewing the proposal. At this time, it is not possible to estimate what potential costs may be required to meet these new water discharge limits, however costs for compliance with these regulations should qualify as federally mandated regulatory requirements and be recoverable under Senate Bill 251 referenced above.

Conclusions Regarding Air and Water Regulations

To comply with Indiana’s implementation plan of the Clean Air Act, and other federal air quality standards, the Company obtained authority from the IURC to invest in clean coal technology.  Using this authorization, the Company invested approximately $411 million starting in 2001 with the last equipment being placed into service on January 1, 2010.  The pollution control equipment included SCR systems, fabric filters, and an SO2 scrubber at its generating facility that is jointly owned with AGC.  SCR technology is the most effective method of reducing NOX emissions where high removal efficiencies are required and fabric filters control particulate matter emissions.  The unamortized portion of the $411 million clean coal technology investment was included in rate base for purposes of determining SIGECO’s electric base rates approved in the latest base rate order obtained April 27, 2011.  SIGECO’s coal-fired generating fleet is 100 percent scrubbed for SO2 and 90 percent controlled for NOX.  

Utilization of the Company’s NOX and SO2 allowances can be impacted as regulations are revised and implemented.  Most of these allowances were granted to the Company at zero cost; therefore, any reduction in carrying value that could result from future changes in regulations would be immaterial.

The Company continues to review the sufficiency of its existing pollution control equipment in relation to the requirements described in the MATS Rule, the recent renewal of water discharge permits, and the NOV discussed above.  Some operational modifications to the control equipment are likely. The Company is continuing to evaluate potential technologies to address compliance and what the additional costs may be associated with these efforts. Currently, it is expected that the capital costs could be between $70 million and $90 million. Compliance is required by government regulation, and the Company believes that such additional costs, if incurred, should be recoverable under Senate Bill 251 referenced above. On January 17, 2014, the Company filed its request with the IURC seeking approval to upgrade its existing emissions control equipment to comply with the MATS Rule, take steps to address the EPA's allegations in the NOV and comply with new mercury limits to the waste water discharge permits at the Culley and Brown generating stations. In that filing, the Company has proposed to defer recovery of the costs until 2020 in order to mitigate the impact on customer rates in the near term. In July a hearing was held before the IURC in this matter. The case has been fully briefed as of October 2, 2014, and the Company is awaiting a Commission order.

Coal Ash Waste Disposal & Ash Ponds

In June 2010, the EPA issued proposed regulations affecting the management and disposal of coal combustion products, such as ash generated by the Company’s coal-fired power plants.  The proposed rules more stringently regulate these byproducts and would likely increase the cost of operating or expanding existing ash ponds and the development of new ash ponds.  The alternatives include regulating coal combustion by-products that are not being beneficially reused as hazardous waste.  The EPA did not offer a preferred alternative, but took public comment on multiple alternative regulations.  Rules have not been finalized given oversight hearings, congressional interest, and other factors. Recently the EPA entered into a consent decree in which it agreed to finalize by December 2014 its determination whether to regulate ash as hazardous waste, or the less stringent solid waste designation.

At this time, the majority of the Company’s ash is being beneficially reused.  However, the alternatives proposed would require modification to, or closure of, existing ash ponds.  The Company estimates capital expenditures to comply could be as much as $30 million, and such expenditures could exceed $100 million if the most stringent of the alternatives is selected.  Annual compliance costs could increase only slightly or be impacted by as much as $5 million.  Costs for compliance with these regulations should qualify as federally mandated regulatory requirements and be recoverable under Senate Bill 251 referenced above. 

Climate Change

In April 2007, the US Supreme Court determined that greenhouse gases (GHG's) meet the definition of "air pollutant" under the Clean Air Act and ordered the EPA to determine whether GHG emissions cause or contribute to air pollution that may reasonably be anticipated to endanger public health or welfare. The endangerment finding was finalized in December 2009, concluding that carbon emissions pose an endangerment to public health and the environment.

The EPA has finalized two sets of GHG regulations that apply to the Company’s generating facilities.  In 2009, the EPA finalized a mandatory GHG emissions registry which requires the reporting of emissions.  The EPA has also finalized a revision to the Prevention of Significant Deterioration (PSD) and Title V permitting rules which would require facilities that emit 75,000 tons or more of GHG's a year to obtain a PSD permit for new construction or a significant modification of an existing facility.  The EPA's PSD and Title V permitting rules for GHG's were upheld by the US Court of Appeals for the District of Columbia, and in June 2014 the US Supreme Court upheld the regulations with respect to applicability to major sources such as coal-fired power plants that are required to hold PSD construction and Title V air operating permits for other criteria pollutants.

While the Company has no plans to invest in new coal fired generation, there is also a rule making and related legal challenge involving new source performance standards for new construction. This rulemaking must be finalized and withstand legal scrutiny in order for the EPA to implement its proposed new source performance standards for existing units discussed below.

In July 2013, the President announced a Climate Action Plan, which calls on the EPA to finalize the rule for new construction expeditiously, and by June 2014 propose, and by June 2015 finalize, New Source Performance Standards (NSPS) for GHG's for existing electric generating units which would apply to the Company's power plants. States must have their implementation plans to the EPA no later than June 2016. On June 2, 2014, the EPA proposed its rule for states to regulate CO2 emissions from existing electric generating units. The rule, when final, will require states to adopt plans that reduce CO2 emissions by 30 percent from 2005 levels by 2030. Unlike most rulemakings which allow for a 30 day public comment period, the EPA provided an initial 120 days from publication of the proposal in the Federal Register, and a subsequent extension of the public comment period was granted to December 1, 2014. The proposal sets state-specific CO2 emission rate-based CO2 goals (measured in lb CO2/MWh or “megawatt hour”) and guidelines for the development, submission and implementation of state plans to achieve the state goals. These state-specific goals are calculated based upon 2012 average emission rates aggregated for all fossil fuel-based units in the state. For Indiana, the proposal uses a 2012 emission rate of 1,923 lb CO2/MWh, and sets an interim goal of 1,607 lb CO2/MWh and a final emission goal of 1,531 lb CO2/MWh that must be met by 2030. Under this proposal, these CO2 emission rate goals do not apply directly to individual units, or generating systems. They are state goals. As such, the state must establish a framework that will guide how compliance will be met on a statewide basis. The state’s interim or “phase in” goal of 1,607 lb CO2/MWh must be met as averaged over a ten year period (2020 - 2029) with progress toward this goal to be demonstrated for every two rolling calendar years starting in 2020, with the first report due in 2022.

Under the proposal all states have unique goals based upon each state’s mix of electric generating assets. The EPA is proposing a 20 percent reduction in Indiana’s total CO2 emission rate compared to 2012. At 20 percent Indiana’s CO2 emission rate reduction requirement is tied with West Virginia as the 9^th lowest reduction requirement in US. This is due in part to the EPA’s attempt to recognize the existing generating resource mix in the state and take into account each state’s ability to cost effectively lower its CO2 emission rate through a portfolio approach including energy efficiency and renewables, improving power plant heat rates, and dispatching lower emitting fuel sources. Each state’s goals were set by taking 2012 emissions data and applying four “building blocks” of emission rate improvements that the EPA asserts can be achieved by that state. These four building blocks constitute the EPA’s determination of “Best System of Emission Reductions that has been adequately demonstrated,” which defines the EPA’s authority under § 111(d) for existing sources. When applied to each state, the portfolio approach leads to significant differences in requirements across state lines. With the exception of building block number 1 (heat rate improvement of 6 percent), other building blocks are tailored to individual states based upon each state’s existing generating mix and what the EPA concluded a state could reasonably accomplish to reduce its CO2 emission rate. Despite having just been recently proposed and not expected to be finalized until June of 2015, legal challenges to the EPA's proposal have begun. On July 31, 2014, litigation was filed by the state of Indiana and other parties challenging the rules which may delay the timing of approval of the various state plans.

With respect to the state of Indiana, the four building blocks that support Indiana’s goal are as follows:

(1) Heat rate (HR) improvements of 6 percent (this is consistently applied to all states).

(2) Increasing the dispatch of existing natural gas baseload generation sources to 70 percent.

(3) Renewable energy portfolio requirements of 5 percent (interim) and 7 percent (final).

(4) Energy efficiency / DSM that results in reductions of 1.5 percent annually starting in 2020, ending at a sustained 11 percent by 2030.

Under the proposal, Indiana may choose to implement a program based upon an annual average emission rate target or convert that target rate to a comparable CO2 emission cap. Indiana is the 5^th largest carbon emitter in the nation in tons of CO2 produced from electric generation. In 2013, Indiana’s electric utilities generated 105.6 million tons of CO2. The Company’s share of that total was 6.3 million, or <6 percent. Since 2005, the Company’s emissions of CO2 have declined 23 percent (on a tonnage basis). These reductions have come from the retirement of FB Culley Unit 1, expiration of municipal contracts, electric conservation and the addition of renewable generation and the installation of more efficient dense pack turbine technology. With respect to CO2 emission rate, since 2005 the Company has lowered its CO2 emission rate (as measured in lbs CO2/MWh) from 1967 lbs CO2/MWh to 1922 lbs CO2/MWh, for a reduction of 3 percent. the Company’s CO2 emission rate of 1922 lbs/MWh is basically the same as the State’s average CO2 emission rate of 1923 lb CO2/MWh.

Impact of Legislative Actions & Other Initiatives is Unknown

If the regulations referenced above are finalized by the EPA, or if legislation requiring reductions in CO2 and other GHG's or legislation mandating a renewable energy portfolio standard is adopted, such regulation could substantially affect both the costs and operating characteristics of the Company’s fossil fuel generating plants and natural gas distribution businesses.  At this time and in the absence of final legislation or rulemaking, compliance costs and other effects associated with reductions in GHG emissions or obtaining renewable energy sources remain uncertain.  The Company has gathered preliminary estimates of the costs to control GHG emissions.  A preliminary investigation demonstrated costs to comply would be significant, first with regard to operating expenses and later for capital expenditures as technology becomes available to control GHG emissions.  However, these compliance cost estimates were based on highly uncertain assumptions, including allowance prices if a cap and trade approach were employed, and energy efficiency targets.  As the EPA moves toward finalization of the NSPS for existing sources and the State of Indiana begins formulation of its state implementation plan, the Company will have more information to enable it to better assess potential compliance costs with a final regulation. Costs to purchase allowances that cap GHG emissions or expenditures made to control emissions or lower carbon emission rates should be considered a federally mandated cost of providing electricity, and as such, the Company believes such costs and expenditures should be recoverable from customers through Senate Bill 251 as referenced above or Senate Bill 29, which was used by the Company to recover its initial pollution control investments.

Renewables

Senate Bill 251 also established a voluntary clean energy portfolio standard that provides incentives to Indiana electricity suppliers participating in the program. The goal of the program is that by 2025, at least 10 percent of the total electricity obtained by the supplier to meet the energy needs of Indiana retail customers will be provided by clean energy sources, as defined. In advance of a federal portfolio standard and Senate Bill 251, SIGECO received regulatory approval to purchase a 3 MW landfill gas generation facility from a related entity. The facility was purchased in 2009 and is directly connected to the Company's distribution system. In 2008 and 2009, the Company executed long-term purchase power commitments for a total of 80 MW of wind energy. The Company currently has approximately 4 percent of its electricity being provided by clean energy sources due to the long-term wind contracts and landfill gas investment.

Manufactured Gas Plants

In the past, the Company operated facilities to manufacture natural gas.  Given the availability of natural gas transported by pipelines, these facilities have not been operated for many years.  Under current environmental laws and regulations, those that owned or operated these facilities may now be required to take remedial action if certain contaminants are found above the regulatory thresholds.

In the Indiana Gas service territory, the existence, location, and certain general characteristics of 26 gas manufacturing and storage sites have been identified for which the Company may have some remedial responsibility.  A remedial investigation/feasibility study (RI/FS) was completed at one of the sites under an agreed order between Indiana Gas and the IDEM, and a Record of Decision was issued by the IDEM in January 2000.  The remaining sites have been submitted to the IDEM's Voluntary Remediation Program (VRP).  The Company has identified its involvement in five manufactured gas plant sites in SIGECO’s service territory, all of which are currently enrolled in the IDEM’s VRP.  The Company is currently conducting some level of remedial activities, including groundwater monitoring at certain sites.

The Company has accrued the estimated costs for further investigation, remediation, groundwater monitoring, and related costs for the sites.  While the total costs that may be incurred in connection with addressing these sites cannot be determined at this time, the Company has recorded cumulative costs that it has incurred or reasonably expects to incur totaling approximately $43.4 million ($23.2 million at Indiana Gas and $20.2 million at SIGECO).  The estimated accrued costs are limited to the Company’s share of the remediation efforts and are therefore net of exposures of other potentially responsible parties (PRP).

With respect to insurance coverage, Indiana Gas has received approximately $20.8 million from all known insurance carriers under insurance policies in effect when these plants were in operation.  Likewise, SIGECO has settlement agreements with all known insurance carriers and has received to date approximately $14.3 million of the expected $15.8 million in insurance recoveries.

The costs the Company expects to incur are estimated by management using assumptions based on actual costs incurred, the timing of expected future payments, and inflation factors, among others.  While the Company’s utilities have recorded all costs which they presently expect to incur in connection with activities at these sites, it is possible that future events may require remedial activities which are not presently foreseen and those costs may not be subject to PRP or insurance recovery.  As of September 30, 2014 and December 31, 2013, approximately $4.3 million and $5.7 million, respectively, of accrued, but not yet spent, costs are included in Other Liabilities related to the Indiana Gas and SIGECO sites.

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Commitments and Contingencies

9 Months Ended

Sep. 30, 2014

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments & Contingencies

Commitments

The Company has both firm and non-firm commitments to purchase natural gas, electricity, and coal as well as certain transportation and storage rights and certain contracts are firm commitments under five and ten year arrangements. Costs arising from these commitments, while significant, are pass-through costs, generally collected dollar-for-dollar from retail customers through regulator-approved cost recovery mechanisms.

Legal & Regulatory Proceedings

The Company is party to various legal proceedings, audits, and reviews by taxing authorities and other government agencies arising in the normal course of business.  In the opinion of management, there are no legal proceedings or other regulatory reviews or audits pending against the Company that are likely to have a material adverse effect on its financial position, results of operations or cash flows.

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Rate & Regulatory Matters

9 Months Ended

Sep. 30, 2014

Public Utilities, General Disclosures [Abstract]

Rate and Regulatory Matters

Rate & Regulatory Matters

Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement

The Company monitors and maintains its natural gas distribution system to ensure that natural gas is delivered in a safe and efficient manner. The Company's natural gas utilities are currently engaged in replacement programs in both Indiana and Ohio to mitigate risk, improve the system, and comply with applicable regulations. Laws in both Indiana and Ohio were passed that provide utilities the opportunity to timely recover costs of federally mandated projects and other infrastructure improvement projects outside of a base rate proceeding.

Ohio Recovery and Deferral Mechanisms

The PUCO Order approving the Company's 2009 base rate case in the Ohio service territory authorized a distribution replacement rider (DRR). The DRR's primary purpose is recovery of investments in utility plant and related operating expenses associated with replacing bare steel and cast iron pipelines and certain other infrastructure. This rider is updated annually for qualifying capital expenditures and allows for a return to be earned on those capital expenditures based on the rate of return approved in the 2009 base rate case. In addition, deferral of depreciation and the ability to accrue debt-related post in service carrying costs is also allowed until the related capital expenditures are included in the DRR. The Order also initially established a prospective bill impact evaluation on the annual deferrals. To date, the Company has made capital investments under this rider totaling $132.9 million. Regulatory assets associated with post in service carrying costs and depreciation deferrals were $12.1 million and $9.3 million at September 30, 2014 and December 31, 2013, respectively. Due to the expiration of the initial five year term for the DRR in early 2014, the Company filed a request in August 2013 to extend and expand the DRR. On February 19, 2014, the PUCO approved a Stipulation entered into by the PUCO Staff and the Company which provided for the extension of the DRR for the recovery of costs incurred through 2017 and expanded the types of investment covered by the DRR to include recovery of other infrastructure investments. The Order also approved an adjustment to the bill impact evaluation, limiting the resulting DRR rate per month for residential and small general service customers to specific graduated levels over the next five years. The Company's five year capital expenditure plan related to these infrastructure investments for calendar years 2013 through 2017 totals approximately $200 million, subject to the DRR rate caps approved in the Order. In addition, the Order approved the Company's commitment that the DRR can only be further extended as part of a base rate case. On May 1, 2014, the Company filed its annual request to adjust the DRR for recovery of costs incurred through December 31, 2013. On August 27, 2014 the PUCO issued an Order approving the Company’s revised DRR rate, effective September 1, 2014.

In June 2011, Ohio House Bill 95 was signed into law. Outside of a base rate proceeding, this legislation permits a natural gas company to apply for recovery of much of its capital expenditure program. The legislation also allows for the deferral of costs, such as depreciation, property taxes, and debt-related post in service carrying costs. On December 12, 2012, the PUCO issued an Order approving the Company's initial deferral application under this law, reflecting its capital expenditure program covering the fifteen month period ending December 31, 2012. Such capital expenditures include infrastructure expansion and improvements not covered by the DRR as well as expenditures necessary to comply with PUCO rules, regulations, orders, and system expansion to some new customers. The Order also established a prospective bill impact evaluation on the cumulative deferrals, limiting the total deferrals at a level which would equal $1.50 per residential and small general service customer per month. In addition, the Order approved the Company's proposal that subsequent requests for accounting authority will be filed annually in April. The Company submitted its most recent annual filing on April 30, 2014, which covers the Company’s capital expenditure program through calendar year 2014.

Given the extension of the DRR through 2017 as discussed above and the continued ability to defer other capital expenses under House Bill 95, it is anticipated that the Company will file a general rate case for the inclusion in rate base of the above costs near the expiration of the DRR. As such, the bill impact limits discussed above are not expected to be reached given the Company's capital expenditure plan during the remaining four year time frame.

Indiana Recovery and Deferral Mechanisms

The Company's Indiana natural gas utilities received Orders in 2008 and 2007 associated with the most recent base rate cases. These Orders authorized the deferral of financial impacts associated with bare steel and cast iron replacement activities. The Orders provide for the deferral of depreciation and post in service carrying costs on qualifying projects totaling $20 million annually at Indiana Gas and $3 million annually at SIGECO. The debt-related post in service carrying costs are recognized in the Condensed Consolidated Statements of Income currently. The recording of post in service carrying costs and depreciation deferral is limited by individual qualifying project to three years after being placed into service at SIGECO and four years after being placed into service at Indiana Gas. At September 30, 2014 and December 31, 2013, the Company has regulatory assets totaling $15.3 million and $12.1 million, respectively, associated with the deferral of depreciation and debt-related post in service carrying cost activities.

In April 2011, Senate Bill 251 was signed into Indiana law. The law provides a framework to recover 80 percent of federally mandated costs through a periodic rate adjustment mechanism outside of a general rate case. Such costs include a return on the federally mandated capital investment, along with recovery of depreciation and other operating costs associated with these mandates. The remaining 20 percent of those costs are to be deferred for future recovery in the utility's next general rate case.

In April 2013, Senate Bill 560 was signed into law.  This legislation supplements Senate Bill 251 described above, which addressed federally mandated investment, and provides for cost recovery outside of a base rate proceeding for projects that either improve electric and gas system reliability and safety or are economic development projects that provide rural areas with access to gas service.  Provisions of the legislation require that, among other things, requests for recovery include a seven year project plan.  Once the plan is approved by the IURC, 80 percent of such costs are eligible for current recovery using a periodic rate adjustment mechanism.  Recoverable costs include a return on and of the investment, as well as property taxes and operating expenses.  The remaining 20 percent of project costs are to be deferred and recovered in the Company'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.

Pipeline Safety Law

On January 3, 2012, the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 (Pipeline Safety Law) was signed into law. The Pipeline Safety Law, which reauthorizes federal pipeline safety programs through fiscal year 2015, provides for enhanced safety, reliability, and environmental protection in the transportation of energy products by pipeline. The law increases federal enforcement authority; grants the federal government expanded authority over pipeline safety; provides for new safety regulations and standards; and authorizes or requires the completion of several pipeline safety-related studies. The DOT is required to promulgate a number of new regulatory requirements over the next two years. Those regulations may eventually lead to further regulatory or statutory requirements.

While the Company continues to study the impact of the Pipeline Safety Law and potential new regulations associated with its implementation, it is expected that the law will result in further investment in pipeline inspections, and where necessary, additional investments in pipeline infrastructure and, therefore, result in both increased levels of operating expenses and capital expenditures associated with the Company's natural gas distribution businesses.

Requests for Recovery Under Indiana Regulatory Mechanisms

The Company filed in November 2013 for authority to recover costs related to its gas infrastructure replacement and improvement programs in Indiana, including costs associated with existing pipeline safety regulations, using the mechanisms allowed under Senate Bill 251 and Senate Bill 560. On August 27, 2014, the Commission issued an Order approving the Company’s seven year capital infrastructure replacement and improvement plan, beginning in 2014, and the proposed accounting authority and recovery, pursuant to the legislation. As provided in the two laws, the Order approved semi-annual filings for rate recovery of 100 percent of the costs, inclusive of return, related to these capital investments and operating expenses associated with pipeline safety rules, with 80 percent of the costs recovered currently via an approved tracking mechanism and 20 percent of the costs deferred and recovered in the Company’s next base rate proceeding. In addition, the Order established guidelines for the Company to update its seven year capital investment plan annually, with detailed estimates provided for the upcoming calendar year. Finally, the Order approved the Company’s proposal to recover eligible costs via a fixed monthly rate per residential customer. On September 26, 2014, the Indiana Office of Utility Consumer Counselor (OUCC) filed a Notice of Appeal with the Indiana Court of Appeals in response to the IURC's Order. The specific issues raised by the OUCC have not yet been identified. An appeal was filed in response to the IURC's Order in Northern Indiana Public Service Company's (NIPSCO) Senate Bill 560 electric infrastructure proceeding, pertaining to certain issues regarding the Commission's authority to approve NIPSCO's infrastructure plan. The outcome of the NIPSCO appeal and its implications to the Company’s Order, if any, cannot be determined.

On October 1, 2014, the Company filed its initial request for approval of the revenue requirement associated with capital investment through June 30, 2014 as part of its approved infrastructure improvement plan. As the next step of the recovery process as outlined in the legislation, this filing, once approved, will initiate the rates necessary to begin cash recovery of 80 percent of the revenue requirement, with the remaining 20 percent deferred for recovery in the Company's next rate cases. Also in this filing, consistent with the guidelines set forth in the Order, the Company submitted an update to its seven year plan, to reflect changes to project prioritization as a result of both additional risk modeling and cost increases. The updated plan reflects capital expenditures of approximately $900 million, inclusive of an estimated $30 million of economic development related expenditures, over the seven year period beginning in 2014. The plan also includes approximately $15 million of annual operating costs associated with pipeline safety rules. Pursuant to Senate Bill 560, the Company expects an order by the end of 2014.

Indiana Gas GCA Cost Recovery Issue

On July 1, 2014, Indiana Gas filed its recurring quarterly Gas Cost Adjustment (GCA) mechanism, which included recovery of gas cost variances incurred for the period January through March 2014.  In August 2014, the Indiana Office of Utility Consumer Counselor (OUCC) filed testimony opposing the recovery of approximately $3.9 million of natural gas commodity purchases incurred during this period on the basis that a gas cost incentive calculation had not been properly performed. The calculation at issue is performed by the Company's supply administrator. In the winter period at issue, a pipeline force majeure event caused the gas to be priced at a location that was impacted by the extreme winter temperatures. After further review, the OUCC has modified its position in testimony filed on November 5, 2014, and now supports a reduced disallowance of $3.0 million. The Company believes that the costs are either recoverable in its GCA, or that if the incentive mechanism calculation is found to create a cost disallowance, any such loss would be allocated to its supply administrator. An order is expected in November 2014.

SIGECO Electric Environmental Compliance Filing

On January 17, 2014, SIGECO filed a request with the IURC for approval of capital investments estimated to be between $70 and $90 million on its coal-fired generation units to comply with new EPA mandates related to mercury and air toxin standards effective in 2015 and to address an outstanding Notice of Violation (NOV) from the EPA. Roughly half of the investment will be made to control mercury in both air and water emissions. The remaining investment will be made to address the NOV on alleged increases in sulfur trioxide emissions. Although the Company believes these investments are recoverable as clean coal technology under Senate Bill 29 and federal mandated investments under Senate Bill 251, the Company has requested deferred accounting treatment in lieu of timely recovery to avoid immediate customer bill impacts. The accounting treatment request seeks deferral of depreciation and property tax expense related to these investments, accrual of post in service carrying costs, and deferral of incremental operating expenses related to compliance with these standards. The Company filed its case-in-chief on March 14, 2014. Intervening parties filed their testimony on May 28, 2014, to which the Company responded with rebuttal testimony on June 20, 2014. A hearing was held beginning on July 30, 2014. The case has been fully briefed as of October 2, 2014, and the Company is awaiting a Commission order.

Coal Procurement Procedures

SIGECO annually submits its coal procurement plan for IURC review in a sub docket proceeding.  Entering 2014,  SIGECO had in place staggered term coal contracts with Vectren Fuels and one other supplier to provide supply for its generating units.  During 2014, SIGECO entered into separate negotiations with Vectren Fuels and Sunrise Coal to modify its existing contracts as well as enter into new long-term contracts in order to secure supply of coal with specifications that support its compliance with the Mercury and Air Toxins Rule. Subsequent to the sale of Vectren Fuels to an affiliate of Sunrise Coal, all such contracts have been assigned to Sunrise Coal. Those contracts were submitted to the IURC for review as part of the 2014 annual sub docket proceeding.  The OUCC filed testimony in September 2014 in support of the reasonableness of these contracts. A hearing was held in October 2014 and the Company is awaiting an order from the Commission.  

On December 5, 2011 within the quarterly FAC filing, SIGECO submitted a joint proposal with the OUCC to reduce its fuel costs billed to customers by accelerating into 2012 the impact of lower cost coal under new term contracts effective after 2012. The cost difference was deferred to a regulatory asset and is being recovered over a six year period without interest beginning in 2014.  The IURC approved this proposal on January 25, 2012, with the reduction to customer’s rates effective February 1, 2012.  The total balance deferred for recovery through the Company’s FAC, starting February 2014, was $42.4 million, of which $37.1 million remains as of September 30, 2014.

SIGECO Electric Demand Side Management Program Filing

On August 16, 2010, SIGECO filed a petition with the IURC, seeking approval of its proposed electric Demand Side Management (DSM) Programs, recovery of the costs associated with these programs, recovery of lost margins as a result of implementing these programs for large customers, and recovery of performance incentives linked with specific measurement criteria on all programs.  The DSM Programs proposed were consistent with a December 9, 2009 Order issued by the IURC, which, among other actions, defined long-term conservation objectives and goals of DSM programs for all Indiana electric utilities under a consistent statewide approach.  In order to meet these objectives, the IURC Order divided the DSM programs into Core and Core Plus programs.  Core programs are joint programs required to be offered by all Indiana electric utilities to all customers, and include some for large industrial customers.  Core Plus programs are those programs not required specifically by the IURC, but defined by each utility to meet the overall energy savings targets defined by the IURC.

On August 31, 2011 the IURC issued an Order approving an initial three year DSM plan in the SIGECO electric service territory that complied with the IURC’s energy saving targets.  Consistent with the Company’s proposal, the Order approved, among other items, the following: 1) recovery of costs associated with implementing the DSM Plan; 2) the recovery of a performance incentive mechanism based on measured savings related to certain DSM programs; 3) lost margin recovery associated with the implementation of DSM programs for large customers; and 4) deferral of lost margin up to $3 million in 2012 and $1 million in 2011 associated with small customer DSM programs for subsequent recovery under a tracking mechanism to be proposed by the Company.  On June 20, 2012, the IURC issued an Order approving a small customer lost margin recovery mechanism, inclusive of all previous deferrals. This mechanism is an alternative to the electric decoupling proposal that was denied by the IURC in the Company's last base rate proceeding.  For the nine months endedSeptember 30, 2014 and September 30, 2013, the Company recognized Electric revenue of $6.6 million and $3.5 million, respectively, associated with this approved lost margin recovery mechanism.

On March 28, 2014, Senate Bill 340 was signed into law. This legislation ends electric DSM programs on December 31, 2014 that have been conducted to meet the energy savings requirements established in the Commission's December 2009 Order. The legislation also allows for industrial customers to opt out of participating in energy efficiency programs. As of July 1, 2014, approximately 71 percent of the Company’s eligible industrial load has opted out of participation in the applicable energy efficiency programs. Indiana's governor has requested that the Commission make new recommendations for energy efficiency programs to be proposed for 2015 and beyond, and has also asked the legislature to consider further legislation requiring some level of utility sponsored energy efficiency programs. The Company filed a request for Commission approval of a new portfolio of DSM programs on May 29, 2014 to be offered in 2015. On October 15, 2014, the Commission issued an Order approving a Settlement between the OUCC and the Company regarding the new portfolio of DSM programs effective January 2015.

Indiana Gas Pipeline Safety Investigation

On April 11, 2012, the IURC's pipeline safety division filed a complaint against Indiana Gas alleging several violations of safety regulations pertaining to damage that occurred at a residence in Indiana Gas's service territory during a pipeline replacement project. The Company negotiated a settlement with the IURC's pipeline safety division, agreeing to a fine and several modifications to the Company's operating policies. The amount of the fine was not material to the Company's financial results. The IURC approved the settlement but modified certain terms of the settlement and added a requirement that Company employees conduct inspections of pipeline excavations. The Company sought and was granted a request for rehearing on the sole issue related to the requirement to use Company employees to inspect excavations. A settlement in the case was reached between the IURC's pipeline safety division and Indiana Gas that allowed Indiana Gas to continue to use its risk based approach to inspecting excavations and to allow the Company to continue using a mix of highly trained and qualified contractors and employees to perform inspections. On January 15, 2014, the IURC issued a Final Order in the case approving the settlement agreement, without modification.

Indiana Gas & SIGECO Gas Decoupling Extension Filing

On August 18, 2011, the IURC issued an Order granting the extension of the current decoupling mechanism in place at both gas companies and recovery of new conservation program costs through December 2015. The Order provides that the companies must submit an extension proposal no later than March 1, 2015.

FERC Return on Equity Complaint

On November 12, 2013, certain parties representing a group of industrial customers filed a joint complaint with the FERC under Section 206 of the Federal Power Act against MISO and various MISO transmission owners, including SIGECO. The joint parties seek to reduce the 12.38 percent return on equity used in the MISO transmission owners’ rates, including SIGECO’s formula transmission rates, to 9.15 percent, and to set a capital structure in which the equity component does not exceed 50 percent. The MISO transmission owners filed their response to the complaint on January 6, 2014, opposing any change to the return. As of September 30, 2014, the Company had invested approximately $157.7 million in qualifying projects. The net plant balance for these projects totaled $144.5 million at September 30, 2014.

This joint complaint is similar to a complaint against the New England Transmission Owners (NETO) filed in September 2011, which requested that the 11.14 percent incentive return granted on qualifying investments in NETO be lowered. On October 16, 2014, the FERC issued an Order in the NETO case approving the 10.57 percent return on equity and the methodology set out in its June 19, 2014 decision.

In addition to the NETO ruling, the FERC acknowledged that the pending complaint raised against the MISO transmission owners is reasonable, and ordered the initiation of a formal settlement discussion, mediated by a FERC appointed judge, in November 2014. If a settlement is not reached, the case will move to a formal evidentiary hearing before the FERC. The Company has established a reserve pending the outcome of this complaint.

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Fair Value Measurements

9 Months Ended

Sep. 30, 2014

Fair Value Disclosures [Abstract]

Fair Value Measurements

Fair Value Measurements

The carrying values and estimated fair values using primarily Level 2 assumptions of the Company's other financial instruments follow:

	September 30, 2014				December 31, 2013
(In millions)	Carrying Amount		Est. Fair Value		Carrying Amount		Est. Fair Value
Long-term debt	$	1,257.3	$	1,398.2	$	1,257.1	$	1,317.4
Short-term borrowings	60.1		60.1		28.6		28.6
Cash & cash equivalents	5.4		5.4		8.6		8.6

For the balance sheet dates presented in these financial statements, the Company had no material assets or liabilities recorded at fair value outstanding, and no material assets or liabilities valued using Level 3 inputs.

Certain methods and assumptions must be used to estimate the fair value of financial instruments.  The fair value of the Company's long-term debt was estimated based on the quoted market prices for the same or similar issues or on the current rates offered to the Company for instruments with similar characteristics.  Because of the maturity dates and variable interest rates of short-term borrowings and cash & cash equivalents, those carrying amounts approximate fair value.  Because of the inherent difficulty of estimating interest rate and other market risks, the methods used to estimate fair value may not always be indicative of actual realizable value, and different methodologies could produce different fair value estimates at the reporting date.

Under current regulatory treatment, call premiums on reacquisition of utility-related long-term debt are generally recovered in customer rates over the life of the refunding issue or over a 15-year period.  Accordingly, any reacquisition of this debt would not be expected to have a material effect on the Company's results of operations.

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Segment Reporting (Tables)

9 Months Ended

Sep. 30, 2014

Segment Reporting [Abstract]

Schedule of Segment Reporting Information, by Segment [Table Text Block]

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(In millions)	2014			2013			2014			2013
Revenues
Gas Utility Services	$	105.1		$	101.9		$	681.1		$	555.8
Electric Utility Services	165.9			165.8			480.9			470.0
Other Operations	9.6			9.5			28.7			28.5
Eliminations	(9.5		)	(9.5		)	(28.5		)	(28.3		)
Total revenues	$	271.1		$	267.7		$	1,162.2		$	1,026.0
Profitability Measure - Net Income
Gas Utility Services	$	(5.1	)	$	(3.8	)	$	33.9		$	37.2
Electric Utility Services	26.7			26.6			65.9			60.1
Other Operations	2.7			2.5			8.7			7.3
Total net income	$	24.3		$	25.3		$	108.5		$	104.6

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Excise and Utility Receipts Taxes (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Excise and Utility Receipts Taxes [Abstract]
Excise and utility taxes collected and reported in operating revenue	$ 4.9	$ 4.8	$ 23.3	$ 20.9

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CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS (Unaudited) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013
CASH FLOWS FROM OPERATING ACTIVITIES [Abstract]
Profitability Measure - Net income (loss)	$ 108.5	$ 104.6
Adjustments to Reconcile Net Income to Cash from Operating Activities [Abstract]
Depreciation & Amortization	151.5	146.8
Deferred income taxes & investment tax credits	19.8	27.9
Expense portion of pension & postretirement periodic benefit cost	3.5	4.2
Provision for uncollectible accounts	3.7	4.8
Other non-cash expense - net	2.3	4.7
Changes in working capital accounts [Abstract]
Accounts receivable & accrued unbilled revenue	111.3	67.7
Inventories	(19.8)	15.5
Recoverable/refundable fuel & natural gas costs	(22.6)	5.8
Prepayments & other current assets	(9.6)	4.3
Accounts payable, including to Vectren companies & affiliated companies	(42.2)	(64.0)
Accrued liabilities	(15.8)	(16.5)
Changes in noncurrent ssets	0.9	(6.5)
Changes in noncurrent liabilities	(9.1)	(3.9)
Net cash provided by operating activities	282.4	295.4
Proceeds from:
Long-term debt - net of issuance costs	63.0	232.7
Additional capital contribution	4.6	4.5
Requirements for:
Dividends to parent	(81.4)	(78.8)
Retirement of long-term debt	(63.6)	(337.5)
Net change in short-term borrowings	31.5	59.4
Net cash used in financing activities	(45.9)	(119.7)
CASH FLOWS FROM INVESTING ACTIVITIES [Abstract]
Proceeds from other investing activities	0.3	0.8
Requirements for:
Capital expenditures, excluding AFUDC equity	(240.0)	(183.6)
Net cash used in investing activities	(239.7)	(182.8)
Net change in cash and cash equivalents	(3.2)	(7.1)
Cash and cash equivalents at beginning of period	8.6	13.3
Cash and cash equivalents at end of period	$ 5.4	$ 6.2

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Accruals for Utility and NonUtility Plant

9 Months Ended

Sep. 30, 2014

Accruals for Utility & Nonutility Plant [Abstract]

Accruals for Utility and NonUtility Plant [Text Block]

Supplemental Cash Flow Information

As of September 30, 2014 and December 31, 2013, the Company has accruals related to utility and nonutility plant purchases totaling approximately $19.3 million and $13.1 million, respectively.

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Accruals for Utility and NonUtility Plant Accruals for Utility and NonUtility Plant (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Accruals for Utility & Nonutility Plant [Abstract]
Public Utilities Accruals For Purchase Of Utility And Non Utility Plant Assets	$ 19.3	$ 13.1

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Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2014

Fair Value Disclosures [Abstract]

Fair Value, by Balance Sheet Grouping [Table Text Block]

The carrying values and estimated fair values using primarily Level 2 assumptions of the Company's other financial instruments follow:

	September 30, 2014				December 31, 2013
(In millions)	Carrying Amount		Est. Fair Value		Carrying Amount		Est. Fair Value
Long-term debt	$	1,257.3	$	1,398.2	$	1,257.1	$	1,317.4
Short-term borrowings	60.1		60.1		28.6		28.6
Cash & cash equivalents	5.4		5.4		8.6		8.6