Edgar Filing: VECTREN UTILITY HOLDINGS INC

VUHI 9.30.2014 10Q

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



[_]	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

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.

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.

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.

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.

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.

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 ended September 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 ended September 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 ended September 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 ended September 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


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

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

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 ended September 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.


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.

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.


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 interes