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 March 31, 2015

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	April 30, 2015
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
EPA:  Environmental Protection Agency	BTU / MMBTU:  British thermal units/ millions of BTU
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	ASC: Accounting Standards Codification
IDEM:  Indiana Department of Environmental Management	OUCC:  Indiana Office of the Utility Consumer Counselor
GCA: Gas Cost Adjustment	XBRL:  eXtensible Business Reporting Language
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	GAAP: Generally Accepted Accounting Principles

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 the Condensed Consolidated Financial Statements (Unaudited)	7
2	Management’s Discussion and Analysis of Results of Operations and Financial Condition	24
3	Quantitative and Qualitative Disclosures About Market Risk	41
4	Controls and Procedures	41
	PART II.  OTHER INFORMATION
1	Legal Proceedings	42
1A	Risk Factors	42
2	Unregistered Sales of Equity Securities and Use of Proceeds	42
3	Defaults Upon Senior Securities	42
4	Mine Safety Disclosures	42
5	Other Information	42
6	Exhibits	43
	Signatures	44

2

PART I.  FINANCIAL INFORMATION

ITEM 1.  FINANCIAL STATEMENTS

VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited – In millions)

	March 31, 2015		December 31, 2014
ASSETS
Current Assets
Cash & cash equivalents	$	10.4	$	19.3
Accounts receivable - less reserves of $5.3 & $3.9, respectively	137.3		113.0
Accrued unbilled revenues	94.3		122.4
Inventories	86.8		113.2
Recoverable fuel & natural gas costs	—		9.8
Prepayments & other current assets	20.5		83.5
Total current assets	349.3		461.2
Utility Plant
Original cost	5,778.0		5,718.7
Less:  accumulated depreciation & amortization	2,316.9		2,279.7
Net utility plant	3,461.1		3,439.0
Investments in unconsolidated affiliates	0.2		0.2
Other investments	25.4		25.6
Nonutility plant - net	145.7		149.2
Goodwill - net	205.0		205.0
Regulatory assets	119.5		128.3
Other assets	17.8		19.6
TOTAL ASSETS	$	4,324.0	$	4,428.1

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)

	March 31, 2015		December 31, 2014
LIABILITIES & SHAREHOLDER'S EQUITY
Current Liabilities
Accounts payable	$	132.2	$	180.4
Payables to other Vectren companies	19.7		28.6
Refundable fuel & natural gas costs	23.0		—
Accrued liabilities	148.6		122.3
Short-term borrowings	5.9		156.4
Current maturities of long-term debt	90.0		95.0
Total current liabilities	419.4		582.7
Long-Term Debt - Net of Current Maturities	1,162.4		1,162.3
Deferred Credits & Other Liabilities
Deferred income taxes	696.4		685.1
Regulatory liabilities	417.1		410.3
Deferred credits & other liabilities	113.2		109.2
Total deferred credits & other liabilities	1,226.7		1,204.6
Commitments & Contingencies (Notes 8 - 11)
Common Shareholder's Equity
Common stock (no par value)	795.3		793.7
Retained earnings	720.2		684.8
Total common shareholder's equity	1,515.5		1,478.5
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	$	4,324.0	$	4,428.1

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
	March 31,
	2015		2014
OPERATING REVENUES
Gas utility	$	352.9	$	443.6
Electric utility	153.9		163.0
Other	0.1		—
Total operating revenues	506.9		606.6
OPERATING EXPENSES
Cost of gas sold	172.0		270.9
Cost of fuel & purchased power	50.1		57.0
Other operating	102.8		98.3
Depreciation & amortization	52.1		49.9
Taxes other than income taxes	19.1		20.1
Total operating expenses	396.1		496.2
OPERATING INCOME	110.8		110.4
Other income - net	4.9		3.9
Interest expense	16.6		16.7
INCOME BEFORE INCOME TAXES	99.1		97.6
Income taxes	36.1		36.3
NET INCOME	$	63.0	$	61.3

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)

	Three Months Ended
	March 31,
	2015			2014
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	63.0		$	61.3
Adjustments to reconcile net income to cash from operating activities:
Depreciation & amortization	52.1			49.9
Deferred income taxes & investment tax credits	13.2			5.0
Expense portion of pension & postretirement periodic benefit cost	1.2			1.2
Provision for uncollectible accounts	3.1			1.6
Other non-cash items - net	1.4			0.9
Changes in working capital accounts:
Accounts receivable & accrued unbilled revenue	0.7			(34.1		)
Inventories	26.4			35.6
Recoverable/refundable fuel & natural gas costs	30.3			(24.2		)
Prepayments & other current assets	60.4			26.8
Accounts payable, including to Vectren companies                     & affiliated companies	(51.7		)	(18.4		)
Accrued liabilities	28.8			39.7
Changes in noncurrent assets	12.7			13.3
Changes in noncurrent liabilities	(0.3		)	(2.6		)
Net cash provided by operating activities	241.3			156.0
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from additional capital contribution	1.6			1.6
Requirements for:
Dividends to parent	(27.6		)	(27.1		)
Retirement of long-term debt	(5.0		)	—
Net change in short-term borrowings	(150.5		)	(28.6		)
Net cash used in financing activities	(181.5		)	(54.1		)
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from other investing activities	0.2			0.1
Requirements for capital expenditures, excluding AFUDC equity	(68.9		)	(58.0		)
Net cash used in investing activities	(68.7		)	(57.9		)
Net change in cash & cash equivalents	(8.9		)	44.0
Cash & cash equivalents at beginning of period	19.3			8.6
Cash & cash equivalents at end of period	$	10.4		$	52.6

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 over 585,000 natural gas customers located in central and southern Indiana. SIGECO provides energy delivery services to over 143,000 electric customers and over 111,000 gas customers located near Evansville in southwestern Indiana.  SIGECO also owns and operates electric generation assets to serve its electric customers and optimizes those assets in the wholesale power market.  Indiana Gas and SIGECO generally do business as Vectren Energy Delivery of Indiana.  VEDO provides energy delivery services to over 317,000 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, 2014, 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 $6 million was outstanding at March 31, 2015, and Utility Holdings’ has unsecured senior notes with a par value of $875 million outstanding at March 31, 2015.  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 March 31, 2015 (in millions):

ASSETS	Subsidiary		Parent		Eliminations &
	Guarantors		Company		Reclassifications			Consolidated
Current Assets
Cash & cash equivalents	$	10.0	$	0.4	$	—		$	10.4
Accounts receivable - less reserves	137.3		—		—			137.3
Intercompany receivables	69.8		109.3		(179.1		)	—
Accrued unbilled revenues	94.3		—		—			94.3
Inventories	86.7		0.1		—			86.8
Prepayments & other current assets	11.6		43.9		(35.0		)	20.5
Total current assets	409.7		153.7		(214.1		)	349.3
Utility Plant
Original cost	5,778.0		—		—			5,778.0
Less:  accumulated depreciation & amortization	2,316.9		—		—			2,316.9
Net utility plant	3,461.1		—		—			3,461.1
Investments in consolidated subsidiaries	—		1,452.3		(1,452.3		)	—
Notes receivable from consolidated subsidiaries	—		746.5		(746.5		)	—
Investments in unconsolidated affiliates	0.2		—		—			0.2
Other investments	21.3		4.1		—			25.4
Nonutility plant - net	1.7		144.0		—			145.7
Goodwill - net	205.0		—		—			205.0
Regulatory assets	98.2		21.3		—			119.5
Other assets	28.8		1.6		(12.6		)	17.8
TOTAL ASSETS	$	4,226.0	$	2,523.5	$	(2,425.5	)	$	4,324.0
LIABILITIES & SHAREHOLDER'S EQUITY	Subsidiary		Parent		Eliminations &
	Guarantors		Company		Reclassifications			Consolidated
Current Liabilities
Accounts payable	$	127.4	$	4.8	$	—		$	132.2
Intercompany payables	12.8		0.7		(13.5		)	—
Payables to other Vectren companies	19.7		—		—			19.7
Refundable fuel & natural gas costs	23.0		—		—			23.0
Accrued liabilities	165.7		17.9		(35.0		)	148.6
Short-term borrowings	—		5.9		—			5.9
Intercompany short-term borrowings	22.4		69.1		(91.5		)	—
Current maturities of long-term debt	15.0		75.0		—			90.0
Current maturities of long-term debt due to VUHI	74.1		—		(74.1		)	—
Total current liabilities	460.1		173.4		(214.1		)	419.4
Long-Term Debt
Long-term debt	362.7		799.7		—			1,162.4
Long-term debt due to VUHI	746.5		—		(746.5		)	—
Total long-term debt - net	1,109.2		799.7		(746.5		)	1,162.4
Deferred Credits & Other Liabilities
Deferred income taxes	668.5		27.9		—			696.4
Regulatory liabilities	415.6		1.5		—			417.1
Deferred credits & other liabilities	120.3		5.5		(12.6		)	113.2
Total deferred credits & other liabilities	1,204.4		34.9		(12.6		)	1,226.7
Common Shareholder's Equity
Common stock (no par value)	808.5		795.3		(808.5		)	795.3
Retained earnings	643.8		720.2		(643.8		)	720.2
Total common shareholder's equity	1,452.3		1,515.5		(1,452.3		)	1,515.5
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	$	4,226.0	$	2,523.5	$	(2,425.5	)	$	4,324.0

8

Condensed Consolidating Balance Sheet as of December 31, 2014 (in millions):

ASSETS	Subsidiary		Parent		Eliminations &
	Guarantors		Company		Reclassifications			Consolidated
Current Assets
Cash & cash equivalents	$	6.9	$	12.4	$	—		$	19.3
Accounts receivable - less reserves	113.0		—		—			113.0
Intercompany receivables	0.8		186.7		(187.5		)	—
Accrued unbilled revenues	122.4		—		—			122.4
Inventories	113.2		—		—			113.2
Recoverable fuel & natural gas costs	9.8		—		—			9.8
Prepayments & other current assets	94.8		38.1		(49.4		)	83.5
Total current assets	460.9		237.2		(236.9		)	461.2
Utility Plant
Original cost	5,718.7		—		—			5,718.7
Less:  accumulated depreciation & amortization	2,279.7		—		—			2,279.7
Net utility plant	3,439.0		—		—			3,439.0
Investments in consolidated subsidiaries	—		1,416.9		(1,416.9		)	—
Notes receivable from consolidated subsidiaries	—		746.5		(746.5		)	—
Investments in unconsolidated affiliates	0.2		—		—			0.2
Other investments	21.3		4.3		—			25.6
Nonutility plant - net	1.8		147.4		—			149.2
Goodwill - net	205.0		—		—			205.0
Regulatory assets	106.7		21.6		—			128.3
Other assets	29.4		1.7		(11.5		)	19.6
TOTAL ASSETS	$	4,264.3	$	2,575.6	$	(2,411.8	)	$	4,428.1
LIABILITIES & SHAREHOLDER'S EQUITY	Subsidiary		Parent		Eliminations &
	Guarantors		Company		Reclassifications			Consolidated
Current Liabilities
Accounts payable	$	176.2	$	4.2	$	—		$	180.4
Intercompany payables	15.6		0.8		(16.4		)	—
Payables to other Vectren companies	28.6		—		—			28.6
Accrued liabilities	136.7		35.0		(49.4		)	122.3
Short-term borrowings	—		156.4		—			156.4
Intercompany short-term borrowings	97.0		—		(97.0		)	—
Current maturities of long-term debt	20.0		75.0		—			95.0
Current maturities of long-term debt due to VUHI	74.1		—		(74.1		)	—
Total current liabilities	548.2		271.4		(236.9		)	582.7
Long-Term Debt
Long-term debt - net of current maturities &
debt subject to tender	362.6		799.7		—			1,162.3
Long-term debt due to VUHI	746.5		—		(746.5		)	—
Total long-term debt - net	1,109.1		799.7		(746.5		)	1,162.3
Deferred Credits & Other Liabilities
Deferred income taxes	665.8		19.3		—			685.1
Regulatory liabilities	408.8		1.5		—			410.3
Deferred credits & other liabilities	115.5		5.2		(11.5		)	109.2
Total deferred credits & other liabilities	1,190.1		26.0		(11.5		)	1,204.6
Common Shareholder's Equity
Common stock (no par value)	806.9		793.7		(806.9		)	793.7
Retained earnings	610.0		684.8		(610.0		)	684.8
Total common shareholder's equity	1,416.9		1,478.5		(1,416.9		)	1,478.5
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	$	4,264.3	$	2,575.6	$	(2,411.8	)	$	4,428.1

9

Condensed Consolidating Statement of Income for the three months ended March 31, 2015 (in millions):

	Subsidiary Guarantors		Parent Company			Eliminations & Reclassifications			Consolidated
OPERATING REVENUES
Gas utility	$	352.9	$	—		$	—		$	352.9
Electric utility	153.9		—			—			153.9
Other	—		10.2			(10.1		)	0.1
Total operating revenues	506.8		10.2			(10.1		)	506.9
OPERATING EXPENSES
Cost of gas sold	172.0		—			—			172.0
Cost of fuel & purchased power	50.1		—			—			50.1
Other operating	112.4		—			(9.6		)	102.8
Depreciation & amortization	45.6		6.4			0.1			52.1
Taxes other than income taxes	18.7		0.4			—			19.1
Total operating expenses	398.8		6.8			(9.5		)	396.1
OPERATING INCOME	108.0		3.4			(0.6		)	110.8
Other income - net	4.1		10.8			(10.0		)	4.9
Interest expense	15.9		11.3			(10.6		)	16.6
INCOME BEFORE INCOME TAXES	96.2		2.9			—			99.1
Income taxes	36.7		(0.6		)	—			36.1
Equity in earnings of consolidated companies, net of tax	—		59.5			(59.5		)	—
NET INCOME	$	59.5	$	63.0		$	(59.5	)	$	63.0

Condensed Consolidating Statement of Income for the three months ended March 31, 2014 (in millions):

	Subsidiary Guarantors		Parent Company			Eliminations & Reclassifications			Consolidated
OPERATING REVENUES
Gas utility	$	443.6	$	—		$	—		$	443.6
Electric utility	163.0		—			—			163.0
Other	—		9.6			(9.6		)	—
Total operating revenues	606.6		9.6			(9.6		)	606.6
OPERATING EXPENSES
Cost of gas sold	270.9		—			—			270.9
Cost of fuel & purchased power	57.0		—			—			57.0
Other operating	107.5		—			(9.2		)	98.3
Depreciation & amortization	44.4		5.4			0.1			49.9
Taxes other than income taxes	19.6		0.4			0.1			20.1
Total operating expenses	499.4		5.8			(9.0		)	496.2
OPERATING INCOME	107.2		3.8			(0.6		)	110.4
Other income - net	3.0		10.7			(9.8		)	3.9
Interest expense	15.8		11.3			(10.4		)	16.7
INCOME BEFORE INCOME TAXES	94.4		3.2			—			97.6
Income taxes	36.8		(0.5		)	—			36.3
Equity in earnings of consolidated companies, net of tax	—		57.6			(57.6		)	—
NET INCOME	$	57.6	$	61.3		$	(57.6	)	$	61.3

10

Condensed Consolidating Statement of Cash Flows for the three months endedMarch 31, 2015 (in millions):

	Subsidiary Guarantors			Parent Company			Eliminations			Consolidated
NET CASH PROVIDED BY OPERATING ACTIVITIES	$	240.6		$	0.7		$	—		$	241.3
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from
Additional capital contribution from parent	1.6			1.6			(1.6		)	1.6
Requirements for:
Dividends to parent	(25.8		)	(27.6		)	25.8			(27.6		)
Retirement of long term debt	(5.0		)	—			—			(5.0		)
Net change in intercompany short-term borrowings	(74.6		)	69.1			5.5			—
Net change in short-term borrowings	—			(150.5		)	—			(150.5		)
Net cash used in financing activities	(103.8		)	(107.4		)	29.7			(181.5		)
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from:
Consolidated subsidiary distributions	—			25.8			(25.8		)	—
Other investing activities	—			0.2			—			0.2
Requirements for:
Capital expenditures, excluding AFUDC equity	(64.6		)	(4.3		)	—			(68.9		)
Consolidated subsidiary investments	—			(1.6		)	1.6			—
Net change in short-term intercompany notes receivable	(69.1		)	74.6			(5.5		)	—
Net cash used in investing activities	(133.7		)	94.7			(29.7		)	(68.7		)
Net change in cash & cash equivalents	3.1			(12.0		)	—			(8.9		)
Cash & cash equivalents at beginning of period	6.9			12.4			—			19.3
Cash & cash equivalents at end of period	$	10.0		$	0.4		$	—		$	10.4

Condensed Consolidating Statement of Cash Flows for the three months endedMarch 31, 2014 (in millions):

	Subsidiary Guarantors			Parent Company			Eliminations			Consolidated
NET CASH PROVIDED BY OPERATING ACTIVITIES	$	137.2		$	18.8		$	—		$	156.0
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from:
Long-term debt, net of issuance costs	124.2			—			(124.2		)	—
Additional capital contribution from parent	1.6			1.6			(1.6		)	1.6
Requirements for:
Dividends to parent	(25.4		)	(27.1		)	25.4			(27.1		)
Net change in intercompany short-term borrowings	(73.1		)	85.6			(12.5		)	—
Net change in short-term borrowings	—			(28.6		)	—			(28.6		)
Net cash used in financing activities	27.3			31.5			(112.9		)	(54.1		)
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from:
Consolidated subsidiary distributions	—			25.4			(25.4		)	—
Other investing activities	—			0.1			—			0.1
Requirements for:
Capital expenditures, excluding AFUDC equity	(51.3		)	(6.7		)	—			(58.0		)
Consolidated subsidiary investments	—			(1.6		)	1.6			—
Net change in long-term intercompany notes receivable	—			(124.2		)	124.2			—
Net change in short-term intercompany notes receivable	(85.6		)	73.1			12.5			—
Net cash used in investing activities	(136.9		)	(33.9		)	112.9			(57.9		)
Net change in cash & cash equivalents	27.6			16.4			—			44.0
Cash & cash equivalents at beginning of period	8.2			0.4			—			8.6
Cash & cash equivalents at end of period	$	35.8		$	16.8		$	—		$	52.6

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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, which totaled $11.7 million and $12.9 million in the three months ended March 31, 2015 and 2014, respectively, as a component of operating revenues. Expense associated with excise and utility receipts taxes are recorded as a component of Taxes other than income taxes.

5. Supplemental Cash Flow Information

As of March 31, 2015 and December 31, 2014, the Company has accruals related to utility and nonutility plant purchases totaling approximately $12.1 million and $19.0 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.  The Company purchased $30.8 million for the three months ended March 31, 2014.  After the exit of the coal mining business by Vectren, Sunrise has assumed Vectren Fuels' supply contracts and has also negotiated new contracts for similar quality coal that will result in the Company purchasing most of its coal supply from Sunrise.

Vectren Infrastructure Services Corporation (VISCO)

VISCO, a wholly owned subsidiary of Vectren, provides underground pipeline construction and repair services. VISCO's customers include Utility Holdings’ utilities and fees incurred by Utility Holdings and its subsidiaries totaled $17.7 million and $11.4 million for the three months ended March 31, 2015 and 2014, respectively. Amounts owed to VISCO at March 31, 2015 and December 31, 2014 are included in Payables to other Vectren companies in the Condensed Consolidated Balance Sheets.

Support Services & Purchases

Vectren provides corporate and general and administrative services to the Company and allocates certain costs to the Company, including costs for share-based compensation and for pension and other postretirement benefits that are not directly charged to subsidiaries. These costs are allocated using various allocators, including number of employees, number of customers and/or the level of payroll, revenue contribution and capital expenditures.  Allocations are at cost.  For the three months ended March 31, 2015 and 2014, Utility Holdings received corporate allocations totaling $15.6 million and $14.7 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

Indiana Gas Unsecured Note Retirement

On March 15, 2015, a $5.0 million Indiana Gas senior unsecured note matured. The Series E note carried a fixed interest rate of 7.15%. The repayment of debt was funded from the Company's short term credit facility.

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. 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.

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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. Gas Rate & Regulatory Matters

Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement

The Company monitors and maintains its natural gas distribution system to ensure that natural gas is delivered in a safe and efficient manner. The Company's natural gas utilities are currently engaged in programs to replace bare steel and cast iron infrastructure and other activities in both Indiana and Ohio to mitigate risk, improve the system, and comply with applicable regulations, many of which are a result of federal pipeline safety requirements. Laws 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.

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

In April 2013, Indiana Senate Bill 560 (Senate Bill 560) was signed into Indiana law. This legislation supplements Senate Bill 251 described above, and provides for cost recovery outside of a base rate proceeding for projects that either improve electric and gas system reliability and safety or are economic development projects that provide rural areas with access to gas service. Provisions of the legislation require that, among other things, requests for recovery include a seven-year project plan. Once the plan is approved by the IURC, 80 percent of such costs are eligible for current recovery using a periodic rate adjustment mechanism. Recoverable costs include a return on and of the investment, as well as property taxes and operating expenses. The remaining 20 percent of project costs is deferred and recovered in the utility’s next general rate case, which must be filed before the expiration of the seven year plan. The adjustment mechanism is capped at an annual increase in retail revenues of no more than two percent.

In June 2011, Ohio House Bill 95 (House Bill 95) was signed into law. Outside of a base rate proceeding, this legislation permits a natural gas utility to apply for recovery of much of its capital expenditure program. By allowing for the deferral of costs, such as depreciation, property taxes, and debt-related post in service carrying costs until recovery is approved by the Ohio Commission.

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 March 31, 2015 and December 31, 2014, the Company has regulatory assets totaling $17.3 million and $16.4 million, respectively, associated with the deferral of depreciation and debt-related post-in-service carrying cost activities. Beginning in 2014, all bare steel and cast iron replacement activities are now part of the Company’s seven-year capital investment plan filed pursuant to Senate Bill 251, discussed further below.

Requests for Recovery Under Indiana Regulatory Mechanisms

On August 27, 2014, the IURC 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 Senate Bill 251 and 560. As provided in the two laws, the Order approved semi-annual filings for rate recovery of 100 percent of the costs,

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inclusive of return, related to these capital investments and operating expenses, 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 to annually update the seven-year capital investment plan. Finally, the Order approved the Company’s proposal to recover eligible costs via a fixed monthly charge per residential customer.

On September 26, 2014, the OUCC filed an appeal of the IURC's finding that the remaining value of retired assets replaced during the infrastructure projects should not be netted against the cost being recovered in the tracking mechanism. In April 2015, the Indiana Court of Appeals issued an opinion on an appeal involving Northern Indiana Public Service Company’s (NIPSCO) infrastructure cost recovery mechanism finding that the value of retired assets should not be netted against the current recovery of costs. Although the opinion is specific to NIPSCO, the Company believes this decision is a positive outcome related to its pending appeal.

Additionally, in the NIPSCO appeal, the IURC’s approval of the reasonableness of that infrastructure investment plan was challenged. The Court found that NIPSCO had failed to provide sufficient detail regarding its planned projects after year one of the plan to support the IURC's approval. An industrial group has asked the Court of Appeals to now consider that issue as part of the pending appeal of the Company's Order. Given this issue was never raised during the Company's IURC case or on appeal during the briefing period, the Company believes the opportunity to raise this issue has been waived and has asked the Court to strike the filing. The Court should decide these issues later this year.

On January 14, 2015, the IURC issued an Order approving the Company’s initial request for recovery of the revenue requirement through June 30, 2014 as part of its approved seven-year plan. As the next step of the recovery process, as outlined in the legislation, this Order initiates the rates and charges 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 case. Also, consistent with the guidelines set forth in the original August 2014 Order, the IURC approved the Company’s 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, an increase of $35 million from the previous plan and is 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.

On April 1, 2015, the Company filed its second request for recovery of the revenue requirement associated with capital investment and applicable operating costs through December 31, 2014. A procedural schedule has not been set in this proceeding. The Company expects an order in this proceeding mid-year in 2015.

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 $156.5 million. Regulatory assets associated with post-in-service carrying costs and depreciation deferrals were $14.2 million and $13.1 million at March 31, 2015 and December 31, 2014, 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 issued an Order approving a Stipulation entered into by the PUCO Staff and the Company which provided for the extension of the DRR for the recovery of costs incurred through 2017 and expanded the types of investment covered by the DRR to include recovery of other infrastructure investments. The Order limits the resulting DRR fixed charge per month for residential and small general service customers to specific graduated levels over the next five years. The Company's five-year capital expenditure plan related to these infrastructure investments for calendar years 2013 through 2017 totals approximately $200 million. The capital expenditure plan is subject to the graduated caps on the fixed DRR monthly charge applicable to residential and small general service customers approved in the Order however is not expected to exceed those caps. In addition, the Order approved the Company's commitment that the DRR can only be

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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 rates and charges, effective September 1, 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 below are not expected to be reached given the Company's capital expenditure plan during the remaining three-year time frame.

The PUCO has also issued Orders approving the Company's filings under Ohio House Bill 95. These Orders approve deferral of the Company’s Ohio capital expenditure program for items not covered by the DRR as well as expenditures necessary to comply with PUCO rules, regulations, orders, and system expansion to some new customers. Ohio House Bill 95 Orders also have established a prospective bill impact evaluation on the cumulative deferrals, limiting the total deferrals at a level which would equal $1.50 per residential and small general service customer per month. As of March 31, 2015, the Company's deferrals have not reached this bill impact cap. In addition, the Orders 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.

Other Regulatory Matters

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 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 modified its position in testimony filed on November 5, 2014, and suggested a reduced disallowance of $3 million. The IURC moved this specific issue to a sub-docket proceeding. On April 1, 2015, a stipulation and settlement agreement between the Company, the OUCC, and the Company’s supply administrator was filed in this proceeding. Pending a final order from the IURC approving the stipulation, the agreement results in recovery of approximately $1.4 million of the disputed amount via the Company’s GCA mechanism, with the remaining $1.6 million from the gas supply administrator.

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 Indiana gas companies and recovery of new conservation program costs through December 2015. The Companies have reached an agreement in principle with the OUCC to extend the decoupling mechanism through 2020. The settlement was filed for approval on March 1, 2015. The settlement was unopposed and a hearing has been set for May 2015. The Company expects an order later in 2015.

10. Electric Rate & Regulatory Matters

SIGECO Electric Environmental Compliance Filing

On January 28, 2015, the IURC issued an Order approving the Company’s request for approval of capital investments on its coal-fired generation units to comply with new EPA mandates related to mercury and air toxin standards effective in 2015 and to address an outstanding Notice of Violation (NOV) from the EPA. As of March 31, 2015, approximately $29 million has been spent on equipment to control mercury in both air and water emissions, and $16 million to address the issues raised in the NOV proceeding on the increase in sulfur trioxide emissions. The total investment is estimated to be between $80 and $90 million. The Order approved the Company’s request for deferred accounting treatment, as supported by provisions under Indiana Senate Bill 29 (Senate Bill 29) and Senate Bill 251. The accounting treatment includes the deferral of depreciation and property tax expense related to these investments, accrual of post-in-service carrying costs, and deferral of incremental operating expenses related to compliance with these standards. The initial phase of the projects went into service in 2014, with the remaining investment expected to occur in 2015 and 2016. As of March 31, 2015, the Company

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has approximately $0.7 million deferred related to depreciation, property tax, and operating expense, and $0.3 million deferred related to post-in-service carrying costs.

In March 2015, the Company was notified that certain parties had filed a Notice of Appeal with the Indiana Court of Appeals in response to the IURC's Order. Appellate briefs will be presented to the Court later in 2015 and it is expected the Court will decide on these issues in the second half of this year.

Coal Procurement Procedures

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 its supply of coal with specifications that support its compliance with the Mercury and Air Toxins Rule. Subsequent to the sale of Vectren Fuels to Sunrise Coal in August 2014, 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. In December 2014, the IURC determined that the terms of the coal contracts were reasonable. The annual sub docket proceeding is no longer required.

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, which began February 2014, was$42.4 million, of which $33.6 million remains as of March 31, 2015.

SIGECO Electric Demand Side Management (DSM) Program Filing

On August 31, 2011 the IURC issued an Order approving an initial three year DSM plan in the SIGECO electric service territory that complied with the IURC’s energy saving targets. Consistent with the Company’s proposal, the Order approved, among other items, the following: 1) recovery of costs associated with implementing the DSM Plan; 2) the recovery of a performance incentive mechanism based on measured savings related to certain DSM programs; 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 three months endedMarch 31, 2015 and 2014, the Company recognized Electric utility revenue of $2.3 million and $1.6 million, respectively, associated with this approved lost margin recovery mechanism.

On March 28, 2014, Indiana Senate Bill 340 was signed into law. This legislation ended electric DSM programs on December 31, 2014 that have been conducted to meet the energy savings requirements established in the IURC's December 2009 Order. The legislation also allows for industrial customers to opt out of participating in energy efficiency programs. As of January 1, 2015, approximately 80 percent of the Company’s eligible industrial load has opted out of participation in the applicable energy efficiency programs. Indiana's governor has requested that the IURC 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 IURC approval of a new portfolio of DSM programs on May 29, 2014 to be offered in 2015. On October 15, 2014, the IURC issued an Order approving a Settlement between the OUCC and the Company regarding the new portfolio of DSM programs effective January 2015, and new programs were implemented during the first quarter 2015. On May 6, 2015, Indiana's governor signed Indiana Senate Bill 412 into law requiring electricity suppliers to create and submit energy-efficiency plans to the IURC at least one time every three years. Senate Bill 412 also supports the recovery of all program costs, including lost revenues and financial incentives associated with those plans and approved by the IURC. The Company will make its first filing pursuant to this bill in May 2015.

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FERC Return on Equity (ROE) 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 March 31, 2015, the Company had invested approximately $157.7 million in qualifying projects. The net plant balance for these projects totaled $142.8 million at March 31, 2015.

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 a 10.57 percent return on equity and a 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. A settlement has not been reached, and the case will move to a formal evidentiary hearing before the FERC. A procedural schedule was set on January 22, 2015, which defines a targeted date of final resolution from the FERC. An initial decision is expected later in 2015, but the timing of the final order from the FERC is unknown at this time. The Company has established a reserve pending the outcome of this complaint.

Separately, on January 6, 2015, the FERC approved a MISO transmission owner joint request for an adder to the approved ROE. Under FERC regulations, transmission owners that are part of a Regional Transmission Organization (RTO) such as MISO are authorized to earn an incentive of 50 basis points above the FERC approved ROE. The FERC deferred the implementation of this adder until the pending complaint is resolved. Once the FERC sets a new ROE in the complaint case, this adder will be applied to that ROE, with retroactive billing to occur back to January 7, 2015.

11. Environmental Matters

Indiana Senate Bill 251

Senate Bill 251 is also applicable to federal environmental mandates impacting SIGECO electric operations in addition to the impact on its gas utility 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

Cross-State Air Pollution Rule

In July 2011, the EPA finalized the Cross-State Air Pollution Rule (CSAPR). CSAPR was the EPA’s response to the US Court of Appeals for the District of Columbia’s (the Court) remand of the Clean Air Interstate Rule (CAIR). CAIR was originally established in 2005 as an allowance cap and trade program that required reductions from coal-burning power plants for NOX emissions beginning January 1, 2009 and SO2 emissions beginning January 1, 2010, with a second phase of reductions in 2015. In an effort to address the Court’s finding that CAIR did not adequately ensure attainment of pollutants in certain downwind states due to unlimited trading of SO2 and NOX allowances, CSAPR reduced the ability of facilities to meet emission reduction targets through allowance trading. CSAPR reductions were to be achieved with initial step reductions beginning January 1, 2012, and final compliance to be achieved in 2014. After a series of legal challenges, the United States Supreme Court upheld CSAPR in April 2014, and the EPA finalized a new deadline schedule for entities that must comply, with CSAPR’s first phase caps starting in 2015 and 2016, and the second phase in 2017. The Company is in full compliance with all requirements of CSAPR.

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

17

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. Reductions are to be achieved within three years of publication of the final rule in the Federal Register. 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. Legal challenges to the MATS Rule continue. 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. On November 25, 2014, the U.S. Supreme Court agreed to hear the case, with oral arguments completed, a decision is expected later in 2015. MATS compliance was required to commence April 16, 2015, and Company is in full compliance with all requirements of MATS.

Notice of Violation for A.B. Brown Power Plant

The Company received a NOV from the EPA in November 2011 pertaining to its A.B. Brown generating station. The NOV asserts that when the facility was equipped with Selective Catalytic Reduction (SCR) systems, the correct permits were not obtained or the best available control technology to control incidental sulfuric acid mist was not installed. The Company reached a settlement in principle with the EPA to resolve the NOV. That settlement was contemplated in the plan filed and approved by the IURC on January 28, 2015 in the SIGECO Electric Environmental Compliance Filing.

Ozone NAAQS

On November 26, 2014, the EPA proposed to tighten the current National Ambient Air Quality Standard (NAAQS) for ozone from the current standard of 75 parts per billion (ppb) to a level with the range of 65 to 70 ppb. The EPA has stated that it intends to finalize the rule by October 2015. Upon finalization, the EPA will then determine whether a particular region is in attainment with the new standard. While it is possible that counties in southwest Indiana could be declared in non-attainment with the new standard, and thus may have an effect on future economic development activities in the Company's service territory, the Company does not anticipate any significant compliance cost impacts from the determination given its previous investment in SCR technology for NOx control on its units.

Water

Section 316(b) of the Clean Water Act requires that generating facilities use the “best technology available” (BTA) to minimize adverse environmental impacts on a body of water. More specifically, Section 316(b) is concerned with impingement and entrainment of aquatic species in once-through cooling water intake structures used at electric generating facilities. A final rule was issued by the EPA on May 19, 2014. The final rule does not mandate cooling water tower retrofits but requires a state level case by case assessment of BTA for each facility. The final rule lists seven presumptive technologies which would qualify as BTA. These technologies range from intake screen modifications to cooling water tower retrofits. Ecological and technology assessment studies must be completed prior to determining BTA for the Company’s facilities. To comply, 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 however the rule is not yet finalized. 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, 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

18

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.

As noted previously, on January 28, 2015, the IURC issued an Order approving the Company’s request for approval of capital investments on its coal-fired generation units to comply with new EPA mandates related to mercury and air toxin standards effective in 2015 and to address an outstanding Notice of Violation (NOV) from the EPA. The total investment is estimated to be between $80 and $90 million, roughly half of which will be made to control mercury in both air and water emissions, and the remaining investment will be made to address the issues raised in the NOV proceeding on the increase in sulfur trioxide emissions.

Coal Ash Waste Disposal & Ash Ponds

In December 2014 the EPA released its final coal ash rule which regulates ash as non-hazardous material under Subtitle D of the Resource Conservation and Recovery Act (RCRA). On April 17, 2015, the final rule was published in the Federal Register. Under the final rule the Company will be required to perform additional safety and structural assessments and an enhanced groundwater monitoring program to determine whether its existing ash ponds may remain in operation, be closed, or retrofitted with liners. The final rule allows beneficial reuse of ash and the Company will continue to reuse a majority of its ash. Legislation is currently being considered by Congress that would provide for enforcement of the federal program by states.

Under the final CCR rule, the Company is required to complete a series of integrity assessments and groundwater monitoring studies to determine whether one or more of the Company's ash ponds can continue in service, or whether a pond must be retrofitted with liners or closed and bottom ash handling conversions completed. The Company estimates capital expenditures to comply with the alternatives in the final rule could range from minor additional capital expenditures, if the ponds are permitted to continue to operate, and could exceed $100 million if all existing ponds at both F.B. Culley and A.B. Brown generating stations must be closed and bottom ash conversions completed at each generating unit. The Company is in the process of evaluating the impact of this rule and any impact on its asset retirement obligation (ARO). It is expected that any 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.

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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 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. The EPA provided an extended time frame for public commentary to December 1, 2014. The proposal sets state-specific CO2 emission rate-based CO2 goals (measured in lb CO2/MWh) 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 instead are state goals. As such, the state must establish a framework that will guide how compliance will be met on a statewide basis. Indiana’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 9th lowest reduction requirement. 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. The Company timely filed comments to the Clean Power Plan proposal on December 1, 2014. The State of Indiana also filed public comments, asking that the proposal be withdrawn. Despite having just been recently proposed and not expected to be finalized until summer 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. Oral arguments have been completed before the U.S. Court of Appeals for the D.C. Circuit, with a decision expected later in the summer.

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 5th largest carbon emitter in the nation in tons of CO2 produced from electric generation. In 2013, Indiana’s electric utilities generated 105.6 million tons of CO2. The Company’s share of that total was 6.3 million, or less than 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 F.B. 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 renewable generation, in 2008 and 2009, the Company executed long-term purchase power commitments for a total of 80 MW of wind energy. The Company currently has approximately 4 percent of its electricity being provided by clean energy sources due to the long-term wind contracts and landfill gas investment. With respect to CO2 emission rate, since 2005 the Company has lowered its CO2 emission rate (as measured in lbs CO2/MWh) from 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.

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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 continue to remain engaged with the state to develop a plan for compliance and 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.

Manufactured Gas Plants

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

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

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

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

The costs the Company expects to incur are estimated by management using assumptions based on actual costs incurred, the timing of expected future payments, and inflation factors, among others. While the Company’s utilities have recorded all costs which they presently expect to incur in connection with activities at these sites, it is possible that future events may require remedial activities which are not presently foreseen and those costs may not be subject to PRP or insurance recovery. As of March 31, 2015 and December 31, 2014, approximately $3.5 million and $3.6 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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12. Fair Value Measurements

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

	March 31, 2015				December 31, 2014
(In millions)	Carrying Amount		Est. Fair Value		Carrying Amount		Est. Fair Value
Long-term debt	$	1,252.4	$	1,409.7	$	1,257.3	$	1,408.0
Short-term borrowings	5.9		5.9		156.4		156.4
Cash & cash equivalents	10.4		10.4		19.3		19.3

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.

13. 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 adopted this guidance on January 1, 2015. The adoption of this guidance had no impact on the Company's financial statements.

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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 adoption permitted. Adoption of this guidance will not have a material impact on the Company’s financial statements.

Simplifying the Presentation of Debt Issuance Costs

In April 2015, the FASB issued new accounting guidance on accounting for debt issuance costs which changes the presentation of debt issuance costs in financial statements. This ASU requires an entity to present such costs in the balance sheet as a direct deduction from the related debt liability rather than as an asset. Amortization of the costs will continue to be reported as interest expense. This ASU is effective for annual reporting periods beginning after December 15, 2015. Early adoption is permitted. The new guidance will be applied retrospectively to each prior period presented. The Company is currently evaluating the standard to understand the overall impact it will have on the financial statements. Adoption will have no impact on the Company's consolidated income statement.

14. 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
	March 31,
(In millions)	2015			2014
Revenues
Gas Utility Services	$	352.9		$	443.6
Electric Utility Services	153.9			163.0
Other Operations	10.2			9.6
Eliminations	(10.1		)	(9.6		)
Total Revenues	$	506.9		$	606.6
Profitability Measure - Net Income
Gas Utility Services	$	40.4		$	38.3
Electric Utility Services	19.2			19.3
Other Operations	3.4			3.7
Total Net Income	$	63.0		$	61.3

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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 585,000 natural gas customers located in central and southern Indiana.  SIGECO provides energy delivery services to approximately 143,000 electric customers and approximately 111,000 gas customers located near Evansville in southwestern Indiana.  SIGECO also owns and operates electric generation assets to serve its electric customers and optimizes those assets in the wholesale power market.  Indiana Gas and SIGECO generally do business as Vectren Energy Delivery of Indiana.  VEDO provides energy delivery services to approximately 317,000 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 2014 annual report filed on Form 10-K.

Executive Summary of Consolidated Results of Operations

In the first quarter of 2015, Utility Holdings' earnings were $63.0 million, compared to $61.3 million in 2014. The increase of $1.7 million relates primarily to increases in gas utility margin from returns on the Indiana and Ohio infrastructure replacement programs.

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.

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

Gas Utility margin and throughput by customer type follows:

	Three Months Ended
	March 31,
(In millions)	2015		2014
Gas utility revenues	$	352.9	$	443.6
Cost of gas sold	172.0		270.9
Total gas utility margin	$	180.9	$	172.7
Margin attributed to:
Residential & commercial customers	$	126.3	$	123.2
Industrial customers	19.3		18.8
Other	3.4		3.6
Regulatory expense recovery mechanisms	31.9		27.1
Total gas utility margin	$	180.9	$	172.7
Sold & transported volumes in MMDth attributed to:
Residential & commercial customers	62.2		65.6
Industrial customers	38.0		36.0
Total sold & transported volumes	100.2		101.6

Gas Utility margins were $180.9 million for thethree months endedMarch 31, 2015, and compared to 2014, increased $8.2 million in the quarter. Margin from small customer growth and large customer usage increased $0.8 million compared to the first quarter of 2014. Additionally, margin was favorably impacted by the return from infrastructure replacement programs of $1.6 million in Indiana and $1.3 million in Ohio. Pass through margin increased $4.8 million in 2015 compared to the first quarter 2014 due to regulatory expense recovery rate increases.

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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
	March 31,
(In millions)	2015		2014
Electric utility revenues	$	153.9	$	163.0
Cost of fuel & purchased power	50.1		57.0
Total electric utility margin	$	103.8	$	106.0
Margin attributed to:
Residential & commercial customers	$	63.7	$	64.3
Industrial customers	26.8		26.0
Other	1.0		0.9
Regulatory expense recovery mechanisms	3.3		4.8
Subtotal: retail	$	94.8	$	96.0
Wholesale power & transmission system margin	9.0		10.0
Total electric utility margin	$	103.8	$	106.0
Electric volumes sold in GWh attributed to:
Residential & commercial customers	702.6		719.1
Industrial customers	672.9		660.1
Other customers	6.1		6.0
Total retail volumes sold	1,381.6		1,385.2

Retail

Electric retail utility margins were $94.8 million for the three months endedMarch 31, 2015, and, compared to 2014, decreased by $1.2 million. Electric results, which are not protected by weather normalizing mechanisms, experienced a $0.9 million decrease in small customer margin related to weather as annualized heating degree days in the first quarter of 2015 were 105 percent of normal compared to 108 percent of normal in 2014. As conservation initiatives continue, in the first quarter 2015 compared to first quarter 2014, the Company's lost revenue recovery mechanism contributed increased margin of $0.6 million related to electric conservation programs. Margin from regulatory expense recovery mechanisms decreased $1.5 million in 2015 compared to 2014, driven primarily by a corresponding decrease in operating expenses associated with the electric conservation programs. Additionally, results reflect an increase in large customer usage of $0.6 million largely driven by an industrial customer coming on line in the Company's service territory in August 2014.

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
	March 31,
(In millions)	2015		2014
MISO Transmission system margin	$	6.5	$	6.1
MISO Off-system margin	2.5		3.9
Total wholesale margin	$	9.0	$	10.0

Transmission system margin associated with qualifying projects, including the reconciliation of recovery mechanisms, and other transmission system operations, totaled $6.5 million and $6.1 million during the three months endedMarch 31, 2015 and 2014, respectively. As of March 31, 2015, the Company had invested approximately $157.7 million in qualifying projects. The net plant balance for these projects totaled $142.8 million at March 31, 2015. These projects include an interstate 345 Kv

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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.

For the three months endedMarch 31, 2015, margin from off-system sales was $2.5 million, compared to $3.9 million in 2014. 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 as well as a decrease in volumes sold due to lower market pricing.

Operating Expenses

Other Operating

For the three months endedMarch 31, 2015, other operating expenses were $102.8 million, an increase of $4.5 million compared to 2014. The increase in other operating costs is primarily due to increases in costs that are recovered directly in margin. Excluding these pass through costs, other operating expenses decreased $0.4 million in 2015, compared to the same period in 2014, primarily driven by decreased energy delivery expenses due to the harsh winter weather in the first quarter 2014.

Depreciation & Amortization

In the first quarter of 2015, depreciation and amortization expense was $52.1 million, compared to $49.9 million in 2014. The increase reflects increased plant placed in service.

Taxes Other Than Income Taxes

For the first quarter, taxes other than income taxes were $19.1 millioncompared to $20.1 million in 2014. The decrease of $1.0 million is primarily due to decreased revenue taxes. These taxes are primarily revenue-related taxes and are offset dollar-for-dollar with lower gas utility and electric utility revenues reflected in margin attributable to regulatory expense recovery mechanisms.

Other Income - Net

Other income-net reflects income of $4.9 million for the first quarter of 2015, an increase of $1.0 million, compared to 2014. The increase is due to higher AFUDC driven by increased capital expenditures related to infrastructure replacement investments, as well as higher AFUDC rates.

Gas Rate & Regulatory Matters

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 programs to replace bare steel and cast iron infrastructure and other activities in both Indiana and Ohio to mitigate risk, improve the system, and comply with applicable regulations, many of which are a result of federal pipeline safety requirements. Laws 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.

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

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In April 2013, Indiana Senate Bill 560 (Senate Bill 560) was signed into Indiana law. This legislation supplements Senate Bill 251 described above, and provides for cost recovery outside of a base rate proceeding for projects that either improve electric and gas system reliability and safety or are economic development projects that provide rural areas with access to gas service. Provisions of the legislation require that, among other things, requests for recovery include a seven-year project plan. Once the plan is approved by the IURC, 80 percent of such costs are eligible for current recovery using a periodic rate adjustment mechanism. Recoverable costs include a return on and of the investment, as well as property taxes and operating expenses. The remaining 20 percent of project costs is deferred and recovered in the utility’s next general rate case, which must be filed before the expiration of the seven year plan. The adjustment mechanism is capped at an annual increase in retail revenues of no more than two percent.

In June 2011, Ohio House Bill 95 (House Bill 95) was signed into law. Outside of a base rate proceeding, this legislation permits a natural gas utility to apply for recovery of much of its capital expenditure program. By allowing for the deferral of costs, such as depreciation, property taxes, and debt-related post in service carrying costs until recovery is approved by the Ohio Commission.

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 March 31, 2015 and December 31, 2014, the Company has regulatory assets totaling $17.3 million and $16.4 million, respectively, associated with the deferral of depreciation and debt-related post-in-service carrying cost activities. Beginning in 2014, all bare steel and cast iron replacement activities are now part of the Company’s seven-year capital investment plan filed pursuant to Senate Bill 251, discussed further below.

Requests for Recovery Under Indiana Regulatory Mechanisms

On August 27, 2014, the IURC 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 Senate Bill 251 and 560. As provided in the two laws, the Order approved semi-annual filings for rate recovery of 100 percent of the costs, inclusive of return, related to these capital investments and operating expenses, with 80 percent of the costs recovered currently via an approved tracking mechanism and 20 percent of the costs deferred and recovered in the Company’s next base rate proceeding. In addition, the Order established guidelines to annually update the seven-year capital investment plan. Finally, the Order approved the Company’s proposal to recover eligible costs via a fixed monthly charge per residential customer.

On September 26, 2014, the OUCC filed an appeal of the IURC's finding that the remaining value of retired assets replaced during the infrastructure projects should not be netted against the cost being recovered in the tracking mechanism. In April 2015, the Indiana Court of Appeals issued an opinion on an appeal involving Northern Indiana Public Service Company’s (NIPSCO) infrastructure cost recovery mechanism finding that the value of retired assets should not be netted against the current recovery of costs. Although the opinion is specific to NIPSCO, the Company believes this decision is a positive outcome related to its pending appeal.

Additionally, in the NIPSCO appeal, the IURC’s approval of the reasonableness of that infrastructure investment plan was challenged. The Court found that NIPSCO had failed to provide sufficient detail regarding its planned projects after year one of the plan to support the IURC's approval. An industrial group has asked the Court of Appeals to now consider that issue as part of the pending appeal of the Company's Order. Given this issue was never raised during the Company's IURC case or on appeal during the briefing period, the Company believes the opportunity to raise this issue has been waived and has asked the Court to strike the filing. The Court should decide these issues later this year.

On January 14, 2015, the IURC issued an Order approving the Company’s initial request for recovery of the revenue requirement through June 30, 2014 as part of its approved seven-year plan. As the next step of the recovery process, as outlined in the legislation, this Order initiates the rates and charges necessary to begin cash recovery of 80 percent of the

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revenue requirement, with the remaining 20 percent deferred for recovery in the Company's next rate case. Also, consistent with the guidelines set forth in the original August 2014 Order, the IURC approved the Company’s 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, an increase of $35 million from the previous plan and is 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.

On April 1, 2015, the Company filed its second request for recovery of the revenue requirement associated with capital investment and applicable operating costs through December 31, 2014. A procedural schedule has not been set in this proceeding. The Company expects an order in this proceeding mid-year in 2015.

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 $156.5 million. Regulatory assets associated with post-in-service carrying costs and depreciation deferrals were $14.2 million and $13.1 million at March 31, 2015 and December 31, 2014, 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 issued an Order approving a Stipulation entered into by the PUCO Staff and the Company which provided for the extension of the DRR for the recovery of costs incurred through 2017 and expanded the types of investment covered by the DRR to include recovery of other infrastructure investments. The Order limits the resulting DRR fixed charge per month for residential and small general service customers to specific graduated levels over the next five years. The Company's five-year capital expenditure plan related to these infrastructure investments for calendar years 2013 through 2017 totals approximately $200 million. The capital expenditure plan is subject to the graduated caps on the fixed DRR monthly charge applicable to residential and small general service customers approved in the Order however is not expected to exceed those caps. 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 rates and charges, effective September 1, 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 below are not expected to be reached given the Company's capital expenditure plan during the remaining three-year time frame.

The PUCO has also issued Orders approving the Company's filings under Ohio House Bill 95. These Orders approve deferral of the Company’s Ohio capital expenditure program for items not covered by the DRR as well as expenditures necessary to comply with PUCO rules, regulations, orders, and system expansion to some new customers. Ohio House Bill 95 Orders also have established a prospective bill impact evaluation on the cumulative deferrals, limiting the total deferrals at a level which would equal $1.50 per residential and small general service customer per month. As of March 31, 2015, the Company's deferrals have not reached this bill impact cap. In addition, the Orders 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.

Other Regulatory Matters

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 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

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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 modified its position in testimony filed on November 5, 2014, and suggested a reduced disallowance of $3 million. The IURC moved this specific issue to a sub-docket proceeding. On April 1, 2015, a stipulation and settlement agreement between the Company, the OUCC, and the Company’s supply administrator was filed in this proceeding. Pending a final order from the IURC approving the stipulation, the agreement results in recovery of approximately $1.4 million of the disputed amount via the Company’s GCA mechanism, with the remaining $1.6 million from the gas supply administrator.

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 Indiana gas companies and recovery of new conservation program costs through December 2015. The Companies have reached an agreement in principle with the OUCC to extend the decoupling mechanism through 2020. The settlement was filed for approval on March 1, 2015. The settlement was unopposed and a hearing has been set for May 2015. The Company expects an order later in 2015.

Electric Rate & Regulatory Matters

SIGECO Electric Environmental Compliance Filing

On January 28, 2015, the IURC issued an Order approving the Company’s request for approval of capital investments on its coal-fired generation units to comply with new EPA mandates related to mercury and air toxin standards effective in 2015 and to address an outstanding Notice of Violation (NOV) from the EPA. As of March 31, 2015, approximately $29 million has been spent on equipment to control mercury in both air and water emissions, and $16 million to address the issues raised in the NOV proceeding on the increase in sulfur trioxide emissions. The total investment is estimated to be between $80 and $90 million. The Order approved the Company’s request for deferred accounting treatment, as supported by provisions under Indiana Senate Bill 29 (Senate Bill 29) and Senate Bill 251. The accounting treatment includes the deferral of depreciation and property tax expense related to these investments, accrual of post-in-service carrying costs, and deferral of incremental operating expenses related to compliance with these standards. The initial phase of the projects went into service in 2014, with the remaining investment expected to occur in 2015 and 2016. As of March 31, 2015, the Company has approximately $0.7 million deferred related to depreciation, property tax, and operating expense, and $0.3 million deferred related to post-in-service carrying costs.

In March 2015, the Company was notified that certain parties had filed a Notice of Appeal with the Indiana Court of Appeals in response to the IURC's Order. Appellate briefs will be presented to the Court later in 2015 and it is expected the Court will decide on these issues in the second half of this year.

Coal Procurement Procedures

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 its supply of coal with specifications that support its compliance with the Mercury and Air Toxins Rule. Subsequent to the sale of Vectren Fuels to Sunrise Coal in August 2014, 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. In December 2014, the IURC determined that the terms of the coal contracts were reasonable. The annual sub docket proceeding is no longer required.

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, which began February 2014, was$42.4 million, of which $33.6 million remains as of March 31, 2015.

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SIGECO Electric Demand Side Management (DSM) Program Filing

On August 31, 2011 the IURC issued an Order approving an initial three year DSM plan in the SIGECO electric service territory that complied with the IURC’s energy saving targets. Consistent with the Company’s proposal, the Order approved, among other items, the following: 1) recovery of costs associated with implementing the DSM Plan; 2) the recovery of a performance incentive mechanism based on measured savings related to certain DSM programs; 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 three months endedMarch 31, 2015 and 2014, the Company recognized Electric utility revenue of $2.3 million and $1.6 million, respectively, associated with this approved lost margin recovery mechanism.

On March 28, 2014, Indiana Senate Bill 340 was signed into law. This legislation ended electric DSM programs on December 31, 2014 that have been conducted to meet the energy savings requirements established in the IURC's December 2009 Order. The legislation also allows for industrial customers to opt out of participating in energy efficiency programs. As of January 1, 2015, approximately 80 percent of the Company’s eligible industrial load has opted out of participation in the applicable energy efficiency programs. Indiana's governor has requested that the IURC 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 IURC approval of a new portfolio of DSM programs on May 29, 2014 to be offered in 2015. On October 15, 2014, the IURC issued an Order approving a Settlement between the OUCC and the Company regarding the new portfolio of DSM programs effective January 2015, and new programs were implemented during the first quarter 2015. On May 6, 2015, Indiana's governor signed Indiana Senate Bill 412 into law requiring electricity suppliers to create and submit energy-efficiency plans to the IURC at least one time every three years. Senate Bill 412 also supports the recovery of all program costs, including lost revenues and financial incentives associated with those plans and approved by the IURC. The Company will make its first filing pursuant to this bill in May 2015.

FERC Return on Equity (ROE) 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 March 31, 2015, the Company had invested approximately $157.7 million in qualifying projects. The net plant balance for these projects totaled $142.8 million at March 31, 2015.

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 a 10.57 percent return on equity and a 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. A settlement has not been reached, and the case will move to a formal evidentiary hearing before the FERC. A procedural schedule was set on January 22, 2015, which defines a targeted date of final resolution from the FERC. An initial decision is expected later in 2015, but the timing of the final order from the FERC is unknown at this time. The Company has established a reserve pending the outcome of this complaint.

Separately, on January 6, 2015, the FERC approved a MISO transmission owner joint request for an adder to the approved ROE. Under FERC regulations, transmission owners that are part of a Regional Transmission Organization (RTO) such as MISO are authorized to earn an incentive of 50 basis points above the FERC approved ROE. The FERC deferred the implementation of this adder until the pending complaint is resolved. Once the FERC sets a new ROE in the complaint case, this adder will be applied to that ROE, with retroactive billing to occur back to January 7, 2015.

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Environmental Matters

Indiana Senate Bill 251

Senate Bill 251 is also applicable to federal environmental mandates impacting SIGECO electric operations in addition to the impact on its gas utility 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

Cross-State Air Pollution Rule

In July 2011, the EPA finalized the Cross-State Air Pollution Rule (CSAPR). CSAPR was the EPA’s response to the US Court of Appeals for the District of Columbia’s (the Court) remand of the Clean Air Interstate Rule (CAIR). CAIR was originally established in 2005 as an allowance cap and trade program that required reductions from coal-burning power plants for NOX emissions beginning January 1, 2009 and SO2 emissions beginning January 1, 2010, with a second phase of reductions in 2015. In an effort to address the Court’s finding that CAIR did not adequately ensure attainment of pollutants in certain downwind states due to unlimited trading of SO2 and NOX allowances, CSAPR reduced the ability of facilities to meet emission reduction targets through allowance trading. CSAPR reductions were to be achieved with initial step reductions beginning January 1, 2012, and final compliance to be achieved in 2014. After a series of legal challenges, the United States Supreme Court upheld CSAPR in April 2014, and the EPA finalized a new deadline schedule for entities that must comply, with CSAPR’s first phase caps starting in 2015 and 2016, and the second phase in 2017. The Company is in full compliance with all requirements of CSAPR.

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. Reductions are to be achieved within three years of publication of the final rule in the Federal Register. 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. Legal challenges to the MATS Rule continue. 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. On November 25, 2014, the U.S. Supreme Court agreed to hear the case, with oral arguments completed, a decision is expected later in 2015. MATS compliance was required to commence April 16, 2015, and Company is in full compliance with all requirements of MATS.

Notice of Violation for A.B. Brown Power Plant

The Company received a NOV from the EPA in November 2011 pertaining to its A.B. Brown generating station. The NOV asserts that when the facility was equipped with Selective Catalytic Reduction (SCR) systems, the correct permits were not obtained or the best available control technology to control incidental sulfuric acid mist was not installed. The Company reached a settlement in principle with the EPA to resolve the NOV. That settlement was contemplated in the plan filed and approved by the IURC on January 28, 2015 in the SIGECO Electric Environmental Compliance Filing.

Ozone NAAQS

On November 26, 2014, the EPA proposed to tighten the current National Ambient Air Quality Standard (NAAQS) for ozone from the current standard of 75 parts per billion (ppb) to a level with the range of 65 to 70 ppb. The EPA has stated that it intends to finalize the rule by October 2015. Upon finalization, the EPA will then determine whether a particular region is in attainment with the new standard. While it is possible that counties in southwest Indiana could be declared in non-attainment with the new standard, and thus may have an effect on future economic development activities in the Company's service territory, the Company does not anticipate any significant compliance cost impacts from the determination given its previous investment in SCR technology for NOx control on its units.

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Water

Section 316(b) of the Clean Water Act requires that generating facilities use the “best technology available” (BTA) to minimize adverse environmental impacts on a body of water. More specifically, Section 316(b) is concerned with impingement and entrainment of aquatic species in once-through cooling water intake structures used at electric generating facilities. A final rule was issued by the EPA on May 19, 2014. The final rule does not mandate cooling water tower retrofits but requires a state level case by case assessment of BTA for each facility. The final rule lists seven presumptive technologies which would qualify as BTA. These technologies range from intake screen modifications to cooling water tower retrofits. Ecological and technology assessment studies must be completed prior to determining BTA for the Company’s facilities. To comply, 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 however the rule is not yet finalized. 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, 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.

As noted previously, on January 28, 2015, the IURC issued an Order approving the Company’s request for approval of capital investments on its coal-fired generation units to comply with new EPA mandates related to mercury and air toxin standards effective in 2015 and to address an outstanding Notice of Violation (NOV) from the EPA. The total investment is estimated to be between $80 and $90 million, roughly half of which will be made to control mercury in both air and water emissions, and the remaining investment will be made to address the issues raised in the NOV proceeding on the increase in sulfur trioxide emissions.

Coal Ash Waste Disposal & Ash Ponds

In December 2014 the EPA released its final coal ash rule which regulates ash as non-hazardous material under Subtitle D of the Resource Conservation and Recovery Act (RCRA). On April 17, 2015, the final rule was published in the Federal Register. Under the final rule the Company will be required to perform additional safety and structural assessments and an enhanced groundwater monitoring program to determine whether its existing ash ponds may remain in operation, be closed, or retrofitted with liners. The final rule allows beneficial reuse of ash and the Company will continue to reuse a majority of its ash. Legislation is currently being considered by Congress that would provide for enforcement of the federal program by states.

Under the final CCR rule, the Company is required to complete a series of integrity assessments and groundwater monitoring studies to determine whether one or more of the Company's ash ponds can continue in service, or whether a pond must be

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retrofitted with liners or closed and bottom ash handling conversions completed. The Company estimates capital expenditures to comply with the alternatives in the final rule could range from minor additional capital expenditures, if the ponds are permitted to continue to operate, and could exceed $100 million if all existing ponds at both F.B. Culley and A.B. Brown generating stations must be closed and bottom ash conversions completed at each generating unit. The Company is in the process of evaluating the impact of this rule and any impact on its asset retirement obligation (ARO). It is expected that any costs for compliance with these regulations should qualify as federally mandated regulatory requirements and be recoverable under Senate Bill 251 referenced above.

Climate Change

As a wholly owned subsidiary of Vectren, Utility Holdings is committed to responsible environmental stewardship and conservation efforts and if a national climate change policy is implemented believes it should have the following elements:

• An inclusive scope that involves all sectors of the economy and sources of greenhouse gases, and recognizes early actions and investments made to mitigate greenhouse gas emissions;

• Provisions for enhanced use of renewable energy sources as a supplement to base load generation including effective energy conservation, demand side management, and generation efficiency measures;

• Inclusion of incentives for investment in advanced clean coal technology and support for research and development; and

• A strategy supporting alternative energy technologies and biofuels and continued increase in the domestic supply of natural gas and oil to reduce dependence on foreign oil.

Based on data made available through the Electronic Greenhouse Gas Reporting Tool (e-GRRT) maintained by the EPA, the Company’s direct CO2 emissions from its fossil fuel electric generation that report under the Acid Rain Program were less than one half of one percent of all emissions in the United States from similar sources. Emissions from other Company operations, including those from its natural gas distribution operations and the greenhouse gas emissions the Company is required to report on behalf of its end use customers, are similarly available through the EPA’s e-GRRT database and reporting tool.

Current Initiatives to Increase Conservation & Reduce Emissions

The Company is committed to a policy that reduces greenhouse gas emissions and conserves energy usage. Evidence of this commitment includes:

• Focusing the Company’s mission statement and purpose on corporate sustainability and the need to help customers conserve and manage energy costs. Vectren's annual sustainability report received C level certification by the Global Reporting Initiative. This certification creates shared value, demonstrates the Company's commitment to sustainability and denotes transparency in operations;

• Implementing conservation initiatives in the Company’s Indiana and Ohio gas utility service territories;

• Implementing conservation and demand side management initiatives in the electric service territory;

• Building a renewable energy portfolio to complement base load generation in advance of mandated renewable energy portfolio standards;

• Evaluating potential carbon requirements with regard to new generation, other fuel supply sources, and future environmental compliance plans; and

• Reducing the Company’s carbon footprint by measures such as utilizing hybrid vehicles and optimizing generation efficiencies by utilizing dense pack technology

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.

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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 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. The EPA provided an extended time frame for public commentary to December 1, 2014. The proposal sets state-specific CO2 emission rate-based CO2 goals (measured in lb CO2/MWh) 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 instead are state goals. As such, the state must establish a framework that will guide how compliance will be met on a statewide basis. Indiana’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 9th lowest reduction requirement. 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. The Company timely filed comments to the Clean Power Plan proposal on December 1, 2014. The State of Indiana also filed public comments, asking that the proposal be withdrawn. Despite having just been recently proposed and not expected to be finalized until summer 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. Oral arguments have been completed before the U.S. Court of Appeals for the D.C. Circuit, with a decision expected later in the summer.

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 5th largest carbon emitter in the nation in tons of CO2 produced from electric generation. In 2013, Indiana’s electric utilities generated 105.6 million tons of CO2. The

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Company’s share of that total was 6.3 million, or less than 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 F.B. 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 renewable generation, in 2008 and 2009, the Company executed long-term purchase power commitments for a total of 80 MW of wind energy. The Company currently has approximately 4 percent of its electricity being provided by clean energy sources due to the long-term wind contracts and landfill gas investment. With respect to CO2 emission rate, since 2005 the Company has lowered its CO2 emission rate (as measured in lbs CO2/MWh) from 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 continue to remain engaged with the state to develop a plan for compliance and 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.

Manufactured Gas Plants

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

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

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

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

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The costs the Company expects to incur are estimated by management using assumptions based on actual costs incurred, the timing of expected future payments, and inflation factors, among others. While the Company’s utilities have recorded all costs which they presently expect to incur in connection with activities at these sites, it is possible that future events may require remedial activities which are not presently foreseen and those costs may not be subject to PRP or insurance recovery. As of March 31, 2015 and December 31, 2014, approximately $3.5 million and $3.6 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 adopted this guidance on January 1, 2015. The adoption of this guidance had no impact on the Company's financial statements.

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 adoption permitted. Adoption of this guidance will not have a material impact on the Company’s financial statements.

Simplifying the Presentation of Debt Issuance Costs

In April 2015, the FASB issued new accounting guidance on accounting for debt issuance costs which changes the presentation of debt issuance costs in financial statements. This ASU requires an entity to present such costs in the balance sheet as a direct deduction from the related debt liability rather than as an asset. Amortization of the costs will continue to be reported as interest expense. This ASU is effective for annual reporting periods beginning after December 15, 2015. Early adoption is permitted. The new guidance will be applied retrospectively to each prior period presented. The Company is currently evaluating the standard to understand the overall impact it will have on the financial statements. Adoption will have no impact on the Company's consolidated income statement.

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Financial Condition

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, including current maturities, outstanding at March 31, 2015 approximated $875 million. As of March 31, 2015, Utility Holdings had $6 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 March 31, 2015, was approximately $377 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 March 31, 2015, 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 55 percent of long-term capitalization at March 31, 2015 and 54 percent at December 31, 2014.  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 March 31, 2015, the Company was in compliance with all debt covenants.

Available Liquidity

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 supplemented with incremental external debt financing. 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.

On May 12, 2015 Utility Holdings priced $200 million of its senior unsecured notes to be issued in three tranches of 20, 30, and 40 years. The notes were sold to various institutional investors through the private placement market and subject to the satisfaction of customary closing conditions, the notes will be issued on or about December 15, 2015. Utility Holdings will be issuing $25 million of 3.90% Series A senior notes due December 15, 2035, $135 million of 4.36% Series B senior notes due December 15, 2045, and $40 million of 4.51% Series C senior notes due December 15, 2055.  

On March 15, 2015, a $5.0 million Indiana Gas senior unsecured note matured. The Series E note carried a fixed interest rate of 7.15%. The repayment of debt was funded from the Company's short-term credit facility.

38

Consolidated Short-Term Borrowing Arrangements

At March 31, 2015, the Company has $350 million of short-term borrowing capacity.  As reduced by borrowings currently outstanding, approximately $344 million was available at March 31, 2015. 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)	2015	2014
As of March 31
Balance Outstanding	$5.9	$—
Weighted Average Interest Rate	0.39%	n/a
Quarterly Average - March 31
Balance Outstanding	$69.2	$1.9
Weighted Average Interest Rate	0.39%	0.26%
Maximum Month End Balance Outstanding	$121.5	$—

Potential Uses of Liquidity

Pension Funding Obligations

For the three months ended March 31, 2015, Vectren contributed $20 million to its qualified pension plans. Utility Holdings may fund a portion of the total contribution as it relates to its plans. Vectren does not anticipate making further contributions in 2015.

Planned Capital Expenditures

Capital expenditures are estimated at $350 million for the remainder of 2015.

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 $241.3 million and $156.0 million for the three months endedMarch 31, 2015 and 2014, respectively. The increase is driven primarily by certain weather related impacts to working capital accounts. Weather related impacts include the fluctuation in the recoverable/refundable natural gas and fuel costs, accounts receivable, and accounts payable. Additionally, a decrease in prepaid taxes was due to a federal refund received in 2015 related to the extension of bonus depreciation in 2014.

Financing Cash Flow

Net cash flow required for financing activities was $181.5 million and $54.1 million during the three months endedMarch 31, 2015 and 2014, respectively.  The current year period, compared to first quarter of 2014, reflects a greater decrease of short term borrowings of $121.9 million. Financing activity in both periods presented reflects the payment of dividends.

Investing Cash Flow

Cash flow required for investing activities was $68.7 million and $57.9 million during the three months endedMarch 31, 2015 and 2014, respectively.   The primary use of cash in both periods presented reflect expenditures for utility capital expenditures.

39

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 the Company's facilities, operations, financial condition, results of operations, and reputation.

• 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, electricity, and other nonutility products and services; 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.

• Volatile oil prices and the potential impact on customer consumption and price of other fuel commodities.

• 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 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 federal and state laws and interpretations of these laws.

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• 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 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 AND 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. 2014 Form 10-K and is therefore not presented herein.

ITEM 4.  CONTROLS AND PROCEDURES

Changes in Internal Controls over Financial Reporting

During the quarter ended March 31, 2015, 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 March 31, 2015, 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 March 31, 2015, 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.

41

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.

During the third quarter of 2014, the Company was notified of claims by a group of current and former SIGECO employees (“claimants”) who participated in the Pension Plan for Salaried Employees of SIGECO (“SIGECO Salaried Plan”).  That plan was merged into the Vectren Corporation Combined Non-Bargaining Retirement Plan (“Vectren Combined Plan”) effective July 1, 2000. The claims relate to the claimants’ election for benefits to be calculated under the Vectren Combined Plan’s cash-balance formula rather than the SIGECO Salaried Plan formula in effect prior to the formation of Vectren.  On March 12, 2015, certain claimants filed a Class Action Complaint against the Vectren Combined Plan and the Company in federal district court requesting that a class be certified and for various relief including that the Combined Plan be reformed and benefits thereunder be recalculated. The Company denied the allegations set forth in the Complaint.

The Company is unable to quantify any potential impact of the claims. The Company does not expect, however, the outcome would have a material adverse effect on the Company’s liquidity, results of operations or financial condition.

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 2014 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

42

ITEM 6.  EXHIBITS

Exhibits and Certifications

10.1	Grant Agreement for Non-Employee Director Stock Grant, dated January 1, 2015.  (Filed and designated in Form 8-K, dated January 2, 2015, File No. 1-16739, as Exhibit 10.1)
10.2	Coal Supply Agreement for A.B. Brown Generating Station between Southern Indiana Gas and Electric Company and Vectren Fuels, Inc., effective January 1, 2015. Contract assigned to Sunrise Coal, LLC. on August 29, 2014. (Filed in Form 10-Q herewith as Exhibit 10.2.) Portions of the document have been omitted and filed separately pursuant to a request for confidential treatment filed with the Securities and Exchange Commission.
10.3	Coal Supply Agreement for F.B. Culley Generating Station between Southern Indiana Gas and Vectren Fuels, Inc., effective January 1, 2015. Contract assigned to Sunrise Coal, LLC. on August 29, 2014. (Filed in Form 10-Q herewith as Exhibit 10.3.) Portions of the document have been omitted and filed separately pursuant to a request for confidential treatment filed with the Securities and Exchange Commission.
10.4	Coal Supply Agreement for Warrick 4 Generating Station between Southern Indiana Gas and Electric Company and Vectren Fuels, Inc., effective January 1, 2015. Contract assigned to Sunrise Coal, LLC. on August 29, 2014. (Filed in Form 10-Q herewith as Exhibit 10.4.) Portions of the document have been omitted and filed separately pursuant to a request for confidential treatment filed with the Securities and Exchange Commission.
10.5	First Amendment to the Vectren Corporation At Risk Compensation Plan (as amended and restated May 1, 2011) (filed and designated in Form 8-K, dated February 9, 2015, File No. 1-16739, as Exhibit 99.1)
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
99.1	Code of By-Laws of Vectren corporation as Most Recently Amended as of March 4, 2015 (filed and designated in Form 8-K, dated March 10, 2015, File No. 1-16739, as Exhibit 3.1)
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

43

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
May 14, 2015	/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)

44

EX-10.2

[**] REPRESENTS CONFIDENTIAL MATERIAL OMITTED AND FILED SEPARATELTY WITH THE SECURITIES

AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.2

A.B. BROWN

COAL SUPPLY AGREEMENT

This Coal Supply Agreement (the “Agreement”) is made and entered into effective as of January 1, 2015 (the “Effective Date”), by and between Southern Indiana Gas And Electric Company d/b/a Vectren Power Supply, Inc., an Indiana corporation (“Buyer”), and Vectren Fuels, Inc., an Indiana corporation (“Seller”). Buyer and Seller are also referred to herein individually as a “Party” and collectively as the “Parties.”

RECITALS

WHEREAS, Buyer and Seller are parties to that certain A.B. Brown Coal Supply Agreement entered into effective as of January 1, 2009, as amended from time to time for the annual supply of 410,000 tons of coal, and that certain A.B. Brown Coal Supply Agreement entered into effective as of January 1, 2009, as amended from time to time for the original annual supply of 1,000,000 tons of coal (each an “Original Agreement” and, collectively, the “Original Agreements”).

WHEREAS, Buyer desires to secure to the extent of the quantities and for the period hereinafter stated, a supply of bituminous coal of the quality hereinafter set forth, for use in its

A.B. Brown generating plant (the “Plant”).

WHEREAS, Seller represents that it is experienced in the commercial production and preparation of coal and that it owns, has leased, or controls reserves of bituminous coal with the quality and characteristics as set forth herein.

WHEREAS, Seller desires to sell coal to Buyer, and Buyer desires to buy coal from Seller, upon the terms and conditions hereinafter set forth.

NOW, THEREFORE, in consideration of the premises and the mutual covenants and agreements of the Parties contained herein, the Parties agree as follows:

ARTICLE 1

TERM; SOURCE; TITLE

1.1 Term. Unless terminated earlier or extended in accordance with the terms hereof, the term of this Agreement shall be from the Effective Date through December 31, 2023, inclusive (the “Term”). Notwithstanding the foregoing, Buyer shall have the right, by providing no less than three (3) years prior written notice to Seller (i.e., in the case of the first such extension, by December 31, 2020), to extend the Term of this Agreement by an additional three (3) years, subject to negotiation of the Base Price for any such extension in accordance with Section 3.4, and subject to Seller’s rights pursuant to Section 12.5; provided that Buyer may extend the Term of this Agreement no more than twice.

1.2 Amendment and Termination of Original Agreements. Unless this Agreement is terminated prior to the Effective Date in accordance with Section 12.3, the Parties agree that the Original Agreements shall be amended in accordance with the Termination Agreement entered

[**] REPRESENTS CONFIDENTIAL MATERIAL OMITTED AND FILED SEPARATELTY WITH THE SECURITIES

AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.2

into by the Parties, as attached hereto as Attachment 1 to this Agreement, which among other things, shall provide for the termination of the Original Agreement for the supply of 1,000,000 tons annually as of December 31, 2014 and the other Original Agreement as of December 31, 2015.

1.3 Source. The coal to be sold by Seller and purchased by Buyer under this Agreement shall be mined from coal produced from the Oaktown 1 Mine or the Oaktown 2 Mine (the “Mines”).

1.4 Alternate Supply Sources.

1.4.1 If Seller becomes an affiliate of Sunrise Coal, LLC, an Indiana limited liability company, on or before December 31, 2014, Seller shall have the right to notify Buyer that the coal to be sold by Seller and purchased by Buyer under this Agreement may also be mined from coal properties and reserves at Sunrise Coal, LLC’s Carlisle Mine, located in and around Sullivan County, Indiana, and all references to the “Mines” hereunder shall thereafter be deemed and construed to include the Carlisle Mine, as well as the Oaktown 1 Mine and the Oaktown 2 Mine. Seller’s right to deliver coal mined from the Carlisle Mine under this Agreement shall not be subject to the requirements of Section 1.4.2 but shall arise automatically upon notice to Buyer, subject to the Parties’ agreement on the Carlisle Deduction (as defined below). Within thirty (30) days after Seller becomes an affiliate of Sunrise Coal, LLC, Buyer shall notify Seller if its cost to transport coal from the Carlisle Mine to the Plant differs from the cost to transport coal from the Oaktown 1 Mine and the Oaktown 2 Mine, which transportation cost was assumed to establish the Base Price as stated in Section 3.1.1. Such notice shall include reasonable supporting documentation of the respective transportation costs. Buyer and Seller, each acting in good faith, shall determine the difference between Buyer’s transportation costs for coal transported for: (a) each ton of coal delivered from the Carlisle Mine, and (b) each ton of coal delivered from the Oaktown 1 Mine and the Oaktown 2 Mine (such difference in costs, the “Carlisle Deduction”), and Seller shall apply the Carlisle Deduction to all tons of coal delivered from the Carlisle Mine. To the extent the Carlisle Deduction is different for rail and truck transportation, the Carlisle Deduction for the applicable transportation mode shall be utilized. For purposes of determining the Carlisle Deduction, coal shall be deemed to be transported to the Plant, notwithstanding Buyer’s right to designate alternate locations pursuant to Section 2.8. The Parties shall document the agreed Carlisle Deduction in a writing signed by both Parties. Once the Parties agree on the Carlisle Deduction, the Carlisle Mine shall be deemed to be one of the “Mines” for all purposes hereunder.

1.4.2 In addition, Seller may deliver to Buyer coal conforming to the quality specifications set forth in Exhibit A, from an alternate source (“Alternate Source Coal”), subject to the Parties agreement on the matters contemplated in this Section 1.4.2. If Seller desires to deliver Alternate Source Coal, Seller shall notify Buyer of the location and source of the Alternate Source Coal, and provide Buyer with sample analyses from such alternate source demonstrating that the Alternate Source Coal meets the quality specifications set forth in Exhibit A. If the delivery point for the Alternate Source Coal will be at a location other than any of the Mines, Buyer shall notify Seller if its cost to transport such Alternate Source Coal to the Plant differs from the transportation costs from the Mines. Such notice shall include reasonable supporting documentation of the respective transportation costs for such Alternate Source Coal

- 2 -

[**] REPRESENTS CONFIDENTIAL MATERIAL OMITTED AND FILED SEPARATELTY WITH THE SECURITIES

AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.2

and for coal delivered at the Oaktown 1 Mine and Oaktown 2 Mine. Buyer and Seller, each acting in good faith, shall determine the difference between Buyer’s transportation costs for: (a) each ton of coal delivered at the Oaktown 1 Mine and the Oaktown 2 Mine, and (b) each ton of coal delivered at the delivery point for such Alternate Source Coal (such difference in costs, the “Alternate Source Deduction”), and Seller shall apply the Alternate Source Deduction to all tons of coal delivered at the location of the Alternate Source Coal. To the extent the Alternate Source Deduction is different for rail and truck transportation, the Alternate Source Deduction for the applicable transportation mode shall be utilized. For purposes of determining the Alternate Source Deduction, coal shall be deemed to be transported to the Plant, notwithstanding Buyer’s right to designate alternate locations pursuant to Section 2.8. The Parties shall document the agreed Alternate Source Deduction in a writing signed by both Parties. Once Buyer accepts the Alternate Source Coal and the Parties agree on the Alternate Source Deduction for such Alternate Source Coal, the source of such Alternate Source Coal shall be deemed to be one of the “Mines” for all purposes hereunder.

1.5 Title and Risk of Loss. Title to the coal and risk of loss thereof shall transfer from Seller to Buyer upon loading for shipment of the coal into railcars or trucks, as applicable, at the Mine. As between the Parties, Seller shall be deemed to be in exclusive control (and responsible for any damages or injury caused thereby) of the coal prior to its being loaded for shipment at the Mine, and Buyer shall be deemed to be in exclusive control (and responsible for any damages or injury caused thereby) of the coal from the time it is loaded for shipment at the Mine.

ARTICLE 2

CONTRACT QUANTITY

2.1 Base Tonnage. Seller agrees to deliver to Buyer, and Buyer agrees to accept from Seller, the total quantity of coal as set forth below in each Contract Year during the Term. A Contract Year shall commence on January 1st and end on December 31st.

Contract YearBase Tonnage 2015 590,000 tons

2016 – 2023 1,000,000 tons

2.2 Annual Tonnage Adjustment. For each Contract Year beginning in 2015, Buyer may elect to increase or decrease the Base Tonnage (as described in Section 2.1) for such Contract Year by an amount of up to [**] of the Base Tonnage for such Contract Year. If Buyer desires to increase or decrease the Base Tonnage for a Contract Year, Buyer shall provide written notice of such election to Seller on or before June 30th of the Contract Year preceding the Contract Year for which the Base Tonnage will be adjusted. If Buyer fails to provide such notice for any Contract Year, the Base Tonnage for such Contract Year shall be the Base Tonnage as set forth in Section 2.1.

2.3 Quarterly Tonnage Adjustments. Beginning in the first quarter of 2015 and for the remainder of the Term, Buyer may elect to increase or decrease the Base Tonnage to be delivered in a calendar quarter by an amount of up to [**] of the Base Tonnage to be delivered in such calendar quarter. Buyer shall provide written notice to Seller of such

- 3 -

[**] REPRESENTS CONFIDENTIAL MATERIAL OMITTED AND FILED SEPARATELTY WITH THE SECURITIES

AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.2

election on or before the date that is 30 days before the first day of such calendar quarter. For the purposes of this Section 2.3, if Buyer has increased or decreased the Base Tonnage for a given Contract Year pursuant to Section 2.2, the Base Tonnage subject to adjustment in each calendar quarter in such Contract Year shall be the Base Tonnage as adjusted pursuant to Section 2.2.

2.4 Scheduled Outages. For each Contract Year beginning in 2015 in which Buyer has scheduled outages for the Plant or a generating unit at the Plant, Buyer may by written notice to Seller on or before June 30th of the Contract Year preceding the Contract Year in which such scheduled outages will occur, decrease the monthly quantity of coal that would otherwise be delivered hereunder during such scheduled outage by up to [**]; provided that the maximum period of time for which Buyer may decrease the monthly quantity of coal pursuant to this Section 2.4 shall not exceed [**] in such Contract Year. Buyer’s notice of such decrease may include Buyer’s preference as to when the quantities of coal that are not delivered during such outage should otherwise be delivered, which may be prior to or after such outage; provided that delivery of such coal shall in any event be on a mutually agreeable delivery schedule.

2.5 Tonnage Adjustment due to De-Rating. If any legislative, regulatory, administrative or other governmental bodies, or any court with jurisdiction, enacts, adopts or imposes new laws, rules or regulations, amends existing laws, rules or regulations, or reinterprets existing laws, rules or regulations, that require Buyer to de-rate the Plant, Buyer may, by written notice to Seller, reduce the Base Tonnage hereunder; provided that such reduction shall be imposed on a pro-rata basis among all of Buyer’s coal suppliers to the Plant, based on the number of tons of coal that Buyer is obligated to receive from its committed suppliers, to the extent that its contracts with other suppliers give Buyer the right to reduce its purchase obligations as a result of such new or amended laws, rules or regulations, or reinterpretation. In the event Buyer is later able to increase operations at the Plant during the Term of this Agreement after such notice has been given, the Base Tonnage hereunder shall be increased, not to exceed the Base Tonnage as stated in Section 2.1, plus any annual and quarterly adjustments to the Base Tonnage pursuant to Section 2.2 and Section 2.3, as applicable; provided that any increase in the number of tons of coal required by Buyer for operation of the Plant shall be allocated on a pro-rata basis among Buyer’s committed coal suppliers to the Plant in the same fashion as the decrease in coal was allocated.

2.6 Delivery. Coal shall be delivered F.O.B. railcar or truck (as elected by Buyer) at any of Seller’s Mines (as elected by Seller), in substantially equal monthly quantities on a mutually agreeable delivery schedule. Seller will coordinate loading at the Mines with Buyer and Buyer’s relevant carriers.

2.7 Shipments. As used herein, a “Shipment” of coal supplied under this Agreement shall refer to all coal delivered by truck in a given day, or all coal delivered by a single train of railcars.

2.8 Transportation. Buyer shall be solely responsible for transportation of the coal from the Mines to the Plant, including providing railcars or trucks, as Buyer elects, for loading at the Mines. Buyer may, in its sole discretion, direct any coal delivered hereunder to any of Buyer’s or its affiliate’s power generating stations other than the Plant; provided that Buyer shall

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.2

be responsible for all additional transportation costs associated with such election. Buyer’s right to direct coal to a power generating station other than the Plant shall in no way be construed as an obligation to do so under any circumstance.

2.9 Monthly Shipping Schedule. On or before the 15th day of each calendar month during the Term, Buyer shall notify Seller of the expected schedule of shipments by railcar and by truck to be made during the following calendar month. On or before the 25th day of each month during the Term, the Parties shall mutually determine a delivery schedule for the following month, including whether shipments will be by rail or by truck, and the daily schedule for delivery of the coal.

ARTICLE 3

PRICING

3.1 Base Price.

3.1.1 The price per ton (2000 pounds) of coal sold by Seller hereunder (the “Base Price”) shall be determined in accordance with this Article 3. The Base Price for Contract Year 2015 shall be [**].

3.1.2 As of January 1st of each Contract Year thereafter, until the Base Price is re-set in accordance with Section 3.4, the Base Price shall be increased by [**] over the Base Price in effect during the prior Contract Year. After the Base Price is re-set in accordance with Section 3.4, the Base Price for each successive Contract Year thereafter shall be increased by [**] over the Base Price in effect during the prior Contract Year until the Base Price is re-set again in accordance with Section 3.4.

3.2 BTU Adjustment.

3.2.1 The Base Price for each ton of coal sold and purchased hereunder during a calendar month shall be adjusted based on the monthly weighted average of the actual BTU/lb of all tons delivered in such calendar month under this Agreement (the “BTU Adjustment”). The BTU Adjustment shall be determined according to the following formula:

BTU Adjustment = ((Actual BTU/lb Value / Guaranteed BTU/lb Value) x (Base Price)) – Base Price Where the Guaranteed BTU/lb Value = 11,000 Btu/Lb

The aggregate BTU Adjustment for a calendar month shall be equal to the total tons delivered in such calendar month, multiplied by the BTU Adjustment. If the BTU Adjustment is a negative value, the BTU Adjustment shall be payable from Seller to Buyer, and if the BTU Adjustment is a positive value, the BTU Adjustment shall be payable from Buyer to Seller. The aggregate BTU Adjustment to be paid with respect to a calendar month shall be included in the first invoice delivered by Seller in the calendar month immediately following the calendar month for which such BTU Adjustment applies.

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.2

3.2.2 Subject to Buyer’s rights under Section 4.3, the Base Price adjustments as described in this Section 3.2, shall be Buyer’s sole and exclusive remedy at law or in equity for the failure of coal sold hereunder to meet the quality specifications with respect to BTU/lb.

3.3 Other Price Adjustments.

3.3.1 The Parties recognize that legislative, regulatory, administrative or other governmental bodies or the courts may impose new laws, rules or regulations, amend existing laws, rules or regulations, or reinterpret existing laws, rules or regulations, including, without limitation, procedural instruction letters issued by MSHA after June 2, 2014 (the “Initial Price Date”), or as applicable, after the date of determination of a Market Adjusted Base Price (such new laws, amendments or reinterpretations, a “Change in Law”), that may increase Seller’s cost of mining coal from the Mines. Without limiting the generality of the foregoing, the implementation after the Initial Price Date of MSHA rule 79 FR 24813 “Lowering Miners’ Exposure to Respirable Coal Mine Dust, Including Continuous Personal Dust Monitors” as adopted on May 1, 2014, shall be deemed to be a Change in Law for purposes of this Agreement, notwithstanding the adoption of such rules prior to the Initial Price Date. A Change in Law shall not in any event include any change in Governmental Impositions (as defined below).

(a) If a Change in Law that affects Seller’s cost of mining occurs after the Initial Price Date, or as applicable, after the date that a Market Adjusted Base Price is determined, Seller shall give notice to Buyer indicating the related increase in the then-current Base Price (or the relevant Market Adjusted Base Price, as applicable) and shall provide to Buyer reasonable documentation of the proposed increase in the Base Price.

(b) If the proposed increase in the Base Price (or the relevant Market Adjusted Base Price, as applicable) is less than or equal to [**] of the then-current Base Price (or the relevant Market Adjusted Base Price, as applicable), the then-current Base Price (or the relevant Market Adjusted Base Price, as applicable) shall be adjusted as of the effective date of such Change in Law by an amount equal to the proposed increase, subject to Buyer’s right to dispute in good faith the existence of a Change in Law or the amount of the proposed price increase. Accordingly, the adjustment to the then-current Base Price (or the relevant Market Adjusted Base Price, as applicable) pursuant to this Section 3.3.1 may be applied retroactively.

(c) If the proposed increase in the Base Price (or the relevant Market Adjusted Base Price, as applicable) is greater than [**] of the then-current Base Price (or the relevant Market Adjusted Base Price, as applicable), then, subject to Buyer’s right to dispute in good faith the existence of a Change in Law or the amount of the proposed price increase, (i) the then-current Base Price shall be increased as of the effective date of such Change in Law to an amount equal to [**] of the initial Base Price in the three (3) year period in which such increase occurs, excluding the annual escalation pursuant to Section 3.1.2, and (ii) if applicable, the relevant Market Adjusted Base Price shall be adjusted by an amount equal to [**] of the relevant Market Adjusted Base Price. Accordingly, the adjustment to the then-current Base Price (or the relevant Market Adjusted Base Price, as applicable) pursuant to this Section 3.3.1 may be applied retroactively.

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.2

(d) Except to the extent described in Section 3.3.1(c), no adjustments to the then-current Base Price (or the Market Adjusted Base Price, as applicable) shall be made with respect to Seller’s increased costs for mining that have already been applied to the then-current Base Price or that have been taken into account and quantified during negotiations to determine a Market Adjusted Base Price pursuant to Section 3.4.

3.3.2 “Governmental Imposition” means taxes or fees imposed by any federal, state or local government or government agency upon the production, severance, preparation or sale of Coal hereunder, including, but not limited to, the Federal Black Lung Excise Tax, severance taxes on Coal produced or sold hereunder, reclamation fees assessed by the US government or the State of Indiana. The term does not include impositions such as generally applicable taxes including federal or state income taxes; employee benefits or payroll taxes such as employer’s Social Security, unemployment or worker’s compensation taxes or payments, or any civil or criminal money fine or penalty imposed as the result of failure to comply with any Law. Buyer shall not be entitled to any adjustment in connection with any benefit derived by Seller for any incentives granted by the U.S. government or the State of Indiana for coal production or investment in coal properties within the State of Indiana.

(a) The Parties shall adjust the then-current Base Price (or the relevant Market Adjusted Base Price, as applicable) by an amount equal to changes in Seller’s costs per ton of coal sold hereunder that are caused directly by increased or decreased Governmental Impositions enacted or imposed after the Initial Price Date, or as applicable, after the date of determination of a Market Adjusted Base Price. Seller shall give prompt notice to Buyer of the amount of any such increased or decreased cost per ton of coal sold hereunder incurred by reason of such a change in Governmental Imposition (including implementation of new Governmental Impositions), along with reasonable documentation of such amounts. The adjustment to the Base Price pursuant to this Section 3.3.2 may be applied retroactively to the date on which such new or changed Government Imposition was first applied to Seller or its operations.

(b) In the event of an increase in cost, such notice from Seller shall also include the increase in the then-current Base Price (or the relevant Market Adjusted Base Price, as applicable) that Seller will require, which increase may not exceed the actual increase in Seller’s costs due to such Governmental Impositions. In the event of a decrease in cost, the then-current Base Price (or the relevant Market Adjusted Base Price, as applicable) will be decreased by an amount equal to the decrease in Seller’s costs caused by Governmental Impositions enacted or changed after the then-current Base Price became effective, or the date of determination of a Market Adjusted Base Price. Adjustments due to Governmental Impositions as described in this Section 3.3.2 shall be subject to Buyer’s right to dispute in good faith the existence of a Governmental Imposition or the amount of the proposed adjustment.

3.3.3 Seller shall follow generally accepted accounting principles (GAAP) as historically applied by Seller in determining its costs related to any Change in Law or Governmental Imposition, and shall provide Buyer with documentation reasonably demonstrating that the increase or decrease in cost is incremental to the costs already included in the Base Price.

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.2

3.4 Market Price Adjustments.

3.4.1 Beginning with the 2018 Contract Year, and again upon the expiration of a three (3) year period beginning on January 1st of such Contract Year, and upon the expiration of each three (3) year period thereafter, the Parties shall adjust the Base Price to reflect then-current market prices for similar quality coal meeting the quality specifications set forth in Exhibit A and sold for delivery the following year (the “Market Adjusted Base Price”). The Parties shall follow the procedures described below to determine the adjusted Base Price. If the Parties agree on a Market Adjusted Base Price, the Market Adjusted Base Price shall become effective and shall be the “Base Price” as described in Section 3.1 for all purposes hereunder as of January 1st of the first Contract Year of the relevant three (3) year period. The Market Adjusted Base Price shall include all adjustments to the Base Price made pursuant to Section 3.3 prior to the date that such Market Adjusted Base Price is determined. If any adjustments to the Base Price made pursuant to Section 3.3 occur after the date on which the Market Adjusted Base Price is determined, but before the date on which the Market Adjusted Base Price becomes effective, such adjustments shall also be applied to the Market Adjusted Base Price as of the date on which the Market Adjusted Base Price becomes effective.

3.4.2 The Parties shall begin negotiations to determine the Market Adjusted Base Price on or before April 1st of the Contract Year prior to the Contract Year in which the Market Adjusted Base Price will become effective pursuant to Section 3.4.1. The Parties shall negotiate in good faith to agree to the Market Adjusted Base Price.

3.4.3 If the Parties fail to reach agreement on the Market Adjusted Base Price by May 31st of the Contract Year prior to the Contract Year in which the Market Adjusted Base Price will become effective pursuant to Section 3.4.1, on or before June 5th of such Contract Year, Seller and Buyer shall each provide the other Party with information relating to contracts for the sale or purchase of coal, as applicable, that such Party has negotiated since January 1st of the Contract Year prior to the Contract Year in which negotiations are occurring. Such information provided by the Parties shall: (a) (i) as to information provided by Seller, be with respect to the sale of coal produced by the Mines and with a term of at least twelve (12) months beginning on or after January 1st of the prior Contract Year, and (ii) as to information provided by Buyer, be with respect to the purchase of coal for use at the Plant and with a term of at least twelve (12) months beginning on or after January 1st of the prior Contract Year; (b) to the extent allowed under the applicable contract, include copies of contracts entered into by such Party, redacted to exclude any identifying information as to the counterparty to such contract; and (c) include a summary of the relevant terms with respect to quantity, quality specifications and pricing of each contract where a Party is unable to provide a redacted copy of such contract due to restrictions imposed on such Party pursuant to such contract (it being understood that the Parties shall use commercially reasonable efforts to obtain the right to provide redacted copies of such contracts as contemplated herein). In the absence of the occurrence of sufficient transactions since January 1st of the Contract Year prior to the Contract Year in which negotiations are occurring, the Parties may rely upon other relevant market information to establish market prices to determine the Market Adjusted Base Price. Buyer and Seller shall have the right to have an independent auditor or consultant review the confidential information provided by the Parties pursuant to this Section 3.4.3, subject to a Party’s independent auditor or

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.2

consultant having entered into a customary confidentiality agreement with the other Party prior to disclosure of any confidential information to such independent auditor or consultant.

3.4.4 If the Parties fail to reach agreement on the Market Adjusted Base Price by June 30th of the Contract Year prior to the Contract Year in which the Market Adjusted Base Price will become effective pursuant to Section 3.4.1, either Party may, by notice to the other Party, elect to begin binding arbitration proceedings to establish the Market Adjusted Base Price. Upon receipt of such notice, the Parties shall select a single neutral, independent arbitrator who is familiar with coal markets and coal market pricing. If the Parties fail to select an arbitrator within thirty (30) days of receipt of such notice, the Parties shall follow the process recommended by the American Arbitration Association to select a single, neutral, independent arbitrator who is familiar with coal markets and coal market pricing. Within thirty (30) days after the selection of the neutral arbitrator, the Parties shall each submit to the arbitrator and to the other Party, such Party’s proposed Market Adjusted Base Price and all reasonable supporting documentation demonstrating the basis on which the proposed Market Adjust Base Price was determined. Within fifteen (15) days after the initial submission of the proposed Market Adjusted Base Prices, the Parties shall each submit any rebuttal to the other Party’s proposed Market Adjusted Base Price, to the arbitrator and to the other Party. Within thirty (30) days after the submission of any rebuttals, or the last day of the fifteen (15) day period in which to submit rebuttals if no rebuttals are submitted, the arbitrator shall select the Market Adjusted Base Price proposed by one of the Parties as the Market Adjusted Base Price for the following Contract Year for the purposes of this Agreement, and shall notify the Parties in writing of the Market Adjusted Base Price that has been selected by the arbitrator. The arbitrator shall not have any authority to select any Market Adjusted Base Price other than the proposed Market Adjusted Base Price submitted by one of the Parties, and shall select the proposed Market Adjusted Base Price that most closely represents the arbitrator’s determination of the current market price of similar quality coal in the same market and sold under substantially similar terms and conditions.

3.4.5 Any information or documents exchanged or produced during the process of negotiating the Market Adjusted Base Price as described in this Section 3.4, including during any arbitration proceeding, and including any redacted contracts, summaries, or briefs or other documents prepared for the arbitration, shall be confidential and shall not be disclosed by the Parties, their employees, officers, directors, counsel, consultants, auditors or expert witnesses, as applicable, except to a court of relevant jurisdiction and then only to the extent necessary to enforce this Section 3.4 or any arbitration award, or as required by applicable laws or the rules of any stock exchange applicable to the Party making such disclosure, or in the case of Buyer to the Indiana Utility Regulatory Commission (the “IURC”). If a Party is required to disclose any such information or documents, such Party shall notify the other Party of the need to make such disclosure as soon as applicable and shall seek confidential treatment, and cooperate with the other Party in seeking confidential treatment, of any information that is disclosed.

ARTICLE 4

COAL QUALITY SPECIFICATIONS

4.1 Quality Specifications. The coal supplied under this Agreement shall meet the quality specifications set forth in Exhibit A on an “as received” basis.

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.2

4.2 Impurities. The coal supplied under this Agreement shall be washed coal, crushed to two inch (2") maximum top size, and shall be substantially free of impurities, such as bone, slate, rock, wood, metal and other mine debris.

4.3 Rejection; Suspension.

4.3.1 If based on the sampling and analysis described herein, the coal in a Shipment fails to comply with the Reject limits as set forth in Exhibit A for any one or more of the quality specifications identified therein, Buyer shall have the right, but not the obligation, to reject such Shipment by notice delivered to Seller by fax or email. In addition, Buyer shall have the right to reject any coal containing bone coal, rock, wood, metal or other mine debris in quantities which Buyer believes, in the exercise of Buyer’s good faith judgment, could be harmful to the Plant.

(a) In the event Buyer rejects any coal, Buyer shall promptly notify Seller of such rejection, such notice to be delivered within 48 hours of Buyer’s receipt of the short proximate analysis for the Shipment if rejection is based on the Shipment having exceeded any of the Reject limits as described in this Section 4.3, or within 24 hours of receipt of the Shipment at the Plant (or other destination designated by Buyer hereunder) if the rejection is based on the Shipment being contaminated with foreign materials. Buyer may reject discrete portions of a Shipment for foreign materials if practical under the circumstances.

(b) If Buyer fails to timely exercise its rights to reject a Shipment under this Section 4.3, Buyer shall be deemed to have waived such rights with respect to rejection of that Shipment only. Buyer’s failure to reject one or more Shipments under this Section 4.3 shall in no way affect its right to reject future Shipments or demand Seller’s strict performance with the requirements of this Section 4.3. If Buyer timely rejects a Shipment under this Section 4.3, Seller and Buyer shall cooperate in good faith to find an acceptable means for Seller to cure the problem so that Buyer can use such coal in the Plant. If the Parties are unable to find an acceptable means of curing the problem, Seller shall be responsible for promptly transporting the rejected coal to an alternative destination determined by Seller, at Seller’s cost, and the rejected coal shall not apply toward the Base Tonnage. In addition, Seller shall be responsible to reimburse Buyer for all reasonable out-of-pocket costs and expenses incurred by Buyer for the transportation of the rejected coal to the Plant. It is understood that Buyer shall not arbitrarily change its equipment in any way as to prevent Buyer from accepting coal and that Seller shall not arbitrarily change its mining, preparation, or loading operations in any way that would provide Buyer with an incentive to not accept the coal delivered by Seller hereunder.

(c) Seller shall, at Buyer’s option, replace the rejected coal as soon as possible, provided that Buyer gives notice to Seller of Buyer’s desire for replacement coal within 48 hours after rejection of a Shipment (or a part thereof).

4.3.2 Regardless of whether Buyer has actually exercised its right to reject any Shipments pursuant to Section 4.3.1: (i) if the coal delivered by Seller, as measured by the weighted average of all short proximate analyses in a given calendar month or the Monthly Composite Analysis (as defined in Section 6.2), fails to meet any of the monthly weighted average (“MWA”) quality specifications for [**]

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.2

[**] (other than with respect to the BTU/lb specification, for which Buyer’s sole remedy for failure of the coal to meet the MWA quality specification shall be the BTU Adjustment as provided in Section 3.2), or (ii) if in any thirty (30) day period, two (2) Shipments by railcar, or six (6) Shipments by truck, fail to comply with the Reject limits as set forth in Exhibit A for any one or more of the quality specifications identified therein, as measured by the short proximate analysis, Buyer may by written notice to Seller suspend any further Shipments other than those already loaded into trucks or railcars; provided that in the case of a partially loaded train, Seller shall finish loading the railcars in such train.

(a) Within thirty (30) days after receipt of Buyer’s suspension notice pursuant to Section 4.3.2, Seller shall provide Buyer with reasonable assurances that subsequent deliveries of coal hereunder will meet the quality specifications on a MWA basis, and that subsequent Shipments of coal will comply with the Reject limits as set forth in Exhibit A for each of the quality specifications identified therein. In providing such assurances, Seller shall provide a reasonably detailed explanation for its failure to deliver coal that complies with the quality specifications as set forth in Exhibit A, and a reasonably detailed description of the remedial actions that Seller will undertake in support of its assurances. Buyer shall promptly review such assurances and respond to Seller within ten (10) days after receipt of such assurances. In reviewing the assurances provided by Seller, Buyer shall act in good faith and shall not unreasonably withhold acceptance of Seller’s assurances, or unreasonably delay the resumption of delivery of coal hereunder if such assurances are accepted. Buyer may require Seller to make-up deficiencies in the Base Tonnage for a Contract Year resulting from any such suspensions, subject to Seller’s right to dispute the validity and circumstances of such suspension, on a delivery schedule mutually agreed by the Parties.

(b) If Seller fails to provide assurances within the thirty (30) day period provided in Section 4.3.2(a) that are reasonably acceptable to Buyer, acting in good faith, Buyer may, in its sole discretion, terminate this Agreement by written notice to Seller.

(c) If Buyer terminates this Agreement pursuant to this Section 4.3, Seller shall reimburse Buyer the positive difference, if any, between (i) the purchase price and transportation costs on a cents per million BTU basis as transported to the Plant (without regard to Buyer’s right to designate alternate locations pursuant to Section 2.8) incurred by Buyer for Replacement Coal, and (ii) the sum, on a cents per million BTU basis, of the Base Price and transportation costs that Buyer incurs for transportation of the coal delivered hereunder to the Plant for each ton of coal remaining as of the date of termination to be delivered to Buyer hereunder during the Current Term (without regard to Buyer’s rights to increase the Base Tonnage pursuant to Section 2.2 or Section 2.3, other than increases for the relevant periods that have been declared by Buyer by written notice to Seller prior to the date of Buyer’s suspension notice pursuant to Section 4.3.2(a)). For purposes of this Agreement, the “Current Term” means, as applicable, the period beginning on the Effective Date and ending on December 31, 2017 if the Contract Year in which this Agreement is terminated occurs during such period, or the three (3) year period beginning on January 1, 2018 or any subsequent three (3) year period thereafter during the Term if the Contract Year in which this Agreement is terminated occurs during such three (3) year period. For purposes of this Agreement, “Replacement Coal” means, to the extent reasonably available, coal having similar quality specifications purchased under similar terms and conditions as this Agreement (excluding Buyer’s rights to extend the Term hereunder) that

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.2

Buyer purchases, in an amount not to exceed the Base Tonnage (without regard to Buyer’s rights to increase the Base Tonnage pursuant to Section 2.2 or Section 2.3, other than increases for the relevant periods that have been declared by Buyer by written notice to Seller prior to the date of Buyer’s suspension notice pursuant to Section 4.3.2(a)) remaining as of the date of termination to be delivered to Buyer hereunder during the Current Term; provided, however that any reasonable good faith purchase of coal to address Buyer’s short-term (i.e., 6 months or less) needs associated with a termination of this Agreement shall be considered Replacement Coal. Buyer shall use commercially reasonable attempts to acquire Replacement Coal at the lowest cost possible and shall take other reasonable steps to mitigate its damages, and shall provide reasonable documentation to Seller of the costs incurred. Payment of amounts, if any, determined under this Section 4.3.2(c) shall be made within 10 days following receipt of notice from Buyer of amounts owed.

4.3.3 OTHER THAN THE BTU ADJUSTMENT AS DETERMINED IN ACCORDANCE WITH SECTION 3.2, THE RIGHTS AND OBLIGATIONS OF THE PARTIES AS SET FORTH IN THIS SECTION 4.3 SHALL BE SELLER’S SOLE OBLIGATIONS AND BUYER’S SOLE AND EXCLUSIVE REMEDY AT LAW OR IN EQUITY FOR THE FAILURE OF COAL SOLD HEREUNDER TO MEET ONE OR MORE OF THE QUALITY SPECIFICATIONS AS SET FORTH IN EXHIBIT A.

4.4 Freeze Treatment Agent. Buyer shall have the right to require Seller to apply a freeze-treatment chemical agent to the coal delivered hereunder, and to the sides of railcars being used to transport the coal (collectively, “Freeze Treatment”). On or before November 1st of each year, Seller shall notify Buyer of the type of chemical agent to be used in the Freeze Treatment, the manufacturer of the chemical agent, and the cost per gallon of the chemical agent that will be used by Seller, and shall provide Buyer with a copy of the MSDS sheet of such chemical agent. Buyer shall provide Seller with reasonable advance notice of the dates for starting and ending the Freeze Treatment, and the temperature to which Buyer requests Freeze Treatment (e.g., 10°F below the expected low temperature), for Seller’s use in determining application rates. Seller shall invoice Buyer monthly in accordance with Section 7.1 for the cost of the Freeze Treatment provided by Seller, which shall be equal to (a) (i) Seller’s actual cost per gallon for the chemical agent used, multiplied by (ii) the gallons of chemical agent applied to each Shipment of coal hereunder during the prior calendar month, plus (b) an application fee of [**] of the total cost determined pursuant to subparagraph (a) of this Section 4.4.

ARTICLE 5

WEIGHING

5.1 Weighing. Determination of weights of coal delivered hereunder for payment purposes shall be based on weights obtained at the Mines. Coal shipped by railcar shall be weighed at the relevant Mine on a certified batch weigh load out system. Coal transported by truck shall be weighed at the relevant Mine by Seller’s certified truck scales.

5.2 Scales. All scales referred to herein shall be operated and maintained to be in conformance with the National Institute of Standards and Technology (NIST) Handbook 44, or the applicable Standards of the Association of American Railroads (AAR). Seller shall provide

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.2

copies of all scale certification test reports to Buyer upon request. Seller shall promptly notify Buyer if Seller believes its scales have experienced a failure or are unavailable, or are inaccurate.

5.3 Unavailability; Inaccuracies.

5.3.1 If weights from Seller’s scales are not available for a Shipment due to failure, mechanical or otherwise, of Seller’s scales, or if Seller has determined that its scales are inaccurate, weights for such Shipments will be obtained from Buyer’s scales and the weights so determined shall be the governing weights for payment purposes; provided that Buyer’s scales shall be certified and maintained in accordance with the standards as referenced in Section 5.2. For rail shipments, if no other weights are available, the average per car weight of the previous three train deliveries shall be the weight used for payment purposes.

5.3.2 If either Party believes the other Party’s scales to be in error beyond acceptable tolerance, that Party shall notify the other of such discrepancy and its apparent duration as soon as practicable, and the Party owning or controlling the scale in question shall have such scale tested for accuracy. The other Party shall have the right to be present during such test. Should such test reveal an inaccuracy which exceeds permitted tolerances, the weights from the time first stated in the notice until the testing and calibration of such scales shall be adjusted by the percentage of inaccuracy discovered by such testing.

ARTICLE 6

SAMPLING AND ANALYSIS

6.1 Sampling. Coal samples to be used for determination of coal quality for coal delivered to Buyer hereunder shall be taken by Seller at the Mine in conformance with applicable American Society for Testing Materials (“ASTM”) standards. For deliveries by truck, governing coal samples shall be a representative composite of trucks loaded daily, taken by Seller at the Mine using sampling methods in accordance with applicable ASTM standards, or by use of such other methods as may be mutually agreed upon by the Parties. For coal delivered by rail car, governing coal samples shall be obtained using an automatic sampling system in accordance with methods approved by the ASTM or such other methods as may be mutually agreed upon by the Parties. Each calendar month, Seller shall collect a composite sample representative of the coal delivered in that particular month (the “Monthly Composite Sample”) for the purpose of preparing a Monthly Composite Analysis, as defined in Section 6.2 below.

6.2 Analysis. For purposes of this Agreement, the governing analysis of coal samples collected by Seller shall be performed by Standard Laboratories in Evansville, Indiana. All governing analyses performed shall be done in accordance with ASTM standards. Seller shall direct Standard Laboratories to conduct a short proximate analysis of such coal samples and provide the results of such analysis to Buyer at the same time that such results are provided to Seller. If Standard Laboratories fails to deliver any such analytical results to Buyer, Seller shall deliver a copy of such analytical results to Buyer as soon as possible after Buyer’s request. Seller shall or shall cause Standard Laboratories to also provide quick analyses to Buyer for each Shipment. Seller shall use commercially reasonable efforts to cause Standard Laboratories to provide the results of its quick analysis within twenty four (24) hours of delivery of the

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.2

Shipment, or as soon as reasonably practicable. Each calendar month, Seller shall direct Standard Laboratories to analyze the [**] (as set forth in Exhibit A) of the Monthly Composite Sample (the “Monthly Composite Analysis”), which Standard Laboratories shall provide to Seller and Buyer as soon as reasonably practicable. If Buyer requires monthly analysis of any of the other quality specifications set forth on Exhibit A, Buyer shall provide Seller with reasonable advance notice and Seller shall direct Standard Laboratories to perform the relevant analyses for such additional specifications as part of the Monthly Composite Analysis for that particular month. Not more than once every six calendar months, Buyer may request, and Seller shall cause Standard Laboratories to conduct, a Full Proximate Analysis of the Monthly Composite Sample and such analysis shall be treated as the Monthly Composite Analysis for that particular month. Seller shall require Standard Laboratories to retain samples for thirty (30) days after such results are submitted to Seller, during which period Buyer may request from Seller a split of such samples for purposes of conducting its own analyses. If Buyer does not give Seller notice within such thirty (30) day period that, based on analysis of such split by Buyer, Buyer disagrees with Seller’s analysis, then Seller’s analysis shall apply to all of the Coal in the Shipment from which the sample was taken and shall be the binding basis for any BTU Adjustments and for the exercise of Buyer’s rights to reject coal pursuant to Section 4.3. Buyer’s notice of disagreement with the analyses received from Standard Laboratories, if any, shall be accompanied by the results of Buyer’s analysis. If the Parties cannot reach agreement on the analysis within thirty (30) days following Seller’s receipt of Buyer’s notice, the dispute shall be settled by an analysis performed by a commercial testing laboratory mutually agreed upon by the Parties, and the results of those tests shall be final and binding on the Parties. In the event of a dispute, the cost of the analysis made by such commercial testing laboratory shall be shared equally by the Parties. Until such dispute is resolved, Buyer shall be responsible for payment based on the results of Seller’s analysis.

6.3 Alternatives. In the event that a Shipment of coal is not sampled at a Mine, or a sample is lost or has obviously been contaminated, Seller shall notify Buyer as promptly as practicable. Unless the Parties agree on an alternate sampling method, analytical results obtained from the weighted average quality of the three (3) previous Shipments to Buyer from such Mine will be used as representative of the quality of the Shipment not sampled at such Mine.

ARTICLE 7

INVOICING AND PAYMENT

7.1 Invoicing. Seller will prepare and submit invoices to Buyer via e-mail twice each calendar month. Seller shall submit one invoice to Buyer on or before the fifth (5th) day of each calendar month, which invoice shall include the coal delivered during the period from the sixteenth (16th) day of the prior calendar month to the last day of the prior calendar month, plus any BTU Adjustment for the prior calendar month as determined in accordance with Section 3.2, plus any Freeze Treatment costs for Shipments made during the prior calendar month determined in accordance with Section 4.4, plus any applicable Carlisle Deduction or Alternate Source Deduction determined in accordance with Section 1.4. Seller shall submit one invoice to Buyer on or before the twentieth (20th) day of each calendar month, which invoice shall include the coal delivered during the period from the first (1st) day of such calendar month to the fifteenth

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.2

(15th) day of such calendar month, plus any applicable Carlisle Deduction or Alternate Source Deduction determined in accordance with Section 1.4.

7.2 Payment. Payment with respect to each invoice submitted by Seller hereunder shall be due no later than ten (10) days after Buyer’s receipt of such invoice. All payments will be made by ACH wire transfer of immediately available funds to the bank account as shown on Seller’s invoice.

7.3 Offset. If each Party is required to pay an amount to the other Party in the same month, then such amounts with respect to each Party shall be aggregated and the Parties shall discharge their obligations to pay through netting; in which case, the Party owing the greater aggregate amount shall pay to the other Party the difference between the amounts owed.

ARTICLE 8

FORCE MAJEURE

8.1 Impact of Force Majeure. If because of a Force Majeure Event, either Party is unable to carry out any of its obligations under this Agreement (other than any obligation to pay or expend money in connection with performance hereunder), and provided such Party promptly gives notice to the other Party of the existence of any such Force Majeure Event, then the obligations of the Party affected by such Force Majeure Event (other than any obligation to pay or expend money in connection with performance hereunder) shall be suspended to the extent made necessary by such Force Majeure Event and during its continuance, provided that the Party subject to such Force Majeure Event shall make all reasonable efforts to mitigate the impact of the Force Majeure Event and remove it with all reasonable dispatch.

8.2 Force Majeure Event. A “Force Majeure Event” as used herein means any cause beyond the reasonable control of the Party affected thereby, including but not limited to: acts of God, acts of the public enemy, insurrections, riots, terrorism, labor disputes, strikes, lockouts, boycotts, labor and material shortages, fires, explosions, landslides, earthquakes, storms, roof falls, rib falls, cave-ins, floods, aquifers, floor conditions, breakdowns of or damage to equipment or facilities, interruptions to transportation or shortages of transportation equipment, embargoes, blockades, acts of military authorities, inability to obtain permits or authorization from any government authority, any laws, orders, rules, regulations, enforcement proceedings or other acts or restraint of governmental authority, unexpected mining conditions including unforeseen changes in the coal seam, or faults or sandstone intrusions in the coal seam, and other cause including unsafe working conditions, or unscheduled outages and other unexpected disruptions at the Plant that exceed seven (7) days in duration, whether of the kind or character herein enumerated or otherwise, which is not within the control of the Party claiming excuse, whether or not foreseen or foreseeable, which wholly or partly renders the mining removal, processing or loading of all or part, of the normal output of the Mines impractical or unfeasible, or renders the accepting, utilizing, unloading, or intended use of the coal impossible, impractical or unfeasible, and which are not caused by acts or omissions of the Party failing to perform. Settlement of labor disputes shall be deemed beyond the control and without the fault or negligence of the Party experiencing such event. Seller’s ability to sell coal at a more advantageous price, Buyer’s ability to buy coal at a more advantageous price, or the change in the

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.2

market price of coal, price of power, or other related costs, shall not constitute a Force Majeure Event.

8.3 Mitigation. Prior to deeming any legislation or regulation a Force Majeure Event, the Parties shall consider what steps can be taken by Buyer in the handling, transportation and use of the coal, or by Seller in the production, processing, preparation and loading of the coal. If no such practicable solution to the problem is presented by either Party, such legislation or regulation may constitute a Force Majeure Event. A Force Majeure Event shall not in any event include a lack of sufficient financial means to perform obligations or the failure to make payments in accordance with this Agreement. During the continuation of a Force Majeure Event, the other Party may make arrangements to sell or purchase the estimated quantity of coal so affected for the estimated duration of the Force Majeure Event.

8.4 Make-Up. In the event that a Force Majeure Event occurs, the delivery of the affected quantity of coal shall be made up by the Parties during the Contract Year in which such Force Majeure Event occurred, unless not reasonably practicable, in which case the delivery of the affected quantity of coal shall be made-up as soon as practicable in the following Contract Year; provided that coal delivered in the following Contract Year shall be applied first to make-up deliveries affected by a Force Majeure Event. Coal delivered pursuant to this Section 8.4 shall be delivered on a delivery schedule agreed to by the Parties, and the Base Price to be paid by Buyer for coal delivered pursuant to this Section 8.4 shall be the Base Price in effect when the applicable Force Majeure Event occurred.

8.5 Allocation in Event of Partially Reduced Capability. If a Force Majeure Event occurs and results in, or is reasonably projected to result in: (i) a reduction or limitation of Seller's ability to supply coal from a Mine, or (ii) the inability of Buyer to accept or utilize coal at the Plant, then in the case of Seller, Seller shall allocate available supplies of coal from Seller's Mines on a pro-rata basis among its customers, or others as required by law, to the extent that its contracts with other customers give Seller the right to reduce its supply obligations as a result of the Force Majeure Event. In the case of Buyer, Buyer shall spread its reduced ability to accept or utilize coal at the Plant among all its suppliers of coal to the Plant, committed at the time the Force Majeure Event occurred, on a pro-rata basis to the extent that its contracts with other suppliers give Buyer the right to reduce its purchase obligations as a-result of the Force Majeure Event. Any such allocation shall be determined on the basis of the number of tons of coal which Seller is obligated to deliver to its committed customers, or Buyer is obligated to receive from its committed suppliers, at the time the Force Majeure Event occurred.

8.6 Suspension; Termination. If due to a Force Majeure Event, a Party is unable to deliver or accept any coal hereunder, such Force Majeure Event continues for a continuous period of ninety (90) days or longer, and such event or events cannot be reasonably eliminated or are not likely to terminate within a reasonable period of time, the other Party shall, at any time after such ninety (90) day period and while such Force Majeure Event suspension continues, have the right, at its option, to terminate this Agreement by giving thirty (30) days written notice of termination to the Party claiming the Force Majeure Event. Other than outstanding payments due hereunder, no damages or compensation shall be paid by either Party because of such termination and such termination shall not be subject to the provisions of Article 12.

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.2

ARTICLE 9

REPRESENTATIONS AND WARRANTIES

9.1 Representations; Warranties. As a material inducement to entering into this Agreement, each Party hereby represents and warrants to the other Party as of the date on which this Agreement is executed, as follows:

9.1.1 Such Party is a corporation duly organized, legally existing and in good standing under the laws of the jurisdiction of its incorporation; it has all requisite corporate power, and has all material governmental licenses, authorizations, consents and approvals necessary to own its assets and carry on its business as now being conducted; and it is qualified to do business in those jurisdictions necessary to perform this Agreement.

9.1.2 There are no bankruptcy proceedings pending or being contemplated by it, or to its knowledge, threatened against such Party.

9.1.3 Neither the execution and delivery of this Agreement, nor compliance with the terms and provisions hereof will conflict with or result in a breach of, or require any consent which has not been obtained as of the effective date of this Agreement under such Party’s charter, by-laws or operating agreement, any governmental requirement, or any agreement or instrument to which it is a party or by which it is bound or to which it or its properties are subject, or constitute a default under any such agreement or instrument.

9.1.4 Such Party has all necessary corporate power and authority to execute, deliver and perform its obligations under this Agreement; the execution, delivery and performance by it of this Agreement has been duly authorized by all necessary corporate action, as applicable, on its part; and this Agreement constitutes the legal, valid and binding obligations of such entity, enforceable against such entity in accordance with its terms, except as the same may be limited by applicable bankruptcy, insolvency, reorganization, moratorium or similar laws in effect from time to time relating to or affecting the enforcement of creditors’ rights generally and by general principles of equity.

9.1.5 No authorizations, approvals or consents of, and no filings or registrations with, any governmental authority are necessary for the execution, delivery or performance of this Agreement by such Party or for the validity or enforceability thereof.

9.1.6 Seller represents and warrants that it holds all necessary legal rights to sell to Buyer coal sufficient in quantity and quality to perform its obligations under this Agreement for the term hereof, and that Seller will hold good and marketable title to all coal that it sells hereunder.

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.2

ARTICLE 10

COMPLIANCE WITH LAW

Seller shall be in material compliance with all applicable laws and regulations in the performance of its obligations under this Agreement, including all environmental requirements in the mining, processing and storing of coal.

ARTICLE 11

INDEMNIFICATION

Seller shall defend, indemnify and hold harmless Buyer and its affiliates, directors, officers, employees and agents from and against all claims, demands, losses, damages, liabilities, obligations and costs (including reasonable attorneys’ and other litigation fees and expenses) (collectively “Claims”) arising out of or relating to personal injury to third parties or third party property damage resulting from the acts or omissions of Seller or its agents in the performance of this Agreement, without regard to which Party has title to the coal pursuant to Section 1.5, except to the extent such injury or damage arises out of the negligent acts or omissions of Buyer or its agents. Buyer shall defend, indemnify and hold harmless Seller and its directors, officers, employees and agents from and against all Claims arising out of or relating to personal injury to third parties or third party property damage resulting from the acts or omissions of Buyer or its agents in the performance of this Agreement, without regard to which Party has title to the coal pursuant to Section 1.5, except to the extent such injury or damage arises out of the negligent acts or omissions of Seller or its agents.

ARTICLE 12

DEFAULT, REMEDIES, AND TERMINATION

12.1 Default. In the event a Party shall: (i) make an assignment or any general arrangement for the benefit of creditors; (ii) file a petition or otherwise commence, authorize, or acquiesce in the commencement of a proceeding or case under any bankruptcy or similar law for the protection of creditors or shall have such a petition filed or proceeding commenced against it and such proceeding is not dismissed within sixty (60) days; (iii) otherwise become bankrupt or insolvent (however evidenced); (iv) be unable to pay its debts as they fall due; (v) have a receiver, provisional liquidator, conservator, custodian, trustee, or other similar official appointed with respect to it or substantially all of its assets; (vi) fail to perform any material obligation to the other Party with respect to this Agreement on or before the thirtieth (30th) day after written notice of such failure from the other Party is received (other than a failure of the coal to meet one or more of the quality specifications set forth in Exhibit A, for which the sole and exclusive rights, obligations and remedies are as set forth in Section 4.3 and, if applicable, Section 3.2); or (vii) not have paid any amount due the other Party hereunder on or before the tenth (10th) day following written notice that such payment is due, such Party shall be the “Defaulting Party” and such event shall be an “Event of Default” hereunder.

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.2

12.2 Remedies. The other Party that is not suffering the Event of Default (the “Non-Defaulting Party”) may, for so long as the Event of Default is continuing, (a) establish by written notice to the Defaulting Party a date, which shall be no earlier than thirty (30) days following the date of such notice, on which this Agreement shall terminate and withhold any payments due from and after the date of such notice in respect of this Agreement, subject to the rights of the Defaulting Party to dispute such termination and withholding in accordance with Article 14; and (b) suspend performance of its obligations under this Agreement, until the Event of Default is cured; provided that if the Event of Default is not cured in the time allowed under Section 12.1, or within thirty (30) days if no specific time period for cure is stated in Section 12.1, the Non-Defaulting Party may terminate this Agreement in accordance with subparagraph (a) of this Section 12.2. The termination of this Agreement pursuant to this Section 12.2 is not an exclusive right, but is in addition to any other rights recognized at law or in equity which may accrue to one Party or the other by reason of circumstances and conditions that are not the subject of an exclusive right that is specifically stated herein.

12.3 Termination by Buyer or Seller. Notwithstanding the Effective Date of this Agreement, if Seller does not become an affiliate of Sunrise Coal, LLC, an Indiana limited liability company, on or before December 31, 2014, either Buyer or Seller may terminate this Agreement immediately upon written notice to the other Party. Neither of the Parties shall have any obligation to the other hereunder following the termination of this Agreement pursuant to this Section 12.3.

12.4 Termination by Buyer.

12.4.1 In the event that Buyer determines that it [**], Buyer shall promptly notify Seller in writing. The Parties shall in good faith attempt to resolve the problem in a manner that would allow Buyer to [**]. If after six (6) months, the Parties have not reached agreement on a mutually acceptable solution, Buyer shall have the right to terminate this Agreement as of such date after which it [**], by given written notice of such termination to Seller. Buyer shall use good faith efforts to give Seller as much prior notice of termination as practicable. Nothing herein shall be construed as requiring Buyer to incur any significant added expense or significant capital investment to [**]. Neither of the Parties shall have any obligation to the other hereunder following the date of such termination, except with respect to matters occurring prior to the date of termination.

12.4.2 As a regulated utility, Buyer engages in [**]. In the event [**] directs Buyer to [**], Buyer may terminate this Agreement by giving Seller no less than one (1) year advance written notice of such termination, in which event this Agreement will terminate on the date specified in Buyer’s notice; provided that such date shall not be any earlier than the date on which Buyer [**]. In the event [**] directs Buyer to [**], Buyer may reduce the Base Tonnage of coal to be supplied hereunder by giving Seller no less than one (1) year advance written notice of such reduction; provided [**]. Neither of the Parties shall have any obligation to the other hereunder following the date of such termination, except with respect to matters occurring prior to the date of termination.

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.2

12.5 Termination by Seller. Notwithstanding Buyer’s extension of the Term of this Agreement pursuant to Section 1.1, if after the first extension of the Term of this Agreement pursuant to Section 1.1, Seller intends to permanently cease production from any of the Mines during the three (3) year period of any on-going or pending extension term (other than the first extension of the Term of this Agreement pursuant to Section 1.1), and Seller determines in its reasonable discretion that it will not be able to supply the Base Tonnage from the other Mines once such Mine ceases production, Seller may reduce the Base Tonnage by giving Buyer no less than one (1) year advance written notice of such reduction in the Base Tonnage hereunder to an amount equal to the amount of coal meeting the quality specifications that Seller reasonably expects to be able to deliver during the remaining Term of this Agreement and any remaining extensions hereunder, taking into account the quantity of uncommitted coal, and the quality specifications of such coal, that Seller expects to produce at the other Mines as of the date that Seller ceases production at the Mine in question; provided that in no event shall the Base Tonnage exceed 40% of the total production from the remaining Mines. If Seller does not expect to produce more than a de minimis amount of coal in excess of Seller’s commitments to other coal purchasers, Seller’s notice to Buyer may instead give Buyer notice of the date on which this Agreement will terminate. If Seller has elected to reduce the Base Tonnage hereunder, this Agreement shall continue in accordance with its terms and conditions. In determining the extent of the reduction in the Base Tonnage upon shutdown of a Mine, Seller shall not give any of its other customers any priority over Buyer with respect to the purchase of any uncommitted coal that Seller has available at such time. Nothing herein shall be construed as requiring Seller to (i) incur any significant added expense or significant capital investment to continue the production of coal from the Mine in question, or (ii) reserve or withhold any coal from the other Mines from any of its other customers in order to have uncommitted coal available for Buyer hereunder. Neither of the Parties shall have any obligation to the other hereunder following the date of such termination, except with respect to matters occurring prior to the date of termination.

12.6 Consequential Damages. Neither Party shall be liable to the other Party for any special, consequential or punitive damages, loss of profit, loss of customers, loss of revenues, loss of productivity, loss of goodwill or loss of use arising out of the performance, breach or nonperformance of this Agreement by such Party, irrespective of any legal theory under which the same may otherwise be asserted, except to the extent that third party claims with respect to which a Party is indemnified hereunder are deemed to constitute such damages.

ARTICLE 13

RECORDS; AUDITS

13.1 Records. Seller shall establish and maintain, subject to modification from time to time as may be required by Seller, a system of accounting such that all information which must be provided to Buyer as part of this Agreement shall be determinable by accounting periods

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.2

regularly used by Seller. Such system shall be in accordance with generally accepted accounting principles consistently applied, and appropriate to permit the development of the invoices, accountings and other documentation required by this Agreement.

13.2 Audit Rights. Upon reasonable notice and during normal business hours, each Party and its designated independent auditors, shall have the right to inspect the other Party’s books and records relating to all provisions of this Agreement, which include coal quality, quantity shipped and quantity received, price adjustments, or as may be necessary to satisfy inquiries from governmental or regulatory agencies, but only to the extent necessary to verify the accuracy of any statement, charges, payments or computations made pursuant to this Agreement. Each Party shall make a reasonable effort to facilitate the other Party’s inspection of such records in its possession. The Party conducting the inspection and its auditors, to the extent permitted by law or regulation, shall treat all such information as confidential. Any such audit shall in any event be conducted during the 12 months after the date of the report, accounting or statement provided that is subject to such audit.

13.3 Inspections. Buyer and its duly authorized representatives shall upon reasonable advance notice and during normal operating hours, have the right to inspect the Mines and Seller’s related coal preparation, loading and other related facilities. Buyer’s inspections shall be performed in a reasonable manner and without interfering with Seller or Seller’s operations at the Mine. Buyer shall cause each of its representatives that perform such inspections to participate in any required safety training, sign appropriate waivers and comply with all of Seller’s safety and security policies then in effect at the Mines.

13.4 Confidential Nature of Records. Buyer recognizes that the records to be maintained by Seller under this Article 13, and the information provided by either party in the course of an audit are confidential and proprietary in nature. Accordingly, each Party agrees that no information obtained in an audit or inspection will be disclosed without prior consent in writing from the other Party, except to the extent a Party is legally compelled to make such disclosure pursuant to applicable law, or to establish a claim or defense on behalf of Buyer in a Dispute between Buyer and Seller. Buyer shall in any event seek confidential treatment of such information prior to making any such disclosure.

ARTICLE 14

DISPUTE RESOLUTION

14.1 Dispute Notice. Except for disputes regarding the determination of the Market Adjusted Base Price, which shall be settled in accordance with Section 3.4, any controversy, claim, counterclaim, dispute, difference or misunderstanding arising out of or relating to the interpretation or application of this Agreement (a “Dispute”), shall be resolved by the Parties in accordance with this Article 14. In the event of a Dispute, either Party may provide written notice to the other of the existence of a Dispute. Such notice shall state the nature or subject of the Dispute, and the notifying Party’s position thereon. The Parties shall, for a period of thirty (30) days following the date of such notice, engage in good faith discussions and negotiations in an attempt to resolve such Dispute.

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.2

14.2 Escalation. In the event no resolution is reached in the preliminary thirty (30) day period as described in Section 14.1, either Party may, following the expiration of the original thirty (30) day period, designate by written notice, a member of such Party’s senior management for further discussions and negotiations. Within five (5) business days of receipt of that designation, the other Party shall designate by written notice, a member of its senior management to participate in such further discussions and negotiations. Commencing on receipt of this second designation, an additional twenty (20) day period shall commence during which the designated senior management from both Parties, together with such assistance as they may deem appropriate, shall engage in good faith discussions and negotiations to resolve the Dispute. In the event that the discussions and negotiations involving senior management during such additional twenty (20) day period produces no resolution, either Party may submit the Dispute to binding arbitration in accordance with Section 14.3.

14.3 Arbitration. In the event the Parties are unable to resolve a Dispute pursuant to Section 14.1 or Section 14.2, either Party may demand an arbitration proceeding by written demand to the other Party and the appropriate office of the American Arbitration Association (the “AAA”). All arbitration proceedings shall take place in Indianapolis, Indiana under the auspices of the AAA in accordance with the Federal Arbitration Act and the AAA Commercial Arbitration Rules then in effect, subject to the specific provisions of this Section 14.3.

14.3.1 For all Disputes where the amount or value of the Dispute is less than $1,000,000, the arbitration proceeding shall be conducted by a single neutral arbitrator selected by Buyer and Seller (or the AAA if the Buyer and Seller cannot agree within twenty (20) days) of the demand for arbitration. For all Disputes where the amount or value of the Dispute is equal to or more than $1,000,000, the arbitration proceeding shall be conducted by a panel of three (3) neutral arbitrators, one of which shall be selected by Buyer, and one of which shall be selected by Seller. Buyer and Seller shall mutually select the third neutral arbitrator. If the arbitration is to be conducted by a panel of three (3) arbitrators, and the Parties have not each appointed a neutral arbitrator and agreed on the third arbitrator on or before thirty (30) days following the delivery of a demand for arbitration, then either Party may request that the AAA designate any remaining arbitrators pursuant to its Commercial Arbitration Rules and such designation shall be binding on the Parties.

14.3.2 The arbitration decision shall be by majority vote if the arbitration proceeding is conducted by a panel, and shall be issued in a writing that sets forth in separately numbered paragraphs all of the findings of fact and conclusions of law necessary for the decision. Findings of fact and conclusions of law shall be separately designated as such. The arbitrator(s) shall not be entitled to deviate from the construct, procedures or requirements of this Agreement. Any decision rendered by the arbitrator(s) in any arbitration shall be final and binding upon the Parties, and judgment may be entered on the award in any court of competent jurisdiction. The cost of the arbitration shall be borne equally by the Parties.

14.3.3 Each Party shall be entitled to be represented by counsel in any such arbitration proceeding, to present written and oral evidence and arguments, to cross-examine the other Party’s witnesses, and to obtain a list of the other Party’s witnesses and evidence no less than fourteen (14) days prior to the hearing. The formal rules of evidence shall not apply, but the arbitrator(s) may be guided by the Federal Rules of Evidence in conducting the proceeding. The

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.2

arbitrator(s) shall permit and facilitate such disclosure and discovery of facts, documents and tangible things as the arbitrator(s) shall determine is appropriate in the circumstances, taking into account the needs of the Parties and the desirability of making disclosure expeditious and cost-effective. The arbitrator(s) may issue orders to protect the confidentiality of proprietary information, trade secrets and other sensitive information disclosed.

14.4 Extensions. The Parties may agree, in writing, to extend any time period provided for in this Article 14.

ARTICLE 15 MISCELLANEOUS

15.1 Notices. Any notice, request, consent, demand, report, or statement which is given or made under any of the provisions of this Agreement shall be in writing unless otherwise provided herein, and shall be treated as duly delivered when the same is either personally delivered to the Party to whom directed, when sent by United States certified mail with all necessary postage prepaid and a return receipt requested, when sent by a nationally recognized overnight delivery service with charges fully prepaid, or when sent by electronic mail or facsimile with confirmation of receipt, and addressed to the respective Party at the below specified address:

Notices to Buyer

Southern Indiana Gas and Electric Company

One Vectren Square

Evansville, IN 47708

Attn: Wayne D. Games

E-mail: wdgames@Vectren.com

Fax: 812.491.4684

With a copy to:

Robert E. Heidorn

Senior Vice President and General Counsel

Vectren Corporation

One Vectren Square

Evansville, IN 47741

E-mail: rheidorn@Vectren.com

Fax: 812.491.4238

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.2

Notices to Seller

Vectren Fuels, Inc.

One Vectren Square

Evansville, IN 47741

Attn: Randy Beck

Either Party may update or modify the address(es) to whom notice shall be sent hereunder from time to time, by written notice to the other Party as provided above.

15.2 Successors and Assigns. This Agreement shall inure to the benefit of and be binding upon the Parties hereto and their respective successors and assigns.

15.3 Assignment. This Agreement may not be assigned by either Party without the written consent of the other Party, not to be unreasonably withheld or delayed. Notwithstanding the foregoing, either Party may without the written consent of the other Party, assign or otherwise transfer this Agreement (a) in the case of Seller, to an affiliate of such Party; (b) to a successor to all or substantially all of such Party’s assets; provided that such successor has a financial condition at least equivalent to that of the assigning Party; (c) in the case of Buyer, to a successor to all or substantially all of the property and assets comprising the Plant; (d) to secure such Party’s indebtedness incurred or to be incurred for the purposes of or in connection with the performance of this Agreement; and (e) to one or more persons, firms or corporations who shall assume the obligation of the transferring Party hereunder in connection with the enforcement of any assignment or transfer referred to in subparagraph (d) of this Section 15.3. The Party making any such permitted assignment or transfer hereunder shall give the other Party ten (10) days written notice of such assignment or transfer. Except with respect to an assignment pursuant to subparagraph (d) of this Section 15.3, no assignment under this Agreement shall be effective until the assignee, in writing delivered to the non-assigning Party, has agreed to accept the assignment and to be bound by all the terms and conditions in this Agreement.

15.4 Survival. The terms and provisions of this Agreement regarding payment and indemnity shall survive the expiration or the termination of this Agreement indefinitely. The terms and provisions of this Agreement regarding records and confidentiality shall survive the expiration or the termination of this Agreement for a period of five (5) years.

15.5 Waivers. The failure of a Party to insist in any one or more instances upon strict performance of any provisions of the Agreement by the other Party, or to take advantage of any of its rights hereunder, shall not be construed as a waiver by such Party of any such provision or the relinquishment by such Party of any such rights in respect of any subsequent nonperformance of such provision, but the same shall continue and remain in full force and effect.

15.6 Severability. The provisions of this Agreement are severable, and the invalidity or unenforceability of any one or more provision shall not affect or limit the validity of the remaining provisions. Should any particular provision be held to be unreasonable or unenforceable for any reason, then such provision shall be given effect and enforced. to whatever extent would be reasonable and enforceable under the applicable law.

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.2

15.7 Governing Law. This Agreement and any questions concerning its validity, construction, interpretation or performance shall be governed by the laws of the State of Indiana without reference to any other choice of law provisions. Any action which may be commenced based on, arising from or related to this Agreement shall be brought only in the federal or state courts sitting in the State of Indiana.

15.8 Headings. The captions of Articles and Sections in this Agreement are for convenience of reference only and shall not be taken or construed to define or limit any of the terms or provisions of this Agreement.

15.9 Confidentiality. Each Party acknowledges that this Agreement contains confidential information, which could put the other Party at a competitive disadvantage in its purchasing and sales activities, if disclosed to the public. Therefore, this Agreement and its terms shall be kept confidential and shall not be disclosed to any third party, except (a) as required by law or governmental or judicial order, including as required by the IURC, (b) pursuant to securities laws and regulations applicable to a Party, (c) as mutually agreed to by the Parties hereto; provided that this Section 15.9 shall not be construed to prohibit disclosure of this Agreement and its terms to a Party’s affiliates and its directors, employees, advisors, lenders, counsel, accountants, representatives, and prospective purchasers, solely for the purpose of evaluating, negotiating, and consummating the transactions contemplated by the Parties under this Agreement, and who have been notified of such Party’s confidentiality obligations hereunder. Each Party shall be responsible for any disclosure of this Agreement or its terms by any of such persons or entities that receive such information from such Party. If a Party reasonably believes it is required to disclose this Agreement or any of its terms pursuant to subparagraph (a) or (b) of this Section 15.9, such Party shall promptly notify the other Party, shall seek confidential treatment of any information that is disclosed, shall disclose only that part of the information that such Party is advised by counsel is required to be disclosed, and shall cooperate with the other Party’s reasonable attempts to obtain confidential treatment of this Agreement and any terms that may have been disclosed. This Section 15.9 shall not apply to information, including redacted copies of other coal supply agreements entered into by a Party, provided by a Party in connection with the Market Price Adjustments contemplated in Section 3.4, which shall be subject to the requirements of Section 3.4.5.

15.10 Guarantee. Unless this Agreement is terminated pursuant to Section 12.3, within ten (10) days after Seller becomes an affiliate of Sunrise Coal, LLC, if at all, Seller shall in its sole discretion, either assign this Agreement to Sunrise Coal, LLC and notify Buyer accordingly, or deliver to Buyer, and thereafter maintain until such time as this Agreement is assigned to Sunrise Coal, LLC (or its successor), a guarantee by Sunrise Coal, LLC (or its successor) of Seller’s obligations hereunder substantially in the form set forth in Attachment 2 to this Agreement. Notwithstanding anything to the contrary in the foregoing or in Section 15.3(a) or Section 15.3(e), (i) if this Agreement is assigned to Sunrise Coal, LLC and subsequently assigned to an affiliate of Sunrise Coal, LLC (or its successor), Seller shall as a condition to such assignment, deliver to Buyer and thereafter maintain until such time as this Agreement is assigned to Sunrise Coal, LLC (or its successor), a guarantee by Sunrise Coal, LLC (or its successor) of Seller’s obligations hereunder substantially in the form set forth in Attachment 2 to this Agreement; (ii) if (A) Seller has the obligation to deliver a guarantee by Sunrise Coal, LLC pursuant to this Section 15.10, (B) Sunrise Coal, LLC no longer directly or indirectly holds all of

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.2

the Mines, and (C) the financial condition of Sunrise Coal, LLC is no longer equivalent to or better than the financial condition of Sunrise Coal, LLC as of the Effective Date, and (iii) if this Agreement is assigned pursuant to Section 15.3(c) and the financial condition of the assignee is not equivalent to or better than the financial condition of Sunrise Coal, LLC as of the Effective Date, then Seller or such assignee, as applicable, shall, in lieu of delivering a guarantee by Sunrise Coal, LLC (or its successor), deliver to Buyer and thereafter maintain a guarantee of Seller’s obligations hereunder substantially in the form set forth in Attachment 2 to this Agreement by an affiliate of Sunrise Coal, LLC (or its successor) with a financial condition equivalent to or better than the financial condition of Sunrise Coal, LLC as of the Effective Date, or such other form of financial security as is reasonably acceptable to Buyer.

15.11 Entire Agreement. This Agreement contains the complete and exclusive embodiment of the Parties’ agreement as to matters herein referenced, and supersedes all other or prior agreements with respect thereto. No amendments or modifications hereto shall be binding unless in a writing signed by each of the Parties.

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.2

IN WITNESS WHEREOF, Buyer and Seller have caused this Agreement to be executed by their respective officers as of June 30, 2014.

SELLER

VECTREN FUELS, INC.

By:     /s/ Randy L. Beck        

Name :     Randy L. Beck    

Title:         President        

BUYER

SOUTHERN INDIANA GAS AND ELECTRIC COMPANY

d/b/a VECTREN POWER SUPPLY, INC.

By:     /s/ Wayne D. Games        

Name :     Wayne D. Games    

Title:         VP - Power Supply    

{Signature page to A.B. Brown Coal Supply Agreement}

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.2

EXHIBIT A

COAL QUALITY SPECIFICATIONS

The coal supplied under this Agreement shall meet the following quality specifications on an “as received” basis. Coal quality shall be determined in accordance with Article 6.

	Typical	MWA (monthly weighted average)	Reject (per Shipment)
Moisture (%)	[**]	[**]	[**]
Ash (%)	[**]	[**]	[**]
BTU/Lb.	[**]	[**]	[**]
SO2 (LBs/MMBTU)	[**]	[**]	[**]
Sulfur (%)	[**]	[**]	[**]
Volatile Matter (%)	[**]	[**]	[**]
AFT h/w, reducing 0F	[**]	[**]	[**]
HGI	[**]	[**]	[**]
Size (2” x 0) (Percent passing thru ¼” screen)	[**]	[**]	[**]
Sodium Equivalent (% Ignited)	[**]	[**]	[**]
Ferric Oxide (% Ignited)	[**]	[**]	[**]
Silicon Dioxide (% Ignited)	[**]	[**]	[**]
Aluminum Oxide (% Ignited)	[**]	[**]	[**]
Arsenic (ug/g dry basis)	[**]	[**]	[**]
% Chlorine (until December 31, 2019, inclusive)	[**]	[**]	[**]
% Chlorine (beginning January 1 2020 and thereafter)	[**]	[**]	[**]
Mercury (ug/g dry basis)	[**]	[**]	[**]

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.2

ATTACHMENT 1

AMENDMENT AND TERMINATION AGREEMENT

This Amendment and Termination Agreement (this “Agreement”) is made and entered into effective as of June 30, 2014 (the “Effective Date”), by and between Southern Indiana Gas And Electric Company d/b/a Vectren Power Supply, Inc., an Indiana corporation (“Buyer”), and Vectren Fuels, Inc., an Indiana corporation (“Seller”). Buyer and Seller are also referred to herein individually as a “Party” and collectively as the “Parties.”

RECITALS

WHEREAS, Buyer and Seller are parties to that certain A.B. Brown Coal Supply Agreement entered into effective as of January 1, 2009, as amended from time to time for the annual supply of 410,000 tons of coal (the “AB Brown 1 Agreement”), and that certain A.B. Brown Coal Supply Agreement entered into effective as of January 1, 2009, as amended from time to time for the original annual supply of 1,000,000 tons of coal (the “AB Brown 2 Agreement” and together with the AB Brown 1 Agreement, the “Original Agreements”).

WHEREAS, Buyer and Seller are entering into that certain A.B. Brown Coal Supply Agreement made and entered into effective as of January 1, 2015 (the “2015 CSA”), for the supply of bituminous coal for use in its A.B. Brown generating plant (the “Plant”).

WHEREAS, it is a condition to the willingness of Seller to enter into the 2015 CSA that certain amendments be made to the terms and conditions of the Original Agreements, as set forth herein.

NOW, THEREFORE, in consideration of the premises and the mutual covenants and agreements of the Parties contained herein, the Parties agree as follows:

AGREEMENT

1. Amendments to the Original Agreements. Notwithstanding anything to the contrary in either of the Original Agreements, the Parties hereto agree that the following terms shall apply effective immediately as of the date on which Seller becomes an affiliate of Sunrise Coal, LLC. In the case of any conflicts between the foregoing and the terms of the Original Agreements, the provisions of this Section 1 shall govern.

a). Source of Coal. The source of the coal to be delivered by Seller shall be the Seller’s Oaktown 1 or Oaktown 2 Mines (collectively, the “Mines”). Seller shall have the right to notify Buyer that the coal to be sold by Seller and purchased by Buyer under this Agreement may also be mined from coal properties and reserves at Sunrise Coal, LLC’s Carlisle Mine, located in and around Sullivan County, Indiana. Seller’s right to deliver coal mined from the Carlisle Mine under this Agreement shall arise automatically upon Seller’s notice to Buyer, subject to the Parties’ agreement on the Carlisle Deduction (as defined below). Within thirty (30) days after Seller becomes an affiliate of Sunrise Coal, LLC, Buyer shall notify Seller if its cost to transport coal from the Carlisle Mine to the Plant differs from the cost to transport coal from the Seller’s Oaktown 1 or Oaktown 2 Mines. Such notice shall include reasonable supporting documentation of the respective transportation costs. Buyer and Seller, each acting in good faith,

Att 1 - 1

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.2

shall determine the difference between Buyer’s transportation costs for coal transported for: (a) each ton of coal delivered from the Carlisle Mine, and (b) each ton of coal delivered the Seller’s Oaktown 1 or Oaktown 2 Mines (such difference in costs, the “Carlisle Deduction”), and Seller shall apply the Carlisle Deduction to all tons of coal delivered from the Carlisle Mine in its invoices when submitted to Buyer. To the extent the Carlisle Deduction is different for rail and truck transportation, the Carlisle Deduction for the applicable transportation mode shall be utilized. The Parties shall document the agreed Carlisle Deduction in a writing signed by both Parties. Once the Parties agree on the Carlisle Deduction, the Carlisle Mine shall be deemed to be one of the “Mines” for all purposes hereunder.

b), Delivery. Coal shall be delivered F.O.B. railcar or truck (as elected by Buyer) at the Mines (as elected by Seller), in substantially equal monthly quantities on a mutually agreeable delivery schedule. Seller will coordinate loading at the Mines with Buyer and Buyer’s relevant carriers. The foregoing provisions replace any provisions in the Original Agreements regarding point of delivery and delivery schedule, including, without limitation, any limitations set forth in Section 3.1 or otherwise in the Original Agreements with respect to the number of tons that may be delivered per day , all of which are hereby superseded in their entirety.

c). Transportation. Buyer shall be solely responsible for transportation of the coal from the Mines to the Plant, including providing railcars or trucks, as Buyer elects, for loading at the Mines. Buyer may, in its sole discretion, direct any coal delivered hereunder to any of Buyer’s or its affiliate’s power generating stations other than the Plant; provided that Buyer shall be responsible for all additional transportation costs associated with such election. Buyer’s right to direct coal to a power generating station other than the Plant shall in no way be construed as an obligation to do so under any circumstance. The foregoing provisions replace any provisions in the Original Agreements regarding transportation and transportation costs, all of which are hereby superseded in their entirety.

d). Base Tonnage. The quantity of coal to be delivered under each of the Original Agreements in calendar year 2014 and 2015, as applicable, is as follows (the “Base Tonnage”):

AB Brown 1 Agreement

2014 - 410,000 tons

2015 - 410,000 tons

Buyer has notified Seller that Buyer has utilized its option to adjust the Base Tonnage by + [**] pursuant to the AB Brown 1 Agreement to increase the amount of coal to be delivered pursuant to the AB Brown 1 Agreement to [**] tons annually, until further notice.

AB Brown 2 Agreement

2014 - 600,000 tons

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.2

Buyer has notified Seller that Buyer has utilized its option to adjust the Base Tonnage by + [**] pursuant to the AB Brown 2 Agreement to decrease the amount of coal to be delivered pursuant to the AB Brown 2 Agreement to [**] tons annually, until further notice.

e). Buyer Option to Adjust. Buyer’s option to adjust the annual Base Tonnage by + [**] as stated in Section 3.1 of each of the Original Agreements, shall remain in full force and effect during the term thereof.

f). Coal Quality Specifications. The table in Exhibit A to each of the Original Agreements is hereby deleted in its entirety and replaced with the following table:

Quality Specifications
Coal Characteristics	MWA (monthly weighted average)	Penalty Threshold	Reject
Caloric value, as received	[**]	[**]	[**]
% Moisture, as received	[**]	[**]	[**]
% Ash, as received	[**]	[**]	[**]
SO2	[**]	[**]	[**]
Ash Fusion, softening, H=W red	[**]	[**]	[**]
Hardgrove Grindability Index	[**]	[**]	[**]
Nominal Size	[**]	[**]	[**]
Percent passing thru ¼” screen	[**]	[**]	[**]
Chlorine	[**]	[**]	[**]
Mercury (ug/g dry basis)	[**]	[**]	[**]

g). Weighing. The provisions of Article 5 of the 2015 CSA shall apply, and shall replace any provisions of the Original Agreements regarding weighing or the other matters addressed in Article 5 of the 2015 CSA, in their entirety.

h). Sampling and Analysis. The provisions of Article 6 of the 2015 CSA (other than quality specifications and without regard to cross-references to other provisions of the 2015 CSA) shall apply, and shall replace any provisions of the Original Agreements regarding sampling and analysis or the other matters addressed in Article 6 of the 2015 CSA, in their entirety.

i). Invoicing and Payment. The provisions of Article 7 of the 2015 CSA shall apply, and shall replace any provisions of the Original Agreements regarding invoicing and payments or the other matters addressed in Article 7 of the 2015 CSA, in their entirety

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.2

2. Termination of the Original Agreements.

a). Notwithstanding anything to the contrary in the AB Brown 1 Agreement, the Parties hereby agree that the AB Brown 1 Agreement shall terminate and be of no further force and effect as of 11:59 pm Eastern on December 31, 2015, except with respect to the obligation to make any payments remaining to be made as of such date.

b). Notwithstanding anything to the contrary in the AB Brown 2 Agreement, the Parties hereby agree that the AB Brown 2 Agreement shall terminate and be of no further force and effect as of 11:59 pm Eastern on December 31, 2014, except with respect to the obligation to make any payments remaining to be made as of such date.

3. Termination of this Agreement. If Seller does not become an affiliate of Sunrise Coal, LLC, an Indiana limited liability company, on or before December 31, 2014, either Buyer or Seller may terminate this Agreement immediately upon written notice to the other Party, after which this Agreement shall be of no further force and effect.

4. No Other Modifications. Except as amended herein, all other terms, conditions and provisions of the Original Agreements not explicitly modified or amended in this Agreement shall remain unchanged and shall continue in full force and effect.

5. Counterparts and Facsimile. This Agreement may be executed in counterparts and by facsimile, each of which shall be an original and all of which taken together shall constitute one and the same instrument.

[signature page follows]

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.2

IN WITNESS WHEREOF, Buyer and Seller have caused this Agreement to be executed by their respective officers as of the date first written above.

SELLER

VECTREN FUELS, INC.

By:     /s/ Randy L. Beck        

Name :     Randy L. Beck    

Title:         President        

BUYER

SOUTHERN INDIANA GAS AND ELECTRIC COMPANY

d/b/a VECTREN POWER SUPPLY, INC.

By:     /s/ Wayne D. Games        

Name :     Wayne D. Games    

Title:         VP - Power Supply    

{Signature page to A.B. Brown Amendment and Termination Agreement}

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.2

ATTACHMENT 2

FORM OF GUARANTEE

Guaranty

This GUARANTY, dated as of theday of, 2014, is entered into by Sunrise Coal, LLC, an Indiana limited liability company (“Sunrise”), to and for the benefit of Southern Indiana Gas And Electric Company d/b/a Vectren Power Supply, Inc., an Indiana corporation (“VPS”).

WITNESSETH:

WHEREAS, VECTREN FUELS, INC., an Indiana corporation (“Fuels”), is a wholly owned subsidiary of Sunrise.

WHEREAS, Fuels and VPS have entered into that certain A.B. Brown Coal Supply Agreement made and entered into effective as of January 1, 2015 (the “2015 CSA”).

WHEREAS, as an inducement to VPS entering into the 2015 CSA and subject to Fuels becoming a wholly-owned subsidiary of Sunrise, Fuels has agreed to cause Sunrise to execute and deliver this Guaranty for the benefit of VPS within 10 days after the date on which Fuels becomes a wholly-owned subsidiary of Sunrise, if at all.

NOW, THEREFORE, in consideration of the foregoing premises and the following covenants and other good and valuable consideration, the receipt and sufficiency of which is hereby acknowledged, Sunrise covenants with VPS as follows:

1. Guaranty. For value received and in consideration of the direct and indirect benefits to be derived by Sunrise in connection with the transactions contemplated by the 2015 CSA, with effect from January 1, 2015, Sunrise hereby guarantees to VPS the payment and performance as and when due of all obligations of Fuels (and any assignee of Fuels that is an affiliate of Sunrise) arising out of or related to the 2015 CSA, subject in all respects to all of the conditions, limitations, and qualifications set forth in the 2015 CSA (the “Obligations). This is a continuing Guaranty of payment and performance and not merely of collection. Subject to the provisions of Section 4, this Guaranty shall terminate upon the earlier of the termination of the Obligations or the date that is 12 months after the termination or expiration of the 2015 CSA; provided, however, that this Guaranty and Sunrise’s liability hereunder shall survive any such termination with respect to any claims made by VPS under the 2015 CSA if such claims are made prior to such termination.

2. Waiver. Sunrise hereby expressly waives notice from VPS of its acceptance of and reliance upon this Guaranty. Sunrise consents to any extensions of time for the payment or performance of the Obligations and to any changes in the terms of the 2015 CSA, and waives any notices thereof. Sunrise also waives promptness, diligence, presentment to or demand of payment or performance from anyone other than Fuels liable upon the Obligations, and presentment, notice of dishonor, protest and all other notices whatsoever. No waiver,

Att 2 - 1

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.2

amendment, release or modification of this Guaranty shall be established by conduct, custom or course of dealing, but solely by an instrument in writing duly executed by Sunrise and VPS. VPS’s failure or delay in exercising any right, remedy or power hereunder shall not operate as a waiver thereof, nor shall any single or partial exercise by VPS of any right, remedy or power hereunder preclude VPS from any other or future exercise of any right, remedy or power. Each and every right, remedy and power granted to VPS hereunder or allowed to it by law or other agreement shall be cumulative with and not exclusive of any other.

3. Waiver of Defenses. The liability of Sunrise under this Guaranty, and Sunrise’ obligations under this Guaranty shall not be impaired or released as a result of (a) any change of the time, manner or terms of payment or performance of any of the Obligations; (b) any renewal or increase of any of the Obligations; (c) the assignment of the 2015 CSA to an affiliate of Sunrise pursuant to Section 15.3(a) of the 2015 CSA; (d) any release or partial release of any other guarantor or other obligor in respect of any of the Obligations; (e) any modification, amendment, waiver or renewal of, or consent to departure from, any agreement or instrument relating to any of the Obligations; (f) VPS’s exercise or failure to exercise any rights against Fuels, Sunrise or others or any other action or inaction by VPS in respect of any of the Obligations; (g) with respect to any of the foregoing, the lack of notice to or consent by Sunrise; or (h) any other circumstance which might otherwise constitute a defense available to, or discharge of, a surety or a guarantor excepting payment and performance, as applicable. Nothing herein is intended to deny Sunrise, and Sunrise shall have and may assert any and all of the defenses, set-offs, counterclaims and other rights which Fuels is or may be entitled to assert that arise from or out of the 2015 CSA, except for defenses arising out of the bankruptcy, insolvency, dissolution or liquidation of Fuels. The obligations of Sunrise hereunder are several from Fuels or any other person, and are primary obligations concerning which Sunrise is the principal obligor. There are no conditions precedent to the enforcement of this Guaranty, except as expressly contained herein.

4. Reinstatement Provision. If VPS receives any payment or payments on account of the Obligations, which payment or payments of any part thereof are subsequently invalidated, declared to be fraudulent or preferential, set aside and/or required to be repaid to a trustee, receiver, or any other party under any bankruptcy act or code, state or federal law, common law or equitable doctrine, then to the extent of any sum not finally retained by VPS, Sunrise’ obligations to VPS hereunder shall be reinstated and this Guaranty, shall remain in full force and effect (or be reinstated) until payment of the Obligations shall have been made to VPS, which payment shall be due on demand.

5. Assignment. This Guaranty shall be binding upon Sunrise and upon its successors and assigns and shall be for the benefit of VPS and its successors and assigns. Sunrise may not assign this Guaranty or the obligations hereunder without the express written consent of VPS and such consent will not be unreasonably withheld. Any purported assignment in violation of this Section 5 shall be void and without effect.

6. Applicable Law. This Guaranty shall be governed by and construed in accordance with the laws of the State of Indiana, without giving effect to laws of such state that would require the application of the laws of any other state.

Att 2 - 2

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.2

7. Severability. In case any clause, provision or section of this Guaranty, or any application thereof, is for any reason held to be illegal, invalid, or inoperable, Sunrise and VPS shall negotiate an equitable adjustment to such affected provisions of this guaranty with a view towards effecting the purpose and intent of the Guaranty, and subject to such adjustment such illegality, invalidity or inoperability shall not affect the remainder thereof or any other clause, provision or section, and each such clause, provision or section shall be deemed to be effective and operative in the manner and to the fullest extent permitted by law.

8. Only Agreement. This Guaranty is the entire and only agreement between Sunrise and VPS with respect to the guaranty of the Obligations of Fuels by Sunrise.

9. Representations and Warranties. Sunrise represents and warrants to VPS that: (a) Sunrise is a limited liability company duly organized and validly existing under the laws of the State of Indiana; (b) Sunrise has all requisite power and authority to execute and to deliver and to perform all of its obligations under this Guaranty; (c) the execution, delivery and performance of this Guaranty by Sunrise are within its powers and have been duly authorized by all necessary limited liability company actions; (d) this Guaranty constitutes a legally valid and binding agreement of Sunrise, subject only to insolvency, bankruptcy, moratorium, reorganization, fraudulent conveyance or similar laws affecting creditors’ rights generally and by general principles of equity; (e) the execution, delivery and performance of this Guaranty will not violate any provision of any requirement of law or contractual obligation of Sunrise (except to the extent that any such violation would not reasonably be expected to have a material adverse effect on Sunrise’ ability to perform this Guaranty); (f) no consent or authorization of, filing with, or other act by or in respect of, any arbitrator or governmental authority and no consent of any other person (including, without limitation, any stockholder or creditor of Sunrise) is required in connection with the execution, delivery, performance, validity or enforceability of this Guaranty, other than any which have been obtained or made prior to the date hereof and remain in full force and effect; and (g) no litigation, investigation or proceeding of or before any arbitrator or governmental authority is pending or, to the knowledge of Sunrise, threatened by or against Sunrise relating to this Guaranty or that would have a material adverse effect on Sunrise’ ability to perform this Guaranty.

10. Collection Expenses. If VPS is required to pursue any remedy against Sunrise hereunder, Sunrise shall pay to VPS upon demand, all reasonable attorneys’ fees and expenses and all other reasonable costs, expenses and fees incurred by VPS in successfully enforcing this Guaranty.

11. Notices. Any notices given or required to be given hereunder shall be given to Sunrise and VPS, as applicable, by being either: (a) delivered personally against written receipt, (b) sent by facsimile or e-mail transmission, (c) mailed by registered or certified mail, postage prepaid, return receipt requested, or (d) mailed by reputable international overnight courier, fee prepaid, to Sunrise or VPS, as applicable, at the following addresses or facsimile numbers:

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.2

If to Sunrise: Sunrise Coal, LLC Attention: Brent Bilsland 1183 East Canvasback Dr. Terre Haute, IN 47802 Phone: (812) 298-3702

Fax No.: (812) 299-2810

E-mail: bbilsland@sunrisecoal.com

If to VPS: Southern Indiana Gas and Electric Company One Vectren Square

Evansville, IN 47708 Attn: Wayne D. Games

E-mail: wdgames@Vectren.com Fax: 812.491.4684

With a copy to: Robert E. Heidorn

Senior Vice President and General Counsel Vectren Corporation

One Vectren Square Evansville, IN 47741

E-mail: rheidorn@Vectren.com Fax: 812.491.4238

All such notices, requests and other communications will be deemed given, (w) if delivered personally as provided in this Section 11, upon delivery, (x) if delivered by facsimile or email transmission as provided in this Section 11, upon confirmed receipt, (y) if delivered by mail as provided in this Section 11, upon the earlier of the fifth business day following mailing and receipt, and (z) if delivered by overnight courier as provided in this Section 11, upon the earlier of the second business day following the date sent by such overnight courier and receipt (in each case regardless of whether such notice, request or other communication is received by any other person or entity to whom a copy of such notice is to be delivered pursuant to this Section 11). Sunrise and VPS may change the address to which notices to it are to be sent upon written notice to VPS or Sunrise, respectively.

12. Modification. This Guaranty may not be amended or modified unless the changes are in writing and signed by both VPS and Sunrise.

13. JURY TRIAL WAIVER. SUNRISE HEREBY IRREVOCABLY WAIVES ANY AND ALL RIGHTS TO TRIAL BY JURY WITH RESPECT TO ANY LEGAL PROCEEDING ARISING OUT OF OR RELATING TO THIS GUARANTY.

[signature page follows]

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.2

IN WITNESS WHEREOF, Sunrise has executed and delivered this Guaranty effective as of the day and year first above written.

Sunrise Coal, LLC

By:

Name :

Title:

Accepted:

Southern Indiana Gas and Electric Company d/b/a Vectren Power Supply, Inc.

By:

Name:

Title:     

Att 2 - 5

EX-10.3

[**] REPRESENTS CONFIDENTIAL MATERIAL OMITTED AND FILED SEPARATELTY WITH THE SECURITIES

AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.3

F.B. CULLEY

COAL SUPPLY AGREEMENT

This Coal Supply Agreement (the “Agreement”) is made and entered into effective as of January 1, 2015 (the “Effective Date”), by and between Southern Indiana Gas And Electric Company d/b/a Vectren Power Supply, Inc., an Indiana corporation (“Buyer”), and Vectren Fuels, Inc., an Indiana corporation (“Seller”). Buyer and Seller are also referred to herein individually as a “Party” and collectively as the “Parties.”

RECITALS

WHEREAS, Buyer and Seller are parties to that certain F.B. Culley Coal Supply Agreement entered into effective as of January 1, 2009, as amended from time to time (the “Original Agreement”).

WHEREAS, Buyer desires to secure to the extent of the quantities and for the period hereinafter stated, a supply of bituminous coal of the quality hereinafter set forth, for use in its

F.B. Culley generating plant (the “Plant”).

WHEREAS, Seller represents that it is experienced in the commercial production and preparation of coal and that it owns, has leased, or controls reserves of bituminous coal with the quality and characteristics as set forth herein.

WHEREAS, Seller desires to sell coal to Buyer, and Buyer desires to buy coal from Seller, upon the terms and conditions hereinafter set forth.

NOW, THEREFORE, in consideration of the premises and the mutual covenants and agreements of the Parties contained herein, the Parties agree as follows:

ARTICLE 1

TERM; SOURCE; TITLE

1.1 Term. Unless terminated earlier or extended in accordance with the terms hereof, the term of this Agreement shall be from the Effective Date through December 31, 2024, inclusive (the “Term”). Notwithstanding the foregoing, Buyer shall have the right, by providing no less than three (3) years prior written notice to Seller (i.e., in the case of the first such extension, by December 31, 2021), to extend the Term of this Agreement by an additional three (3) years, subject to negotiation of the Base Price for any such extension in accordance with Section 3.4, and subject to Seller’s rights pursuant to Section 12.5; provided that Buyer may extend the Term of this Agreement no more than three times.

1.2 Amendment and Termination of Original Agreement. Unless this Agreement is terminated prior to the Effective Date in accordance with Section 12.3, the Parties agree that the Original Agreement shall be amended in accordance with the Termination Agreement entered into by the Parties, as attached hereto as Attachment 1 to this Agreement, which among other things, shall provide for the termination of the Original Agreement as of December 31, 2015.

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.3

1.3 Source. The coal to be sold by Seller and purchased by Buyer under this Agreement shall be mined from coal produced from the Oaktown 1 Mine or the Oaktown 2 Mine (the “Mines”).

1.4 Alternate Supply Sources.

1.4.1 If Seller becomes an affiliate of Sunrise Coal, LLC, an Indiana limited liability company, on or before December 31, 2014, Seller shall have the right to notify Buyer that the coal to be sold by Seller and purchased by Buyer under this Agreement may also be mined from coal properties and reserves at Sunrise Coal, LLC’s Carlisle Mine, located in and around Sullivan County, Indiana, and all references to the “Mines” hereunder shall thereafter be deemed and construed to include the Carlisle Mine, as well as the Oaktown 1 Mine and the Oaktown 2 Mine. Seller’s right to deliver coal mined from the Carlisle Mine under this Agreement shall not be subject to the requirements of Section 1.4.2 but shall arise automatically upon notice to Buyer, subject to the Parties’ agreement on the Carlisle Deduction (as defined below). Within thirty (30) days after Seller becomes an affiliate of Sunrise Coal, LLC, Buyer shall notify Seller if its cost to transport coal from the Carlisle Mine to the Plant differs from the cost to transport coal from the Oaktown 1 Mine and the Oaktown 2 Mine, which transportation cost was assumed to establish the Base Price as stated in Section 3.1.1. Such notice shall include reasonable supporting documentation of the respective transportation costs. Buyer and Seller, each acting in good faith, shall determine the difference between Buyer’s transportation costs for coal transported for: (a) each ton of coal delivered from the Carlisle Mine, and (b) each ton of coal delivered from the Oaktown 1 Mine and the Oaktown 2 Mine (such difference in costs, the “Carlisle Deduction”), and Seller shall apply the Carlisle Deduction to all tons of coal delivered from the Carlisle Mine. To the extent the Carlisle Deduction is different for rail and truck transportation, the Carlisle Deduction for the applicable transportation mode shall be utilized. For purposes of determining the Carlisle Deduction, coal shall be deemed to be transported to the Plant, notwithstanding Buyer’s right to designate alternate locations pursuant to Section 2.8. The Parties shall document the agreed Carlisle Deduction in a writing signed by both Parties. Once the Parties agree on the Carlisle Deduction, the Carlisle Mine shall be deemed to be one of the “Mines” for all purposes hereunder.

1.4.2 In addition, Seller may deliver to Buyer coal conforming to the quality specifications set forth in Exhibit A, from an alternate source (“Alternate Source Coal”), subject to the Parties agreement on the matters contemplated in this Section 1.4.2. If Seller desires to deliver Alternate Source Coal, Seller shall notify Buyer of the location and source of the Alternate Source Coal, and provide Buyer with sample analyses from such alternate source demonstrating that the Alternate Source Coal meets the quality specifications set forth in Exhibit A. If the delivery point for the Alternate Source Coal will be at a location other than any of the Mines, Buyer shall notify Seller if its cost to transport such Alternate Source Coal to the Plant differs from the transportation costs from the Mines. Such notice shall include reasonable supporting documentation of the respective transportation costs for such Alternate Source Coal and for coal delivered at the Oaktown 1 Mine and Oaktown 2 Mine. Buyer and Seller, each acting in good faith, shall determine the difference between Buyer’s transportation costs for: (a) each ton of coal delivered at the Oaktown 1 Mine and the Oaktown 2 Mine, and (b) each ton of coal delivered at the delivery point for such Alternate Source Coal (such difference in costs, the “Alternate Source Deduction”), and Seller shall apply the Alternate Source Deduction to all tons

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.3

of coal delivered at the location of the Alternate Source Coal. To the extent the Alternate Source Deduction is different for rail and truck transportation, the Alternate Source Deduction for the applicable transportation mode shall be utilized. For purposes of determining the Alternate Source Deduction, coal shall be deemed to be transported to the Plant, notwithstanding Buyer’s right to designate alternate locations pursuant to Section 2.8. The Parties shall document the agreed Alternate Source Deduction in a writing signed by both Parties. Once Buyer accepts the Alternate Source Coal and the Parties agree on the Alternate Source Deduction for such Alternate Source Coal, the source of such Alternate Source Coal shall be deemed to be one of the “Mines” for all purposes hereunder.

1.5 Title and Risk of Loss. Title to the coal and risk of loss thereof shall transfer from Seller to Buyer upon loading for shipment of the coal into railcars or trucks, as applicable, at the Mine. As between the Parties, Seller shall be deemed to be in exclusive control (and responsible for any damages or injury caused thereby) of the coal prior to its being loaded for shipment at the Mine, and Buyer shall be deemed to be in exclusive control (and responsible for any damages or injury caused thereby) of the coal from the time it is loaded for shipment at the Mine.

ARTICLE 2

CONTRACT QUANTITY

2.1 Base Tonnage. Seller agrees to deliver to Buyer, and Buyer agrees to accept from Seller, the total quantity of coal as set forth below in each Contract Year during the Term. A Contract Year shall commence on January 1st and end on December 31st.

Contract YearBase Tonnage 2015 150,000 tons

2016 – 2024 1,000,000 tons

2.2 Annual Tonnage Adjustment. For each Contract Year beginning in 2015, Buyer may elect to increase or decrease the Base Tonnage (as described in Section 2.1) for such Contract Year by an amount of up to [**] of the Base Tonnage for such Contract Year. If Buyer desires to increase or decrease the Base Tonnage for a Contract Year, Buyer shall provide written notice of such election to Seller on or before June 30th of the Contract Year preceding the Contract Year for which the Base Tonnage will be adjusted. If Buyer fails to provide such notice for any Contract Year, the Base Tonnage for such Contract Year shall be the Base Tonnage as set forth in Section 2.1.

2.3 Quarterly Tonnage Adjustments. Beginning in the first quarter of 2015 and for the remainder of the Term, Buyer may elect to increase or decrease the Base Tonnage to be delivered in a calendar quarter by an amount of up to [**] of the Base Tonnage to be delivered in such calendar quarter. Buyer shall provide written notice to Seller of such election on or before the date that is 30 days before the first day of such calendar quarter. For the purposes of this Section 2.3, if Buyer has increased or decreased the Base Tonnage for a given Contract Year pursuant to Section 2.2, the Base Tonnage subject to adjustment in each calendar quarter in such Contract Year shall be the Base Tonnage as adjusted pursuant to Section 2.2.

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[**] REPRESENTS CONFIDENTIAL MATERIAL OMITTED AND FILED SEPARATELTY WITH THE SECURITIES

AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.3

2.4 Scheduled Outages. For each Contract Year beginning in 2015 in which Buyer has scheduled outages for the Plant or a generating unit at the Plant, Buyer may by written notice to Seller on or before June 30th of the Contract Year preceding the Contract Year in which such scheduled outages will occur, decrease the monthly quantity of coal that would otherwise be delivered hereunder during such scheduled outage by up to [**]; provided that the maximum period of time for which Buyer may decrease the monthly quantity of coal pursuant to this Section 2.4 shall not exceed [**] in such Contract Year. Buyer’s notice of such decrease may include Buyer’s preference as to when the quantities of coal that are not delivered during such outage should otherwise be delivered, which may be prior to or after such outage; provided that delivery of such coal shall in any event be on a mutually agreeable delivery schedule.

2.5 Tonnage Adjustment due to De-Rating. If any legislative, regulatory, administrative or other governmental bodies, or any court with jurisdiction, enacts, adopts or imposes new laws, rules or regulations, amends existing laws, rules or regulations, or reinterprets existing laws, rules or regulations, that require Buyer to de-rate the Plant, Buyer may, by written notice to Seller, reduce the Base Tonnage hereunder; provided that such reduction shall be imposed on a pro-rata basis among all of Buyer’s coal suppliers to the Plant, based on the number of tons of coal that Buyer is obligated to receive from its committed suppliers, to the extent that its contracts with other suppliers give Buyer the right to reduce its purchase obligations as a result of such new or amended laws, rules or regulations, or reinterpretation. In the event Buyer is later able to increase operations at the Plant during the Term of this Agreement after such notice has been given, the Base Tonnage hereunder shall be increased, not to exceed the Base Tonnage as stated in Section 2.1, plus any annual and quarterly adjustments to the Base Tonnage pursuant to Section 2.2 and Section 2.3, as applicable; provided that any increase in the number of tons of coal required by Buyer for operation of the Plant shall be allocated on a pro-rata basis among Buyer’s committed coal suppliers to the Plant in the same fashion as the decrease in coal was allocated.

2.6 Delivery. Coal shall be delivered F.O.B. railcar or truck (as elected by Buyer) at any of Seller’s Mines (as elected by Seller), in substantially equal monthly quantities on a mutually agreeable delivery schedule. Seller will coordinate loading at the Mines with Buyer and Buyer’s relevant carriers.

2.7 Shipments. As used herein, a “Shipment” of coal supplied under this Agreement shall refer to all coal delivered by truck in a given day, or all coal delivered by a single train of railcars.

2.8 Transportation. Buyer shall be solely responsible for transportation of the coal from the Mines to the Plant, including providing railcars or trucks, as Buyer elects, for loading at the Mines. Buyer may, in its sole discretion, direct any coal delivered hereunder to any of Buyer’s or its affiliate’s power generating stations other than the Plant; provided that Buyer shall be responsible for all additional transportation costs associated with such election. Buyer’s right to direct coal to a power generating station other than the Plant shall in no way be construed as an obligation to do so under any circumstance.

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.3

2.9 Monthly Shipping Schedule. On or before the 15th day of each calendar month during the Term, Buyer shall notify Seller of the expected schedule of shipments by railcar and by truck to be made during the following calendar month. On or before the 25th day of each month during the Term, the Parties shall mutually determine a delivery schedule for the following month, including whether shipments will be by rail or by truck, and the daily schedule for delivery of the coal.

ARTICLE 3

PRICING

3.1 Base Price.

3.1.1 The price per ton (2000 pounds) of coal sold by Seller hereunder (the “Base Price”) shall be determined in accordance with this Article 3. The Base Price for Contract Year 2015 shall be [**].

3.1.2 As of January 1st of each Contract Year thereafter, until the Base Price is re-set in accordance with Section 3.4, the Base Price shall be increased by [**] over the Base Price in effect during the prior Contract Year. After the Base Price is re-set in accordance with Section 3.4, the Base Price for each successive Contract Year thereafter shall be increased by [**] over the Base Price in effect during the prior Contract Year until the Base Price is re-set again in accordance with Section 3.4.

3.2 BTU Adjustment.

3.2.1 The Base Price for each ton of coal sold and purchased hereunder during a calendar month shall be adjusted based on the monthly weighted average of the actual BTU/lb of all tons delivered in such calendar month under this Agreement (the “BTU Adjustment”). The BTU Adjustment shall be determined according to the following formula:

BTU Adjustment = ((Actual BTU/lb Value / Guaranteed BTU/lb Value) x (Base Price)) – Base Price Where the Guaranteed BTU/lb Value = 11,000 Btu/Lb

The aggregate BTU Adjustment for a calendar month shall be equal to the total tons delivered in such calendar month, multiplied by the BTU Adjustment. If the BTU Adjustment is a negative value, the BTU Adjustment shall be payable from Seller to Buyer, and if the BTU Adjustment is a positive value, the BTU Adjustment shall be payable from Buyer to Seller. The aggregate BTU Adjustment to be paid with respect to a calendar month shall be included in the first invoice delivered by Seller in the calendar month immediately following the calendar month for which such BTU Adjustment applies.

3.2.2 Subject to Buyer’s rights under Section 4.3, the Base Price adjustments as described in this Section 3.2, shall be Buyer’s sole and exclusive remedy at law or in equity for the failure of coal sold hereunder to meet the quality specifications with respect to BTU/lb.

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.3

3.3 Other Price Adjustments.

3.3.1 The Parties recognize that legislative, regulatory, administrative or other governmental bodies or the courts may impose new laws, rules or regulations, amend existing laws, rules or regulations, or reinterpret existing laws, rules or regulations, including, without limitation, procedural instruction letters issued by MSHA after June 2, 2014 (the “Initial Price Date”), or as applicable, after the date of determination of a Market Adjusted Base Price (such new laws, amendments or reinterpretations, a “Change in Law”), that may increase Seller’s cost of mining coal from the Mines. Without limiting the generality of the foregoing, the implementation after the Initial Price Date of MSHA rule 79 FR 24813 “Lowering Miners’ Exposure to Respirable Coal Mine Dust, Including Continuous Personal Dust Monitors” as adopted on May 1, 2014, shall be deemed to be a Change in Law for purposes of this Agreement, notwithstanding the adoption of such rules prior to the Initial Price Date. A Change in Law shall not in any event include any change in Governmental Impositions (as defined below).

(a) If a Change in Law that affects Seller’s cost of mining occurs after the Initial Price Date, or as applicable, after the date that a Market Adjusted Base Price is determined, Seller shall give notice to Buyer indicating the related increase in the then-current Base Price (or the relevant Market Adjusted Base Price, as applicable) and shall provide to Buyer reasonable documentation of the proposed increase in the Base Price.

(b) If the proposed increase in the Base Price (or the relevant Market Adjusted Base Price, as applicable) is less than or equal to [**] of the then-current Base Price (or the relevant Market Adjusted Base Price, as applicable), the then-current Base Price (or the relevant Market Adjusted Base Price, as applicable) shall be adjusted as of the effective date of such Change in Law by an amount equal to the proposed increase, subject to Buyer’s right to dispute in good faith the existence of a Change in Law or the amount of the proposed price increase. Accordingly, the adjustment to the then-current Base Price (or the relevant Market Adjusted Base Price, as applicable) pursuant to this Section 3.3.1 may be applied retroactively.

(c) If the proposed increase in the Base Price (or the relevant Market Adjusted Base Price, as applicable) is greater than [**] of the then-current Base Price (or the relevant Market Adjusted Base Price, as applicable), then, subject to Buyer’s right to dispute in good faith the existence of a Change in Law or the amount of the proposed price increase, (i) the then-current Base Price shall be increased as of the effective date of such Change in Law to an amount equal to [**] of the initial Base Price in the three (3) year period in which such increase occurs, excluding the annual escalation pursuant to Section 3.1.2, and (ii) if applicable, the relevant Market Adjusted Base Price shall be adjusted by an amount equal to [**] of the relevant Market Adjusted Base Price. Accordingly, the adjustment to the then-current Base Price (or the relevant Market Adjusted Base Price, as applicable) pursuant to this Section 3.3.1 may be applied retroactively.

(d) Except to the extent described in Section 3.3.1(c), no adjustments to the then-current Base Price (or the Market Adjusted Base Price, as applicable) shall be made with respect to Seller’s increased costs for mining that have already been applied to the then-current Base Price or that have been taken into account and quantified during negotiations to determine a Market Adjusted Base Price pursuant to Section 3.4.

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.3

3.3.2 “Governmental Imposition” means taxes or fees imposed by any federal, state or local government or government agency upon the production, severance, preparation or sale of Coal hereunder, including, but not limited to, the Federal Black Lung Excise Tax, severance taxes on Coal produced or sold hereunder, reclamation fees assessed by the US government or the State of Indiana. The term does not include impositions such as generally applicable taxes including federal or state income taxes; employee benefits or payroll taxes such as employer’s Social Security, unemployment or worker’s compensation taxes or payments, or any civil or criminal money fine or penalty imposed as the result of failure to comply with any Law. Buyer shall not be entitled to any adjustment in connection with any benefit derived by Seller for any incentives granted by the U.S. government or the State of Indiana for coal production or investment in coal properties within the State of Indiana.

(a) The Parties shall adjust the then-current Base Price (or the relevant Market Adjusted Base Price, as applicable) by an amount equal to changes in Seller’s costs per ton of coal sold hereunder that are caused directly by increased or decreased Governmental Impositions enacted or imposed after the Initial Price Date, or as applicable, after the date of determination of a Market Adjusted Base Price. Seller shall give prompt notice to Buyer of the amount of any such increased or decreased cost per ton of coal sold hereunder incurred by reason of such a change in Governmental Imposition (including implementation of new Governmental Impositions), along with reasonable documentation of such amounts. The adjustment to the Base Price pursuant to this Section 3.3.2 may be applied retroactively to the date on which such new or changed Government Imposition was first applied to Seller or its operations.

(b) In the event of an increase in cost, such notice from Seller shall also include the increase in the then-current Base Price (or the relevant Market Adjusted Base Price, as applicable) that Seller will require, which increase may not exceed the actual increase in Seller’s costs due to such Governmental Impositions. In the event of a decrease in cost, the then-current Base Price (or the relevant Market Adjusted Base Price, as applicable) will be decreased by an amount equal to the decrease in Seller’s costs caused by Governmental Impositions enacted or changed after the then-current Base Price became effective, or the date of determination of a Market Adjusted Base Price. Adjustments due to Governmental Impositions as described in this Section 3.3.2 shall be subject to Buyer’s right to dispute in good faith the existence of a Governmental Imposition or the amount of the proposed adjustment.

3.3.3 Seller shall follow generally accepted accounting principles (GAAP) as historically applied by Seller in determining its costs related to any Change in Law or Governmental Imposition, and shall provide Buyer with documentation reasonably demonstrating that the increase or decrease in cost is incremental to the costs already included in the Base Price.

3.4 Market Price Adjustments.

3.4.1 Beginning with the 2016 Contract Year, and again upon the expiration of a three (3) year period beginning on January 1st of such Contract Year, and upon the expiration of each three (3) year period thereafter, the Parties shall adjust the Base Price to reflect then-current market prices for similar quality coal meeting the quality specifications set forth in Exhibit A and sold for delivery the following year (the “Market Adjusted Base Price”). The Parties shall follow

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.3

the procedures described below to determine the adjusted Base Price. If the Parties agree on a Market Adjusted Base Price, the Market Adjusted Base Price shall become effective and shall be the “Base Price” as described in Section 3.1 for all purposes hereunder as of January 1st of the first Contract Year of the relevant three (3) year period. The Market Adjusted Base Price shall include all adjustments to the Base Price made pursuant to Section 3.3 prior to the date that such Market Adjusted Base Price is determined. If any adjustments to the Base Price made pursuant to Section 3.3 occur after the date on which the Market Adjusted Base Price is determined, but before the date on which the Market Adjusted Base Price becomes effective, such adjustments shall also be applied to the Market Adjusted Base Price as of the date on which the Market Adjusted Base Price becomes effective.

3.4.2 The Parties shall begin negotiations to determine the Market Adjusted Base Price on or before April 1st of the Contract Year prior to the Contract Year in which the Market Adjusted Base Price will become effective pursuant to Section 3.4.1. The Parties shall negotiate in good faith to agree to the Market Adjusted Base Price.

3.4.3 If the Parties fail to reach agreement on the Market Adjusted Base Price by May 31st of the Contract Year prior to the Contract Year in which the Market Adjusted Base Price will become effective pursuant to Section 3.4.1, on or before June 5th of such Contract Year, Seller and Buyer shall each provide the other Party with information relating to contracts for the sale or purchase of coal, as applicable, that such Party has negotiated since January 1st of the Contract Year prior to the Contract Year in which negotiations are occurring. Such information provided by the Parties shall: (a) (i) as to information provided by Seller, be with respect to the sale of coal produced by the Mines and with a term of at least twelve (12) months beginning on or after January 1st of the prior Contract Year, and (ii) as to information provided by Buyer, be with respect to the purchase of coal for use at the Plant and with a term of at least twelve (12) months beginning on or after January 1st of the prior Contract Year; (b) to the extent allowed under the applicable contract, include copies of contracts entered into by such Party, redacted to exclude any identifying information as to the counterparty to such contract; and (c) include a summary of the relevant terms with respect to quantity, quality specifications and pricing of each contract where a Party is unable to provide a redacted copy of such contract due to restrictions imposed on such Party pursuant to such contract (it being understood that the Parties shall use commercially reasonable efforts to obtain the right to provide redacted copies of such contracts as contemplated herein). In the absence of the occurrence of sufficient transactions since January 1st of the Contract Year prior to the Contract Year in which negotiations are occurring, the Parties may rely upon other relevant market information to establish market prices to determine the Market Adjusted Base Price. Buyer and Seller shall have the right to have an independent auditor or consultant review the confidential information provided by the Parties pursuant to this Section 3.4.3, subject to a Party’s independent auditor or consultant having entered into a customary confidentiality agreement with the other Party prior to disclosure of any confidential information to such independent auditor or consultant.

3.4.4 If the Parties fail to reach agreement on the Market Adjusted Base Price by June 30th of the Contract Year prior to the Contract Year in which the Market Adjusted Base Price will become effective pursuant to Section 3.4.1, either Party may, by notice to the other Party, elect to begin binding arbitration proceedings to establish the Market Adjusted Base Price. Upon receipt of such notice, the Parties shall select a single neutral, independent arbitrator who

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.3

is familiar with coal markets and coal market pricing. If the Parties fail to select an arbitrator within thirty (30) days of receipt of such notice, the Parties shall follow the process recommended by the American Arbitration Association to select a single, neutral, independent arbitrator who is familiar with coal markets and coal market pricing. Within thirty (30) days after the selection of the neutral arbitrator, the Parties shall each submit to the arbitrator and to the other Party, such Party’s proposed Market Adjusted Base Price and all reasonable supporting documentation demonstrating the basis on which the proposed Market Adjust Base Price was determined. Within fifteen (15) days after the initial submission of the proposed Market Adjusted Base Prices, the Parties shall each submit any rebuttal to the other Party’s proposed Market Adjusted Base Price, to the arbitrator and to the other Party. Within thirty (30) days after the submission of any rebuttals, or the last day of the fifteen (15) day period in which to submit rebuttals if no rebuttals are submitted, the arbitrator shall select the Market Adjusted Base Price proposed by one of the Parties as the Market Adjusted Base Price for the following Contract Year for the purposes of this Agreement, and shall notify the Parties in writing of the Market Adjusted Base Price that has been selected by the arbitrator. The arbitrator shall not have any authority to select any Market Adjusted Base Price other than the proposed Market Adjusted Base Price submitted by one of the Parties, and shall select the proposed Market Adjusted Base Price that most closely represents the arbitrator’s determination of the current market price of similar quality coal in the same market and sold under substantially similar terms and conditions.

3.4.5 Any information or documents exchanged or produced during the process of negotiating the Market Adjusted Base Price as described in this Section 3.4, including during any arbitration proceeding, and including any redacted contracts, summaries, or briefs or other documents prepared for the arbitration, shall be confidential and shall not be disclosed by the Parties, their employees, officers, directors, counsel, consultants, auditors or expert witnesses, as applicable, except to a court of relevant jurisdiction and then only to the extent necessary to enforce this Section 3.4 or any arbitration award, or as required by applicable laws or the rules of any stock exchange applicable to the Party making such disclosure, or in the case of Buyer to the Indiana Utility Regulatory Commission (the “IURC”). If a Party is required to disclose any such information or documents, such Party shall notify the other Party of the need to make such disclosure as soon as applicable and shall seek confidential treatment, and cooperate with the other Party in seeking confidential treatment, of any information that is disclosed.

ARTICLE 4

COAL QUALITY SPECIFICATIONS

4.1 Quality Specifications. The coal supplied under this Agreement shall meet the quality specifications set forth in Exhibit A on an “as received” basis.

4.2 Impurities. The coal supplied under this Agreement shall be washed coal, crushed to two inch (2") maximum top size, and shall be substantially free of impurities, such as bone, slate, rock, wood, metal and other mine debris.

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.3

4.3 Rejection; Suspension.

4.3.1 If based on the sampling and analysis described herein, the coal in a Shipment fails to comply with the Reject limits as set forth in Exhibit A for any one or more of the quality specifications identified therein, Buyer shall have the right, but not the obligation, to reject such Shipment by notice delivered to Seller by fax or email. In addition, Buyer shall have the right to reject any coal containing bone coal, rock, wood, metal or other mine debris in quantities which Buyer believes, in the exercise of Buyer’s good faith judgment, could be harmful to the Plant.

(a) In the event Buyer rejects any coal, Buyer shall promptly notify Seller of such rejection, such notice to be delivered within 48 hours of Buyer’s receipt of the short proximate analysis for the Shipment if rejection is based on the Shipment having exceeded any of the Reject limits as described in this Section 4.3, or within 24 hours of receipt of the Shipment at the Plant (or other destination designated by Buyer hereunder) if the rejection is based on the Shipment being contaminated with foreign materials. Buyer may reject discrete portions of a Shipment for foreign materials if practical under the circumstances.

(b) If Buyer fails to timely exercise its rights to reject a Shipment under this Section 4.3, Buyer shall be deemed to have waived such rights with respect to rejection of that Shipment only. Buyer’s failure to reject one or more Shipments under this Section 4.3 shall in no way affect its right to reject future Shipments or demand Seller’s strict performance with the requirements of this Section 4.3. If Buyer timely rejects a Shipment under this Section 4.3, Seller and Buyer shall cooperate in good faith to find an acceptable means for Seller to cure the problem so that Buyer can use such coal in the Plant. If the Parties are unable to find an acceptable means of curing the problem, Seller shall be responsible for promptly transporting the rejected coal to an alternative destination determined by Seller, at Seller’s cost, and the rejected coal shall not apply toward the Base Tonnage. In addition, Seller shall be responsible to reimburse Buyer for all reasonable out-of-pocket costs and expenses incurred by Buyer for the transportation of the rejected coal to the Plant. It is understood that Buyer shall not arbitrarily change its equipment in any way as to prevent Buyer from accepting coal and that Seller shall not arbitrarily change its mining, preparation, or loading operations in any way that would provide Buyer with an incentive to not accept the coal delivered by Seller hereunder.

(c) Seller shall, at Buyer’s option, replace the rejected coal as soon as possible, provided that Buyer gives notice to Seller of Buyer’s desire for replacement coal within 48 hours after rejection of a Shipment (or a part thereof).

4.3.2 Regardless of whether Buyer has actually exercised its right to reject any Shipments pursuant to Section 4.3.1: (i) if the coal delivered by Seller, as measured by the weighted average of all short proximate analyses in a given calendar month or the Monthly Composite Analysis (as defined in Section 6.2), fails to meet any of the monthly weighted average (“MWA”) quality specifications for [**] (other than with respect to the BTU/lb specification, for which Buyer’s sole remedy for failure of the coal to meet the MWA quality specification shall be the BTU Adjustment as provided in Section 3.2), or (ii) if in any thirty (30) day period, two (2) Shipments by railcar, or six (6) Shipments by truck, fail to comply with the Reject limits as

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.3

set forth in Exhibit A for any one or more of the quality specifications identified therein, as measured by the short proximate analysis, Buyer may by written notice to Seller suspend any further Shipments other than those already loaded into trucks or railcars; provided that in the case of a partially loaded train, Seller shall finish loading the railcars in such train.

(a) Within thirty (30) days after receipt of Buyer’s suspension notice pursuant to Section 4.3.2, Seller shall provide Buyer with reasonable assurances that subsequent deliveries of coal hereunder will meet the quality specifications on a MWA basis, and that subsequent Shipments of coal will comply with the Reject limits as set forth in Exhibit A for each of the quality specifications identified therein. In providing such assurances, Seller shall provide a reasonably detailed explanation for its failure to deliver coal that complies with the quality specifications as set forth in Exhibit A, and a reasonably detailed description of the remedial actions that Seller will undertake in support of its assurances. Buyer shall promptly review such assurances and respond to Seller within ten (10) days after receipt of such assurances. In reviewing the assurances provided by Seller, Buyer shall act in good faith and shall not unreasonably withhold acceptance of Seller’s assurances, or unreasonably delay the resumption of delivery of coal hereunder if such assurances are accepted. Buyer may require Seller to make-up deficiencies in the Base Tonnage for a Contract Year resulting from any such suspensions, subject to Seller’s right to dispute the validity and circumstances of such suspension, on a delivery schedule mutually agreed by the Parties.

(b) If Seller fails to provide assurances within the thirty (30) day period provided in Section 4.3.2(a) that are reasonably acceptable to Buyer, acting in good faith, Buyer may, in its sole discretion, terminate this Agreement by written notice to Seller.

(c) If Buyer terminates this Agreement pursuant to this Section 4.3, Seller shall reimburse Buyer the positive difference, if any, between (i) the purchase price and transportation costs on a cents per million BTU basis as transported to the Plant (without regard to Buyer’s right to designate alternate locations pursuant to Section 2.8) incurred by Buyer for Replacement Coal, and (ii) the sum, on a cents per million BTU basis, of the Base Price and transportation costs that Buyer incurs for transportation of the coal delivered hereunder to the Plant for each ton of coal remaining as of the date of termination to be delivered to Buyer hereunder during the Current Term (without regard to Buyer’s rights to increase the Base Tonnage pursuant to Section 2.2 or Section 2.3, other than increases for the relevant periods that have been declared by Buyer by written notice to Seller prior to the date of Buyer’s suspension notice pursuant to Section 4.3.2(a)). For purposes of this Agreement, the “Current Term” means, as applicable, the period beginning on the Effective Date and ending on December 31, 2015 if the Contract Year in which this Agreement is terminated occurs during such period, or the three (3) year period beginning on January 1, 2016 or any subsequent three (3) year period thereafter during the Term if the Contract Year in which this Agreement is terminated occurs during such three (3) year period. For purposes of this Agreement, “Replacement Coal” means, to the extent reasonably available, coal having similar quality specifications purchased under similar terms and conditions as this Agreement (excluding Buyer’s rights to extend the Term hereunder) that Buyer purchases, in an amount not to exceed the Base Tonnage (without regard to Buyer’s rights to increase the Base Tonnage pursuant to Section 2.2 or Section 2.3, other than increases for the relevant periods that have been declared by Buyer by written notice to Seller prior to the date of Buyer’s suspension notice pursuant to Section 4.3.2(a)) remaining as of the date of termination to

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.3

be delivered to Buyer hereunder during the Current Term; provided, however that any reasonable good faith purchase of coal to address Buyer’s short-term (i.e., 6 months or less) needs associated with a termination of this Agreement shall be considered Replacement Coal. Buyer shall use commercially reasonable attempts to acquire Replacement Coal at the lowest cost possible and shall take other reasonable steps to mitigate its damages, and shall provide reasonable documentation to Seller of the costs incurred. Payment of amounts, if any, determined under this Section 4.3.2(c) shall be made within 10 days following receipt of notice from Buyer of amounts owed.

4.3.3 OTHER THAN THE BTU ADJUSTMENT AS DETERMINED IN ACCORDANCE WITH SECTION 3.2, THE RIGHTS AND OBLIGATIONS OF THE PARTIES AS SET FORTH IN THIS SECTION 4.3 SHALL BE SELLER’S SOLE OBLIGATIONS AND BUYER’S SOLE AND EXCLUSIVE REMEDY AT LAW OR IN EQUITY FOR THE FAILURE OF COAL SOLD HEREUNDER TO MEET ONE OR MORE OF THE QUALITY SPECIFICATIONS AS SET FORTH IN EXHIBIT A.

4.4 Freeze Treatment Agent. Buyer shall have the right to require Seller to apply a freeze-treatment chemical agent to the coal delivered hereunder, and to the sides of railcars being used to transport the coal (collectively, “Freeze Treatment”). On or before November 1st of each year, Seller shall notify Buyer of the type of chemical agent to be used in the Freeze Treatment, the manufacturer of the chemical agent, and the cost per gallon of the chemical agent that will be used by Seller, and shall provide Buyer with a copy of the MSDS sheet of such chemical agent. Buyer shall provide Seller with reasonable advance notice of the dates for starting and ending the Freeze Treatment, and the temperature to which Buyer requests Freeze Treatment (e.g., 10°F below the expected low temperature), for Seller’s use in determining application rates. Seller shall invoice Buyer monthly in accordance with Section 7.1 for the cost of the Freeze Treatment provided by Seller, which shall be equal to (a) (i) Seller’s actual cost per gallon for the chemical agent used, multiplied by (ii) the gallons of chemical agent applied to each Shipment of coal hereunder during the prior calendar month, plus (b) an application fee of [**] of the total cost determined pursuant to subparagraph (a) of this Section 4.4.

ARTICLE 5

WEIGHING

5.1 Weighing. Determination of weights of coal delivered hereunder for payment purposes shall be based on weights obtained at the Mines. Coal shipped by railcar shall be weighed at the relevant Mine on a certified batch weigh load out system. Coal transported by truck shall be weighed at the relevant Mine by Seller’s certified truck scales.

5.2 Scales. All scales referred to herein shall be operated and maintained to be in conformance with the National Institute of Standards and Technology (NIST) Handbook 44, or the applicable Standards of the Association of American Railroads (AAR). Seller shall provide copies of all scale certification test reports to Buyer upon request. Seller shall promptly notify Buyer if Seller believes its scales have experienced a failure or are unavailable, or are inaccurate.

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.3

5.3 Unavailability; Inaccuracies.

5.3.1 If weights from Seller’s scales are not available for a Shipment due to failure, mechanical or otherwise, of Seller’s scales, or if Seller has determined that its scales are inaccurate, weights for such Shipments will be obtained from Buyer’s scales and the weights so determined shall be the governing weights for payment purposes; provided that Buyer’s scales shall be certified and maintained in accordance with the standards as referenced in Section 5.2. For rail shipments, if no other weights are available, the average per car weight of the previous three train deliveries shall be the weight used for payment purposes.

5.3.2 If either Party believes the other Party’s scales to be in error beyond acceptable tolerance, that Party shall notify the other of such discrepancy and its apparent duration as soon as practicable, and the Party owning or controlling the scale in question shall have such scale tested for accuracy. The other Party shall have the right to be present during such test. Should such test reveal an inaccuracy which exceeds permitted tolerances, the weights from the time first stated in the notice until the testing and calibration of such scales shall be adjusted by the percentage of inaccuracy discovered by such testing.

ARTICLE 6

SAMPLING AND ANALYSIS

6.1 Sampling. Coal samples to be used for determination of coal quality for coal delivered to Buyer hereunder shall be taken by Seller at the Mine in conformance with applicable American Society for Testing Materials (“ASTM”) standards. For deliveries by truck, governing coal samples shall be a representative composite of trucks loaded daily, taken by Seller at the Mine using sampling methods in accordance with applicable ASTM standards, or by use of such other methods as may be mutually agreed upon by the Parties. For coal delivered by rail car, governing coal samples shall be obtained using an automatic sampling system in accordance with methods approved by the ASTM or such other methods as may be mutually agreed upon by the Parties. Each calendar month, Seller shall collect a composite sample representative of the coal delivered in that particular month (the “Monthly Composite Sample”) for the purpose of preparing a Monthly Composite Analysis, as defined in Section 6.2 below.

6.2 Analysis. For purposes of this Agreement, the governing analysis of coal samples collected by Seller shall be performed by Standard Laboratories in Evansville, Indiana. All governing analyses performed shall be done in accordance with ASTM standards. Seller shall direct Standard Laboratories to conduct a short proximate analysis of such coal samples and provide the results of such analysis to Buyer at the same time that such results are provided to Seller. If Standard Laboratories fails to deliver any such analytical results to Buyer, Seller shall deliver a copy of such analytical results to Buyer as soon as possible after Buyer’s request. Seller shall or shall cause Standard Laboratories to also provide quick analyses to Buyer for each Shipment. Seller shall use commercially reasonable efforts to cause Standard Laboratories to provide the results of its quick analysis within twenty four (24) hours of delivery of the Shipment, or as soon as reasonably practicable. Each calendar month, Seller shall direct Standard Laboratories to analyze the [**] (as set forth in Exhibit A) of the Monthly Composite Sample (the “Monthly Composite Analysis”), which

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.3

Standard Laboratories shall provide to Seller and Buyer as soon as reasonably practicable. If Buyer requires monthly analysis of any of the other quality specifications set forth on Exhibit A, Buyer shall provide Seller with reasonable advance notice and Seller shall direct Standard Laboratories to perform the relevant analyses for such additional specifications as part of the Monthly Composite Analysis for that particular month. Not more than once every six calendar months, Buyer may request, and Seller shall cause Standard Laboratories to conduct, a Full Proximate Analysis of the Monthly Composite Sample and such analysis shall be treated as the Monthly Composite Analysis for that particular month. Seller shall require Standard Laboratories to retain samples for thirty (30) days after such results are submitted to Seller, during which period Buyer may request from Seller a split of such samples for purposes of conducting its own analyses. If Buyer does not give Seller notice within such thirty (30) day period that, based on analysis of such split by Buyer, Buyer disagrees with Seller’s analysis, then Seller’s analysis shall apply to all of the Coal in the Shipment from which the sample was taken and shall be the binding basis for any BTU Adjustments and for the exercise of Buyer’s rights to reject coal pursuant to Section 4.3. Buyer’s notice of disagreement with the analyses received from Standard Laboratories, if any, shall be accompanied by the results of Buyer’s analysis. If the Parties cannot reach agreement on the analysis within thirty (30) days following Seller’s receipt of Buyer’s notice, the dispute shall be settled by an analysis performed by a commercial testing laboratory mutually agreed upon by the Parties, and the results of those tests shall be final and binding on the Parties. In the event of a dispute, the cost of the analysis made by such commercial testing laboratory shall be shared equally by the Parties. Until such dispute is resolved, Buyer shall be responsible for payment based on the results of Seller’s analysis.

6.3 Alternatives. In the event that a Shipment of coal is not sampled at a Mine, or a sample is lost or has obviously been contaminated, Seller shall notify Buyer as promptly as practicable. Unless the Parties agree on an alternate sampling method, analytical results obtained from the weighted average quality of the three (3) previous Shipments to Buyer from such Mine will be used as representative of the quality of the Shipment not sampled at such Mine.

ARTICLE 7

INVOICING AND PAYMENT

7.1 Invoicing. Seller will prepare and submit invoices to Buyer via e-mail twice each calendar month. Seller shall submit one invoice to Buyer on or before the fifth (5th) day of each calendar month, which invoice shall include the coal delivered during the period from the sixteenth (16th) day of the prior calendar month to the last day of the prior calendar month, plus any BTU Adjustment for the prior calendar month as determined in accordance with Section 3.2, plus any Freeze Treatment costs for Shipments made during the prior calendar month determined in accordance with Section 4.4, plus any applicable Carlisle Deduction or Alternate Source Deduction determined in accordance with Section 1.4. Seller shall submit one invoice to Buyer on or before the twentieth (20th) day of each calendar month, which invoice shall include the coal delivered during the period from the first (1st) day of such calendar month to the fifteenth (15th) day of such calendar month, plus any applicable Carlisle Deduction or Alternate Source Deduction determined in accordance with Section 1.4.

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.3

7.2 Payment. Payment with respect to each invoice submitted by Seller hereunder shall be due no later than ten (10) days after Buyer’s receipt of such invoice. All payments will be made by ACH wire transfer of immediately available funds to the bank account as shown on Seller’s invoice.

7.3 Offset. If each Party is required to pay an amount to the other Party in the same month, then such amounts with respect to each Party shall be aggregated and the Parties shall discharge their obligations to pay through netting; in which case, the Party owing the greater aggregate amount shall pay to the other Party the difference between the amounts owed.

ARTICLE 8

FORCE MAJEURE

8.1 Impact of Force Majeure. If because of a Force Majeure Event, either Party is unable to carry out any of its obligations under this Agreement (other than any obligation to pay or expend money in connection with performance hereunder), and provided such Party promptly gives notice to the other Party of the existence of any such Force Majeure Event, then the obligations of the Party affected by such Force Majeure Event (other than any obligation to pay or expend money in connection with performance hereunder) shall be suspended to the extent made necessary by such Force Majeure Event and during its continuance, provided that the Party subject to such Force Majeure Event shall make all reasonable efforts to mitigate the impact of the Force Majeure Event and remove it with all reasonable dispatch.

8.2 Force Majeure Event. A “Force Majeure Event” as used herein means any cause beyond the reasonable control of the Party affected thereby, including but not limited to: acts of God, acts of the public enemy, insurrections, riots, terrorism, labor disputes, strikes, lockouts, boycotts, labor and material shortages, fires, explosions, landslides, earthquakes, storms, roof falls, rib falls, cave-ins, floods, aquifers, floor conditions, breakdowns of or damage to equipment or facilities, interruptions to transportation or shortages of transportation equipment, embargoes, blockades, acts of military authorities, inability to obtain permits or authorization from any government authority, any laws, orders, rules, regulations, enforcement proceedings or other acts or restraint of governmental authority, unexpected mining conditions including unforeseen changes in the coal seam, or faults or sandstone intrusions in the coal seam, and other cause including unsafe working conditions, or unscheduled outages and other unexpected disruptions at the Plant that exceed seven (7) days in duration, whether of the kind or character herein enumerated or otherwise, which is not within the control of the Party claiming excuse, whether or not foreseen or foreseeable, which wholly or partly renders the mining removal, processing or loading of all or part, of the normal output of the Mines impractical or unfeasible, or renders the accepting, utilizing, unloading, or intended use of the coal impossible, impractical or unfeasible, and which are not caused by acts or omissions of the Party failing to perform. Settlement of labor disputes shall be deemed beyond the control and without the fault or negligence of the Party experiencing such event. Seller’s ability to sell coal at a more advantageous price, Buyer’s ability to buy coal at a more advantageous price, or the change in the market price of coal, price of power, or other related costs, shall not constitute a Force Majeure Event.

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.3

8.3 Mitigation. Prior to deeming any legislation or regulation a Force Majeure Event, the Parties shall consider what steps can be taken by Buyer in the handling, transportation and use of the coal, or by Seller in the production, processing, preparation and loading of the coal. If no such practicable solution to the problem is presented by either Party, such legislation or regulation may constitute a Force Majeure Event. A Force Majeure Event shall not in any event include a lack of sufficient financial means to perform obligations or the failure to make payments in accordance with this Agreement. During the continuation of a Force Majeure Event, the other Party may make arrangements to sell or purchase the estimated quantity of coal so affected for the estimated duration of the Force Majeure Event.

8.4 Make-Up. In the event that a Force Majeure Event occurs, the delivery of the affected quantity of coal shall be made up by the Parties during the Contract Year in which such Force Majeure Event occurred, unless not reasonably practicable, in which case the delivery of the affected quantity of coal shall be made-up as soon as practicable in the following Contract Year; provided that coal delivered in the following Contract Year shall be applied first to make-up deliveries affected by a Force Majeure Event. Coal delivered pursuant to this Section 8.4 shall be delivered on a delivery schedule agreed to by the Parties, and the Base Price to be paid by Buyer for coal delivered pursuant to this Section 8.4 shall be the Base Price in effect when the applicable Force Majeure Event occurred.

8.5 Allocation in Event of Partially Reduced Capability. If a Force Majeure Event occurs and results in, or is reasonably projected to result in: (i) a reduction or limitation of Seller's ability to supply coal from a Mine, or (ii) the inability of Buyer to accept or utilize coal at the Plant, then in the case of Seller, Seller shall allocate available supplies of coal from Seller's Mines on a pro-rata basis among its customers, or others as required by law, to the extent that its contracts with other customers give Seller the right to reduce its supply obligations as a result of the Force Majeure Event. In the case of Buyer, Buyer shall spread its reduced ability to accept or utilize coal at the Plant among all its suppliers of coal to the Plant, committed at the time the Force Majeure Event occurred, on a pro-rata basis to the extent that its contracts with other suppliers give Buyer the right to reduce its purchase obligations as a-result of the Force Majeure Event. Any such allocation shall be determined on the basis of the number of tons of coal which Seller is obligated to deliver to its committed customers, or Buyer is obligated to receive from its committed suppliers, at the time the Force Majeure Event occurred.

8.6 Suspension; Termination. If due to a Force Majeure Event, a Party is unable to deliver or accept any coal hereunder, such Force Majeure Event continues for a continuous period of ninety (90) days or longer, and such event or events cannot be reasonably eliminated or are not likely to terminate within a reasonable period of time, the other Party shall, at any time after such ninety (90) day period and while such Force Majeure Event suspension continues, have the right, at its option, to terminate this Agreement by giving thirty (30) days written notice of termination to the Party claiming the Force Majeure Event. Other than outstanding payments due hereunder, no damages or compensation shall be paid by either Party because of such termination and such termination shall not be subject to the provisions of Article 12.

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.3

ARTICLE 9

REPRESENTATIONS AND WARRANTIES

9.1 Representations; Warranties. As a material inducement to entering into this Agreement, each Party hereby represents and warrants to the other Party as of the date on which this Agreement is executed, as follows:

9.1.1 Such Party is a corporation duly organized, legally existing and in good standing under the laws of the jurisdiction of its incorporation; it has all requisite corporate power, and has all material governmental licenses, authorizations, consents and approvals necessary to own its assets and carry on its business as now being conducted; and it is qualified to do business in those jurisdictions necessary to perform this Agreement.

9.1.2 There are no bankruptcy proceedings pending or being contemplated by it, or to its knowledge, threatened against such Party.

9.1.3 Neither the execution and delivery of this Agreement, nor compliance with the terms and provisions hereof will conflict with or result in a breach of, or require any consent which has not been obtained as of the effective date of this Agreement under such Party’s charter, by-laws or operating agreement, any governmental requirement, or any agreement or instrument to which it is a party or by which it is bound or to which it or its properties are subject, or constitute a default under any such agreement or instrument.

9.1.4 Such Party has all necessary corporate power and authority to execute, deliver and perform its obligations under this Agreement; the execution, delivery and performance by it of this Agreement has been duly authorized by all necessary corporate action, as applicable, on its part; and this Agreement constitutes the legal, valid and binding obligations of such entity, enforceable against such entity in accordance with its terms, except as the same may be limited by applicable bankruptcy, insolvency, reorganization, moratorium or similar laws in effect from time to time relating to or affecting the enforcement of creditors’ rights generally and by general principles of equity.

9.1.5 No authorizations, approvals or consents of, and no filings or registrations with, any governmental authority are necessary for the execution, delivery or performance of this Agreement by such Party or for the validity or enforceability thereof.

9.1.6 Seller represents and warrants that it holds all necessary legal rights to sell to Buyer coal sufficient in quantity and quality to perform its obligations under this Agreement for the term hereof, and that Seller will hold good and marketable title to all coal that it sells hereunder.

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.3

ARTICLE 10

COMPLIANCE WITH LAW

Seller shall be in material compliance with all applicable laws and regulations in the performance of its obligations under this Agreement, including all environmental requirements in the mining, processing and storing of coal.

ARTICLE 11

INDEMNIFICATION

Seller shall defend, indemnify and hold harmless Buyer and its affiliates, directors, officers, employees and agents from and against all claims, demands, losses, damages, liabilities, obligations and costs (including reasonable attorneys’ and other litigation fees and expenses) (collectively “Claims”) arising out of or relating to personal injury to third parties or third party property damage resulting from the acts or omissions of Seller or its agents in the performance of this Agreement, without regard to which Party has title to the coal pursuant to Section 1.5, except to the extent such injury or damage arises out of the negligent acts or omissions of Buyer or its agents. Buyer shall defend, indemnify and hold harmless Seller and its directors, officers, employees and agents from and against all Claims arising out of or relating to personal injury to third parties or third party property damage resulting from the acts or omissions of Buyer or its agents in the performance of this Agreement, without regard to which Party has title to the coal pursuant to Section 1.5, except to the extent such injury or damage arises out of the negligent acts or omissions of Seller or its agents.

ARTICLE 12

DEFAULT, REMEDIES, AND TERMINATION

12.1 Default. In the event a Party shall: (i) make an assignment or any general arrangement for the benefit of creditors; (ii) file a petition or otherwise commence, authorize, or acquiesce in the commencement of a proceeding or case under any bankruptcy or similar law for the protection of creditors or shall have such a petition filed or proceeding commenced against it and such proceeding is not dismissed within sixty (60) days; (iii) otherwise become bankrupt or insolvent (however evidenced); (iv) be unable to pay its debts as they fall due; (v) have a receiver, provisional liquidator, conservator, custodian, trustee, or other similar official appointed with respect to it or substantially all of its assets; (vi) fail to perform any material obligation to the other Party with respect to this Agreement on or before the thirtieth (30th) day after written notice of such failure from the other Party is received (other than a failure of the coal to meet one or more of the quality specifications set forth in Exhibit A, for which the sole and exclusive rights, obligations and remedies are as set forth in Section 4.3 and, if applicable, Section 3.2); or (vii) not have paid any amount due the other Party hereunder on or before the tenth (10th) day following written notice that such payment is due, such Party shall be the “Defaulting Party” and such event shall be an “Event of Default” hereunder.

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.3

12.2 Remedies. The other Party that is not suffering the Event of Default (the “Non-Defaulting Party”) may, for so long as the Event of Default is continuing, (a) establish by written notice to the Defaulting Party a date, which shall be no earlier than thirty (30) days following the date of such notice, on which this Agreement shall terminate and withhold any payments due from and after the date of such notice in respect of this Agreement, subject to the rights of the Defaulting Party to dispute such termination and withholding in accordance with Article 14; and (b) suspend performance of its obligations under this Agreement, until the Event of Default is cured; provided that if the Event of Default is not cured in the time allowed under Section 12.1, or within thirty (30) days if no specific time period for cure is stated in Section 12.1, the Non-Defaulting Party may terminate this Agreement in accordance with subparagraph (a) of this Section 12.2. The termination of this Agreement pursuant to this Section 12.2 is not an exclusive right, but is in addition to any other rights recognized at law or in equity which may accrue to one Party or the other by reason of circumstances and conditions that are not the subject of an exclusive right that is specifically stated herein.

12.3 Termination by Buyer or Seller. Notwithstanding the Effective Date of this Agreement, if Seller does not become an affiliate of Sunrise Coal, LLC, an Indiana limited liability company, on or before December 31, 2014, either Buyer or Seller may terminate this Agreement immediately upon written notice to the other Party. Neither of the Parties shall have any obligation to the other hereunder following the termination of this Agreement pursuant to this Section 12.3.

12.4 Termination by Buyer.

12.4.1 In the event that Buyer determines that it [**], Buyer shall promptly notify Seller in writing. The Parties shall in good faith attempt to resolve the problem in a manner that would allow Buyer to [**]. If after six (6) months, the Parties have not reached agreement on a mutually acceptable solution, Buyer shall have the right to terminate this Agreement as of such date after which it [**], by given written notice of such termination to Seller. Buyer shall use good faith efforts to give Seller as much prior notice of termination as practicable. Nothing herein shall be construed as requiring Buyer to incur any significant added expense or significant capital investment to [**]. Neither of the Parties shall have any obligation to the other hereunder following the date of such termination, except with respect to matters occurring prior to the date of termination.

12.4.2 As a regulated utility, Buyer engages in [**]. In the event [**] directs Buyer to [**], Buyer may terminate this Agreement by giving Seller no less than one (1) year advance written notice of such termination, in which event this Agreement will terminate on the date specified in Buyer’s notice; provided that such date shall not be any earlier than the date on which Buyer [**]. In the event [**] directs Buyer to [**], Buyer may reduce the Base Tonnage of coal to be supplied hereunder by giving Seller no less than one (1) year advance written notice of such reduction; provided [**]. Neither of the Parties shall have any obligation to the other hereunder following the date of such termination, except with respect to matters occurring prior to the date of termination.

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.3

12.5 Termination by Seller. Notwithstanding Buyer’s extension of the Term of this Agreement pursuant to Section 1.1, if after the first extension of the Term of this Agreement pursuant to Section 1.1, Seller intends to permanently cease production from any of the Mines during the three (3) year period of any on-going or pending extension term (other than the first extension of the Term of this Agreement pursuant to Section 1.1), and Seller determines in its reasonable discretion that it will not be able to supply the Base Tonnage from the other Mines once such Mine ceases production, Seller may reduce the Base Tonnage by giving Buyer no less than one (1) year advance written notice of such reduction in the Base Tonnage hereunder to an amount equal to the amount of coal meeting the quality specifications that Seller reasonably expects to be able to deliver during the remaining Term of this Agreement and any remaining extensions hereunder, taking into account the quantity of uncommitted coal, and the quality specifications of such coal, that Seller expects to produce at the other Mines as of the date that Seller ceases production at the Mine in question; provided that in no event shall the Base Tonnage exceed 40% of the total production from the remaining Mines. If Seller does not expect to produce more than a de minimis amount of coal in excess of Seller’s commitments to other coal purchasers, Seller’s notice to Buyer may instead give Buyer notice of the date on which this Agreement will terminate. If Seller has elected to reduce the Base Tonnage hereunder, this Agreement shall continue in accordance with its terms and conditions. In determining the extent of the reduction in the Base Tonnage upon shutdown of a Mine, Seller shall not give any of its other customers any priority over Buyer with respect to the purchase of any uncommitted coal that Seller has available at such time. Nothing herein shall be construed as requiring Seller to (i) incur any significant added expense or significant capital investment to continue the production of coal from the Mine in question, or (ii) reserve or withhold any coal from the other Mines from any of its other customers in order to have uncommitted coal available for Buyer hereunder. Neither of the Parties shall have any obligation to the other hereunder following the date of such termination, except with respect to matters occurring prior to the date of termination.

12.6 Consequential Damages. Neither Party shall be liable to the other Party for any special, consequential or punitive damages, loss of profit, loss of customers, loss of revenues, loss of productivity, loss of goodwill or loss of use arising out of the performance, breach or nonperformance of this Agreement by such Party, irrespective of any legal theory under which the same may otherwise be asserted, except to the extent that third party claims with respect to which a Party is indemnified hereunder are deemed to constitute such damages.

ARTICLE 13

RECORDS; AUDITS

13.1 Records. Seller shall establish and maintain, subject to modification from time to time as may be required by Seller, a system of accounting such that all information which must be provided to Buyer as part of this Agreement shall be determinable by accounting periods

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.3

regularly used by Seller. Such system shall be in accordance with generally accepted accounting principles consistently applied, and appropriate to permit the development of the invoices, accountings and other documentation required by this Agreement.

13.2 Audit Rights. Upon reasonable notice and during normal business hours, each Party and its designated independent auditors, shall have the right to inspect the other Party’s books and records relating to all provisions of this Agreement, which include coal quality, quantity shipped and quantity received, price adjustments, or as may be necessary to satisfy inquiries from governmental or regulatory agencies, but only to the extent necessary to verify the accuracy of any statement, charges, payments or computations made pursuant to this Agreement. Each Party shall make a reasonable effort to facilitate the other Party’s inspection of such records in its possession. The Party conducting the inspection and its auditors, to the extent permitted by law or regulation, shall treat all such information as confidential. Any such audit shall in any event be conducted during the 12 months after the date of the report, accounting or statement provided that is subject to such audit.

13.3 Inspections. Buyer and its duly authorized representatives shall upon reasonable advance notice and during normal operating hours, have the right to inspect the Mines and Seller’s related coal preparation, loading and other related facilities. Buyer’s inspections shall be performed in a reasonable manner and without interfering with Seller or Seller’s operations at the Mine. Buyer shall cause each of its representatives that perform such inspections to participate in any required safety training, sign appropriate waivers and comply with all of Seller’s safety and security policies then in effect at the Mines.

13.4 Confidential Nature of Records. Buyer recognizes that the records to be maintained by Seller under this Article 13, and the information provided by either party in the course of an audit are confidential and proprietary in nature. Accordingly, each Party agrees that no information obtained in an audit or inspection will be disclosed without prior consent in writing from the other Party, except to the extent a Party is legally compelled to make such disclosure pursuant to applicable law, or to establish a claim or defense on behalf of Buyer in a Dispute between Buyer and Seller. Buyer shall in any event seek confidential treatment of such information prior to making any such disclosure.

ARTICLE 14

DISPUTE RESOLUTION

14.1 Dispute Notice. Except for disputes regarding the determination of the Market Adjusted Base Price, which shall be settled in accordance with Section 3.4, any controversy, claim, counterclaim, dispute, difference or misunderstanding arising out of or relating to the interpretation or application of this Agreement (a “Dispute”), shall be resolved by the Parties in accordance with this Article 14. In the event of a Dispute, either Party may provide written notice to the other of the existence of a Dispute. Such notice shall state the nature or subject of the Dispute, and the notifying Party’s position thereon. The Parties shall, for a period of thirty (30) days following the date of such notice, engage in good faith discussions and negotiations in an attempt to resolve such Dispute.

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.3

14.2 Escalation. In the event no resolution is reached in the preliminary thirty (30) day period as described in Section 14.1, either Party may, following the expiration of the original thirty (30) day period, designate by written notice, a member of such Party’s senior management for further discussions and negotiations. Within five (5) business days of receipt of that designation, the other Party shall designate by written notice, a member of its senior management to participate in such further discussions and negotiations. Commencing on receipt of this second designation, an additional twenty (20) day period shall commence during which the designated senior management from both Parties, together with such assistance as they may deem appropriate, shall engage in good faith discussions and negotiations to resolve the Dispute. In the event that the discussions and negotiations involving senior management during such additional twenty (20) day period produces no resolution, either Party may submit the Dispute to binding arbitration in accordance with Section 14.3.

14.3 Arbitration. In the event the Parties are unable to resolve a Dispute pursuant to Section 14.1 or Section 14.2, either Party may demand an arbitration proceeding by written demand to the other Party and the appropriate office of the American Arbitration Association (the “AAA”). All arbitration proceedings shall take place in Indianapolis, Indiana under the auspices of the AAA in accordance with the Federal Arbitration Act and the AAA Commercial Arbitration Rules then in effect, subject to the specific provisions of this Section 14.3.

14.3.1 For all Disputes where the amount or value of the Dispute is less than $1,000,000, the arbitration proceeding shall be conducted by a single neutral arbitrator selected by Buyer and Seller (or the AAA if the Buyer and Seller cannot agree within twenty (20) days) of the demand for arbitration. For all Disputes where the amount or value of the Dispute is equal to or more than $1,000,000, the arbitration proceeding shall be conducted by a panel of three (3) neutral arbitrators, one of which shall be selected by Buyer, and one of which shall be selected by Seller. Buyer and Seller shall mutually select the third neutral arbitrator. If the arbitration is to be conducted by a panel of three (3) arbitrators, and the Parties have not each appointed a neutral arbitrator and agreed on the third arbitrator on or before thirty (30) days following the delivery of a demand for arbitration, then either Party may request that the AAA designate any remaining arbitrators pursuant to its Commercial Arbitration Rules and such designation shall be binding on the Parties.

14.3.2 The arbitration decision shall be by majority vote if the arbitration proceeding is conducted by a panel, and shall be issued in a writing that sets forth in separately numbered paragraphs all of the findings of fact and conclusions of law necessary for the decision. Findings of fact and conclusions of law shall be separately designated as such. The arbitrator(s) shall not be entitled to deviate from the construct, procedures or requirements of this Agreement. Any decision rendered by the arbitrator(s) in any arbitration shall be final and binding upon the Parties, and judgment may be entered on the award in any court of competent jurisdiction. The cost of the arbitration shall be borne equally by the Parties.

14.3.3 Each Party shall be entitled to be represented by counsel in any such arbitration proceeding, to present written and oral evidence and arguments, to cross-examine the other Party’s witnesses, and to obtain a list of the other Party’s witnesses and evidence no less than fourteen (14) days prior to the hearing. The formal rules of evidence shall not apply, but the arbitrator(s) may be guided by the Federal Rules of Evidence in conducting the proceeding. The

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.3

arbitrator(s) shall permit and facilitate such disclosure and discovery of facts, documents and tangible things as the arbitrator(s) shall determine is appropriate in the circumstances, taking into account the needs of the Parties and the desirability of making disclosure expeditious and cost-effective. The arbitrator(s) may issue orders to protect the confidentiality of proprietary information, trade secrets and other sensitive information disclosed.

14.4 Extensions. The Parties may agree, in writing, to extend any time period provided for in this Article 14.

ARTICLE 15

MISCELLANEOUS

15.1 Notices. Any notice, request, consent, demand, report, or statement which is given or made under any of the provisions of this Agreement shall be in writing unless otherwise provided herein, and shall be treated as duly delivered when the same is either personally delivered to the Party to whom directed, when sent by United States certified mail with all necessary postage prepaid and a return receipt requested, when sent by a nationally recognized overnight delivery service with charges fully prepaid, or when sent by electronic mail or facsimile with confirmation of receipt, and addressed to the respective Party at the below specified address:

Notices to Buyer

Southern Indiana Gas and Electric Company

One Vectren Square

Evansville, IN 47708

Attn: Wayne D. Games

E-mail: wdgames@Vectren.com

Fax: 812.491.4684

With a copy to:

Robert E. Heidorn

Senior Vice President and General Counsel

Vectren Corporation

One Vectren Square

Evansville, IN 47741

E-mail: rheidorn@Vectren.com

Fax: 812.491.4238

Notices to Seller

Vectren Fuels, Inc.

One Vectren Square

Evansville, IN 47741

Attn: Randy Beck

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.3

Either Party may update or modify the address(es) to whom notice shall be sent hereunder from time to time, by written notice to the other Party as provided above.

15.2 Successors and Assigns. This Agreement shall inure to the benefit of and be binding upon the Parties hereto and their respective successors and assigns.

15.3 Assignment. This Agreement may not be assigned by either Party without the written consent of the other Party, not to be unreasonably withheld or delayed. Notwithstanding the foregoing, either Party may without the written consent of the other Party, assign or otherwise transfer this Agreement (a) in the case of Seller, to an affiliate of such Party; (b) to a successor to all or substantially all of such Party’s assets; provided that such successor has a financial condition at least equivalent to that of the assigning Party; (c) in the case of Buyer, to a successor to all or substantially all of the property and assets comprising the Plant; (d) to secure such Party’s indebtedness incurred or to be incurred for the purposes of or in connection with the performance of this Agreement; and (e) to one or more persons, firms or corporations who shall assume the obligation of the transferring Party hereunder in connection with the enforcement of any assignment or transfer referred to in subparagraph (d) of this Section 15.3. The Party making any such permitted assignment or transfer hereunder shall give the other Party ten (10) days written notice of such assignment or transfer. Except with respect to an assignment pursuant to subparagraph (d) of this Section 15.3, no assignment under this Agreement shall be effective until the assignee, in writing delivered to the non-assigning Party, has agreed to accept the assignment and to be bound by all the terms and conditions in this Agreement.

15.4 Survival. The terms and provisions of this Agreement regarding payment and indemnity shall survive the expiration or the termination of this Agreement indefinitely. The terms and provisions of this Agreement regarding records and confidentiality shall survive the expiration or the termination of this Agreement for a period of five (5) years.

15.5 Waivers. The failure of a Party to insist in any one or more instances upon strict performance of any provisions of the Agreement by the other Party, or to take advantage of any of its rights hereunder, shall not be construed as a waiver by such Party of any such provision or the relinquishment by such Party of any such rights in respect of any subsequent nonperformance of such provision, but the same shall continue and remain in full force and effect.

15.6 Severability. The provisions of this Agreement are severable, and the invalidity or unenforceability of any one or more provision shall not affect or limit the validity of the remaining provisions. Should any particular provision be held to be unreasonable or unenforceable for any reason, then such provision shall be given effect and enforced. to whatever extent would be reasonable and enforceable under the applicable law.

15.7 Governing Law. This Agreement and any questions concerning its validity, construction, interpretation or performance shall be governed by the laws of the State of Indiana without reference to any other choice of law provisions. Any action which may be commenced based on, arising from or related to this Agreement shall be brought only in the federal or state courts sitting in the State of Indiana.

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.3

15.8 Headings. The captions of Articles and Sections in this Agreement are for convenience of reference only and shall not be taken or construed to define or limit any of the terms or provisions of this Agreement.

15.9 Confidentiality. Each Party acknowledges that this Agreement contains confidential information, which could put the other Party at a competitive disadvantage in its purchasing and sales activities, if disclosed to the public. Therefore, this Agreement and its terms shall be kept confidential and shall not be disclosed to any third party, except (a) as required by law or governmental or judicial order, including as required by the IURC, (b) pursuant to securities laws and regulations applicable to a Party, (c) as mutually agreed to by the Parties hereto; provided that this Section 15.9 shall not be construed to prohibit disclosure of this Agreement and its terms to a Party’s affiliates and its directors, employees, advisors, lenders, counsel, accountants, representatives, and prospective purchasers, solely for the purpose of evaluating, negotiating, and consummating the transactions contemplated by the Parties under this Agreement, and who have been notified of such Party’s confidentiality obligations hereunder. Each Party shall be responsible for any disclosure of this Agreement or its terms by any of such persons or entities that receive such information from such Party. If a Party reasonably believes it is required to disclose this Agreement or any of its terms pursuant to subparagraph (a) or (b) of this Section 15.9, such Party shall promptly notify the other Party, shall seek confidential treatment of any information that is disclosed, shall disclose only that part of the information that such Party is advised by counsel is required to be disclosed, and shall cooperate with the other Party’s reasonable attempts to obtain confidential treatment of this Agreement and any terms that may have been disclosed. This Section 15.9 shall not apply to information, including redacted copies of other coal supply agreements entered into by a Party, provided by a Party in connection with the Market Price Adjustments contemplated in Section 3.4, which shall be subject to the requirements of Section 3.4.5.

15.10 Guarantee. Unless this Agreement is terminated pursuant to Section 12.3, within ten (10) days after Seller becomes an affiliate of Sunrise Coal, LLC, if at all, Seller shall in its sole discretion, either assign this Agreement to Sunrise Coal, LLC and notify Buyer accordingly, or deliver to Buyer, and thereafter maintain until such time as this Agreement is assigned to Sunrise Coal, LLC (or its successor), a guarantee by Sunrise Coal, LLC (or its successor) of Seller’s obligations hereunder substantially in the form set forth in Attachment 2 to this Agreement. Notwithstanding anything to the contrary in the foregoing or in Section 15.3(a) or Section 15.3(e), (i) if this Agreement is assigned to Sunrise Coal, LLC and subsequently assigned to an affiliate of Sunrise Coal, LLC (or its successor), Seller shall as a condition to such assignment, deliver to Buyer and thereafter maintain until such time as this Agreement is assigned to Sunrise Coal, LLC (or its successor), a guarantee by Sunrise Coal, LLC (or its successor) of Seller’s obligations hereunder substantially in the form set forth in Attachment 2 to this Agreement; (ii) if (A) Seller has the obligation to deliver a guarantee by Sunrise Coal, LLC pursuant to this Section 15.10, (B) Sunrise Coal, LLC no longer directly or indirectly holds all of the Mines, and (C) the financial condition of Sunrise Coal, LLC is no longer equivalent to or better than the financial condition of Sunrise Coal, LLC as of the Effective Date, and (iii) if this Agreement is assigned pursuant to Section 15.3(c) and the financial condition of the assignee is not equivalent to or better than the financial condition of Sunrise Coal, LLC as of the Effective Date, then Seller or such assignee, as applicable, shall, in lieu of delivering a guarantee by Sunrise Coal, LLC (or its successor), deliver to Buyer and thereafter maintain a guarantee of

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.3

Seller’s obligations hereunder substantially in the form set forth in Attachment 2 to this Agreement by an affiliate of Sunrise Coal, LLC (or its successor) with a financial condition equivalent to or better than the financial condition of Sunrise Coal, LLC as of the Effective Date, or such other form of financial security as is reasonably acceptable to Buyer.

15.11 Entire Agreement. This Agreement contains the complete and exclusive embodiment of the Parties’ agreement as to matters herein referenced, and supersedes all other or prior agreements with respect thereto. No amendments or modifications hereto shall be binding unless in a writing signed by each of the Parties.

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.3

IN WITNESS WHEREOF, Buyer and Seller have caused this Agreement to be executed by their respective officers as of June 30, 2014.

SELLER

VECTREN FUELS, INC.

By:     /s/ Randy L. Beck        

Name :     Randy L. Beck    

Title:         President        

BUYER

SOUTHERN INDIANA GAS AND ELECTRIC COMPANY

d/b/a VECTREN POWER SUPPLY, INC.

By:     /s/ Wayne D. Games        

Name :     Wayne D. Games    

Title:         VP - Power Supply    

{Signature page to F.B Culley Coal Supply Agreement}

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.3

EXHIBIT A

COAL QUALITY SPECIFICATIONS

The coal supplied under this Agreement shall meet the following quality specifications on an “as received” basis. Coal quality shall be determined in accordance with Article 6.

	Typical	MWA (monthly weighted average)	Reject (per Shipment)
Moisture (%)	[**]	[**]	[**]
Ash (%)	[**]	[**]	[**]
BTU/Lb.	[**]	[**]	[**]
SO2 (LBs/MMBTU)	[**]	[**]	[**]
Sulfur (%)	[**]	[**]	[**]
Volatile Matter (%)	[**]	[**]	[**]
AFT h/w, reducing 0F	[**]	[**]	[**]
HGI	[**]	[**]	[**]
Size (2” x 0) (Percent passing thru ¼” screen)	[**]	[**]	[**]
Sodium Equivalent (% Ignited)	[**]	[**]	[**]
Ferric Oxide (% Ignited)	[**]	[**]	[**]
Silicon Dioxide (% Ignited)	[**]	[**]	[**]
Aluminum Oxide (% Ignited)	[**]	[**]	[**]
Arsenic (ug/g dry basis)	[**]	[**]	[**]
% Chlorine (until December 31, 2019, inclusive)	[**]	[**]	[**]
% Chlorine (beginning January 1 2020 and thereafter)	[**]	[**]	[**]
Mercury (ug/g dry basis)	[**]	[**]	[**]

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.3

ATTACHMENT 1

AMENDMENT AND TERMINATION AGREEMENT

This Amendment and Termination Agreement (this “Agreement”) is made and entered into effective as of June 30, 2014 (the “Effective Date”), by and between Southern Indiana Gas And Electric Company d/b/a Vectren Power Supply, Inc., an Indiana corporation (“Buyer”), and Vectren Fuels, Inc., an Indiana corporation (“Seller”). Buyer and Seller are also referred to herein individually as a “Party” and collectively as the “Parties.”

RECITALS

WHEREAS, Buyer and Seller are parties to that certain F.B. Culley Coal Supply Agreement entered into effective as of January 1, 2009, as amended from time to time (the “Original Agreement”).

WHEREAS, Buyer and Seller are entering into that certain F.B. Culley Coal Supply Agreement made and entered into effective as of January 1, 2015 (the “2015 CSA”), for the supply of bituminous coal for use in its F.B. Culley generating plant (the “Plant”).

WHEREAS, it is a condition to the willingness of Seller to enter into the 2015 CSA that certain amendments be made to the terms and conditions of the Original Agreement, as set forth herein.

NOW, THEREFORE, in consideration of the premises and the mutual covenants and agreements of the Parties contained herein, the Parties agree as follows:

AGREEMENT

1. Amendments to the Original Agreement. Notwithstanding anything to the contrary in the Original Agreement, the Parties hereto agree that the following terms shall apply effective immediately as of the date on which Seller becomes an affiliate of Sunrise Coal, LLC. In the case of any conflicts between the foregoing and the terms of the Original Agreement, the provisions of this Section 1 shall govern.

a). Source of Coal. The source of the coal to be delivered by Seller shall be the Seller’s Oaktown 1 or Oaktown 2 Mines (collectively, the “Mines”). Seller shall have the right to notify Buyer that the coal to be sold by Seller and purchased by Buyer under this Agreement may also be mined from coal properties and reserves at Sunrise Coal, LLC’s Carlisle Mine, located in and around Sullivan County, Indiana. Seller’s right to deliver coal mined from the Carlisle Mine under this Agreement shall arise automatically upon Seller’s notice to Buyer, subject to the Parties’ agreement on the Carlisle Deduction (as defined below). Within thirty (30) days after Seller becomes an affiliate of Sunrise Coal, LLC, Buyer shall notify Seller if its cost to transport coal from the Carlisle Mine to the Plant differs from the cost to transport coal from the Seller’s Oaktown 1 or Oaktown 2 Mines. Such notice shall include reasonable supporting documentation of the respective transportation costs. Buyer and Seller, each acting in good faith, shall determine the difference between Buyer’s transportation costs for coal transported for: (a) each ton of coal delivered from the Carlisle Mine, and (b) each ton of coal delivered the

Att 1 - 1

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.3

Seller’s Oaktown 1 or Oaktown 2 Mines (such difference in costs, the “Carlisle Deduction”), and Seller shall apply the Carlisle Deduction to all tons of coal delivered from the Carlisle Mine in its invoices when submitted to Buyer. To the extent the Carlisle Deduction is different for rail and truck transportation, the Carlisle Deduction for the applicable transportation mode shall be utilized. The Parties shall document the agreed Carlisle Deduction in a writing signed by both Parties. Once the Parties agree on the Carlisle Deduction, the Carlisle Mine shall be deemed to be one of the “Mines” for all purposes hereunder.

b). Delivery. Coal shall be delivered F.O.B. railcar or truck (as elected by Buyer) at the Mines (as elected by Seller), in substantially equal monthly quantities on a mutually agreeable delivery schedule. Seller will coordinate loading at the Mines with Buyer and Buyer’s relevant carriers. The foregoing provisions replace any provisions in the Original Agreement regarding point of delivery and delivery schedule, including, without limitation, any limitations set forth in Section 3.1 or otherwise in the Original Agreement with respect to the number of tons that may be delivered per day , all of which are hereby superseded in their entirety.

c). Transportation. Buyer shall be solely responsible for transportation of the coal from the Mines to the Plant, including providing railcars or trucks, as Buyer elects, for loading at the Mines. Buyer may, in its sole discretion, direct any coal delivered hereunder to any of Buyer’s or its affiliate’s power generating stations other than the Plant; provided that Buyer shall be responsible for all additional transportation costs associated with such election. Buyer’s right to direct coal to a power generating station other than the Plant shall in no way be construed as an obligation to do so under any circumstance. The foregoing provisions replace any provisions in the Original Agreement regarding transportation and transportation costs, all of which are hereby superseded in their entirety.

d). Base Tonnage. The quantity of coal to be delivered under the Original Agreement in calendar year 2014 and 2015, as applicable, is as follows (the “Base Tonnage”):

2014 - 1,000,000 tons

2015 - 1,000,000 tons

Buyer has notified Seller that Buyer has utilized its option to adjust the Base Tonnage by + [**] pursuant to the Original Agreement to decrease the amount of coal to be delivered pursuant to the Original Agreement to [**] tons annually, until further notice.

e). Buyer Option to Adjust. Buyer’s option to adjust the annual Base Tonnage by + [**] as stated in Section 3.1 of the Original Agreement, shall remain in full force and effect during the term thereof.

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.3

f). Coal Quality Specifications. The table in Exhibit A to the Original Agreement is hereby deleted in its entirety and replaced with the following table:

Quality Specifications
Coal Characteristics	MWA (monthly weighted average)	Penalty Threshold	Reject
Caloric value, as received	[**]	[**]	[**]
% Moisture, as received	[**]	[**]	[**]
% Ash, as received	[**]	[**]	[**]
SO2	[**]	[**]	[**]
Ash Fusion, softening, H=W red	[**]	[**]	[**]
Hardgrove Grindability Index	[**]	[**]	[**]
Nominal Size	[**]	[**]	[**]
Percent passing thru ¼” screen	[**]	[**]	[**]
Chlorine	[**]	[**]	[**]
Mercury (ug/g dry basis)	[**]	[**]	[**]

g). Weighing. The provisions of Article 5 of the 2015 CSA shall apply, and shall replace any provisions of the Original Agreement regarding weighing or the other matters addressed in Article 5 of the 2015 CSA, in their entirety.

h). Sampling and Analysis. The provisions of Article 6 of the 2015 CSA (other than quality specifications and without regard to cross-references to other provisions of the 2015 CSA) shall apply, and shall replace any provisions of the Original Agreement regarding sampling and analysis or the other matters addressed in Article 6 of the 2015 CSA, in their entirety.

i). Invoicing and Payment. The provisions of Article 7 of the 2015 CSA shall apply, and shall replace any provisions of the Original Agreement regarding invoicing and payments or the other matters addressed in Article 7 of the 2015 CSA, in their entirety

2. Termination of the Original Agreement. Notwithstanding anything to the contrary in the Original Agreement, the Parties hereby agree that the Original Agreement shall terminate and be of no further force and effect as of 11:59 pm Eastern on December 31, 2015, except with respect to the obligation to make any payments remaining to be made as of such date.

3. Termination of this Agreement. If Seller does not become an affiliate of Sunrise Coal, LLC, an Indiana limited liability company, on or before December 31, 2014, either Buyer or Seller may terminate this Agreement immediately upon written notice to the other Party, after which this Agreement shall be of no further force and effect.

Att 1 - 3

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.3

4. No Other Modifications. Except as amended herein, all other terms, conditions and provisions of the Original Agreement not explicitly modified or amended in this Agreement shall remain unchanged and shall continue in full force and effect.

5. Counterparts and Facsimile. This Agreement may be executed in counterparts and by facsimile, each of which shall be an original and all of which taken together shall constitute one and the same instrument.

[signature page follows]

Att 1 - 4

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.3

IN WITNESS WHEREOF, Buyer and Seller have caused this Agreement to be executed by their respective officers as of the date first written above.

SELLER

VECTREN FUELS, INC.

By:     /s/ Randy L. Beck        

Name :     Randy L. Beck    

Title:         President        

BUYER

SOUTHERN INDIANA GAS AND ELECTRIC COMPANY

d/b/a VECTREN POWER SUPPLY, INC.

By:     /s/ Wayne D. Games        

Name :     Wayne D. Games    

Title:         VP - Power Supply    

{Signature page to F.B. Culley Amendment and Termination Agreement}

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.3

ATTACHMENT 2 FORM OF GUARANTEE

Guaranty

This GUARANTY, dated as of the day of , 2014, is entered into by Sunrise Coal, LLC, an Indiana limited liability company (“Sunrise”), to and for the benefit of Southern Indiana Gas And Electric Company d/b/a Vectren Power Supply, Inc., an Indiana corporation (“VPS”).

WITNESSETH:

WHEREAS, VECTREN FUELS, INC., an Indiana corporation (“Fuels”), is a wholly owned subsidiary of Sunrise.

WHEREAS, Fuels and VPS have entered into that certain F.B. Culley Coal Supply Agreement made and entered into effective as of January 1, 2015 (the “2015 CSA”).

WHEREAS, as an inducement to VPS entering into the 2015 CSA and subject to Fuels becoming a wholly-owned subsidiary of Sunrise, Fuels has agreed to cause Sunrise to execute and deliver this Guaranty for the benefit of VPS within 10 days after the date on which Fuels becomes a wholly-owned subsidiary of Sunrise, if at all.

NOW, THEREFORE, in consideration of the foregoing premises and the following covenants and other good and valuable consideration, the receipt and sufficiency of which is hereby acknowledged, Sunrise covenants with VPS as follows:

1. Guaranty. For value received and in consideration of the direct and indirect benefits to be derived by Sunrise in connection with the transactions contemplated by the 2015 CSA, with effect from January 1, 2015, Sunrise hereby guarantees to VPS the payment and performance as and when due of all obligations of Fuels (and any assignee of Fuels that is an affiliate of Sunrise) arising out of or related to the 2015 CSA, subject in all respects to all of the conditions, limitations, and qualifications set forth in the 2015 CSA (the “Obligations). This is a continuing Guaranty of payment and performance and not merely of collection. Subject to the provisions of Section 4, this Guaranty shall terminate upon the earlier of the termination of the Obligations or the date that is 12 months after the termination or expiration of the 2015 CSA; provided, however, that this Guaranty and Sunrise’s liability hereunder shall survive any such termination with respect to any claims made by VPS under the 2015 CSA if such claims are made prior to such termination.

2. Waiver. Sunrise hereby expressly waives notice from VPS of its acceptance of and reliance upon this Guaranty. Sunrise consents to any extensions of time for the payment or performance of the Obligations and to any changes in the terms of the 2015 CSA, and waives any notices thereof. Sunrise also waives promptness, diligence, presentment to or demand of payment or performance from anyone other than Fuels liable upon the Obligations, and presentment, notice of dishonor, protest and all other notices whatsoever. No waiver,

Att 2 - 1

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.3

amendment, release or modification of this Guaranty shall be established by conduct, custom or course of dealing, but solely by an instrument in writing duly executed by Sunrise and VPS. VPS’s failure or delay in exercising any right, remedy or power hereunder shall not operate as a waiver thereof, nor shall any single or partial exercise by VPS of any right, remedy or power hereunder preclude VPS from any other or future exercise of any right, remedy or power. Each and every right, remedy and power granted to VPS hereunder or allowed to it by law or other agreement shall be cumulative with and not exclusive of any other.

3. Waiver of Defenses. The liability of Sunrise under this Guaranty, and Sunrise’ obligations under this Guaranty shall not be impaired or released as a result of (a) any change of the time, manner or terms of payment or performance of any of the Obligations; (b) any renewal or increase of any of the Obligations; (c) the assignment of the 2015 CSA to an affiliate of Sunrise pursuant to Section 15.3(a) of the 2015 CSA; (d) any release or partial release of any other guarantor or other obligor in respect of any of the Obligations; (e) any modification, amendment, waiver or renewal of, or consent to departure from, any agreement or instrument relating to any of the Obligations; (f) VPS’s exercise or failure to exercise any rights against Fuels, Sunrise or others or any other action or inaction by VPS in respect of any of the Obligations; (g) with respect to any of the foregoing, the lack of notice to or consent by Sunrise; or (h) any other circumstance which might otherwise constitute a defense available to, or discharge of, a surety or a guarantor excepting payment and performance, as applicable. Nothing herein is intended to deny Sunrise, and Sunrise shall have and may assert any and all of the defenses, set-offs, counterclaims and other rights which Fuels is or may be entitled to assert that arise from or out of the 2015 CSA, except for defenses arising out of the bankruptcy, insolvency, dissolution or liquidation of Fuels. The obligations of Sunrise hereunder are several from Fuels or any other person, and are primary obligations concerning which Sunrise is the principal obligor. There are no conditions precedent to the enforcement of this Guaranty, except as expressly contained herein.

4. Reinstatement Provision. If VPS receives any payment or payments on account of the Obligations, which payment or payments of any part thereof are subsequently invalidated, declared to be fraudulent or preferential, set aside and/or required to be repaid to a trustee, receiver, or any other party under any bankruptcy act or code, state or federal law, common law or equitable doctrine, then to the extent of any sum not finally retained by VPS, Sunrise’ obligations to VPS hereunder shall be reinstated and this Guaranty, shall remain in full force and effect (or be reinstated) until payment of the Obligations shall have been made to VPS, which payment shall be due on demand.

5. Assignment. This Guaranty shall be binding upon Sunrise and upon its successors and assigns and shall be for the benefit of VPS and its successors and assigns. Sunrise may not assign this Guaranty or the obligations hereunder without the express written consent of VPS and such consent will not be unreasonably withheld. Any purported assignment in violation of this Section 5 shall be void and without effect.

6. Applicable Law. This Guaranty shall be governed by and construed in accordance with the laws of the State of Indiana, without giving effect to laws of such state that would require the application of the laws of any other state.

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.3

7. Severability. In case any clause, provision or section of this Guaranty, or any application thereof, is for any reason held to be illegal, invalid, or inoperable, Sunrise and VPS shall negotiate an equitable adjustment to such affected provisions of this guaranty with a view towards effecting the purpose and intent of the Guaranty, and subject to such adjustment such illegality, invalidity or inoperability shall not affect the remainder thereof or any other clause, provision or section, and each such clause, provision or section shall be deemed to be effective and operative in the manner and to the fullest extent permitted by law.

8. Only Agreement. This Guaranty is the entire and only agreement between Sunrise and VPS with respect to the guaranty of the Obligations of Fuels by Sunrise.

9. Representations and Warranties. Sunrise represents and warrants to VPS that: (a) Sunrise is a limited liability company duly organized and validly existing under the laws of the State of Indiana; (b) Sunrise has all requisite power and authority to execute and to deliver and to perform all of its obligations under this Guaranty; (c) the execution, delivery and performance of this Guaranty by Sunrise are within its powers and have been duly authorized by all necessary limited liability company actions; (d) this Guaranty constitutes a legally valid and binding agreement of Sunrise, subject only to insolvency, bankruptcy, moratorium, reorganization, fraudulent conveyance or similar laws affecting creditors’ rights generally and by general principles of equity; (e) the execution, delivery and performance of this Guaranty will not violate any provision of any requirement of law or contractual obligation of Sunrise (except to the extent that any such violation would not reasonably be expected to have a material adverse effect on Sunrise’ ability to perform this Guaranty); (f) no consent or authorization of, filing with, or other act by or in respect of, any arbitrator or governmental authority and no consent of any other person (including, without limitation, any stockholder or creditor of Sunrise) is required in connection with the execution, delivery, performance, validity or enforceability of this Guaranty, other than any which have been obtained or made prior to the date hereof and remain in full force and effect; and (g) no litigation, investigation or proceeding of or before any arbitrator or governmental authority is pending or, to the knowledge of Sunrise, threatened by or against Sunrise relating to this Guaranty or that would have a material adverse effect on Sunrise’ ability to perform this Guaranty.

10. Collection Expenses. If VPS is required to pursue any remedy against Sunrise hereunder, Sunrise shall pay to VPS upon demand, all reasonable attorneys’ fees and expenses and all other reasonable costs, expenses and fees incurred by VPS in successfully enforcing this Guaranty.

11. Notices. Any notices given or required to be given hereunder shall be given to Sunrise and VPS, as applicable, by being either: (a) delivered personally against written receipt, (b) sent by facsimile or e-mail transmission, (c) mailed by registered or certified mail, postage prepaid, return receipt requested, or (d) mailed by reputable international overnight courier, fee prepaid, to Sunrise or VPS, as applicable, at the following addresses or facsimile numbers:

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.3

If to Sunrise: Sunrise Coal, LLC

Attention: Brent Bilsland

1183 East Canvasback Dr.

Terre Haute, IN 47802

Phone: (812) 298-3702

Fax No.: (812) 299-2810

E-mail: bbilsland@sunrisecoal.com

If to VPS: Southern Indiana Gas and Electric Company One Vectren Square

Evansville, IN 47708 Attn: Wayne D. Games

E-mail: wdgames@Vectren.com

Fax: 812.491.4684

With a copy to: Robert E. Heidorn

Senior Vice President and General Counsel Vectren Corporation

One Vectren Square Evansville, IN 47741

E-mail: rheidorn@Vectren.com

Fax: 812.491.4238

All such notices, requests and other communications will be deemed given, (w) if delivered personally as provided in this Section 11, upon delivery, (x) if delivered by facsimile or email transmission as provided in this Section 11, upon confirmed receipt, (y) if delivered by mail as provided in this Section 11, upon the earlier of the fifth business day following mailing and receipt, and (z) if delivered by overnight courier as provided in this Section 11, upon the earlier of the second business day following the date sent by such overnight courier and receipt (in each case regardless of whether such notice, request or other communication is received by any other person or entity to whom a copy of such notice is to be delivered pursuant to this Section 11). Sunrise and VPS may change the address to which notices to it are to be sent upon written notice to VPS or Sunrise, respectively.

12. Modification. This Guaranty may not be amended or modified unless the changes are in writing and signed by both VPS and Sunrise.

13. JURY TRIAL WAIVER. SUNRISE HEREBY IRREVOCABLY WAIVES ANY AND ALL RIGHTS TO TRIAL BY JURY WITH RESPECT TO ANY LEGAL PROCEEDING ARISING OUT OF OR RELATING TO THIS GUARANTY.

[signature page follows]

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.3

IN WITNESS WHEREOF, Sunrise has executed and delivered this Guaranty effective as of the day and year first above written.

Sunrise Coal, LLC

By:     

Name:     

Title:     

Accepted:

Southern Indiana Gas and Electric Company

d/b/a Vectren Power Supply, Inc.

By:     

Name:

Title:     

Att 2 - 5

EX-10.4

[**] REPRESENTS CONFIDENTIAL MATERIAL OMITTED AND FILED SEPARATELTY WITH THE SECURITIES

AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.4

WARRICK UNIT 4

COAL SUPPLY AGREEMENT

This Coal Supply Agreement (the “Agreement”) is made and entered into effective as of January 1, 2015 (the “Effective Date”), by and between Southern Indiana Gas And Electric Company d/b/a Vectren Power Supply, Inc., an Indiana corporation (“Buyer”), and Vectren Fuels, Inc., an Indiana corporation (“Seller”). Buyer and Seller are also referred to herein individually as a “Party” and collectively as the “Parties.”

RECITALS

WHEREAS, Buyer and Seller are parties to that certain Warrick Unit #4 Coal Supply Agreement entered into effective as of January 1, 2009, as amended from time to time (the “Original Agreement”).

WHEREAS, Buyer desires to secure to the extent of the quantities and for the period hereinafter stated, a supply of bituminous coal of the quality hereinafter set forth, for use in its

A.B. Brown generating plant (the “Plant”).

WHEREAS, Seller represents that it is experienced in the commercial production and preparation of coal and that it owns, has leased, or controls reserves of bituminous coal with the quality and characteristics as set forth herein.

WHEREAS, Seller desires to sell coal to Buyer, and Buyer desires to buy coal from Seller, upon the terms and conditions hereinafter set forth.

NOW, THEREFORE, in consideration of the premises and the mutual covenants and agreements of the Parties contained herein, the Parties agree as follows:

ARTICLE 1

TERM; SOURCE; TITLE

1.1 Term. Unless terminated earlier or extended in accordance with the terms hereof, the term of this Agreement shall be from the Effective Date through December 31, 2022, inclusive (the “Term”). Notwithstanding the foregoing, Buyer shall have the right, by providing no less than three (3) years prior written notice to Seller (i.e., in the case of the first such extension, by December 31, 2019), to extend the Term of this Agreement by an additional three (3) years, subject to negotiation of the Base Price for any such extension in accordance with Section 3.4, and subject to Seller’s rights pursuant to Section 12.5; provided that Buyer may extend the Term of this Agreement no more than twice.

1.2 Amendment and Termination of Original Agreement. Unless this Agreement is terminated prior to the Effective Date in accordance with Section 12.3, the Parties agree that the Original Agreement shall be amended in accordance with the Termination Agreement entered into by the Parties, as attached hereto as Attachment 1 to this Agreement, which among other things, shall provide for the termination of the Original Agreement as of December 31, 2014.

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.4

1.3 Source. The coal to be sold by Seller and purchased by Buyer under this Agreement shall be mined from coal produced from the Oaktown 1 Mine or the Oaktown 2 Mine (the “Mines”).

1.4 Alternate Supply Sources.

1.4.1 If Seller becomes an affiliate of Sunrise Coal, LLC, an Indiana limited liability company, on or before December 31, 2014, Seller shall have the right to notify Buyer that the coal to be sold by Seller and purchased by Buyer under this Agreement may also be mined from coal properties and reserves at Sunrise Coal, LLC’s Carlisle Mine, located in and around Sullivan County, Indiana, and all references to the “Mines” hereunder shall thereafter be deemed and construed to include the Carlisle Mine, as well as the Oaktown 1 Mine and the Oaktown 2 Mine. Seller’s right to deliver coal mined from the Carlisle Mine under this Agreement shall not be subject to the requirements of Section 1.4.2 but shall arise automatically upon notice to Buyer, subject to the Parties’ agreement on the Carlisle Deduction (as defined below). Within thirty (30) days after Seller becomes an affiliate of Sunrise Coal, LLC, Buyer shall notify Seller if its cost to transport coal from the Carlisle Mine to the Plant differs from the cost to transport coal from the Oaktown 1 Mine and the Oaktown 2 Mine, which transportation cost was assumed to establish the Base Price as stated in Section 3.1.1. Such notice shall include reasonable supporting documentation of the respective transportation costs. Buyer and Seller, each acting in good faith, shall determine the difference between Buyer’s transportation costs for coal transported for: (a) each ton of coal delivered from the Carlisle Mine, and (b) each ton of coal delivered from the Oaktown 1 Mine and the Oaktown 2 Mine (such difference in costs, the “Carlisle Deduction”), and Seller shall apply the Carlisle Deduction to all tons of coal delivered from the Carlisle Mine. To the extent the Carlisle Deduction is different for rail and truck transportation, the Carlisle Deduction for the applicable transportation mode shall be utilized. For purposes of determining the Carlisle Deduction, coal shall be deemed to be transported to the Plant, notwithstanding Buyer’s right to designate alternate locations pursuant to Section 2.8. The Parties shall document the agreed Carlisle Deduction in a writing signed by both Parties. Once the Parties agree on the Carlisle Deduction, the Carlisle Mine shall be deemed to be one of the “Mines” for all purposes hereunder.

1.4.2 In addition, Seller may deliver to Buyer coal conforming to the quality specifications set forth in Exhibit A, from an alternate source (“Alternate Source Coal”), subject to the Parties agreement on the matters contemplated in this Section 1.4.2. If Seller desires to deliver Alternate Source Coal, Seller shall notify Buyer of the location and source of the Alternate Source Coal, and provide Buyer with sample analyses from such alternate source demonstrating that the Alternate Source Coal meets the quality specifications set forth in Exhibit A. If the delivery point for the Alternate Source Coal will be at a location other than any of the Mines, Buyer shall notify Seller if its cost to transport such Alternate Source Coal to the Plant differs from the transportation costs from the Mines. Such notice shall include reasonable supporting documentation of the respective transportation costs for such Alternate Source Coal and for coal delivered at the Oaktown 1 Mine and Oaktown 2 Mine. Buyer and Seller, each acting in good faith, shall determine the difference between Buyer’s transportation costs for: (a) each ton of coal delivered at the Oaktown 1 Mine and the Oaktown 2 Mine, and (b) each ton of coal delivered at the delivery point for such Alternate Source Coal (such difference in costs, the “Alternate Source Deduction”), and Seller shall apply the Alternate Source Deduction to all tons

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.4

of coal delivered at the location of the Alternate Source Coal. To the extent the Alternate Source Deduction is different for rail and truck transportation, the Alternate Source Deduction for the applicable transportation mode shall be utilized. For purposes of determining the Alternate Source Deduction, coal shall be deemed to be transported to the Plant, notwithstanding Buyer’s right to designate alternate locations pursuant to Section 2.8. The Parties shall document the agreed Alternate Source Deduction in a writing signed by both Parties. Once Buyer accepts the Alternate Source Coal and the Parties agree on the Alternate Source Deduction for such Alternate Source Coal, the source of such Alternate Source Coal shall be deemed to be one of the “Mines” for all purposes hereunder.

1.5 Title and Risk of Loss. Title to the coal and risk of loss thereof shall transfer from Seller to Buyer upon loading for shipment of the coal into railcars or trucks, as applicable, at the Mine. As between the Parties, Seller shall be deemed to be in exclusive control (and responsible for any damages or injury caused thereby) of the coal prior to its being loaded for shipment at the Mine, and Buyer shall be deemed to be in exclusive control (and responsible for any damages or injury caused thereby) of the coal from the time it is loaded for shipment at the Mine.

ARTICLE 2

CONTRACT QUANTITY

2.1 Base Tonnage. Seller agrees to deliver to Buyer, and Buyer agrees to accept from Seller, the total quantity of coal as set forth below in each Contract Year during the Term. A Contract Year shall commence on January 1st and end on December 31st.

Contract Year Base Tonnage 2015 480,000 tons

2016 – 2022 480,000 tons

2.2 Annual Tonnage Adjustment. For each Contract Year beginning in 2015, Buyer may elect to increase or decrease the Base Tonnage (as described in Section 2.1) for such Contract Year by an amount of up to [**] of the Base Tonnage for such Contract Year. If Buyer desires to increase or decrease the Base Tonnage for a Contract Year, Buyer shall provide written notice of such election to Seller on or before June 30th of the Contract Year preceding the Contract Year for which the Base Tonnage will be adjusted. If Buyer fails to provide such notice for any Contract Year, the Base Tonnage for such Contract Year shall be the Base Tonnage as set forth in Section 2.1.

2.3 Quarterly Tonnage Adjustments. Beginning in the first quarter of 2015 and for the remainder of the Term, Buyer may elect to increase or decrease the Base Tonnage to be delivered in a calendar quarter by an amount of up to [**] of the Base Tonnage to be delivered in such calendar quarter. Buyer shall provide written notice to Seller of such election on or before the date that is 30 days before the first day of such calendar quarter. For the purposes of this Section 2.3, if Buyer has increased or decreased the Base Tonnage for a given Contract Year pursuant to Section 2.2, the Base Tonnage subject to adjustment in each calendar quarter in such Contract Year shall be the Base Tonnage as adjusted pursuant to Section 2.2.

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.4

2.4 Scheduled Outages. For each Contract Year beginning in 2015 in which Buyer has scheduled outages for the Plant or a generating unit at the Plant, Buyer may by written notice to Seller on or before June 30th of the Contract Year preceding the Contract Year in which such scheduled outages will occur, decrease the monthly quantity of coal that would otherwise be delivered hereunder during such scheduled outage by up to [**]; provided that the maximum period of time for which Buyer may decrease the monthly quantity of coal pursuant to this Section 2.4 shall not exceed [**] in such Contract Year. Buyer’s notice of such decrease may include Buyer’s preference as to when the quantities of coal that are not delivered during such outage should otherwise be delivered, which may be prior to or after such outage; provided that delivery of such coal shall in any event be on a mutually agreeable delivery schedule.

2.5 Tonnage Adjustment due to De-Rating. If any legislative, regulatory, administrative or other governmental bodies, or any court with jurisdiction, enacts, adopts or imposes new laws, rules or regulations, amends existing laws, rules or regulations, or reinterprets existing laws, rules or regulations, that require Buyer to de-rate the Plant, Buyer may, by written notice to Seller, reduce the Base Tonnage hereunder; provided that such reduction shall be imposed on a pro-rata basis among all of Buyer’s coal suppliers to the Plant, based on the number of tons of coal that Buyer is obligated to receive from its committed suppliers, to the extent that its contracts with other suppliers give Buyer the right to reduce its purchase obligations as a result of such new or amended laws, rules or regulations, or reinterpretation. In the event Buyer is later able to increase operations at the Plant during the Term of this Agreement after such notice has been given, the Base Tonnage hereunder shall be increased, not to exceed the Base Tonnage as stated in Section 2.1, plus any annual and quarterly adjustments to the Base Tonnage pursuant to Section 2.2 and Section 2.3, as applicable; provided that any increase in the number of tons of coal required by Buyer for operation of the Plant shall be allocated on a pro-rata basis among Buyer’s committed coal suppliers to the Plant in the same fashion as the decrease in coal was allocated.

2.6 Delivery. Coal shall be delivered F.O.B. railcar or truck (as elected by Buyer) at any of Seller’s Mines (as elected by Seller), in substantially equal monthly quantities on a mutually agreeable delivery schedule. Seller will coordinate loading at the Mines with Buyer and Buyer’s relevant carriers.

2.7 Shipments. As used herein, a “Shipment” of coal supplied under this Agreement shall refer to all coal delivered by truck in a given day, or all coal delivered by a single train of railcars.

2.8 Transportation. Buyer shall be solely responsible for transportation of the coal from the Mines to the Plant, including providing railcars or trucks, as Buyer elects, for loading at the Mines. Buyer may, in its sole discretion, direct any coal delivered hereunder to any of Buyer’s or its affiliate’s power generating stations other than the Plant; provided that Buyer shall be responsible for all additional transportation costs associated with such election. Buyer’s right to direct coal to a power generating station other than the Plant shall in no way be construed as an obligation to do so under any circumstance.

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.4

2.9 Monthly Shipping Schedule. On or before the 15th day of each calendar month during the Term, Buyer shall notify Seller of the expected schedule of shipments by railcar and by truck to be made during the following calendar month. On or before the 25th day of each month during the Term, the Parties shall mutually determine a delivery schedule for the following month, including whether shipments will be by rail or by truck, and the daily schedule for delivery of the coal.

ARTICLE 3

PRICING

3.1 Base Price.

3.1.1 The price per ton (2000 pounds) of coal sold by Seller hereunder (the “Base Price”) shall be determined in accordance with this Article 3. The Base Price for Contract Year 2015 shall be [**].

3.1.2 As of January 1st of each Contract Year thereafter, until the Base Price is re-set in accordance with Section 3.4, the Base Price shall be increased by [**] over the Base Price in effect during the prior Contract Year. After the Base Price is re-set in accordance with Section 3.4, the Base Price for each successive Contract Year thereafter shall be increased by [**] over the Base Price in effect during the prior Contract Year until the Base Price is re-set again in accordance with Section 3.4.

3.2 BTU Adjustment.

3.2.1 The Base Price for each ton of coal sold and purchased hereunder during a calendar month shall be adjusted based on the monthly weighted average of the actual BTU/lb of all tons delivered in such calendar month under this Agreement (the “BTU Adjustment”). The BTU Adjustment shall be determined according to the following formula:

BTU Adjustment = ((Actual BTU/lb Value / Guaranteed BTU/lb Value) x (Base Price)) – Base Price Where the Guaranteed BTU/lb Value = 11,000 Btu/Lb

The aggregate BTU Adjustment for a calendar month shall be equal to the total tons delivered in such calendar month, multiplied by the BTU Adjustment. If the BTU Adjustment is a negative value, the BTU Adjustment shall be payable from Seller to Buyer, and if the BTU Adjustment is a positive value, the BTU Adjustment shall be payable from Buyer to Seller. The aggregate BTU Adjustment to be paid with respect to a calendar month shall be included in the first invoice delivered by Seller in the calendar month immediately following the calendar month for which such BTU Adjustment applies.

3.2.2 Subject to Buyer’s rights under Section 4.3, the Base Price adjustments as described in this Section 3.2, shall be Buyer’s sole and exclusive remedy at law or in equity for the failure of coal sold hereunder to meet the quality specifications with respect to BTU/lb.

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.4

3.3 Other Price Adjustments.

\        3.3.1 The Parties recognize that legislative, regulatory, administrative or other governmental bodies or the courts may impose new laws, rules or regulations, amend existing laws, rules or regulations, or reinterpret existing laws, rules or regulations, including, without limitation, procedural instruction letters issued by MSHA after June 2, 2014 (the “Initial Price Date”), or as applicable, after the date of determination of a Market Adjusted Base Price (such new laws, amendments or reinterpretations, a “Change in Law”), that may increase Seller’s cost of mining coal from the Mines. Without limiting the generality of the foregoing, the implementation after the Initial Price Date of MSHA rule 79 FR 24813 “Lowering Miners’ Exposure to Respirable Coal Mine Dust, Including Continuous Personal Dust Monitors” as adopted on May 1, 2014, shall be deemed to be a Change in Law for purposes of this Agreement, notwithstanding the adoption of such rules prior to the Initial Price Date. A Change in Law shall not in any event include any change in Governmental Impositions (as defined below).

(a) If a Change in Law that affects Seller’s cost of mining occurs after the Initial Price Date, or as applicable, after the date that a Market Adjusted Base Price is determined, Seller shall give notice to Buyer indicating the related increase in the then-current Base Price (or the relevant Market Adjusted Base Price, as applicable) and shall provide to Buyer reasonable documentation of the proposed increase in the Base Price.

(b) If the proposed increase in the Base Price (or the relevant Market Adjusted Base Price, as applicable) is less than or equal to [**] of the then-current Base Price (or the relevant Market Adjusted Base Price, as applicable), the then-current Base Price (or the relevant Market Adjusted Base Price, as applicable) shall be adjusted as of the effective date of such Change in Law by an amount equal to the proposed increase, subject to Buyer’s right to dispute in good faith the existence of a Change in Law or the amount of the proposed price increase. Accordingly, the adjustment to the then-current Base Price (or the relevant Market Adjusted Base Price, as applicable) pursuant to this Section 3.3.1 may be applied retroactively.

(c) If the proposed increase in the Base Price (or the relevant Market Adjusted Base Price, as applicable) is greater than [**] of the then-current Base Price (or the relevant Market Adjusted Base Price, as applicable), then, subject to Buyer’s right to dispute in good faith the existence of a Change in Law or the amount of the proposed price increase, (i) the then-current Base Price shall be increased as of the effective date of such Change in Law to an amount equal to [**] of the initial Base Price in the three (3) year period in which such increase occurs, excluding the annual escalation pursuant to Section 3.1.2, and (ii) if applicable, the relevant Market Adjusted Base Price shall be adjusted by an amount equal to [**] of the relevant Market Adjusted Base Price. Accordingly, the adjustment to the then-current Base Price (or the relevant Market Adjusted Base Price, as applicable) pursuant to this Section 3.3.1 may be applied retroactively.

(d) Except to the extent described in Section 3.3.1(c), no adjustments to the then-current Base Price (or the Market Adjusted Base Price, as applicable) shall be made with respect to Seller’s increased costs for mining that have already been applied to the then-current Base Price or that have been taken into account and quantified during negotiations to determine a Market Adjusted Base Price pursuant to Section 3.4.

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.4

3.3.2 “Governmental Imposition” means taxes or fees imposed by any federal, state or local government or government agency upon the production, severance, preparation or sale of Coal hereunder, including, but not limited to, the Federal Black Lung Excise Tax, severance taxes on Coal produced or sold hereunder, reclamation fees assessed by the US government or the State of Indiana. The term does not include impositions such as generally applicable taxes including federal or state income taxes; employee benefits or payroll taxes such as employer’s Social Security, unemployment or worker’s compensation taxes or payments, or any civil or criminal money fine or penalty imposed as the result of failure to comply with any Law. Buyer shall not be entitled to any adjustment in connection with any benefit derived by Seller for any incentives granted by the U.S. government or the State of Indiana for coal production or investment in coal properties within the State of Indiana.

(a) The Parties shall adjust the then-current Base Price (or the relevant Market Adjusted Base Price, as applicable) by an amount equal to changes in Seller’s costs per ton of coal sold hereunder that are caused directly by increased or decreased Governmental Impositions enacted or imposed after the Initial Price Date, or as applicable, after the date of determination of a Market Adjusted Base Price. Seller shall give prompt notice to Buyer of the amount of any such increased or decreased cost per ton of coal sold hereunder incurred by reason of such a change in Governmental Imposition (including implementation of new Governmental Impositions), along with reasonable documentation of such amounts. The adjustment to the Base Price pursuant to this Section 3.3.2 may be applied retroactively to the date on which such new or changed Government Imposition was first applied to Seller or its operations.

(b) In the event of an increase in cost, such notice from Seller shall also include the increase in the then-current Base Price (or the relevant Market Adjusted Base Price, as applicable) that Seller will require, which increase may not exceed the actual increase in Seller’s costs due to such Governmental Impositions. In the event of a decrease in cost, the then-current Base Price (or the relevant Market Adjusted Base Price, as applicable) will be decreased by an amount equal to the decrease in Seller’s costs caused by Governmental Impositions enacted or changed after the then-current Base Price became effective, or the date of determination of a Market Adjusted Base Price. Adjustments due to Governmental Impositions as described in this Section 3.3.2 shall be subject to Buyer’s right to dispute in good faith the existence of a Governmental Imposition or the amount of the proposed adjustment.

3.3.3 Seller shall follow generally accepted accounting principles (GAAP) as historically applied by Seller in determining its costs related to any Change in Law or Governmental Imposition, and shall provide Buyer with documentation reasonably demonstrating that the increase or decrease in cost is incremental to the costs already included in the Base Price.

3.4 Market Price Adjustments.

3.4.1 Beginning with the 2017 Contract Year, and again upon the expiration of a three (3) year period beginning on January 1st of such Contract Year, and upon the expiration of each three (3) year period thereafter, the Parties shall adjust the Base Price to reflect then-current market prices for similar quality coal meeting the quality specifications set forth in Exhibit A and sold for delivery the following year (the “Market Adjusted Base Price”). The Parties shall follow

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.4

the procedures described below to determine the adjusted Base Price. If the Parties agree on a Market Adjusted Base Price, the Market Adjusted Base Price shall become effective and shall be the “Base Price” as described in Section 3.1 for all purposes hereunder as of January 1st of the first Contract Year of the relevant three (3) year period. The Market Adjusted Base Price shall include all adjustments to the Base Price made pursuant to Section 3.3 prior to the date that such Market Adjusted Base Price is determined. If any adjustments to the Base Price made pursuant to Section 3.3 occur after the date on which the Market Adjusted Base Price is determined, but before the date on which the Market Adjusted Base Price becomes effective, such adjustments shall also be applied to the Market Adjusted Base Price as of the date on which the Market Adjusted Base Price becomes effective.

3.4.2 The Parties shall begin negotiations to determine the Market Adjusted Base Price on or before April 1st of the Contract Year prior to the Contract Year in which the Market Adjusted Base Price will become effective pursuant to Section 3.4.1. The Parties shall negotiate in good faith to agree to the Market Adjusted Base Price.

3.4.3 If the Parties fail to reach agreement on the Market Adjusted Base Price by May 31st of the Contract Year prior to the Contract Year in which the Market Adjusted Base Price will become effective pursuant to Section 3.4.1, on or before June 5th of such Contract Year, Seller and Buyer shall each provide the other Party with information relating to contracts for the sale or purchase of coal, as applicable, that such Party has negotiated since January 1st of the Contract Year prior to the Contract Year in which negotiations are occurring. Such information provided by the Parties shall: (a) (i) as to information provided by Seller, be with respect to the sale of coal produced by the Mines and with a term of at least twelve (12) months beginning on or after January 1st of the prior Contract Year, and (ii) as to information provided by Buyer, be with respect to the purchase of coal for use at the Plant and with a term of at least twelve (12) months beginning on or after January 1st of the prior Contract Year; (b) to the extent allowed under the applicable contract, include copies of contracts entered into by such Party, redacted to exclude any identifying information as to the counterparty to such contract; and (c) include a summary of the relevant terms with respect to quantity, quality specifications and pricing of each contract where a Party is unable to provide a redacted copy of such contract due to restrictions imposed on such Party pursuant to such contract (it being understood that the Parties shall use commercially reasonable efforts to obtain the right to provide redacted copies of such contracts as contemplated herein). In the absence of the occurrence of sufficient transactions since January 1st of the Contract Year prior to the Contract Year in which negotiations are occurring, the Parties may rely upon other relevant market information to establish market prices to determine the Market Adjusted Base Price. Buyer and Seller shall have the right to have an independent auditor or consultant review the confidential information provided by the Parties pursuant to this Section 3.4.3, subject to a Party’s independent auditor or consultant having entered into a customary confidentiality agreement with the other Party prior to disclosure of any confidential information to such independent auditor or consultant.

3.4.4 If the Parties fail to reach agreement on the Market Adjusted Base Price by June 30th of the Contract Year prior to the Contract Year in which the Market Adjusted Base Price will become effective pursuant to Section 3.4.1, either Party may, by notice to the other Party, elect to begin binding arbitration proceedings to establish the Market Adjusted Base Price. Upon receipt of such notice, the Parties shall select a single neutral, independent arbitrator who

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is familiar with coal markets and coal market pricing. If the Parties fail to select an arbitrator within thirty (30) days of receipt of such notice, the Parties shall follow the process recommended by the American Arbitration Association to select a single, neutral, independent arbitrator who is familiar with coal markets and coal market pricing. Within thirty (30) days after the selection of the neutral arbitrator, the Parties shall each submit to the arbitrator and to the other Party, such Party’s proposed Market Adjusted Base Price and all reasonable supporting documentation demonstrating the basis on which the proposed Market Adjust Base Price was determined. Within fifteen (15) days after the initial submission of the proposed Market Adjusted Base Prices, the Parties shall each submit any rebuttal to the other Party’s proposed Market Adjusted Base Price, to the arbitrator and to the other Party. Within thirty (30) days after the submission of any rebuttals, or the last day of the fifteen (15) day period in which to submit rebuttals if no rebuttals are submitted, the arbitrator shall select the Market Adjusted Base Price proposed by one of the Parties as the Market Adjusted Base Price for the following Contract Year for the purposes of this Agreement, and shall notify the Parties in writing of the Market Adjusted Base Price that has been selected by the arbitrator. The arbitrator shall not have any authority to select any Market Adjusted Base Price other than the proposed Market Adjusted Base Price submitted by one of the Parties, and shall select the proposed Market Adjusted Base Price that most closely represents the arbitrator’s determination of the current market price of similar quality coal in the same market and sold under substantially similar terms and conditions.

3.4.5 Any information or documents exchanged or produced during the process of negotiating the Market Adjusted Base Price as described in this Section 3.4, including during any arbitration proceeding, and including any redacted contracts, summaries, or briefs or other documents prepared for the arbitration, shall be confidential and shall not be disclosed by the Parties, their employees, officers, directors, counsel, consultants, auditors or expert witnesses, as applicable, except to a court of relevant jurisdiction and then only to the extent necessary to enforce this Section 3.4 or any arbitration award, or as required by applicable laws or the rules of any stock exchange applicable to the Party making such disclosure, or in the case of Buyer to the Indiana Utility Regulatory Commission (the “IURC”). If a Party is required to disclose any such information or documents, such Party shall notify the other Party of the need to make such disclosure as soon as applicable and shall seek confidential treatment, and cooperate with the other Party in seeking confidential treatment, of any information that is disclosed.

ARTICLE 4

COAL QUALITY SPECIFICATIONS

4.1 Quality Specifications. The coal supplied under this Agreement shall meet the quality specifications set forth in Exhibit A on an “as received” basis.

4.2 Impurities. The coal supplied under this Agreement shall be washed coal, crushed to two inch (2") maximum top size, and shall be substantially free of impurities, such as bone, slate, rock, wood, metal and other mine debris.

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.4

4.3 Rejection; Suspension.

4.3.1 If based on the sampling and analysis described herein, the coal in a Shipment fails to comply with the Reject limits as set forth in Exhibit A for any one or more of the quality specifications identified therein, Buyer shall have the right, but not the obligation, to reject such Shipment by notice delivered to Seller by fax or email. In addition, Buyer shall have the right to reject any coal containing bone coal, rock, wood, metal or other mine debris in quantities which Buyer believes, in the exercise of Buyer’s good faith judgment, could be harmful to the Plant.

(a) In the event Buyer rejects any coal, Buyer shall promptly notify Seller of such rejection, such notice to be delivered within 48 hours of Buyer’s receipt of the short proximate analysis for the Shipment if rejection is based on the Shipment having exceeded any of the Reject limits as described in this Section 4.3, or within 24 hours of receipt of the Shipment at the Plant (or other destination designated by Buyer hereunder) if the rejection is based on the Shipment being contaminated with foreign materials. Buyer may reject discrete portions of a Shipment for foreign materials if practical under the circumstances.

(b) If Buyer fails to timely exercise its rights to reject a Shipment under this Section 4.3, Buyer shall be deemed to have waived such rights with respect to rejection of that Shipment only. Buyer’s failure to reject one or more Shipments under this Section 4.3 shall in no way affect its right to reject future Shipments or demand Seller’s strict performance with the requirements of this Section 4.3. If Buyer timely rejects a Shipment under this Section 4.3, Seller and Buyer shall cooperate in good faith to find an acceptable means for Seller to cure the problem so that Buyer can use such coal in the Plant. If the Parties are unable to find an acceptable means of curing the problem, Seller shall be responsible for promptly transporting the rejected coal to an alternative destination determined by Seller, at Seller’s cost, and the rejected coal shall not apply toward the Base Tonnage. In addition, Seller shall be responsible to reimburse Buyer for all reasonable out-of-pocket costs and expenses incurred by Buyer for the transportation of the rejected coal to the Plant. It is understood that Buyer shall not arbitrarily change its equipment in any way as to prevent Buyer from accepting coal and that Seller shall not arbitrarily change its mining, preparation, or loading operations in any way that would provide Buyer with an incentive to not accept the coal delivered by Seller hereunder.

(c) Seller shall, at Buyer’s option, replace the rejected coal as soon as possible, provided that Buyer gives notice to Seller of Buyer’s desire for replacement coal within 48 hours after rejection of a Shipment (or a part thereof).

4.3.2 Regardless of whether Buyer has actually exercised its right to reject any Shipments pursuant to Section 4.3.1: (i) if the coal delivered by Seller, as measured by the weighted average of all short proximate analyses in a given calendar month or the Monthly Composite Analysis (as defined in Section 6.2), fails to meet any of the monthly weighted average (“MWA”) quality specifications for [**] (other than with respect to the BTU/lb specification, for which Buyer’s sole remedy for failure of the coal to meet the MWA quality specification shall be the BTU Adjustment as provided in Section 3.2), or (ii) if in any thirty (30) day period, two (2) Shipments by railcar, or six (6) Shipments by truck, fail to comply with the Reject limits as

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.4

set forth in Exhibit A for any one or more of the quality specifications identified therein, as measured by the short proximate analysis, Buyer may by written notice to Seller suspend any further Shipments other than those already loaded into trucks or railcars; provided that in the case of a partially loaded train, Seller shall finish loading the railcars in such train.

(a) Within thirty (30) days after receipt of Buyer’s suspension notice pursuant to Section 4.3.2, Seller shall provide Buyer with reasonable assurances that subsequent deliveries of coal hereunder will meet the quality specifications on a MWA basis, and that subsequent Shipments of coal will comply with the Reject limits as set forth in Exhibit A for each of the quality specifications identified therein. In providing such assurances, Seller shall provide a reasonably detailed explanation for its failure to deliver coal that complies with the quality specifications as set forth in Exhibit A, and a reasonably detailed description of the remedial actions that Seller will undertake in support of its assurances. Buyer shall promptly review such assurances and respond to Seller within ten (10) days after receipt of such assurances. In reviewing the assurances provided by Seller, Buyer shall act in good faith and shall not unreasonably withhold acceptance of Seller’s assurances, or unreasonably delay the resumption of delivery of coal hereunder if such assurances are accepted. Buyer may require Seller to make-up deficiencies in the Base Tonnage for a Contract Year resulting from any such suspensions, subject to Seller’s right to dispute the validity and circumstances of such suspension, on a delivery schedule mutually agreed by the Parties.

(b) If Seller fails to provide assurances within the thirty (30) day period provided in Section 4.3.2(a) that are reasonably acceptable to Buyer, acting in good faith, Buyer may, in its sole discretion, terminate this Agreement by written notice to Seller.

(c) If Buyer terminates this Agreement pursuant to this Section 4.3, Seller shall reimburse Buyer the positive difference, if any, between (i) the purchase price and transportation costs on a cents per million BTU basis as transported to the Plant (without regard to Buyer’s right to designate alternate locations pursuant to Section 2.8) incurred by Buyer for Replacement Coal, and (ii) the sum, on a cents per million BTU basis, of the Base Price and transportation costs that Buyer incurs for transportation of the coal delivered hereunder to the Plant for each ton of coal remaining as of the date of termination to be delivered to Buyer hereunder during the Current Term (without regard to Buyer’s rights to increase the Base Tonnage pursuant to Section 2.2 or Section 2.3, other than increases for the relevant periods that have been declared by Buyer by written notice to Seller prior to the date of Buyer’s suspension notice pursuant to Section 4.3.2(a)). For purposes of this Agreement, the “Current Term” means, as applicable, the period beginning on the Effective Date and ending on December 31, 2016 if the Contract Year in which this Agreement is terminated occurs during such period, or the three (3) year period beginning on January 1, 2017 or any subsequent three (3) year period thereafter during the Term if the Contract Year in which this Agreement is terminated occurs during such three (3) year period. For purposes of this Agreement, “Replacement Coal” means, to the extent reasonably available, coal having similar quality specifications purchased under similar terms and conditions as this Agreement (excluding Buyer’s rights to extend the Term hereunder) that Buyer purchases, in an amount not to exceed the Base Tonnage (without regard to Buyer’s rights to increase the Base Tonnage pursuant to Section 2.2 or Section 2.3, other than increases for the relevant periods that have been declared by Buyer by written notice to Seller prior to the date of Buyer’s suspension notice pursuant to Section 4.3.2(a)) remaining as of the date of termination to

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.4

be delivered to Buyer hereunder during the Current Term; provided, however that any reasonable good faith purchase of coal to address Buyer’s short-term (i.e., 6 months or less) needs associated with a termination of this Agreement shall be considered Replacement Coal. Buyer shall use commercially reasonable attempts to acquire Replacement Coal at the lowest cost possible and shall take other reasonable steps to mitigate its damages, and shall provide reasonable documentation to Seller of the costs incurred. Payment of amounts, if any, determined under this Section 4.3.2(c) shall be made within 10 days following receipt of notice from Buyer of amounts owed.

4.3.3 OTHER THAN THE BTU ADJUSTMENT AS DETERMINED IN ACCORDANCE WITH SECTION 3.2, THE RIGHTS AND OBLIGATIONS OF THE PARTIES AS SET FORTH IN THIS SECTION 4.3 SHALL BE SELLER’S SOLE OBLIGATIONS AND BUYER’S SOLE AND EXCLUSIVE REMEDY AT LAW OR IN EQUITY FOR THE FAILURE OF COAL SOLD HEREUNDER TO MEET ONE OR MORE OF THE QUALITY SPECIFICATIONS AS SET FORTH IN EXHIBIT A.

4.4 Freeze Treatment Agent. Buyer shall have the right to require Seller to apply a freeze-treatment chemical agent to the coal delivered hereunder, and to the sides of railcars being used to transport the coal (collectively, “Freeze Treatment”). On or before November 1st of each year, Seller shall notify Buyer of the type of chemical agent to be used in the Freeze Treatment, the manufacturer of the chemical agent, and the cost per gallon of the chemical agent that will be used by Seller, and shall provide Buyer with a copy of the MSDS sheet of such chemical agent. Buyer shall provide Seller with reasonable advance notice of the dates for starting and ending the Freeze Treatment, and the temperature to which Buyer requests Freeze Treatment (e.g., 10°F below the expected low temperature), for Seller’s use in determining application rates. Seller shall invoice Buyer monthly in accordance with Section 7.1 for the cost of the Freeze Treatment provided by Seller, which shall be equal to (a) (i) Seller’s actual cost per gallon for the chemical agent used, multiplied by (ii) the gallons of chemical agent applied to each Shipment of coal hereunder during the prior calendar month, plus (b) an application fee of [**] of the total cost determined pursuant to subparagraph (a) of this Section 4.4.

ARTICLE 5

WEIGHING

5.1 Weighing. Determination of weights of coal delivered hereunder for payment purposes shall be based on weights obtained at the Mines. Coal shipped by railcar shall be weighed at the relevant Mine on a certified batch weigh load out system. Coal transported by truck shall be weighed at the relevant Mine by Seller’s certified truck scales.

5.2 Scales. All scales referred to herein shall be operated and maintained to be in conformance with the National Institute of Standards and Technology (NIST) Handbook 44, or the applicable Standards of the Association of American Railroads (AAR). Seller shall provide copies of all scale certification test reports to Buyer upon request. Seller shall promptly notify Buyer if Seller believes its scales have experienced a failure or are unavailable, or are inaccurate.

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.4

5.3 Unavailability; Inaccuracies.

5.3.1 If weights from Seller’s scales are not available for a Shipment due to failure, mechanical or otherwise, of Seller’s scales, or if Seller has determined that its scales are inaccurate, weights for such Shipments will be obtained from Buyer’s scales and the weights so determined shall be the governing weights for payment purposes; provided that Buyer’s scales shall be certified and maintained in accordance with the standards as referenced in Section 5.2. For rail shipments, if no other weights are available, the average per car weight of the previous three train deliveries shall be the weight used for payment purposes.

5.3.2 If either Party believes the other Party’s scales to be in error beyond acceptable tolerance, that Party shall notify the other of such discrepancy and its apparent duration as soon as practicable, and the Party owning or controlling the scale in question shall have such scale tested for accuracy. The other Party shall have the right to be present during such test. Should such test reveal an inaccuracy which exceeds permitted tolerances, the weights from the time first stated in the notice until the testing and calibration of such scales shall be adjusted by the percentage of inaccuracy discovered by such testing.

ARTICLE 6

SAMPLING AND ANALYSIS

6.1 Sampling. Coal samples to be used for determination of coal quality for coal delivered to Buyer hereunder shall be taken by Seller at the Mine in conformance with applicable American Society for Testing Materials (“ASTM”) standards. For deliveries by truck, governing coal samples shall be a representative composite of trucks loaded daily, taken by Seller at the Mine using sampling methods in accordance with applicable ASTM standards, or by use of such other methods as may be mutually agreed upon by the Parties. For coal delivered by rail car, governing coal samples shall be obtained using an automatic sampling system in accordance with methods approved by the ASTM or such other methods as may be mutually agreed upon by the Parties. Each calendar month, Seller shall collect a composite sample representative of the coal delivered in that particular month (the “Monthly Composite Sample”) for the purpose of preparing a Monthly Composite Analysis, as defined in Section 6.2 below.

6.2 Analysis. For purposes of this Agreement, the governing analysis of coal samples collected by Seller shall be performed by Standard Laboratories in Evansville, Indiana. All governing analyses performed shall be done in accordance with ASTM standards. Seller shall direct Standard Laboratories to conduct a short proximate analysis of such coal samples and provide the results of such analysis to Buyer at the same time that such results are provided to Seller. If Standard Laboratories fails to deliver any such analytical results to Buyer, Seller shall deliver a copy of such analytical results to Buyer as soon as possible after Buyer’s request. Seller shall or shall cause Standard Laboratories to also provide quick analyses to Buyer for each Shipment. Seller shall use commercially reasonable efforts to cause Standard Laboratories to provide the results of its quick analysis within twenty four (24) hours of delivery of the Shipment, or as soon as reasonably practicable. Each calendar month, Seller shall direct Standard Laboratories to analyze the [**] (as set forth in Exhibit A) of the Monthly Composite Sample (the “Monthly Composite Analysis”), which

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.4

Standard Laboratories shall provide to Seller and Buyer as soon as reasonably practicable. If Buyer requires monthly analysis of any of the other quality specifications set forth on Exhibit A, Buyer shall provide Seller with reasonable advance notice and Seller shall direct Standard Laboratories to perform the relevant analyses for such additional specifications as part of the Monthly Composite Analysis for that particular month. Not more than once every six calendar months, Buyer may request, and Seller shall cause Standard Laboratories to conduct, a Full Proximate Analysis of the Monthly Composite Sample and such analysis shall be treated as the Monthly Composite Analysis for that particular month. Seller shall require Standard Laboratories to retain samples for thirty (30) days after such results are submitted to Seller, during which period Buyer may request from Seller a split of such samples for purposes of conducting its own analyses. If Buyer does not give Seller notice within such thirty (30) day period that, based on analysis of such split by Buyer, Buyer disagrees with Seller’s analysis, then Seller’s analysis shall apply to all of the Coal in the Shipment from which the sample was taken and shall be the binding basis for any BTU Adjustments and for the exercise of Buyer’s rights to reject coal pursuant to Section 4.3. Buyer’s notice of disagreement with the analyses received from Standard Laboratories, if any, shall be accompanied by the results of Buyer’s analysis. If the Parties cannot reach agreement on the analysis within thirty (30) days following Seller’s receipt of Buyer’s notice, the dispute shall be settled by an analysis performed by a commercial testing laboratory mutually agreed upon by the Parties, and the results of those tests shall be final and binding on the Parties. In the event of a dispute, the cost of the analysis made by such commercial testing laboratory shall be shared equally by the Parties. Until such dispute is resolved, Buyer shall be responsible for payment based on the results of Seller’s analysis.

6.3 Alternatives. In the event that a Shipment of coal is not sampled at a Mine, or a sample is lost or has obviously been contaminated, Seller shall notify Buyer as promptly as practicable. Unless the Parties agree on an alternate sampling method, analytical results obtained from the weighted average quality of the three (3) previous Shipments to Buyer from such Mine will be used as representative of the quality of the Shipment not sampled at such Mine.

ARTICLE 7

INVOICING AND PAYMENT

7.1 Invoicing. Seller will prepare and submit invoices to Buyer via e-mail twice each calendar month. Seller shall submit one invoice to Buyer on or before the fifth (5th) day of each calendar month, which invoice shall include the coal delivered during the period from the sixteenth (16th) day of the prior calendar month to the last day of the prior calendar month, plus any BTU Adjustment for the prior calendar month as determined in accordance with Section 3.2, plus any Freeze Treatment costs for Shipments made during the prior calendar month determined in accordance with Section 4.4, plus any applicable Carlisle Deduction or Alternate Source Deduction determined in accordance with Section 1.4. Seller shall submit one invoice to Buyer on or before the twentieth (20th) day of each calendar month, which invoice shall include the coal delivered during the period from the first (1st) day of such calendar month to the fifteenth (15th) day of such calendar month, plus any applicable Carlisle Deduction or Alternate Source Deduction determined in accordance with Section 1.4.

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.4

7.2 Payment. Payment with respect to each invoice submitted by Seller hereunder shall be due no later than ten (10) days after Buyer’s receipt of such invoice. All payments will be made by ACH wire transfer of immediately available funds to the bank account as shown on Seller’s invoice.

7.3 Offset. If each Party is required to pay an amount to the other Party in the same month, then such amounts with respect to each Party shall be aggregated and the Parties shall discharge their obligations to pay through netting; in which case, the Party owing the greater aggregate amount shall pay to the other Party the difference between the amounts owed.

ARTICLE 8

FORCE MAJEURE

8.1 Impact of Force Majeure. If because of a Force Majeure Event, either Party is unable to carry out any of its obligations under this Agreement (other than any obligation to pay or expend money in connection with performance hereunder), and provided such Party promptly gives notice to the other Party of the existence of any such Force Majeure Event, then the obligations of the Party affected by such Force Majeure Event (other than any obligation to pay or expend money in connection with performance hereunder) shall be suspended to the extent made necessary by such Force Majeure Event and during its continuance, provided that the Party subject to such Force Majeure Event shall make all reasonable efforts to mitigate the impact of the Force Majeure Event and remove it with all reasonable dispatch.

8.2 Force Majeure Event. A “Force Majeure Event” as used herein means any cause beyond the reasonable control of the Party affected thereby, including but not limited to: acts of God, acts of the public enemy, insurrections, riots, terrorism, labor disputes, strikes, lockouts, boycotts, labor and material shortages, fires, explosions, landslides, earthquakes, storms, roof falls, rib falls, cave-ins, floods, aquifers, floor conditions, breakdowns of or damage to equipment or facilities, interruptions to transportation or shortages of transportation equipment, embargoes, blockades, acts of military authorities, inability to obtain permits or authorization from any government authority, any laws, orders, rules, regulations, enforcement proceedings or other acts or restraint of governmental authority, unexpected mining conditions including unforeseen changes in the coal seam, or faults or sandstone intrusions in the coal seam, and other cause including unsafe working conditions, or unscheduled outages and other unexpected disruptions at the Plant that exceed seven (7) days in duration, whether of the kind or character herein enumerated or otherwise, which is not within the control of the Party claiming excuse, whether or not foreseen or foreseeable, which wholly or partly renders the mining removal, processing or loading of all or part, of the normal output of the Mines impractical or unfeasible, or renders the accepting, utilizing, unloading, or intended use of the coal impossible, impractical or unfeasible, and which are not caused by acts or omissions of the Party failing to perform. Settlement of labor disputes shall be deemed beyond the control and without the fault or negligence of the Party experiencing such event. Seller’s ability to sell coal at a more advantageous price, Buyer’s ability to buy coal at a more advantageous price, or the change in the market price of coal, price of power, or other related costs, shall not constitute a Force Majeure Event.

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.4

8.3 Mitigation. Prior to deeming any legislation or regulation a Force Majeure Event, the Parties shall consider what steps can be taken by Buyer in the handling, transportation and use of the coal, or by Seller in the production, processing, preparation and loading of the coal. If no such practicable solution to the problem is presented by either Party, such legislation or regulation may constitute a Force Majeure Event. A Force Majeure Event shall not in any event include a lack of sufficient financial means to perform obligations or the failure to make payments in accordance with this Agreement. During the continuation of a Force Majeure Event, the other Party may make arrangements to sell or purchase the estimated quantity of coal so affected for the estimated duration of the Force Majeure Event.

8.4 Make-Up. In the event that a Force Majeure Event occurs, the delivery of the affected quantity of coal shall be made up by the Parties during the Contract Year in which such Force Majeure Event occurred, unless not reasonably practicable, in which case the delivery of the affected quantity of coal shall be made-up as soon as practicable in the following Contract Year; provided that coal delivered in the following Contract Year shall be applied first to make-up deliveries affected by a Force Majeure Event. Coal delivered pursuant to this Section 8.4 shall be delivered on a delivery schedule agreed to by the Parties, and the Base Price to be paid by Buyer for coal delivered pursuant to this Section 8.4 shall be the Base Price in effect when the applicable Force Majeure Event occurred.

8.5 Allocation in Event of Partially Reduced Capability. If a Force Majeure Event occurs and results in, or is reasonably projected to result in: (i) a reduction or limitation of Seller's ability to supply coal from a Mine, or (ii) the inability of Buyer to accept or utilize coal at the Plant, then in the case of Seller, Seller shall allocate available supplies of coal from Seller's Mines on a pro-rata basis among its customers, or others as required by law, to the extent that its contracts with other customers give Seller the right to reduce its supply obligations as a result of the Force Majeure Event. In the case of Buyer, Buyer shall spread its reduced ability to accept or utilize coal at the Plant among all its suppliers of coal to the Plant, committed at the time the Force Majeure Event occurred, on a pro-rata basis to the extent that its contracts with other suppliers give Buyer the right to reduce its purchase obligations as a-result of the Force Majeure Event. Any such allocation shall be determined on the basis of the number of tons of coal which Seller is obligated to deliver to its committed customers, or Buyer is obligated to receive from its committed suppliers, at the time the Force Majeure Event occurred.

8.6 Suspension; Termination. If due to a Force Majeure Event, a Party is unable to deliver or accept any coal hereunder, such Force Majeure Event continues for a continuous period of ninety (90) days or longer, and such event or events cannot be reasonably eliminated or are not likely to terminate within a reasonable period of time, the other Party shall, at any time after such ninety (90) day period and while such Force Majeure Event suspension continues, have the right, at its option, to terminate this Agreement by giving thirty (30) days written notice of termination to the Party claiming the Force Majeure Event. Other than outstanding payments due hereunder, no damages or compensation shall be paid by either Party because of such termination and such termination shall not be subject to the provisions of Article 12.

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.4

ARTICLE 9

REPRESENTATIONS AND WARRANTIES

9.1 Representations; Warranties. As a material inducement to entering into this Agreement, each Party hereby represents and warrants to the other Party as of the date on which this Agreement is executed, as follows:

9.1.1 Such Party is a corporation duly organized, legally existing and in good standing under the laws of the jurisdiction of its incorporation; it has all requisite corporate power, and has all material governmental licenses, authorizations, consents and approvals necessary to own its assets and carry on its business as now being conducted; and it is qualified to do business in those jurisdictions necessary to perform this Agreement.

9.1.2 There are no bankruptcy proceedings pending or being contemplated by it, or to its knowledge, threatened against such Party.

9.1.3 Neither the execution and delivery of this Agreement, nor compliance with the terms and provisions hereof will conflict with or result in a breach of, or require any consent which has not been obtained as of the effective date of this Agreement under such Party’s charter, by-laws or operating agreement, any governmental requirement, or any agreement or instrument to which it is a party or by which it is bound or to which it or its properties are subject, or constitute a default under any such agreement or instrument.

9.1.4 Such Party has all necessary corporate power and authority to execute, deliver and perform its obligations under this Agreement; the execution, delivery and performance by it of this Agreement has been duly authorized by all necessary corporate action, as applicable, on its part; and this Agreement constitutes the legal, valid and binding obligations of such entity, enforceable against such entity in accordance with its terms, except as the same may be limited by applicable bankruptcy, insolvency, reorganization, moratorium or similar laws in effect from time to time relating to or affecting the enforcement of creditors’ rights generally and by general principles of equity.

9.1.5 No authorizations, approvals or consents of, and no filings or registrations with, any governmental authority are necessary for the execution, delivery or performance of this Agreement by such Party or for the validity or enforceability thereof.

9.1.6 Seller represents and warrants that it holds all necessary legal rights to sell to Buyer coal sufficient in quantity and quality to perform its obligations under this Agreement for the term hereof, and that Seller will hold good and marketable title to all coal that it sells hereunder.

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.4

ARTICLE 10

COMPLIANCE WITH LAW

Seller shall be in material compliance with all applicable laws and regulations in the

performance of its obligations under this Agreement, including all environmental requirements in the mining, processing and storing of coal.

ARTICLE 11

INDEMNIFICATION

Seller shall defend, indemnify and hold harmless Buyer and its affiliates, directors, officers, employees and agents from and against all claims, demands, losses, damages, liabilities, obligations and costs (including reasonable attorneys’ and other litigation fees and expenses) (collectively “Claims”) arising out of or relating to personal injury to third parties or third party property damage resulting from the acts or omissions of Seller or its agents in the performance of this Agreement, without regard to which Party has title to the coal pursuant to Section 1.5, except to the extent such injury or damage arises out of the negligent acts or omissions of Buyer or its agents. Buyer shall defend, indemnify and hold harmless Seller and its directors, officers, employees and agents from and against all Claims arising out of or relating to personal injury to third parties or third party property damage resulting from the acts or omissions of Buyer or its agents in the performance of this Agreement, without regard to which Party has title to the coal pursuant to Section 1.5, except to the extent such injury or damage arises out of the negligent acts or omissions of Seller or its agents.

ARTICLE 12

DEFAULT, REMEDIES, AND TERMINATION

12.1 Default. In the event a Party shall: (i) make an assignment or any general arrangement for the benefit of creditors; (ii) file a petition or otherwise commence, authorize, or acquiesce in the commencement of a proceeding or case under any bankruptcy or similar law for the protection of creditors or shall have such a petition filed or proceeding commenced against it and such proceeding is not dismissed within sixty (60) days; (iii) otherwise become bankrupt or insolvent (however evidenced); (iv) be unable to pay its debts as they fall due; (v) have a receiver, provisional liquidator, conservator, custodian, trustee, or other similar official appointed with respect to it or substantially all of its assets; (vi) fail to perform any material obligation to the other Party with respect to this Agreement on or before the thirtieth (30th) day after written notice of such failure from the other Party is received (other than a failure of the coal to meet one or more of the quality specifications set forth in Exhibit A, for which the sole and exclusive rights, obligations and remedies are as set forth in Section 4.3 and, if applicable, Section 3.2); or (vii) not have paid any amount due the other Party hereunder on or before the tenth (10th) day following written notice that such payment is due, such Party shall be the “Defaulting Party” and such event shall be an “Event of Default” hereunder.

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.4

12.2 Remedies. The other Party that is not suffering the Event of Default (the “Non-Defaulting Party”) may, for so long as the Event of Default is continuing, (a) establish by written notice to the Defaulting Party a date, which shall be no earlier than thirty (30) days following the date of such notice, on which this Agreement shall terminate and withhold any payments due from and after the date of such notice in respect of this Agreement, subject to the rights of the Defaulting Party to dispute such termination and withholding in accordance with Article 14; and (b) suspend performance of its obligations under this Agreement, until the Event of Default is cured; provided that if the Event of Default is not cured in the time allowed under Section 12.1, or within thirty (30) days if no specific time period for cure is stated in Section 12.1, the Non-Defaulting Party may terminate this Agreement in accordance with subparagraph (a) of this Section 12.2. The termination of this Agreement pursuant to this Section 12.2 is not an exclusive right, but is in addition to any other rights recognized at law or in equity which may accrue to one Party or the other by reason of circumstances and conditions that are not the subject of an exclusive right that is specifically stated herein.

12.3 Termination by Buyer or Seller. Notwithstanding the Effective Date of this Agreement, if Seller does not become an affiliate of Sunrise Coal, LLC, an Indiana limited liability company, on or before December 31, 2014, either Buyer or Seller may terminate this Agreement immediately upon written notice to the other Party. Neither of the Parties shall have any obligation to the other hereunder following the termination of this Agreement pursuant to this Section 12.3.

12.4 Termination by Buyer.

12.4.1 In the event that Buyer determines that it [**], Buyer shall promptly notify Seller in writing. The Parties shall in good faith attempt to resolve the problem in a manner that would allow Buyer to [**]. If after six (6) months, the Parties have not reached agreement on a mutually acceptable solution, Buyer shall have the right to terminate this Agreement as of such date after which it [**], by given written notice of such termination to Seller. Buyer shall use good faith efforts to give Seller as much prior notice of termination as practicable. Nothing herein shall be construed as requiring Buyer to incur any significant added expense or significant capital investment to [**]. Neither of the Parties shall have any obligation to the other hereunder following the date of such termination, except with respect to matters occurring prior to the date of termination.

12.4.2 As a regulated utility, Buyer engages in [**]. In the event [**] directs Buyer to [**], Buyer may terminate this Agreement by giving Seller no less than one (1) year advance written notice of such termination, in which event this Agreement will terminate on the date specified in Buyer’s notice; provided that such date shall not be any earlier than the date on which Buyer [**]. In the event [**] directs Buyer to [**], Buyer may reduce the Base Tonnage of coal to be supplied hereunder by giving Seller no less than one (1) year advance written notice of such reduction; provided [**]. Neither of the Parties shall have any obligation to the other hereunder following the date of such termination, except with respect to matters occurring prior to the date of termination.

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.4

12.5 Termination by Seller. Notwithstanding Buyer’s extension of the Term of this Agreement pursuant to Section 1.1, if after the first extension of the Term of this Agreement pursuant to Section 1.1, Seller intends to permanently cease production from any of the Mines during the three (3) year period of any on-going or pending extension term (other than the first extension of the Term of this Agreement pursuant to Section 1.1), and Seller determines in its reasonable discretion that it will not be able to supply the Base Tonnage from the other Mines once such Mine ceases production, Seller may reduce the Base Tonnage by giving Buyer no less than one (1) year advance written notice of such reduction in the Base Tonnage hereunder to an amount equal to the amount of coal meeting the quality specifications that Seller reasonably expects to be able to deliver during the remaining Term of this Agreement and any remaining extensions hereunder, taking into account the quantity of uncommitted coal, and the quality specifications of such coal, that Seller expects to produce at the other Mines as of the date that Seller ceases production at the Mine in question; provided that in no event shall the Base Tonnage exceed 40% of the total production from the remaining Mines. If Seller does not expect to produce more than a de minimis amount of coal in excess of Seller’s commitments to other coal purchasers, Seller’s notice to Buyer may instead give Buyer notice of the date on which this Agreement will terminate. If Seller has elected to reduce the Base Tonnage hereunder, this Agreement shall continue in accordance with its terms and conditions. In determining the extent of the reduction in the Base Tonnage upon shutdown of a Mine, Seller shall not give any of its other customers any priority over Buyer with respect to the purchase of any uncommitted coal that Seller has available at such time. Nothing herein shall be construed as requiring Seller to (i) incur any significant added expense or significant capital investment to continue the production of coal from the Mine in question, or (ii) reserve or withhold any coal from the other Mines from any of its other customers in order to have uncommitted coal available for Buyer hereunder. Neither of the Parties shall have any obligation to the other hereunder following the date of such termination, except with respect to matters occurring prior to the date of termination.

12.6 Consequential Damages. Neither Party shall be liable to the other Party for any special, consequential or punitive damages, loss of profit, loss of customers, loss of revenues, loss of productivity, loss of goodwill or loss of use arising out of the performance, breach or nonperformance of this Agreement by such Party, irrespective of any legal theory under which the same may otherwise be asserted, except to the extent that third party claims with respect to which a Party is indemnified hereunder are deemed to constitute such damages.

ARTICLE 13

RECORDS; AUDITS

13.1 Records. Seller shall establish and maintain, subject to modification from time to time as may be required by Seller, a system of accounting such that all information which must be provided to Buyer as part of this Agreement shall be determinable by accounting periods

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regularly used by Seller. Such system shall be in accordance with generally accepted accounting principles consistently applied, and appropriate to permit the development of the invoices, accountings and other documentation required by this Agreement.

13.2 Audit Rights. Upon reasonable notice and during normal business hours, each Party and its designated independent auditors, shall have the right to inspect the other Party’s books and records relating to all provisions of this Agreement, which include coal quality, quantity shipped and quantity received, price adjustments, or as may be necessary to satisfy inquiries from governmental or regulatory agencies, but only to the extent necessary to verify the accuracy of any statement, charges, payments or computations made pursuant to this Agreement. Each Party shall make a reasonable effort to facilitate the other Party’s inspection of such records in its possession. The Party conducting the inspection and its auditors, to the extent permitted by law or regulation, shall treat all such information as confidential. Any such audit shall in any event be conducted during the 12 months after the date of the report, accounting or statement provided that is subject to such audit.

13.3 Inspections. Buyer and its duly authorized representatives shall upon reasonable advance notice and during normal operating hours, have the right to inspect the Mines and Seller’s related coal preparation, loading and other related facilities. Buyer’s inspections shall be performed in a reasonable manner and without interfering with Seller or Seller’s operations at the Mine. Buyer shall cause each of its representatives that perform such inspections to participate in any required safety training, sign appropriate waivers and comply with all of Seller’s safety and security policies then in effect at the Mines.

13.4 Confidential Nature of Records. Buyer recognizes that the records to be maintained by Seller under this Article 13, and the information provided by either party in the course of an audit are confidential and proprietary in nature. Accordingly, each Party agrees that no information obtained in an audit or inspection will be disclosed without prior consent in writing from the other Party, except to the extent a Party is legally compelled to make such disclosure pursuant to applicable law, or to establish a claim or defense on behalf of Buyer in a Dispute between Buyer and Seller. Buyer shall in any event seek confidential treatment of such information prior to making any such disclosure.

ARTICLE 14

DISPUTE RESOLUTION

14.1 Dispute Notice. Except for disputes regarding the determination of the Market Adjusted Base Price, which shall be settled in accordance with Section 3.4, any controversy, claim, counterclaim, dispute, difference or misunderstanding arising out of or relating to the interpretation or application of this Agreement (a “Dispute”), shall be resolved by the Parties in accordance with this Article 14. In the event of a Dispute, either Party may provide written notice to the other of the existence of a Dispute. Such notice shall state the nature or subject of the Dispute, and the notifying Party’s position thereon. The Parties shall, for a period of thirty (30) days following the date of such notice, engage in good faith discussions and negotiations in an attempt to resolve such Dispute.

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.4

14.2 Escalation. In the event no resolution is reached in the preliminary thirty (30) day period as described in Section 14.1, either Party may, following the expiration of the original thirty (30) day period, designate by written notice, a member of such Party’s senior management for further discussions and negotiations. Within five (5) business days of receipt of that designation, the other Party shall designate by written notice, a member of its senior management to participate in such further discussions and negotiations. Commencing on receipt of this second designation, an additional twenty (20) day period shall commence during which the designated senior management from both Parties, together with such assistance as they may deem appropriate, shall engage in good faith discussions and negotiations to resolve the Dispute. In the event that the discussions and negotiations involving senior management during such additional twenty (20) day period produces no resolution, either Party may submit the Dispute to binding arbitration in accordance with Section 14.3.

14.3 Arbitration. In the event the Parties are unable to resolve a Dispute pursuant to Section 14.1 or Section 14.2, either Party may demand an arbitration proceeding by written demand to the other Party and the appropriate office of the American Arbitration Association (the “AAA”). All arbitration proceedings shall take place in Indianapolis, Indiana under the auspices of the AAA in accordance with the Federal Arbitration Act and the AAA Commercial Arbitration Rules then in effect, subject to the specific provisions of this Section 14.3.

14.3.1 For all Disputes where the amount or value of the Dispute is less than $1,000,000, the arbitration proceeding shall be conducted by a single neutral arbitrator selected by Buyer and Seller (or the AAA if the Buyer and Seller cannot agree within twenty (20) days) of the demand for arbitration. For all Disputes where the amount or value of the Dispute is equal to or more than $1,000,000, the arbitration proceeding shall be conducted by a panel of three (3) neutral arbitrators, one of which shall be selected by Buyer, and one of which shall be selected by Seller. Buyer and Seller shall mutually select the third neutral arbitrator. If the arbitration is to be conducted by a panel of three (3) arbitrators, and the Parties have not each appointed a neutral arbitrator and agreed on the third arbitrator on or before thirty (30) days following the delivery of a demand for arbitration, then either Party may request that the AAA designate any remaining arbitrators pursuant to its Commercial Arbitration Rules and such designation shall be binding on the Parties.

14.3.2 The arbitration decision shall be by majority vote if the arbitration proceeding is conducted by a panel, and shall be issued in a writing that sets forth in separately numbered paragraphs all of the findings of fact and conclusions of law necessary for the decision. Findings of fact and conclusions of law shall be separately designated as such. The arbitrator(s) shall not be entitled to deviate from the construct, procedures or requirements of this Agreement. Any decision rendered by the arbitrator(s) in any arbitration shall be final and binding upon the Parties, and judgment may be entered on the award in any court of competent jurisdiction. The cost of the arbitration shall be borne equally by the Parties.

14.3.3 Each Party shall be entitled to be represented by counsel in any such arbitration proceeding, to present written and oral evidence and arguments, to cross-examine the other Party’s witnesses, and to obtain a list of the other Party’s witnesses and evidence no less than fourteen (14) days prior to the hearing. The formal rules of evidence shall not apply, but the arbitrator(s) may be guided by the Federal Rules of Evidence in conducting the proceeding. The

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arbitrator(s) shall permit and facilitate such disclosure and discovery of facts, documents and tangible things as the arbitrator(s) shall determine is appropriate in the circumstances, taking into account the needs of the Parties and the desirability of making disclosure expeditious and cost-effective. The arbitrator(s) may issue orders to protect the confidentiality of proprietary information, trade secrets and other sensitive information disclosed.

14.4 Extensions. The Parties may agree, in writing, to extend any time period provided for in this Article 14.

ARTICLE 15

MISCELLANEOUS

15.1 Notices. Any notice, request, consent, demand, report, or statement which is given or made under any of the provisions of this Agreement shall be in writing unless otherwise provided herein, and shall be treated as duly delivered when the same is either personally delivered to the Party to whom directed, when sent by United States certified mail with all necessary postage prepaid and a return receipt requested, when sent by a nationally recognized overnight delivery service with charges fully prepaid, or when sent by electronic mail or facsimile with confirmation of receipt, and addressed to the respective Party at the below specified address:

Notices to Buyer

Southern Indiana Gas and Electric Company

One Vectren Square

Evansville, IN 47708

Attn: Wayne D. Games

E-mail: wdgames@Vectren.com

Fax: 812.491.4684

With a copy to:

Robert E. Heidorn

Senior Vice President and General Counsel

Vectren Corporation

One Vectren Square

Evansville, IN 47741

E-mail: rheidorn@Vectren.com

Fax: 812.491.4238

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.4

Notices to Seller

Vectren Fuels, Inc.

One Vectren Square

Evansville, IN 47741

Attn: Randy Beck

Either Party may update or modify the address(es) to whom notice shall be sent hereunder from time to time, by written notice to the other Party as provided above.

15.2 Successors and Assigns. This Agreement shall inure to the benefit of and be binding upon the Parties hereto and their respective successors and assigns.

15.3 Assignment. This Agreement may not be assigned by either Party without the written consent of the other Party, not to be unreasonably withheld or delayed. Notwithstanding the foregoing, either Party may without the written consent of the other Party, assign or otherwise transfer this Agreement (a) in the case of Seller, to an affiliate of such Party; (b) to a successor to all or substantially all of such Party’s assets; provided that such successor has a financial condition at least equivalent to that of the assigning Party; (c) in the case of Buyer, to a successor to all or substantially all of the property and assets comprising the Plant; (d) to secure such Party’s indebtedness incurred or to be incurred for the purposes of or in connection with the performance of this Agreement; and (e) to one or more persons, firms or corporations who shall assume the obligation of the transferring Party hereunder in connection with the enforcement of any assignment or transfer referred to in subparagraph (d) of this Section 15.3. The Party making any such permitted assignment or transfer hereunder shall give the other Party ten (10) days written notice of such assignment or transfer. Except with respect to an assignment pursuant to subparagraph (d) of this Section 15.3, no assignment under this Agreement shall be effective until the assignee, in writing delivered to the non-assigning Party, has agreed to accept the assignment and to be bound by all the terms and conditions in this Agreement.

15.4 Survival. The terms and provisions of this Agreement regarding payment and indemnity shall survive the expiration or the termination of this Agreement indefinitely. The terms and provisions of this Agreement regarding records and confidentiality shall survive the expiration or the termination of this Agreement for a period of five (5) years.

15.5 Waivers. The failure of a Party to insist in any one or more instances upon strict performance of any provisions of the Agreement by the other Party, or to take advantage of any of its rights hereunder, shall not be construed as a waiver by such Party of any such provision or the relinquishment by such Party of any such rights in respect of any subsequent nonperformance of such provision, but the same shall continue and remain in full force and effect.

15.6 Severability. The provisions of this Agreement are severable, and the invalidity or unenforceability of any one or more provision shall not affect or limit the validity of the remaining provisions. Should any particular provision be held to be unreasonable or unenforceable for any reason, then such provision shall be given effect and enforced. to whatever extent would be reasonable and enforceable under the applicable law.

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.4

15.7 Governing Law. This Agreement and any questions concerning its validity, construction, interpretation or performance shall be governed by the laws of the State of Indiana without reference to any other choice of law provisions. Any action which may be commenced based on, arising from or related to this Agreement shall be brought only in the federal or state courts sitting in the State of Indiana.

15.8 Headings. The captions of Articles and Sections in this Agreement are for convenience of reference only and shall not be taken or construed to define or limit any of the terms or provisions of this Agreement.

15.9 Confidentiality. Each Party acknowledges that this Agreement contains confidential information, which could put the other Party at a competitive disadvantage in its purchasing and sales activities, if disclosed to the public. Therefore, this Agreement and its terms shall be kept confidential and shall not be disclosed to any third party, except (a) as required by law or governmental or judicial order, including as required by the IURC, (b) pursuant to securities laws and regulations applicable to a Party, (c) as mutually agreed to by the Parties hereto; provided that this Section 15.9 shall not be construed to prohibit disclosure of this Agreement and its terms to a Party’s affiliates and its directors, employees, advisors, lenders, counsel, accountants, representatives, and prospective purchasers, solely for the purpose of evaluating, negotiating, and consummating the transactions contemplated by the Parties under this Agreement, and who have been notified of such Party’s confidentiality obligations hereunder. Each Party shall be responsible for any disclosure of this Agreement or its terms by any of such persons or entities that receive such information from such Party. If a Party reasonably believes it is required to disclose this Agreement or any of its terms pursuant to subparagraph (a) or (b) of this Section 15.9, such Party shall promptly notify the other Party, shall seek confidential treatment of any information that is disclosed, shall disclose only that part of the information that such Party is advised by counsel is required to be disclosed, and shall cooperate with the other Party’s reasonable attempts to obtain confidential treatment of this Agreement and any terms that may have been disclosed. This Section 15.9 shall not apply to information, including redacted copies of other coal supply agreements entered into by a Party, provided by a Party in connection with the Market Price Adjustments contemplated in Section 3.4, which shall be subject to the requirements of Section 3.4.5.

15.10 Guarantee. Unless this Agreement is terminated pursuant to Section 12.3, within ten (10) days after Seller becomes an affiliate of Sunrise Coal, LLC, if at all, Seller shall in its sole discretion, either assign this Agreement to Sunrise Coal, LLC and notify Buyer accordingly, or deliver to Buyer, and thereafter maintain until such time as this Agreement is assigned to Sunrise Coal, LLC (or its successor), a guarantee by Sunrise Coal, LLC (or its successor) of Seller’s obligations hereunder substantially in the form set forth in Attachment 2 to this Agreement. Notwithstanding anything to the contrary in the foregoing or in Section 15.3(a) or Section 15.3(e), (i) if this Agreement is assigned to Sunrise Coal, LLC and subsequently assigned to an affiliate of Sunrise Coal, LLC (or its successor), Seller shall as a condition to such assignment, deliver to Buyer and thereafter maintain until such time as this Agreement is assigned to Sunrise Coal, LLC (or its successor), a guarantee by Sunrise Coal, LLC (or its successor) of Seller’s obligations hereunder substantially in the form set forth in Attachment 2 to this Agreement; (ii) if (A) Seller has the obligation to deliver a guarantee by Sunrise Coal, LLC pursuant to this Section 15.10, (B) Sunrise Coal, LLC no longer directly or indirectly holds all of

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the Mines, and (C) the financial condition of Sunrise Coal, LLC is no longer equivalent to or better than the financial condition of Sunrise Coal, LLC as of the Effective Date, and (iii) if this Agreement is assigned pursuant to Section 15.3(c) and the financial condition of the assignee is not equivalent to or better than the financial condition of Sunrise Coal, LLC as of the Effective Date, then Seller or such assignee, as applicable, shall, in lieu of delivering a guarantee by Sunrise Coal, LLC (or its successor), deliver to Buyer and thereafter maintain a guarantee of Seller’s obligations hereunder substantially in the form set forth in Attachment 2 to this Agreement by an affiliate of Sunrise Coal, LLC (or its successor) with a financial condition equivalent to or better than the financial condition of Sunrise Coal, LLC as of the Effective Date, or such other form of financial security as is reasonably acceptable to Buyer.

15.11 Entire Agreement. This Agreement contains the complete and exclusive embodiment of the Parties’ agreement as to matters herein referenced, and supersedes all other or prior agreements with respect thereto. No amendments or modifications hereto shall be binding unless in a writing signed by each of the Parties.

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.4

IN WITNESS WHEREOF, Buyer and Seller have caused this Agreement to be executed by their respective officers as of June 30, 2014.

SELLER

VECTREN FUELS, INC.

By:     /s/ Randy L. Beck        

Name :     Randy L. Beck    

Title:         President        

BUYER

SOUTHERN INDIANA GAS AND ELECTRIC COMPANY

d/b/a VECTREN POWER SUPPLY, INC.

By:     /s/ Wayne D. Games        

Name :     Wayne D. Games    

Title:         VP - Power Supply    

{Signature page to Warrick Unit #4 Coal Supply Agreement}

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.4

EXHIBIT A

COAL QUALITY SPECIFICATIONS

The coal supplied under this Agreement shall meet the following quality specifications on an “as received” basis. Coal quality shall be determined in accordance with Article 6.

	Typical	MWA (monthly weighted average)	Reject (per Shipment)
Moisture (%)	[**]	[**]	[**]
Ash (%)	[**]	[**]	[**]
BTU/Lb.	[**]	[**]	[**]
SO2 (LBs/MMBTU)	[**]	[**]	[**]
Sulfur (%)	[**]	[**]	[**]
Volatile Matter (%)	[**]	[**]	[**]
AFT h/w, reducing 0F	[**]	[**]	[**]
HGI	[**]	[**]	[**]
Size (2” x 0) (Percent passing thru ¼” screen)	[**]	[**]	[**]
Sodium Equivalent (% Ignited)	[**]	[**]	[**]
Ferric Oxide (% Ignited)	[**]	[**]	[**]
Silicon Dioxide (% Ignited)	[**]	[**]	[**]
Aluminum Oxide (% Ignited)	[**]	[**]	[**]
Arsenic (ug/g dry basis)	[**]	[**]	[**]
% Chlorine (until December 31, 2019, inclusive)	[**]	[**]	[**]
% Chlorine (beginning January 1 2020 and thereafter)	[**]	[**]	[**]
Mercury (ug/g dry basis)	[**]	[**]	[**]

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AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.4

ATTACHMENT 1

AMENDMENT AND TERMINATION AGREEMENT

This Amendment and Termination Agreement (this “Agreement”) is made and entered into effective as of June 30, 2014 (the “Effective Date”), by and between Southern Indiana Gas And Electric Company d/b/a Vectren Power Supply, Inc., an Indiana corporation (“Buyer”), and Vectren Fuels, Inc., an Indiana corporation (“Seller”). Buyer and Seller are also referred to herein individually as a “Party” and collectively as the “Parties.”

RECITALS

WHEREAS, Buyer and Seller are parties to that certain Warrick Unit # 4 Coal Supply Agreement entered into effective as of January 1, 2009, as amended from time to time (the “Original Agreement”).

WHEREAS, Buyer and Seller are entering into that certain Warrick Unit #4 Coal Supply Agreement made and entered into effective as of January 1, 2015 (the “2015 CSA”), for the supply of bituminous coal for use in its Warrick Unit #4 generating plant (the “Plant”).

WHEREAS, it is a condition to the willingness of Seller to enter into the 2015 CSA that certain amendments be made to the terms and conditions of the Original Agreement, as set forth herein.

NOW, THEREFORE, in consideration of the premises and the mutual covenants and agreements of the Parties contained herein, the Parties agree as follows:

AGREEMENT

1. Amendments to the Original Agreement. Notwithstanding anything to the contrary in the Original Agreement, the Parties hereto agree that the following terms shall apply effective immediately as of the date on which Seller becomes an affiliate of Sunrise Coal, LLC. In the case of any conflicts between the foregoing and the terms of the Original Agreement, the provisions of this Section 1 shall govern.

a). Source of Coal. The source of the coal to be delivered by Seller shall be the Seller’s Oaktown 1 or Oaktown 2 Mines (collectively, the “Mines”). Seller shall have the right to notify Buyer that the coal to be sold by Seller and purchased by Buyer under this Agreement may also be mined from coal properties and reserves at Sunrise Coal, LLC’s Carlisle Mine, located in and around Sullivan County, Indiana. Seller’s right to deliver coal mined from the Carlisle Mine under this Agreement shall arise automatically upon Seller’s notice to Buyer, subject to the Parties’ agreement on the Carlisle Deduction (as defined below). Within thirty (30) days after Seller becomes an affiliate of Sunrise Coal, LLC, Buyer shall notify Seller if its cost to transport coal from the Carlisle Mine to the Plant differs from the cost to transport coal from the Seller’s Oaktown 1 or Oaktown 2 Mines. Such notice shall include reasonable supporting documentation of the respective transportation costs. Buyer and Seller, each acting in good faith, shall determine the difference between Buyer’s transportation costs for coal transported for: (a) each ton of coal delivered from the Carlisle Mine, and (b) each ton of coal delivered the

Att 1 - 1

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Seller’s Oaktown 1 or Oaktown 2 Mines (such difference in costs, the “Carlisle Deduction”), and Seller shall apply the Carlisle Deduction to all tons of coal delivered from the Carlisle Mine in its invoices when submitted to Buyer. To the extent the Carlisle Deduction is different for rail and truck transportation, the Carlisle Deduction for the applicable transportation mode shall be utilized. The Parties shall document the agreed Carlisle Deduction in a writing signed by both Parties. Once the Parties agree on the Carlisle Deduction, the Carlisle Mine shall be deemed to be one of the “Mines” for all purposes hereunder.

b). Delivery. Coal shall be delivered F.O.B. railcar or truck (as elected by Buyer) at the Mines (as elected by Seller), in substantially equal monthly quantities on a mutually agreeable delivery schedule. Seller will coordinate loading at the Mines with Buyer and Buyer’s relevant carriers. The foregoing provisions replace any provisions in the Original Agreement regarding point of delivery and delivery schedule, including, without limitation, any limitations set forth in Section 3.1 or otherwise in the Original Agreement with respect to the number of tons that may be delivered per day , all of which are hereby superseded in their entirety.

c). Transportation. Buyer shall be solely responsible for transportation of the coal from the Mines to the Plant, including providing railcars or trucks, as Buyer elects, for loading at the Mines. Buyer may, in its sole discretion, direct any coal delivered hereunder to any of Buyer’s or its affiliate’s power generating stations other than the Plant; provided that Buyer shall be responsible for all additional transportation costs associated with such election. Buyer’s right to direct coal to a power generating station other than the Plant shall in no way be construed as an obligation to do so under any circumstance. The foregoing provisions replace any provisions in the Original Agreement regarding transportation and transportation costs, all of which are hereby superseded in their entirety.

d). Base Tonnage. The quantity of coal to be delivered under the Original Agreement in calendar year 2014, is as follows (the “Base Tonnage”):

2014 - 480,000 tons

Buyer has notified Seller that Buyer has utilized its option to adjust the Base Tonnage by + [**] pursuant to the Original Agreement to decrease the amount of coal to be delivered pursuant to the Original Agreement to [**] tons annually, until further notice.

e). Buyer Option to Adjust. Buyer’s option to adjust the annual Base Tonnage by + [**] as stated in Section 3.1 of the Original Agreement, shall remain in full force and effect during the term thereof.

Att 1 - 2

[**] REPRESENTS CONFIDENTIAL MATERIAL OMITTED AND FILED SEPARATELTY WITH THE SECURITIES

AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.4

f). Coal Quality Specifications. The table in Exhibit A to the Original Agreement is hereby deleted in its entirety and replaced with the following table:

Quality Specifications
Coal Characteristics	MWA (monthly weighted average)	Penalty Threshold	Reject
Caloric value, as received	[**]	[**]	[**]
% Moisture, as received	[**]	[**]	[**]
% Ash, as received	[**]	[**]	[**]
SO2	[**]	[**]	[**]
Ash Fusion, softening, H=W red	[**]	[**]	[**]
Hardgrove Grindability Index	[**]	[**]	[**]
Nominal Size	[**]	[**]	[**]
Percent passing thru ¼” screen	[**]	[**]	[**]
Chlorine	[**]	[**]	[**]
Mercury (ug/g dry basis)	[**]	[**]	[**]

g). Weighing. The provisions of Article 5 of the 2015 CSA shall apply, and shall replace any provisions of the Original Agreement regarding weighing or the other matters addressed in Article 5 of the 2015 CSA, in their entirety.

h). Sampling and Analysis. The provisions of Article 6 of the 2015 CSA (other than quality specifications and without regard to cross-references to other provisions of the 2015 CSA) shall apply, and shall replace any provisions of the Original Agreement regarding sampling and analysis or the other matters addressed in Article 6 of the 2015 CSA, in their entirety.

i). Invoicing and Payment. The provisions of Article 7 of the 2015 CSA shall apply, and shall replace any provisions of the Original Agreement regarding invoicing and payments or the other matters addressed in Article 7 of the 2015 CSA, in their entirety

2. Termination of the Original Agreement. Notwithstanding anything to the contrary in the Original Agreement, the Parties hereby agree that the Original Agreement shall terminate and be of no further force and effect as of 11:59 pm Eastern on December 31, 2014, except with respect to the obligation to make any payments remaining to be made as of such date.

3. Termination of this Agreement. If Seller does not become an affiliate of Sunrise Coal, LLC, an Indiana limited liability company, on or before December 31, 2014, either Buyer or Seller may terminate this Agreement immediately upon written notice to the other Party, after which this Agreement shall be of no further force and effect.

Att 1 - 3

[**] REPRESENTS CONFIDENTIAL MATERIAL OMITTED AND FILED SEPARATELTY WITH THE SECURITIES

AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.4

4. No Other Modifications. Except as amended herein, all other terms, conditions and provisions of the Original Agreement not explicitly modified or amended in this Agreement shall remain unchanged and shall continue in full force and effect.

5. Counterparts and Facsimile. This Agreement may be executed in counterparts and by facsimile, each of which shall be an original and all of which taken together shall constitute one and the same instrument.

[signature page follows]

Att 1 - 4

[**] REPRESENTS CONFIDENTIAL MATERIAL OMITTED AND FILED SEPARATELTY WITH THE SECURITIES

AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.4

IN WITNESS WHEREOF, Buyer and Seller have caused this Agreement to be executed by their respective officers as of the date first written above.

SELLER

VECTREN FUELS, INC.

By:     /s/ Randy L. Beck        

Name :     Randy L. Beck    

Title:         President        

BUYER

SOUTHERN INDIANA GAS AND ELECTRIC COMPANY

d/b/a VECTREN POWER SUPPLY, INC.

By:     /s/ Wayne D. Games        

Name :     Wayne D. Games    

Title:         VP - Power Supply    

{Signature page to Warrick Unit #4 Amendment and Termination Agreement}

[**] REPRESENTS CONFIDENTIAL MATERIAL OMITTED AND FILED SEPARATELTY WITH THE SECURITIES

AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.4

ATTACHMENT 2

FORM OF GUARANTEE

Guaranty

This GUARANTY, dated as of the day of , 2014, is entered into by Sunrise Coal, LLC, an Indiana limited liability company (“Sunrise”), to and for the benefit of Southern Indiana Gas And Electric Company d/b/a Vectren Power Supply, Inc., an Indiana corporation (“VPS”).

WITNESSETH:

WHEREAS, VECTREN FUELS, INC., an Indiana corporation (“Fuels”), is a wholly owned subsidiary of Sunrise.

WHEREAS, Fuels and VPS have entered into that certain Warrick Unit 4 Coal Supply Agreement made and entered into effective as of January 1, 2015 (the “2015 CSA”).

WHEREAS, as an inducement to VPS entering into the 2015 CSA and subject to Fuels becoming a wholly-owned subsidiary of Sunrise, Fuels has agreed to cause Sunrise to execute and deliver this Guaranty for the benefit of VPS within 10 days after the date on which Fuels becomes a wholly-owned subsidiary of Sunrise, if at all.

NOW, THEREFORE, in consideration of the foregoing premises and the following covenants and other good and valuable consideration, the receipt and sufficiency of which is hereby acknowledged, Sunrise covenants with VPS as follows:

1. Guaranty. For value received and in consideration of the direct and indirect benefits to be derived by Sunrise in connection with the transactions contemplated by the 2015 CSA, with effect from January 1, 2015, Sunrise hereby guarantees to VPS the payment and performance as and when due of all obligations of Fuels (and any assignee of Fuels that is an affiliate of Sunrise) arising out of or related to the 2015 CSA, subject in all respects to all of the conditions, limitations, and qualifications set forth in the 2015 CSA (the “Obligations). This is a continuing Guaranty of payment and performance and not merely of collection. Subject to the provisions of Section 4, this Guaranty shall terminate upon the earlier of the termination of the Obligations or the date that is 12 months after the termination or expiration of the 2015 CSA; provided, however, that this Guaranty and Sunrise’s liability hereunder shall survive any such termination with respect to any claims made by VPS under the 2015 CSA if such claims are made prior to such termination.

2. Waiver. Sunrise hereby expressly waives notice from VPS of its acceptance of and reliance upon this Guaranty. Sunrise consents to any extensions of time for the payment or performance of the Obligations and to any changes in the terms of the 2015 CSA, and waives any notices thereof. Sunrise also waives promptness, diligence, presentment to or demand of payment or performance from anyone other than Fuels liable upon the Obligations, and

Att 2 - 1

[**] REPRESENTS CONFIDENTIAL MATERIAL OMITTED AND FILED SEPARATELTY WITH THE SECURITIES

AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.4

presentment, notice of dishonor, protest and all other notices whatsoever. No waiver, amendment, release or modification of this Guaranty shall be established by conduct, custom or course of dealing, but solely by an instrument in writing duly executed by Sunrise and VPS. VPS’s failure or delay in exercising any right, remedy or power hereunder shall not operate as a waiver thereof, nor shall any single or partial exercise by VPS of any right, remedy or power hereunder preclude VPS from any other or future exercise of any right, remedy or power. Each and every right, remedy and power granted to VPS hereunder or allowed to it by law or other agreement shall be cumulative with and not exclusive of any other.

3. Waiver of Defenses. The liability of Sunrise under this Guaranty, and Sunrise’ obligations under this Guaranty shall not be impaired or released as a result of (a) any change of the time, manner or terms of payment or performance of any of the Obligations; (b) any renewal or increase of any of the Obligations; (c) the assignment of the 2015 CSA to an affiliate of Sunrise pursuant to Section 15.3(a) of the 2015 CSA; (d) any release or partial release of any other guarantor or other obligor in respect of any of the Obligations; (e) any modification, amendment, waiver or renewal of, or consent to departure from, any agreement or instrument relating to any of the Obligations; (f) VPS’s exercise or failure to exercise any rights against Fuels, Sunrise or others or any other action or inaction by VPS in respect of any of the Obligations; (g) with respect to any of the foregoing, the lack of notice to or consent by Sunrise; or (h) any other circumstance which might otherwise constitute a defense available to, or discharge of, a surety or a guarantor excepting payment and performance, as applicable. Nothing herein is intended to deny Sunrise, and Sunrise shall have and may assert any and all of the defenses, set-offs, counterclaims and other rights which Fuels is or may be entitled to assert that arise from or out of the 2015 CSA, except for defenses arising out of the bankruptcy, insolvency, dissolution or liquidation of Fuels. The obligations of Sunrise hereunder are several from Fuels or any other person, and are primary obligations concerning which Sunrise is the principal obligor. There are no conditions precedent to the enforcement of this Guaranty, except as expressly contained herein.

4. Reinstatement Provision. If VPS receives any payment or payments on account of the Obligations, which payment or payments of any part thereof are subsequently invalidated, declared to be fraudulent or preferential, set aside and/or required to be repaid to a trustee, receiver, or any other party under any bankruptcy act or code, state or federal law, common law or equitable doctrine, then to the extent of any sum not finally retained by VPS, Sunrise’ obligations to VPS hereunder shall be reinstated and this Guaranty, shall remain in full force and effect (or be reinstated) until payment of the Obligations shall have been made to VPS, which payment shall be due on demand.

5. Assignment. This Guaranty shall be binding upon Sunrise and upon its successors and assigns and shall be for the benefit of VPS and its successors and assigns. Sunrise may not assign this Guaranty or the obligations hereunder without the express written consent of VPS and such consent will not be unreasonably withheld. Any purported assignment in violation of this Section 5 shall be void and without effect.

6. Applicable Law. This Guaranty shall be governed by and construed in accordance with the laws of the State of Indiana, without giving effect to laws of such state that would require the application of the laws of any other state.

Att 2 - 2

[**] REPRESENTS CONFIDENTIAL MATERIAL OMITTED AND FILED SEPARATELTY WITH THE SECURITIES

AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.4

7. Severability. In case any clause, provision or section of this Guaranty, or any application thereof, is for any reason held to be illegal, invalid, or inoperable, Sunrise and VPS shall negotiate an equitable adjustment to such affected provisions of this guaranty with a view towards effecting the purpose and intent of the Guaranty, and subject to such adjustment such illegality, invalidity or inoperability shall not affect the remainder thereof or any other clause, provision or section, and each such clause, provision or section shall be deemed to be effective and operative in the manner and to the fullest extent permitted by law.

8. Only Agreement. This Guaranty is the entire and only agreement between Sunrise and VPS with respect to the guaranty of the Obligations of Fuels by Sunrise.

9. Representations and Warranties. Sunrise represents and warrants to VPS that: (a) Sunrise is a limited liability company duly organized and validly existing under the laws of the State of Indiana; (b) Sunrise has all requisite power and authority to execute and to deliver and to perform all of its obligations under this Guaranty; (c) the execution, delivery and performance of this Guaranty by Sunrise are within its powers and have been duly authorized by all necessary limited liability company actions; (d) this Guaranty constitutes a legally valid and binding agreement of Sunrise, subject only to insolvency, bankruptcy, moratorium, reorganization, fraudulent conveyance or similar laws affecting creditors’ rights generally and by general principles of equity; (e) the execution, delivery and performance of this Guaranty will not violate any provision of any requirement of law or contractual obligation of Sunrise (except to the extent that any such violation would not reasonably be expected to have a material adverse effect on Sunrise’ ability to perform this Guaranty); (f) no consent or authorization of, filing with, or other act by or in respect of, any arbitrator or governmental authority and no consent of any other person (including, without limitation, any stockholder or creditor of Sunrise) is required in connection with the execution, delivery, performance, validity or enforceability of this Guaranty, other than any which have been obtained or made prior to the date hereof and remain in full force and effect; and (g) no litigation, investigation or proceeding of or before any arbitrator or governmental authority is pending or, to the knowledge of Sunrise, threatened by or against Sunrise relating to this Guaranty or that would have a material adverse effect on Sunrise’ ability to perform this Guaranty.

10. Collection Expenses. If VPS is required to pursue any remedy against Sunrise hereunder, Sunrise shall pay to VPS upon demand, all reasonable attorneys’ fees and expenses and all other reasonable costs, expenses and fees incurred by VPS in successfully enforcing this Guaranty.

11. Notices. Any notices given or required to be given hereunder shall be given to Sunrise and VPS, as applicable, by being either: (a) delivered personally against written receipt, (b) sent by facsimile or e-mail transmission, (c) mailed by registered or certified mail, postage prepaid, return receipt requested, or (d) mailed by reputable international overnight courier, fee prepaid, to Sunrise or VPS, as applicable, at the following addresses or facsimile numbers:

Att 2 - 3

[**] REPRESENTS CONFIDENTIAL MATERIAL OMITTED AND FILED SEPARATELTY WITH THE SECURITIES

AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.4

If to Sunrise: Sunrise Coal, LLC

Attention: Brent Bilsland

1183 East Canvasback Dr.

Terre Haute, IN 47802

Phone: (812) 298-3702

Fax No.: (812) 299-2810

E-mail: bbilsland@sunrisecoal.com

If to VPS: Southern Indiana Gas and Electric Company One Vectren Square

Evansville, IN 47708 Attn: Wayne D. Games

E-mail: wdgames@Vectren.com

Fax: 812.491.4684

With a copy to: Robert E. Heidorn

Senior Vice President and General Counsel Vectren Corporation

One Vectren Square Evansville, IN 47741

E-mail: rheidorn@Vectren.com

Fax: 812.491.4238

All such notices, requests and other communications will be deemed given, (w) if delivered personally as provided in this Section 11, upon delivery, (x) if delivered by facsimile or email transmission as provided in this Section 11, upon confirmed receipt, (y) if delivered by mail as provided in this Section 11, upon the earlier of the fifth business day following mailing and receipt, and (z) if delivered by overnight courier as provided in this Section 11, upon the earlier of the second business day following the date sent by such overnight courier and receipt (in each case regardless of whether such notice, request or other communication is received by any other person or entity to whom a copy of such notice is to be delivered pursuant to this Section 11). Sunrise and VPS may change the address to which notices to it are to be sent upon written notice to VPS or Sunrise, respectively.

12. Modification. This Guaranty may not be amended or modified unless the changes are in writing and signed by both VPS and Sunrise.

13. JURY TRIAL WAIVER. SUNRISE HEREBY IRREVOCABLY WAIVES ANY AND ALL RIGHTS TO TRIAL BY JURY WITH RESPECT TO ANY LEGAL PROCEEDING ARISING OUT OF OR RELATING TO THIS GUARANTY.

[signature page follows]

Att 2 - 4

[**] REPRESENTS CONFIDENTIAL MATERIAL OMITTED AND FILED SEPARATELTY WITH THE SECURITIES

AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENTExhibit 10.4

IN WITNESS WHEREOF, Sunrise has executed and delivered this Guaranty effective as of the day and year first above written.

Sunrise Coal, LLC

By:     

Name:     

Title:     

Accepted:

Accepted:

Southern Indiana Gas and Electric Company

d/b/a Vectren Power Supply, Inc.

By:     

Name:

Title:     

Att 2 - 5

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: May 14, 2015

/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: May 14, 2015

/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 May, 2015.

/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

Environmental Matters (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended	12 Months Ended
	Mar. 31, 2015 MW	Dec. 31, 2013 T	Dec. 31, 2014
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
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
Coal Ash Waste Disposal and Ash Ponds [Abstract]
Potential estimated capital expenditures to comply with ash pond and coal ash disposal regulations with stringent alternative	100
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%
Indiana Senate Bill 251 [Abstract]
Long term contract for purchase of electric power generated by wind energy (in megawatts)	80
Percentage of total electricity obtained by the supplier to meet the energy needs of its retail customers provided by clean energy sources (in hundredths)	4.00%
Manufactured Gas Plants
Site contingency, accrual, undiscounted amount	43.4
Accrual for Environmental Loss Contingencies	3.5		3.6
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 Income Statement (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
OPERATING REVENUES [Abstract]
Gas utility	$ 352.9	$ 443.6
Electric utility	153.9	163.0
Other	0.1	0
Total operating revenues	506.9	606.6
OPERATING EXPENSES [Abstract]
Cost of gas sold	172.0	270.9
Cost of fuel & purchased power	50.1	57.0
Other operating	102.8	98.3
Depreciation & Amortization	52.1	49.9
Taxes other than income taxes	19.1	20.1
Total operating expenses	396.1	496.2
OPERATING INCOME	110.8	110.4
Other income - net	4.9	3.9
Interest Expense	16.6	16.7
INCOME BEFORE INCOME TAXES	99.1	97.6
Income taxes	36.1	36.3
NET INCOME	63.0	61.3
Subsidiary Guarantors [Member]
OPERATING REVENUES [Abstract]
Gas utility	352.9	443.6
Electric utility	153.9	163.0
Other	0	0
Total operating revenues	506.8	606.6
OPERATING EXPENSES [Abstract]
Cost of gas sold	172.0	270.9
Cost of fuel & purchased power	50.1	57.0
Other operating	112.4	107.5
Depreciation & Amortization	45.6	44.4
Taxes other than income taxes	18.7	19.6
Total operating expenses	398.8	499.4
OPERATING INCOME	108.0	107.2
Other income - net	4.1	3.0
Interest Expense	15.9	15.8
INCOME BEFORE INCOME TAXES	96.2	94.4
Income taxes	36.7	36.8
Equity in earnings of consolidated companies, net of tax	0	0
NET INCOME	59.5	57.6
Parent Company [Member]
OPERATING REVENUES [Abstract]
Gas utility	0	0
Electric utility	0	0
Other	10.2	9.6
Total operating revenues	10.2	9.6
OPERATING EXPENSES [Abstract]
Cost of gas sold	0	0
Cost of fuel & purchased power	0	0
Other operating	0	0
Depreciation & Amortization	6.4	5.4
Taxes other than income taxes	0.4	0.4
Total operating expenses	6.8	5.8
OPERATING INCOME	3.4	3.8
Other income - net	10.8	10.7
Interest Expense	11.3	11.3
INCOME BEFORE INCOME TAXES	2.9	3.2
Income taxes	(0.6)	(0.5)
Equity in earnings of consolidated companies, net of tax	59.5	57.6
NET INCOME	63.0	61.3
Consolidation, Eliminations [Member]
OPERATING REVENUES [Abstract]
Gas utility	0	0
Electric utility	0	0
Other	(10.1)	(9.6)
Total operating revenues	(10.1)	(9.6)
OPERATING EXPENSES [Abstract]
Cost of gas sold	0	0
Cost of fuel & purchased power	0	0
Other operating	(9.6)	(9.2)
Depreciation & Amortization	0.1	0.1
Taxes other than income taxes	0	0.1
Total operating expenses	(9.5)	(9.0)
OPERATING INCOME	(0.6)	(0.6)
Other income - net	(10.0)	(9.8)
Interest Expense	(10.6)	(10.4)
INCOME BEFORE INCOME TAXES	0	0
Income taxes	0	0
Equity in earnings of consolidated companies, net of tax	(59.5)	(57.6)
NET INCOME	(59.5)	(57.6)
Consolidated Entities [Member]
OPERATING REVENUES [Abstract]
Gas utility	352.9	443.6
Electric utility	153.9	163.0
Other	0.1	0
Total operating revenues	506.9	606.6
OPERATING EXPENSES [Abstract]
Cost of gas sold	172.0	270.9
Cost of fuel & purchased power	50.1	57.0
Other operating	102.8	98.3
Depreciation & Amortization	52.1	49.9
Taxes other than income taxes	19.1	20.1
Total operating expenses	396.1	496.2
OPERATING INCOME	110.8	110.4
Other income - net	4.9	3.9
Interest Expense	16.6	16.7
INCOME BEFORE INCOME TAXES	99.1	97.6
Income taxes	36.1	36.3
Equity in earnings of consolidated companies, net of tax	0	0
NET INCOME	$ 63.0	$ 61.3

XML

Excise and Utility Receipts Taxes

3 Months Ended

Mar. 31, 2015

Excise and Utility Receipts Taxes [Abstract]

Excise and Utility Receipts Taxes

Excise and Utility Receipts Taxes

Excise taxes and a portion of utility receipts taxes are included in rates charged to customers.  Accordingly, the Company records these taxes received, which totaled $11.7 million and $12.9 million in the three months ended March 31, 2015 and 2014, respectively, as a component of operating revenues. Expense associated with excise and utility receipts taxes are recorded as a component of Taxes other than income taxes.

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Transactions with Other Vectren Companies and Affiliates Transactions with Other Vectren Companies and Afffiliates (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Vectren Fuels Inc. [Member]
Transactions with Other Vectren Companies and Affiliates [Line Items]
Expenses from transactions with related party		$ 30.8
Vectren Infrastructure Services Corporation [Member]
Transactions with Other Vectren Companies and Affiliates [Line Items]
Expenses from transactions with related party	17.7	11.4
Support Services & Purchases [Member]
Transactions with Other Vectren Companies and Affiliates [Line Items]
Cost of corporate and general and administrative services	$ 15.6	$ 14.7

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Supplemental Cash Flow Information Supplemental Cash Flow Information (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Accruals for Utility & Nonutility Plant [Abstract]
Public Utilities Accruals For Purchase Of Utility And Non Utility Plant Assets	$ 12.1	$ 19.0

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Financing Activities (Details) (Utility Group [Member], Indiana Gas [Member], Unsecured Debt [Member], Fixed Rate Senior Unsecured Notes 2015 Series E 715 [Member], USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2015
Utility Group [Member] | Indiana Gas [Member] | Unsecured Debt [Member] | Fixed Rate Senior Unsecured Notes 2015 Series E 715 [Member]
Debt Instrument [Line Items]
Stated percentage rate (in hundredths)	7.15%
Maturity date	Mar. 15, 2015
Debt Instrument, Face Amount	$ 5.0

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Gas Rate & Regulatory Matters (Details) (USD $)	3 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
OHIO | Ohio Recovery and Deferral Mechanisms [Member]
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items]
Cumulative gross plant invesment made under Distribution Replacement Rider	$ 156,500,000
Regulatory Asset associated with DRR deferrals of depreciation and post in-service carrying costs	14,200,000	13,100,000
Initial distribution replacement rider mechanism term.	5 years
Extension period requested to recover capital investments	5 years
Amount of Capital Investment Expected Over Next Five Years Recoverable Under DRR	200,000,000
Bill impact per customer per month	1.50
INDIANA | Indiana Recovery and Deferral Mechanisms [Member]
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items]
Regulatory Assset balance associated with Vectren north and south programs	17,300,000	16,400,000
Length of project plan required for recovery under new legislation	7 years
SIGECO [Member] | INDIANA | Indiana Recovery and Deferral Mechanisms [Member]
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items]
Allowable capital expenditures under Vectren programs	3,000,000
Limitations of deferrals of debt-related post in service carrying costs	3
Indiana Gas [Member] | INDIANA | Indiana Recovery and Deferral Mechanisms [Member]
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items]
Allowable capital expenditures under Vectren programs	20,000,000
Limitations of deferrals of debt-related post in service carrying costs	4
INDIANA | Senate Bill 251 and 560 [Member]
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items]
Percentage of costs eligible for recovery using periodic rate recovery mechanism	80.00%
Percentage of project costs to be deferred for future recovery	20.00%
INDIANA | Pipeline Safety Law [Member]
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items]
Expected Seven Year Period Modernization Investment	900,000,000
Capital Expenditure Increases	35,000,000
Expected annual operating costs associated with new pipeline safety regulations	30,000,000
Upper range of expected annual operating costs associated with new pipeline safety regulations	15,000,000
INDIANA | Indiana Gas [Member] | Indiana Gas GCA Cost Recovery [Member]
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items]
Original amount of recovery opposed by OUCC	3,900,000
Amount of recovery supported by OUCC	3,000,000
Estimated amount of settlement recoverable through the Company's GCA mechanism	1,400,000
Estimated amount of settlement recoverable through the gas supply administrator	$ 1,600,000

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Subsidiary Guarantor and Consolidating Information

3 Months Ended

Mar. 31, 2015

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 $6 million was outstanding at March 31, 2015, and Utility Holdings’ has unsecured senior notes with a par value of $875 million outstanding at March 31, 2015.  The guarantees are full and unconditional and joint and several, and Utility Holdings has no direct subsidiaries other than the subsidiary guarantors.   However, Utility Holdings does have operations other than those of the subsidiary guarantors.  Pursuant to Item 3-10 of Regulation S-X, disclosure of the results of operations and balance sheets of the subsidiary guarantors, which are 100 percent owned, separate from the parent company’s operations is required.  Following are consolidating financial statements including information on the combined operations of the subsidiary guarantors separate from the other operations of the parent company.  Pursuant to a tax sharing agreement, consolidating tax effects, which are calculated on a separate return basis, are reflected at the parent level.

Condensed Consolidating Balance Sheet as of March 31, 2015 (in millions):

ASSETS	Subsidiary		Parent		Eliminations &
	Guarantors		Company		Reclassifications			Consolidated
Current Assets
Cash & cash equivalents	$	10.0	$	0.4	$	—		$	10.4
Accounts receivable - less reserves	137.3		—		—			137.3
Intercompany receivables	69.8		109.3		(179.1		)	—
Accrued unbilled revenues	94.3		—		—			94.3
Inventories	86.7		0.1		—			86.8
Prepayments & other current assets	11.6		43.9		(35.0		)	20.5
Total current assets	409.7		153.7		(214.1		)	349.3
Utility Plant
Original cost	5,778.0		—		—			5,778.0
Less:  accumulated depreciation & amortization	2,316.9		—		—			2,316.9
Net utility plant	3,461.1		—		—			3,461.1
Investments in consolidated subsidiaries	—		1,452.3		(1,452.3		)	—
Notes receivable from consolidated subsidiaries	—		746.5		(746.5		)	—
Investments in unconsolidated affiliates	0.2		—		—			0.2
Other investments	21.3		4.1		—			25.4
Nonutility plant - net	1.7		144.0		—			145.7
Goodwill - net	205.0		—		—			205.0
Regulatory assets	98.2		21.3		—			119.5
Other assets	28.8		1.6		(12.6		)	17.8
TOTAL ASSETS	$	4,226.0	$	2,523.5	$	(2,425.5	)	$	4,324.0
LIABILITIES & SHAREHOLDER'S EQUITY	Subsidiary		Parent		Eliminations &
	Guarantors		Company		Reclassifications			Consolidated
Current Liabilities
Accounts payable	$	127.4	$	4.8	$	—		$	132.2
Intercompany payables	12.8		0.7		(13.5		)	—
Payables to other Vectren companies	19.7		—		—			19.7
Refundable fuel & natural gas costs	23.0		—		—			23.0
Accrued liabilities	165.7		17.9		(35.0		)	148.6
Short-term borrowings	—		5.9		—			5.9
Intercompany short-term borrowings	22.4		69.1		(91.5		)	—
Current maturities of long-term debt	15.0		75.0		—			90.0
Current maturities of long-term debt due to VUHI	74.1		—		(74.1		)	—
Total current liabilities	460.1		173.4		(214.1		)	419.4
Long-Term Debt
Long-term debt	362.7		799.7		—			1,162.4
Long-term debt due to VUHI	746.5		—		(746.5		)	—
Total long-term debt - net	1,109.2		799.7		(746.5		)	1,162.4
Deferred Credits & Other Liabilities
Deferred income taxes	668.5		27.9		—			696.4
Regulatory liabilities	415.6		1.5		—			417.1
Deferred credits & other liabilities	120.3		5.5		(12.6		)	113.2
Total deferred credits & other liabilities	1,204.4		34.9		(12.6		)	1,226.7
Common Shareholder's Equity
Common stock (no par value)	808.5		795.3		(808.5		)	795.3
Retained earnings	643.8		720.2		(643.8		)	720.2
Total common shareholder's equity	1,452.3		1,515.5		(1,452.3		)	1,515.5
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	$	4,226.0	$	2,523.5	$	(2,425.5	)	$	4,324.0

Condensed Consolidating Balance Sheet as of December 31, 2014 (in millions):

ASSETS	Subsidiary		Parent		Eliminations &
	Guarantors		Company		Reclassifications			Consolidated
Current Assets
Cash & cash equivalents	$	6.9	$	12.4	$	—		$	19.3
Accounts receivable - less reserves	113.0		—		—			113.0
Intercompany receivables	0.8		186.7		(187.5		)	—
Accrued unbilled revenues	122.4		—		—			122.4
Inventories	113.2		—		—			113.2
Recoverable fuel & natural gas costs	9.8		—		—			9.8
Prepayments & other current assets	94.8		38.1		(49.4		)	83.5
Total current assets	460.9		237.2		(236.9		)	461.2
Utility Plant
Original cost	5,718.7		—		—			5,718.7
Less:  accumulated depreciation & amortization	2,279.7		—		—			2,279.7
Net utility plant	3,439.0		—		—			3,439.0
Investments in consolidated subsidiaries	—		1,416.9		(1,416.9		)	—
Notes receivable from consolidated subsidiaries	—		746.5		(746.5		)	—
Investments in unconsolidated affiliates	0.2		—		—			0.2
Other investments	21.3		4.3		—			25.6
Nonutility plant - net	1.8		147.4		—			149.2
Goodwill - net	205.0		—		—			205.0
Regulatory assets	106.7		21.6		—			128.3
Other assets	29.4		1.7		(11.5		)	19.6
TOTAL ASSETS	$	4,264.3	$	2,575.6	$	(2,411.8	)	$	4,428.1
LIABILITIES & SHAREHOLDER'S EQUITY	Subsidiary		Parent		Eliminations &
	Guarantors		Company		Reclassifications			Consolidated
Current Liabilities
Accounts payable	$	176.2	$	4.2	$	—		$	180.4
Intercompany payables	15.6		0.8		(16.4		)	—
Payables to other Vectren companies	28.6		—		—			28.6
Accrued liabilities	136.7		35.0		(49.4		)	122.3
Short-term borrowings	—		156.4		—			156.4
Intercompany short-term borrowings	97.0		—		(97.0		)	—
Current maturities of long-term debt	20.0		75.0		—			95.0
Current maturities of long-term debt due to VUHI	74.1		—		(74.1		)	—
Total current liabilities	548.2		271.4		(236.9		)	582.7
Long-Term Debt
Long-term debt - net of current maturities &
debt subject to tender	362.6		799.7		—			1,162.3
Long-term debt due to VUHI	746.5		—		(746.5		)	—
Total long-term debt - net	1,109.1		799.7		(746.5		)	1,162.3
Deferred Credits & Other Liabilities
Deferred income taxes	665.8		19.3		—			685.1
Regulatory liabilities	408.8		1.5		—			410.3
Deferred credits & other liabilities	115.5		5.2		(11.5		)	109.2
Total deferred credits & other liabilities	1,190.1		26.0		(11.5		)	1,204.6
Common Shareholder's Equity
Common stock (no par value)	806.9		793.7		(806.9		)	793.7
Retained earnings	610.0		684.8		(610.0		)	684.8
Total common shareholder's equity	1,416.9		1,478.5		(1,416.9		)	1,478.5
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	$	4,264.3	$	2,575.6	$	(2,411.8	)	$	4,428.1

Condensed Consolidating Statement of Income for the three months ended March 31, 2015 (in millions):

	Subsidiary Guarantors		Parent Company			Eliminations & Reclassifications			Consolidated
OPERATING REVENUES
Gas utility	$	352.9	$	—		$	—		$	352.9
Electric utility	153.9		—			—			153.9
Other	—		10.2			(10.1		)	0.1
Total operating revenues	506.8		10.2			(10.1		)	506.9
OPERATING EXPENSES
Cost of gas sold	172.0		—			—			172.0
Cost of fuel & purchased power	50.1		—			—			50.1
Other operating	112.4		—			(9.6		)	102.8
Depreciation & amortization	45.6		6.4			0.1			52.1
Taxes other than income taxes	18.7		0.4			—			19.1
Total operating expenses	398.8		6.8			(9.5		)	396.1
OPERATING INCOME	108.0		3.4			(0.6		)	110.8
Other income - net	4.1		10.8			(10.0		)	4.9
Interest expense	15.9		11.3			(10.6		)	16.6
INCOME BEFORE INCOME TAXES	96.2		2.9			—			99.1
Income taxes	36.7		(0.6		)	—			36.1
Equity in earnings of consolidated companies, net of tax	—		59.5			(59.5		)	—
NET INCOME	$	59.5	$	63.0		$	(59.5	)	$	63.0

Condensed Consolidating Statement of Income for the three months ended March 31, 2014 (in millions):

	Subsidiary Guarantors		Parent Company			Eliminations & Reclassifications			Consolidated
OPERATING REVENUES
Gas utility	$	443.6	$	—		$	—		$	443.6
Electric utility	163.0		—			—			163.0
Other	—		9.6			(9.6		)	—
Total operating revenues	606.6		9.6			(9.6		)	606.6
OPERATING EXPENSES
Cost of gas sold	270.9		—			—			270.9
Cost of fuel & purchased power	57.0		—			—			57.0
Other operating	107.5		—			(9.2		)	98.3
Depreciation & amortization	44.4		5.4			0.1			49.9
Taxes other than income taxes	19.6		0.4			0.1			20.1
Total operating expenses	499.4		5.8			(9.0		)	496.2
OPERATING INCOME	107.2		3.8			(0.6		)	110.4
Other income - net	3.0		10.7			(9.8		)	3.9
Interest expense	15.8		11.3			(10.4		)	16.7
INCOME BEFORE INCOME TAXES	94.4		3.2			—			97.6
Income taxes	36.8		(0.5		)	—			36.3
Equity in earnings of consolidated companies, net of tax	—		57.6			(57.6		)	—
NET INCOME	$	57.6	$	61.3		$	(57.6	)	$	61.3

Condensed Consolidating Statement of Cash Flows for the three months endedMarch 31, 2015 (in millions):

	Subsidiary Guarantors			Parent Company			Eliminations			Consolidated
NET CASH PROVIDED BY OPERATING ACTIVITIES	$	240.6		$	0.7		$	—		$	241.3
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from
Additional capital contribution from parent	1.6			1.6			(1.6		)	1.6
Requirements for:
Dividends to parent	(25.8		)	(27.6		)	25.8			(27.6		)
Retirement of long term debt	(5.0		)	—			—			(5.0		)
Net change in intercompany short-term borrowings	(74.6		)	69.1			5.5			—
Net change in short-term borrowings	—			(150.5		)	—			(150.5		)
Net cash used in financing activities	(103.8		)	(107.4		)	29.7			(181.5		)
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from:
Consolidated subsidiary distributions	—			25.8			(25.8		)	—
Other investing activities	—			0.2			—			0.2
Requirements for:
Capital expenditures, excluding AFUDC equity	(64.6		)	(4.3		)	—			(68.9		)
Consolidated subsidiary investments	—			(1.6		)	1.6			—
Net change in short-term intercompany notes receivable	(69.1		)	74.6			(5.5		)	—
Net cash used in investing activities	(133.7		)	94.7			(29.7		)	(68.7		)
Net change in cash & cash equivalents	3.1			(12.0		)	—			(8.9		)
Cash & cash equivalents at beginning of period	6.9			12.4			—			19.3
Cash & cash equivalents at end of period	$	10.0		$	0.4		$	—		$	10.4

Condensed Consolidating Statement of Cash Flows for the three months endedMarch 31, 2014 (in millions):

	Subsidiary Guarantors			Parent Company			Eliminations			Consolidated
NET CASH PROVIDED BY OPERATING ACTIVITIES	$	137.2		$	18.8		$	—		$	156.0
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from:
Long-term debt, net of issuance costs	124.2			—			(124.2		)	—
Additional capital contribution from parent	1.6			1.6			(1.6		)	1.6
Requirements for:
Dividends to parent	(25.4		)	(27.1		)	25.4			(27.1		)
Net change in intercompany short-term borrowings	(73.1		)	85.6			(12.5		)	—
Net change in short-term borrowings	—			(28.6		)	—			(28.6		)
Net cash used in financing activities	27.3			31.5			(112.9		)	(54.1		)
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from:
Consolidated subsidiary distributions	—			25.4			(25.4		)	—
Other investing activities	—			0.1			—			0.1
Requirements for:
Capital expenditures, excluding AFUDC equity	(51.3		)	(6.7		)	—			(58.0		)
Consolidated subsidiary investments	—			(1.6		)	1.6			—
Net change in long-term intercompany notes receivable	—			(124.2		)	124.2			—
Net change in short-term intercompany notes receivable	(85.6		)	73.1			12.5			—
Net cash used in investing activities	(136.9		)	(33.9		)	112.9			(57.9		)
Net change in cash & cash equivalents	27.6			16.4			—			44.0
Cash & cash equivalents at beginning of period	8.2			0.4			—			8.6
Cash & cash equivalents at end of period	$	35.8		$	16.8		$	—		$	52.6

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Electric Rate and Regulatory Matters (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		12 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2012	Dec. 31, 2011	Feb. 01, 2014
Vectren South Electric Environmental Compliance Filing [Abstract]
Amount of capital investments to date in equipment for mercury control	$ 29
Amount of capital investments to date in equipment to control sulfur trioxide emissions	16
Lower range of request for approval of capital investments on coal-fired generation units	80
Upper range of request for approval of capital investments on coal-fired generation units	90
Amount of deferred costs to date related to depreciation, property tax, and operating expenses under Senate Bill 29 and Senate Bill 251	0.7
Amount of deferred costs to date related to post in-service carrying costs under Senate Bill 29 and Senate Bill 251.	0.3
Coal Procurement Procedures [Abstract]
Number of years for recovery of coal costs	6 years
Cumulative total deferrals related to coal purchases	33.6				42.4
Vectren South Electric Demand Side Management Program Filing [Abstract]
Number of years in initial demand side management program	3 years
Maximum Deferral Of Lost Margin Associated With Small Customer DSM Programs			3	1
Electric revenue recognized associated with lost margin recovery	2.3	1.6
Percent of industrial load opt out of applicable energy efficiency programs	80.00%
FERC Return On Equity Complaint [Abstract]
Current return on equity used in MISO transmission owners rates	12.38%
Reduced return on equity percentage sought by third party through joint complaint	9.15%
Equity component, upper limit, as a percentage, sought by third party through joint complaint	50.00%
Gross Investment In Qualifying Transmission Projects	157.7
Net Investment in Qualifying Transmission Projects	$ 142.8
Incentive return granted on qualifying investments in NETO	11.14%
Percentage return approved by FERC on ROE complaint against NETO	10.57%
Number of incentive basis point above and beyond approved FERC approved ROE	50

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CONSOLIDATED CONDENSED BALANCE SHEETS (Unaudited) (USD $) In Millions, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Assets, Current [Abstract]
Cash & cash equivalents	$ 10.4	$ 19.3
Accounts receivable - less reserves of $5.3 & $3.9, respectively	137.3	113.0
Accrued unbilled revenues	94.3	122.4
Inventories	86.8	113.2
Recoverable fuel & natural gas costs	0	9.8
Prepayments & other current assets	20.5	83.5
Total current assets	349.3	461.2
Utility Plant [Abstract]
Original cost	5,778.0	5,718.7
Less: accumulated depreciation & amortization	2,316.9	2,279.7
Net utility plant	3,461.1	3,439.0
Investments in unconsolidated affiliates	0.2	0.2
Other Investments	25.4	25.6
Nonutility plant - net	145.7	149.2
Goodwill - net	205.0	205.0
Regulatory assets	119.5	128.3
Other assets	17.8	19.6
TOTAL ASSETS	4,324.0	4,428.1
Current Liabilities [Abstract]
Accounts payable	132.2	180.4
Payables to other Vectren companies	19.7	28.6
Refundable fuel and natural gas costs	23.0	0
Accrued liabilities	148.6	122.3
Short-term borrowings	5.9	156.4
Current maturities of long-term debt	90.0	95.0
Total current liabilities	419.4	582.7
Long-Term Debt - Net of Current Maturities	1,162.4	1,162.3
Deferred Credits & Other Liabilities [Abstract]
Deferred income taxes	696.4	685.1
Regulatory liabilities	417.1	410.3
Deferred credits & other liabilities	113.2	109.2
Total deferred credits and other liabilities	1,226.7	1,204.6
Commitments & Contingencies (Notes 8 - 11)
Common Shareholder's Equity [Abstract]
Common stock (no par value)	795.3	793.7
Retained earnings	720.2	684.8
Total common shareholders' equity	1,515.5	1,478.5
TOTAL LIABILITIES and SHAREHOLDERS' EQUITY	$ 4,324.0	$ 4,428.1

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Organization and Nature of Operations

3 Months Ended

Mar. 31, 2015

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 over 585,000 natural gas customers located in central and southern Indiana. SIGECO provides energy delivery services to over 143,000 electric customers and over 111,000 gas customers located near Evansville in southwestern Indiana.  SIGECO also owns and operates electric generation assets to serve its electric customers and optimizes those assets in the wholesale power market.  Indiana Gas and SIGECO generally do business as Vectren Energy Delivery of Indiana.  VEDO provides energy delivery services to over 317,000 natural gas customers located near Dayton in west central Ohio.

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Segment Reporting (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 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	$ 506.9	$ 606.6
Profitability Measure - Net income (loss)	63.0	61.3
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	352.9	443.6
Profitability Measure - Net income (loss)	40.4	38.3
Utility Group [Member] | Electric Utility Services [Member]
Segment Reporting Information [Line Items]
Revenues	153.9	163.0
Profitability Measure - Net income (loss)	19.2	19.3
Utility Group [Member] | Other Segments [Member]
Segment Reporting Information [Line Items]
Revenues	10.2	9.6
Profitability Measure - Net income (loss)	3.4	3.7
Utility Group [Member] | Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues	$ (10.1)	$ (9.6)

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Segment Reporting (Tables)

3 Months Ended

Mar. 31, 2015

Segment Reporting [Abstract]

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

	Three Months Ended
	March 31,
(In millions)	2015			2014
Revenues
Gas Utility Services	$	352.9		$	443.6
Electric Utility Services	153.9			163.0
Other Operations	10.2			9.6
Eliminations	(10.1		)	(9.6		)
Total Revenues	$	506.9		$	606.6
Profitability Measure - Net Income
Gas Utility Services	$	40.4		$	38.3
Electric Utility Services	19.2			19.3
Other Operations	3.4			3.7
Total Net Income	$	63.0		$	61.3

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Subsidiary Guarantor and Consolidating Information Balance Sheet (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Dec. 31, 2014	Mar. 31, 2014	Dec. 31, 2013
ASSETS
Cash & cash equivalents	$ 10.4	$ 19.3	$ 52.6	$ 8.6
Accounts receivable - less reserves	137.3	113.0
Accrued unbilled revenues	94.3	122.4
Inventories	86.8	113.2
Recoverable fuel & natural gas costs	0	9.8
Prepayments & other current assets	20.5	83.5
Total current assets	349.3	461.2
Original cost	5,778.0	5,718.7
Less: accumulated depreciation & amortization	2,316.9	2,279.7
Net utility plant	3,461.1	3,439.0
Investments in unconsolidated affiliates	0.2	0.2
Other investments	25.4	25.6
Nonutility property - net	145.7	149.2
Goodwill - net	205.0	205.0
Regulatory assets	119.5	128.3
Other assets	17.8	19.6
TOTAL ASSETS	4,324.0	4,428.1
LIABILITIES & SHAREHOLDERS' EQUITY
Accounts payable	132.2	180.4
Payables to other Vectren companies	19.7	28.6
Refundable fuel and natural gas costs	23.0	0
Accrued liabilities	148.6	122.3
Short-term borrowings	5.9	156.4
Current maturities of long-term debt	90.0	95.0
Total current liabilities	419.4	582.7
Long-term debt - net of current maturities & debt subject to tender	1,162.4	1,162.3
Deferred income taxes	696.4	685.1
Regulatory liabilities	417.1	410.3
Deferred Credits and Other Liabilities	113.2	109.2
Total deferred credits and other liabilities	1,226.7	1,204.6
Common stock (no par value)	795.3	793.7
Retained earnings	720.2	684.8
Total common shareholders' equity	1,515.5	1,478.5
TOTAL LIABILITIES and SHAREHOLDERS' EQUITY	4,324.0	4,428.1
Subsidiary Guarantors [Member]
ASSETS
Cash & cash equivalents	10.0	6.9	35.8	8.2
Accounts receivable - less reserves	137.3	113.0
Intercompany Receivables	69.8	0.8
Accrued unbilled revenues	94.3	122.4
Inventories	86.7	113.2
Recoverable fuel & natural gas costs		9.8
Prepayments & other current assets	11.6	94.8
Total current assets	409.7	460.9
Original cost	5,778.0	5,718.7
Less: accumulated depreciation & amortization	2,316.9	2,279.7
Net utility plant	3,461.1	3,439.0
Investments in consolidated subsidiaries	0	0
Notes receivable from consolidated subsidiaries	0	0
Investments in unconsolidated affiliates	0.2	0.2
Other investments	21.3	21.3
Nonutility property - net	1.7	1.8
Goodwill - net	205.0	205.0
Regulatory assets	98.2	106.7
Other assets	28.8	29.4
TOTAL ASSETS	4,226.0	4,264.3
LIABILITIES & SHAREHOLDERS' EQUITY
Accounts payable	127.4	176.2
Intercompany payables	12.8	15.6
Payables to other Vectren companies	19.7	28.6
Refundable fuel and natural gas costs	23.0
Accrued liabilities	165.7	136.7
Short-term borrowings	0	0
Intercompany short-term borrowings	22.4	97.0
Current maturities of long-term debt	15.0	20.0
Current maturities of long-term debt due to VUHI	74.1	74.1
Total current liabilities	460.1	548.2
Long-term debt - net of current maturities & debt subject to tender	362.7	362.6
Long-term debt due to VUHI	746.5	746.5
Total long-term debt - net	1,109.2	1,109.1
Deferred income taxes	668.5	665.8
Regulatory liabilities	415.6	408.8
Deferred Credits and Other Liabilities	120.3	115.5
Total deferred credits and other liabilities	1,204.4	1,190.1
Common stock (no par value)	808.5	806.9
Retained earnings	643.8	610.0
Total common shareholders' equity	1,452.3	1,416.9
TOTAL LIABILITIES and SHAREHOLDERS' EQUITY	4,226.0	4,264.3
Parent Company [Member]
ASSETS
Cash & cash equivalents	0.4	12.4	16.8	0.4
Accounts receivable - less reserves	0	0
Intercompany Receivables	109.3	186.7
Accrued unbilled revenues	0	0
Inventories	0.1	0
Recoverable fuel & natural gas costs		0
Prepayments & other current assets	43.9	38.1
Total current assets	153.7	237.2
Original cost	0	0
Less: accumulated depreciation & amortization	0	0
Net utility plant	0	0
Investments in consolidated subsidiaries	1,452.3	1,416.9
Notes receivable from consolidated subsidiaries	746.5	746.5
Investments in unconsolidated affiliates	0	0
Other investments	4.1	4.3
Nonutility property - net	144.0	147.4
Goodwill - net	0	0
Regulatory assets	21.3	21.6
Other assets	1.6	1.7
TOTAL ASSETS	2,523.5	2,575.6
LIABILITIES & SHAREHOLDERS' EQUITY
Accounts payable	4.8	4.2
Intercompany payables	0.7	0.8
Payables to other Vectren companies	0	0
Refundable fuel and natural gas costs	0
Accrued liabilities	17.9	35.0
Short-term borrowings	5.9	156.4
Intercompany short-term borrowings	69.1	0
Current maturities of long-term debt	75.0	75.0
Current maturities of long-term debt due to VUHI	0	0
Total current liabilities	173.4	271.4
Long-term debt - net of current maturities & debt subject to tender	799.7	799.7
Long-term debt due to VUHI	0	0
Total long-term debt - net	799.7	799.7
Deferred income taxes	27.9	19.3
Regulatory liabilities	1.5	1.5
Deferred Credits and Other Liabilities	5.5	5.2
Total deferred credits and other liabilities	34.9	26.0
Common stock (no par value)	795.3	793.7
Retained earnings	720.2	684.8
Total common shareholders' equity	1,515.5	1,478.5
TOTAL LIABILITIES and SHAREHOLDERS' EQUITY	2,523.5	2,575.6
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	(179.1)	(187.5)
Accrued unbilled revenues	0	0
Inventories	0	0
Recoverable fuel & natural gas costs		0
Prepayments & other current assets	(35.0)	(49.4)
Total current assets	(214.1)	(236.9)
Original cost	0	0
Less: accumulated depreciation & amortization	0	0
Net utility plant	0	0
Investments in consolidated subsidiaries	(1,452.3)	(1,416.9)
Notes receivable from consolidated subsidiaries	(746.5)	(746.5)
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	(12.6)	(11.5)
TOTAL ASSETS	(2,425.5)	(2,411.8)
LIABILITIES & SHAREHOLDERS' EQUITY
Accounts payable	0	0
Intercompany payables	(13.5)	(16.4)
Payables to other Vectren companies	0	0
Refundable fuel and natural gas costs	0
Accrued liabilities	(35.0)	(49.4)
Short-term borrowings	0	0
Intercompany short-term borrowings	(91.5)	(97.0)
Current maturities of long-term debt	0	0
Current maturities of long-term debt due to VUHI	(74.1)	(74.1)
Total current liabilities	(214.1)	(236.9)
Long-term debt - net of current maturities & debt subject to tender	0	0
Long-term debt due to VUHI	(746.5)	(746.5)
Total long-term debt - net	(746.5)	(746.5)
Deferred income taxes	0	0
Regulatory liabilities	0	0
Deferred Credits and Other Liabilities	(12.6)	(11.5)
Total deferred credits and other liabilities	(12.6)	(11.5)
Common stock (no par value)	(808.5)	(806.9)
Retained earnings	(643.8)	(610.0)
Total common shareholders' equity	(1,452.3)	(1,416.9)
TOTAL LIABILITIES and SHAREHOLDERS' EQUITY	(2,425.5)	(2,411.8)
Consolidated Entities [Member]
ASSETS
Cash & cash equivalents	10.4	19.3	52.6	8.6
Accounts receivable - less reserves	137.3	113.0
Intercompany Receivables	0	0
Accrued unbilled revenues	94.3	122.4
Inventories	86.8	113.2
Recoverable fuel & natural gas costs		9.8
Prepayments & other current assets	20.5	83.5
Total current assets	349.3	461.2
Original cost	5,778.0	5,718.7
Less: accumulated depreciation & amortization	2,316.9	2,279.7
Net utility plant	3,461.1	3,439.0
Investments in consolidated subsidiaries	0	0
Notes receivable from consolidated subsidiaries	0	0
Investments in unconsolidated affiliates	0.2	0.2
Other investments	25.4	25.6
Nonutility property - net	145.7	149.2
Goodwill - net	205.0	205.0
Regulatory assets	119.5	128.3
Other assets	17.8	19.6
TOTAL ASSETS	4,324.0	4,428.1
LIABILITIES & SHAREHOLDERS' EQUITY
Accounts payable	132.2	180.4
Intercompany payables	0	0
Payables to other Vectren companies	19.7	28.6
Refundable fuel and natural gas costs	23.0
Accrued liabilities	148.6	122.3
Short-term borrowings	5.9	156.4
Intercompany short-term borrowings	0	0
Current maturities of long-term debt	90.0	95.0
Current maturities of long-term debt due to VUHI	0	0
Total current liabilities	419.4	582.7
Long-term debt - net of current maturities & debt subject to tender	1,162.4	1,162.3
Long-term debt due to VUHI	0	0
Total long-term debt - net	1,162.4	1,162.3
Deferred income taxes	696.4	685.1
Regulatory liabilities	417.1	410.3
Deferred Credits and Other Liabilities	113.2	109.2
Total deferred credits and other liabilities	1,226.7	1,204.6
Common stock (no par value)	795.3	793.7
Retained earnings	720.2	684.8
Total common shareholders' equity	1,515.5	1,478.5
TOTAL LIABILITIES and SHAREHOLDERS' EQUITY	$ 4,324.0	$ 4,428.1

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Basis of Presentation

3 Months Ended

Mar. 31, 2015

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, 2014, 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	Mar. 31, 2015	Dec. 31, 2014
Assets, Current [Abstract]
Allowance for Doubtful Accounts Receivable, Current	$ 5.3	$ 3.9

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Fair Value Measurements

3 Months Ended

Mar. 31, 2015

Fair Value Disclosures [Abstract]

Fair Value Measurements

Fair Value Measurements

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

	March 31, 2015				December 31, 2014
(In millions)	Carrying Amount		Est. Fair Value		Carrying Amount		Est. Fair Value
Long-term debt	$	1,252.4	$	1,409.7	$	1,257.3	$	1,408.0
Short-term borrowings	5.9		5.9		156.4		156.4
Cash & cash equivalents	10.4		10.4		19.3		19.3

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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Document and Entity Information	3 Months Ended
	Mar. 31, 2015	Apr. 30, 2015
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	2015
Document Fiscal Period Focus	Q1
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2015

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Impact of Recently Issued Accounting Principles (Notes)

3 Months Ended

Mar. 31, 2015

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 adopted this guidance on January 1, 2015. The adoption of this guidance had no impact on the Company's financial statements.

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 adoption permitted. Adoption of this guidance will not have a material impact on the Company’s financial statements.

Simplifying the Presentation of Debt Issuance Costs

In April 2015, the FASB issued new accounting guidance on accounting for debt issuance costs which changes the presentation of debt issuance costs in financial statements. This ASU requires an entity to present such costs in the balance sheet as a direct deduction from the related debt liability rather than as an asset. Amortization of the costs will continue to be reported as interest expense. This ASU is effective for annual reporting periods beginning after December 15, 2015. Early adoption is permitted. The new guidance will be applied retrospectively to each prior period presented. The Company is currently evaluating the standard to understand the overall impact it will have on the financial statements. Adoption will have no impact on the Company's consolidated income statement.

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CONSOLIDATED CONDENSED STATEMENTS OF INCOME (Unaudited) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
OPERATING REVENUES [Abstract]
Gas utility	$ 352.9	$ 443.6
Electric utility	153.9	163.0
Other	0.1	0
Total operating revenues	506.9	606.6
OPERATING EXPENSES [Abstract]
Cost of gas sold	172.0	270.9
Cost of fuel & purchased power	50.1	57.0
Other operating	102.8	98.3
Depreciation & Amortization	52.1	49.9
Taxes other than income taxes	19.1	20.1
Total operating expenses	396.1	496.2
OPERATING INCOME	110.8	110.4
Nonoperating Income (Expense) [Abstract]
Other income - net	4.9	3.9
Interest Expense	16.6	16.7
INCOME BEFORE INCOME TAXES	99.1	97.6
Income taxes	36.1	36.3
NET INCOME	$ 63.0	$ 61.3

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Financing Activities

3 Months Ended

Mar. 31, 2015

Debt Disclosure [Abstract]

Financing Activities

 Financing Activities

Indiana Gas Unsecured Note Retirement

On March 15, 2015, a $5.0 million Indiana Gas senior unsecured note matured. The Series E note carried a fixed interest rate of 7.15%. The repayment of debt was funded from the Company's short term credit facility.

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Transactions with Other Vectren Companies and Affiliates

3 Months Ended

Mar. 31, 2015

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.  The Company purchased $30.8 million for the three months ended March 31, 2014.  After the exit of the coal mining business by Vectren, Sunrise has assumed Vectren Fuels' supply contracts and has also negotiated new contracts for similar quality coal that will result in the Company purchasing most of its coal supply from Sunrise.

Vectren Infrastructure Services Corporation (VISCO)

VISCO, a wholly owned subsidiary of Vectren, provides underground pipeline construction and repair services. VISCO's customers include Utility Holdings’ utilities and fees incurred by Utility Holdings and its subsidiaries totaled $17.7 million and $11.4 million for the three months ended March 31, 2015 and 2014, respectively. Amounts owed to VISCO at March 31, 2015 and December 31, 2014 are included in Payables to other Vectren companies in the Condensed Consolidated Balance Sheets.

Support Services & Purchases

Vectren provides corporate and general and administrative services to the Company and allocates certain costs to the Company, including costs for share-based compensation and for pension and other postretirement benefits that are not directly charged to subsidiaries. These costs are allocated using various allocators, including number of employees, number of customers and/or the level of payroll, revenue contribution and capital expenditures.  Allocations are at cost.  For the three months ended March 31, 2015 and 2014, Utility Holdings received corporate allocations totaling $15.6 million and $14.7 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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Organization and Nature of Operations (Details)	3 Months Ended
	Mar. 31, 2015
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)	585,000
Estimated number of electric customers located near Evansville in southwestern Indiana serviced by Southern Indiana Gas and Electric Company (in number of customers)	143,000
Estimated number of natural gas customers located near Evansville in southwestern Indiana serviced by Southern Indiana Gas and Electric Company (in number of customers)	111,000
Estimated number of natural gas customers located near Dayton in west central Ohio serviced by the Ohio operations (in number of customers)	317,000

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Segment Reporting

3 Months Ended

Mar. 31, 2015

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
	March 31,
(In millions)	2015			2014
Revenues
Gas Utility Services	$	352.9		$	443.6
Electric Utility Services	153.9			163.0
Other Operations	10.2			9.6
Eliminations	(10.1		)	(9.6		)
Total Revenues	$	506.9		$	606.6
Profitability Measure - Net Income
Gas Utility Services	$	40.4		$	38.3
Electric Utility Services	19.2			19.3
Other Operations	3.4			3.7
Total Net Income	$	63.0		$	61.3

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Electric Rate and Regulatory Matters

3 Months Ended

Mar. 31, 2015

Public Utilities, General Disclosures [Abstract]

Electric Rate and Regulatory Matters

Electric Rate & Regulatory Matters

SIGECO Electric Environmental Compliance Filing

On January 28, 2015, the IURC issued an Order approving the Company’s request for approval of capital investments 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. As of March 31, 2015, approximately $29 million has been spent on equipment to control mercury in both air and water emissions, and $16 million to address the issues raised in the NOV proceeding on the increase in sulfur trioxide emissions. The total investment is estimated to be between $80 and $90 million. The Order approved the Company’s request for deferred accounting treatment, as supported by provisions under Indiana Senate Bill 29 (Senate Bill 29) and Senate Bill 251. The accounting treatment includes the deferral of depreciation and property tax expense related to these investments, accrual of post-in-service carrying costs, and deferral of incremental operating expenses related to compliance with these standards. The initial phase of the projects went into service in 2014, with the remaining investment expected to occur in 2015 and 2016. As of March 31, 2015, the Company has approximately $0.7 million deferred related to depreciation, property tax, and operating expense, and $0.3 million deferred related to post-in-service carrying costs.

In March 2015, the Company was notified that certain parties had filed a Notice of Appeal with the Indiana Court of Appeals in response to the IURC's Order. Appellate briefs will be presented to the Court later in 2015 and it is expected the Court will decide on these issues in the second half of this year.

Coal Procurement Procedures

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 its supply of coal with specifications that support its compliance with the Mercury and Air Toxins Rule. Subsequent to the sale of Vectren Fuels to Sunrise Coal in August 2014, 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. In December 2014, the IURC determined that the terms of the coal contracts were reasonable. The annual sub docket proceeding is no longer required.

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, which began February 2014, was$42.4 million, of which $33.6 million remains as of March 31, 2015.

SIGECO Electric Demand Side Management (DSM) Program Filing

On August 31, 2011 the IURC issued an Order approving an initial three year DSM plan in the SIGECO electric service territory that complied with the IURC’s energy saving targets. Consistent with the Company’s proposal, the Order approved, among other items, the following: 1) recovery of costs associated with implementing the DSM Plan; 2) the recovery of a performance incentive mechanism based on measured savings related to certain DSM programs; 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 three months endedMarch 31, 2015 and 2014, the Company recognized Electric utility revenue of $2.3 million and $1.6 million, respectively, associated with this approved lost margin recovery mechanism.

On March 28, 2014, Indiana Senate Bill 340 was signed into law. This legislation ended electric DSM programs on December 31, 2014 that have been conducted to meet the energy savings requirements established in the IURC's December 2009 Order. The legislation also allows for industrial customers to opt out of participating in energy efficiency programs. As of January 1, 2015, approximately 80 percent of the Company’s eligible industrial load has opted out of participation in the applicable energy efficiency programs. Indiana's governor has requested that the IURC 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 IURC approval of a new portfolio of DSM programs on May 29, 2014 to be offered in 2015. On October 15, 2014, the IURC issued an Order approving a Settlement between the OUCC and the Company regarding the new portfolio of DSM programs effective January 2015, and new programs were implemented during the first quarter 2015. On May 6, 2015, Indiana's governor signed Indiana Senate Bill 412 into law requiring electricity suppliers to create and submit energy-efficiency plans to the IURC at least one time every three years. Senate Bill 412 also supports the recovery of all program costs, including lost revenues and financial incentives associated with those plans and approved by the IURC. The Company will make its first filing pursuant to this bill in May 2015.

FERC Return on Equity (ROE) 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 March 31, 2015, the Company had invested approximately $157.7 million in qualifying projects. The net plant balance for these projects totaled $142.8 million at March 31, 2015.

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 a 10.57 percent return on equity and a 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. A settlement has not been reached, and the case will move to a formal evidentiary hearing before the FERC. A procedural schedule was set on January 22, 2015, which defines a targeted date of final resolution from the FERC. An initial decision is expected later in 2015, but the timing of the final order from the FERC is unknown at this time. The Company has established a reserve pending the outcome of this complaint.

Separately, on January 6, 2015, the FERC approved a MISO transmission owner joint request for an adder to the approved ROE. Under FERC regulations, transmission owners that are part of a Regional Transmission Organization (RTO) such as MISO are authorized to earn an incentive of 50 basis points above the FERC approved ROE. The FERC deferred the implementation of this adder until the pending complaint is resolved. Once the FERC sets a new ROE in the complaint case, this adder will be applied to that ROE, with retroactive billing to occur back to January 7, 2015.

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Commitments and Contingencies

3 Months Ended

Mar. 31, 2015

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. 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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Gas Rate & Regulatory Matters

3 Months Ended

Mar. 31, 2015

Public Utilities, General Disclosures [Abstract]

Gas Rate and Regulatory Matters

Gas Rate & Regulatory Matters

Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement

The Company monitors and maintains its natural gas distribution system to ensure that natural gas is delivered in a safe and efficient manner. The Company's natural gas utilities are currently engaged in programs to replace bare steel and cast iron infrastructure and other activities in both Indiana and Ohio to mitigate risk, improve the system, and comply with applicable regulations, many of which are a result of federal pipeline safety requirements. Laws 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.

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

In April 2013, Indiana Senate Bill 560 (Senate Bill 560) was signed into Indiana law. This legislation supplements Senate Bill 251 described above, and provides for cost recovery outside of a base rate proceeding for projects that either improve electric and gas system reliability and safety or are economic development projects that provide rural areas with access to gas service. Provisions of the legislation require that, among other things, requests for recovery include a seven-year project plan. Once the plan is approved by the IURC, 80 percent of such costs are eligible for current recovery using a periodic rate adjustment mechanism. Recoverable costs include a return on and of the investment, as well as property taxes and operating expenses. The remaining 20 percent of project costs is deferred and recovered in the utility’s next general rate case, which must be filed before the expiration of the seven year plan. The adjustment mechanism is capped at an annual increase in retail revenues of no more than two percent.

In June 2011, Ohio House Bill 95 (House Bill 95) was signed into law. Outside of a base rate proceeding, this legislation permits a natural gas utility to apply for recovery of much of its capital expenditure program. By allowing for the deferral of costs, such as depreciation, property taxes, and debt-related post in service carrying costs until recovery is approved by the Ohio Commission.

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 March 31, 2015 and December 31, 2014, the Company has regulatory assets totaling $17.3 million and $16.4 million, respectively, associated with the deferral of depreciation and debt-related post-in-service carrying cost activities. Beginning in 2014, all bare steel and cast iron replacement activities are now part of the Company’s seven-year capital investment plan filed pursuant to Senate Bill 251, discussed further below.

Requests for Recovery Under Indiana Regulatory Mechanisms

On August 27, 2014, the IURC 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 Senate Bill 251 and 560. As provided in the two laws, the Order approved semi-annual filings for rate recovery of 100 percent of the costs, inclusive of return, related to these capital investments and operating expenses, with 80 percent of the costs recovered currently via an approved tracking mechanism and 20 percent of the costs deferred and recovered in the Company’s next base rate proceeding. In addition, the Order established guidelines to annually update the seven-year capital investment plan. Finally, the Order approved the Company’s proposal to recover eligible costs via a fixed monthly charge per residential customer.

On September 26, 2014, the OUCC filed an appeal of the IURC's finding that the remaining value of retired assets replaced during the infrastructure projects should not be netted against the cost being recovered in the tracking mechanism. In April 2015, the Indiana Court of Appeals issued an opinion on an appeal involving Northern Indiana Public Service Company’s (NIPSCO) infrastructure cost recovery mechanism finding that the value of retired assets should not be netted against the current recovery of costs. Although the opinion is specific to NIPSCO, the Company believes this decision is a positive outcome related to its pending appeal.

Additionally, in the NIPSCO appeal, the IURC’s approval of the reasonableness of that infrastructure investment plan was challenged. The Court found that NIPSCO had failed to provide sufficient detail regarding its planned projects after year one of the plan to support the IURC's approval. An industrial group has asked the Court of Appeals to now consider that issue as part of the pending appeal of the Company's Order. Given this issue was never raised during the Company's IURC case or on appeal during the briefing period, the Company believes the opportunity to raise this issue has been waived and has asked the Court to strike the filing. The Court should decide these issues later this year.

On January 14, 2015, the IURC issued an Order approving the Company’s initial request for recovery of the revenue requirement through June 30, 2014 as part of its approved seven-year plan. As the next step of the recovery process, as outlined in the legislation, this Order initiates the rates and charges 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 case. Also, consistent with the guidelines set forth in the original August 2014 Order, the IURC approved the Company’s 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, an increase of $35 million from the previous plan and is 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.

On April 1, 2015, the Company filed its second request for recovery of the revenue requirement associated with capital investment and applicable operating costs through December 31, 2014. A procedural schedule has not been set in this proceeding. The Company expects an order in this proceeding mid-year in 2015.

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 $156.5 million. Regulatory assets associated with post-in-service carrying costs and depreciation deferrals were $14.2 million and $13.1 million at March 31, 2015 and December 31, 2014, 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 issued an Order approving a Stipulation entered into by the PUCO Staff and the Company which provided for the extension of the DRR for the recovery of costs incurred through 2017 and expanded the types of investment covered by the DRR to include recovery of other infrastructure investments. The Order limits the resulting DRR fixed charge per month for residential and small general service customers to specific graduated levels over the next five years. The Company's five-year capital expenditure plan related to these infrastructure investments for calendar years 2013 through 2017 totals approximately $200 million. The capital expenditure plan is subject to the graduated caps on the fixed DRR monthly charge applicable to residential and small general service customers approved in the Order however is not expected to exceed those caps. 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 rates and charges, effective September 1, 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 below are not expected to be reached given the Company's capital expenditure plan during the remaining three-year time frame.

The PUCO has also issued Orders approving the Company's filings under Ohio House Bill 95. These Orders approve deferral of the Company’s Ohio capital expenditure program for items not covered by the DRR as well as expenditures necessary to comply with PUCO rules, regulations, orders, and system expansion to some new customers. Ohio House Bill 95 Orders also have established a prospective bill impact evaluation on the cumulative deferrals, limiting the total deferrals at a level which would equal $1.50 per residential and small general service customer per month. As of March 31, 2015, the Company's deferrals have not reached this bill impact cap. In addition, the Orders 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.

Other Regulatory Matters

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 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 modified its position in testimony filed on November 5, 2014, and suggested a reduced disallowance of $3 million. The IURC moved this specific issue to a sub-docket proceeding. On April 1, 2015, a stipulation and settlement agreement between the Company, the OUCC, and the Company’s supply administrator was filed in this proceeding. Pending a final order from the IURC approving the stipulation, the agreement results in recovery of approximately $1.4 million of the disputed amount via the Company’s GCA mechanism, with the remaining $1.6 million from the gas supply administrator.

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 Indiana gas companies and recovery of new conservation program costs through December 2015. The Companies have reached an agreement in principle with the OUCC to extend the decoupling mechanism through 2020. The settlement was filed for approval on March 1, 2015. The settlement was unopposed and a hearing has been set for May 2015. The Company expects an order later in 2015.

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Environmental Matters

3 Months Ended

Mar. 31, 2015

Environmental Matters Disclosure [Abstract]

Environmental Matters

Environmental Matters

Indiana Senate Bill 251

Senate Bill 251 is also applicable to federal environmental mandates impacting SIGECO electric operations in addition to the impact on its gas utility 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

Cross-State Air Pollution Rule

In July 2011, the EPA finalized the Cross-State Air Pollution Rule (CSAPR). CSAPR was the EPA’s response to the US Court of Appeals for the District of Columbia’s (the Court) remand of the Clean Air Interstate Rule (CAIR). CAIR was originally established in 2005 as an allowance cap and trade program that required reductions from coal-burning power plants for NOX emissions beginning January 1, 2009 and SO2 emissions beginning January 1, 2010, with a second phase of reductions in 2015. In an effort to address the Court’s finding that CAIR did not adequately ensure attainment of pollutants in certain downwind states due to unlimited trading of SO2 and NOX allowances, CSAPR reduced the ability of facilities to meet emission reduction targets through allowance trading. CSAPR reductions were to be achieved with initial step reductions beginning January 1, 2012, and final compliance to be achieved in 2014. After a series of legal challenges, the United States Supreme Court upheld CSAPR in April 2014, and the EPA finalized a new deadline schedule for entities that must comply, with CSAPR’s first phase caps starting in 2015 and 2016, and the second phase in 2017. The Company is in full compliance with all requirements of CSAPR.

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. Reductions are to be achieved within three years of publication of the final rule in the Federal Register. 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. Legal challenges to the MATS Rule continue. 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. On November 25, 2014, the U.S. Supreme Court agreed to hear the case, with oral arguments completed, a decision is expected later in 2015. MATS compliance was required to commence April 16, 2015, and Company is in full compliance with all requirements of MATS.

Notice of Violation for A.B. Brown Power Plant

The Company received a NOV from the EPA in November 2011 pertaining to its A.B. Brown generating station. The NOV asserts that when the facility was equipped with Selective Catalytic Reduction (SCR) systems, the correct permits were not obtained or the best available control technology to control incidental sulfuric acid mist was not installed. The Company reached a settlement in principle with the EPA to resolve the NOV. That settlement was contemplated in the plan filed and approved by the IURC on January 28, 2015 in the SIGECO Electric Environmental Compliance Filing.

Ozone NAAQS

On November 26, 2014, the EPA proposed to tighten the current National Ambient Air Quality Standard (NAAQS) for ozone from the current standard of 75 parts per billion (ppb) to a level with the range of 65 to 70 ppb. The EPA has stated that it intends to finalize the rule by October 2015. Upon finalization, the EPA will then determine whether a particular region is in attainment with the new standard. While it is possible that counties in southwest Indiana could be declared in non-attainment with the new standard, and thus may have an effect on future economic development activities in the Company's service territory, the Company does not anticipate any significant compliance cost impacts from the determination given its previous investment in SCR technology for NOx control on its units.

Water

Section 316(b) of the Clean Water Act requires that generating facilities use the “best technology available” (BTA) to minimize adverse environmental impacts on a body of water. More specifically, Section 316(b) is concerned with impingement and entrainment of aquatic species in once-through cooling water intake structures used at electric generating facilities. A final rule was issued by the EPA on May 19, 2014. The final rule does not mandate cooling water tower retrofits but requires a state level case by case assessment of BTA for each facility. The final rule lists seven presumptive technologies which would qualify as BTA. These technologies range from intake screen modifications to cooling water tower retrofits. Ecological and technology assessment studies must be completed prior to determining BTA for the Company’s facilities. To comply, 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 however the rule is not yet finalized. 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, 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.

As noted previously, on January 28, 2015, the IURC issued an Order approving the Company’s request for approval of capital investments on its coal-fired generation units to comply with new EPA mandates related to mercury and air toxin standards effective in 2015 and to address an outstanding Notice of Violation (NOV) from the EPA. The total investment is estimated to be between $80 and $90 million, roughly half of which will be made to control mercury in both air and water emissions, and the remaining investment will be made to address the issues raised in the NOV proceeding on the increase in sulfur trioxide emissions.

Coal Ash Waste Disposal & Ash Ponds

In December 2014 the EPA released its final coal ash rule which regulates ash as non-hazardous material under Subtitle D of the Resource Conservation and Recovery Act (RCRA). On April 17, 2015, the final rule was published in the Federal Register. Under the final rule the Company will be required to perform additional safety and structural assessments and an enhanced groundwater monitoring program to determine whether its existing ash ponds may remain in operation, be closed, or retrofitted with liners. The final rule allows beneficial reuse of ash and the Company will continue to reuse a majority of its ash. Legislation is currently being considered by Congress that would provide for enforcement of the federal program by states.

Under the final CCR rule, the Company is required to complete a series of integrity assessments and groundwater monitoring studies to determine whether one or more of the Company's ash ponds can continue in service, or whether a pond must be retrofitted with liners or closed and bottom ash handling conversions completed. The Company estimates capital expenditures to comply with the alternatives in the final rule could range from minor additional capital expenditures, if the ponds are permitted to continue to operate, and could exceed $100 million if all existing ponds at both F.B. Culley and A.B. Brown generating stations must be closed and bottom ash conversions completed at each generating unit. The Company is in the process of evaluating the impact of this rule and any impact on its asset retirement obligation (ARO). It is expected that any 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 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. The EPA provided an extended time frame for public commentary to December 1, 2014. The proposal sets state-specific CO2 emission rate-based CO2 goals (measured in lb CO2/MWh) 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 instead are state goals. As such, the state must establish a framework that will guide how compliance will be met on a statewide basis. Indiana’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 9th lowest reduction requirement. 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. The Company timely filed comments to the Clean Power Plan proposal on December 1, 2014. The State of Indiana also filed public comments, asking that the proposal be withdrawn. Despite having just been recently proposed and not expected to be finalized until summer 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. Oral arguments have been completed before the U.S. Court of Appeals for the D.C. Circuit, with a decision expected later in the summer.

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 5th largest carbon emitter in the nation in tons of CO2 produced from electric generation. In 2013, Indiana’s electric utilities generated 105.6 million tons of CO2. The Company’s share of that total was 6.3 million, or less than 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 F.B. 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 renewable generation, in 2008 and 2009, the Company executed long-term purchase power commitments for a total of 80 MW of wind energy. The Company currently has approximately 4 percent of its electricity being provided by clean energy sources due to the long-term wind contracts and landfill gas investment. With respect to CO2 emission rate, since 2005 the Company has lowered its CO2 emission rate (as measured in lbs CO2/MWh) from 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 continue to remain engaged with the state to develop a plan for compliance and 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.

Manufactured Gas Plants

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

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

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

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

The costs the Company expects to incur are estimated by management using assumptions based on actual costs incurred, the timing of expected future payments, and inflation factors, among others. While the Company’s utilities have recorded all costs which they presently expect to incur in connection with activities at these sites, it is possible that future events may require remedial activities which are not presently foreseen and those costs may not be subject to PRP or insurance recovery. As of March 31, 2015 and December 31, 2014, approximately $3.5 million and $3.6 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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Fair Value Measurements (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Dec. 31, 2014	Mar. 31, 2014	Dec. 31, 2013
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	$ 5.9	$ 156.4
Cash and Cash Equivalents, at Carrying Value	10.4	19.3	52.6	8.6
Estimated Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Fair Value	1,409.7	1,408.0
Short-term Debt, Fair Value	5.9	156.4
Cash and cash equivalents	10.4	19.3
Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Fair Value	1,252.4	1,257.3
Short-term Debt, Fair Value	5.9	156.4
Cash and cash equivalents	$ 10.4	$ 19.3

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Fair Value Measurements (Tables)

3 Months Ended

Mar. 31, 2015

Fair Value Disclosures [Abstract]

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

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

	March 31, 2015				December 31, 2014
(In millions)	Carrying Amount		Est. Fair Value		Carrying Amount		Est. Fair Value
Long-term debt	$	1,252.4	$	1,409.7	$	1,257.3	$	1,408.0
Short-term borrowings	5.9		5.9		156.4		156.4
Cash & cash equivalents	10.4		10.4		19.3		19.3

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Subsidiary Guarantor and Consolidating Information Cash Flows (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014	Dec. 31, 2013
Net cash provided by operating activities	$ 241.3	$ 156.0
Additional capital contribution from parent	1.6	1.6
Dividends to parent	(27.6)	(27.1)
Retirement of long term debt	(5.0)	0
Net change in intercompany short-term borrowings	0
Net change in short-term borrowings	(150.5)	(28.6)
Net cash used in financing activities	(181.5)	(54.1)
Consolidated subsidiary distributions	0
Proceeds from other investing activities	0.2	0.1
Capital expenditures, excluding AFUDC equity	(68.9)	(58.0)
Consolidated subsidiary investments	0
Net change in short term intercompany notes receivable	0
Net cash used in investing activities	(68.7)	(57.9)
Net change in cash and cash equivalents	(8.9)	44.0
Cash & cash equivalents	10.4	52.6	19.3	8.6
Subsidiary Guarantors [Member]
Net cash provided by operating activities	240.6	137.2
Long-term debt - net of issuance costs		124.2
Additional capital contribution from parent	1.6	1.6
Dividends to parent	(25.8)	(25.4)
Retirement of long term debt	(5.0)
Net change in intercompany short-term borrowings	(74.6)	(73.1)
Net change in short-term borrowings	0	0
Net cash used in financing activities	(103.8)	27.3
Consolidated subsidiary distributions	0	0
Proceeds from other investing activities	0	0
Capital expenditures, excluding AFUDC equity	(64.6)	(51.3)
Consolidated subsidiary investments	0	0
Net change in long-term intercompany notes receivable		0
Net change in short term intercompany notes receivable	(69.1)	(85.6)
Net cash used in investing activities	(133.7)	(136.9)
Net change in cash and cash equivalents	3.1	27.6
Cash & cash equivalents	10.0	35.8	6.9	8.2
Parent Company [Member]
Net cash provided by operating activities	0.7	18.8
Long-term debt - net of issuance costs		0
Additional capital contribution from parent	1.6	1.6
Dividends to parent	(27.6)	(27.1)
Retirement of long term debt	0
Net change in intercompany short-term borrowings	69.1	85.6
Net change in short-term borrowings	(150.5)	(28.6)
Net cash used in financing activities	(107.4)	31.5
Consolidated subsidiary distributions	25.8	25.4
Proceeds from other investing activities	0.2	0.1
Capital expenditures, excluding AFUDC equity	(4.3)	(6.7)
Consolidated subsidiary investments	(1.6)	(1.6)
Net change in long-term intercompany notes receivable		(124.2)
Net change in short term intercompany notes receivable	74.6	73.1
Net cash used in investing activities	94.7	(33.9)
Net change in cash and cash equivalents	(12.0)	16.4
Cash & cash equivalents	0.4	16.8	12.4	0.4
Consolidation, Eliminations [Member]
Net cash provided by operating activities	0	0
Long-term debt - net of issuance costs		(124.2)
Additional capital contribution from parent	(1.6)	(1.6)
Dividends to parent	25.8	25.4
Retirement of long term debt	0
Net change in intercompany short-term borrowings	5.5	(12.5)
Net change in short-term borrowings	0	0
Net cash used in financing activities	29.7	(112.9)
Consolidated subsidiary distributions	(25.8)	(25.4)
Proceeds from other investing activities	0	0
Capital expenditures, excluding AFUDC equity	0	0
Consolidated subsidiary investments	1.6	1.6
Net change in long-term intercompany notes receivable		124.2
Net change in short term intercompany notes receivable	(5.5)	12.5
Net cash used in investing activities	(29.7)	112.9
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		156.0
Long-term debt - net of issuance costs		0
Additional capital contribution from parent		1.6
Dividends to parent		(27.1)
Net change in intercompany short-term borrowings		0
Net change in short-term borrowings		(28.6)
Net cash used in financing activities		(54.1)
Consolidated subsidiary distributions		0
Proceeds from other investing activities		0.1
Capital expenditures, excluding AFUDC equity		(58.0)
Consolidated subsidiary investments		0
Net change in long-term intercompany notes receivable		0
Net change in short term intercompany notes receivable		0
Net cash used in investing activities		(57.9)
Net change in cash and cash equivalents		44.0
Cash & cash equivalents	$ 10.4	$ 52.6	$ 19.3	$ 8.6

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CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS (Unaudited) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
CASH FLOWS FROM OPERATING ACTIVITIES [Abstract]
Profitability Measure - Net income (loss)	$ 63.0	$ 61.3
Adjustments to Reconcile Net Income to Cash from Operating Activities [Abstract]
Depreciation & Amortization	52.1	49.9
Deferred income taxes & investment tax credits	13.2	5.0
Expense portion of pension & postretirement periodic benefit cost	1.2	1.2
Provision for uncollectible accounts	3.1	1.6
Other non-cash expense - net	1.4	0.9
Changes in working capital accounts [Abstract]
Accounts receivable & accrued unbilled revenue	0.7	(34.1)
Inventories	26.4	35.6
Recoverable/refundable fuel & natural gas costs	30.3	(24.2)
Prepayments & other current assets	60.4	26.8
Accounts payable, including to Vectren companies & affiliated companies	(51.7)	(18.4)
Accrued liabilities	28.8	39.7
Changes in noncurrent ssets	12.7	13.3
Changes in noncurrent liabilities	(0.3)	(2.6)
Net cash provided by operating activities	241.3	156.0
Proceeds from:
Additional capital contribution	1.6	1.6
Requirements for:
Dividends to parent	(27.6)	(27.1)
Retirement of long-term debt	(5.0)	0
Net change in short-term borrowings	(150.5)	(28.6)
Net cash used in financing activities	(181.5)	(54.1)
CASH FLOWS FROM INVESTING ACTIVITIES [Abstract]
Proceeds from other investing activities	0.2	0.1
Requirements for:
Capital expenditures, excluding AFUDC equity	(68.9)	(58.0)
Net cash used in investing activities	(68.7)	(57.9)
Net change in cash and cash equivalents	(8.9)	44.0
Cash and cash equivalents at beginning of period	19.3	8.6
Cash and cash equivalents at end of period	$ 10.4	$ 52.6

XML

Supplemental Cash Flow Information

3 Months Ended

Mar. 31, 2015

Accruals for Utility & Nonutility Plant [Abstract]

Accruals for Utility and NonUtility Plant [Text Block]

Supplemental Cash Flow Information

As of March 31, 2015 and December 31, 2014, the Company has accruals related to utility and nonutility plant purchases totaling approximately $12.1 million and $19.0 million, respectively.

XML

Excise and Utility Receipts Taxes (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Excise and Utility Receipts Taxes [Abstract]
Excise and utility taxes collected and reported in operating revenue	$ 11.7	$ 12.9

XML

Subsidiary Guarantor and Consolidating Information(Tables)

3 Months Ended

Mar. 31, 2015

Subsidiary Guarantor and Consolidating Information [Abstract]

Condensed consolidating balance sheets [Table Text Block]

Condensed Consolidating Balance Sheet as of March 31, 2015 (in millions):

ASSETS	Subsidiary		Parent		Eliminations &
	Guarantors		Company		Reclassifications			Consolidated
Current Assets
Cash & cash equivalents	$	10.0	$	0.4	$	—		$	10.4
Accounts receivable - less reserves	137.3		—		—			137.3
Intercompany receivables	69.8		109.3		(179.1		)	—
Accrued unbilled revenues	94.3		—		—			94.3
Inventories	86.7		0.1		—			86.8
Prepayments & other current assets	11.6		43.9		(35.0		)	20.5
Total current assets	409.7		153.7		(214.1		)	349.3
Utility Plant
Original cost	5,778.0		—		—			5,778.0
Less:  accumulated depreciation & amortization	2,316.9		—		—			2,316.9
Net utility plant	3,461.1		—		—			3,461.1
Investments in consolidated subsidiaries	—		1,452.3		(1,452.3		)	—
Notes receivable from consolidated subsidiaries	—		746.5		(746.5		)	—
Investments in unconsolidated affiliates	0.2		—		—			0.2
Other investments	21.3		4.1		—			25.4
Nonutility plant - net	1.7		144.0		—			145.7
Goodwill - net	205.0		—		—			205.0
Regulatory assets	98.2		21.3		—			119.5
Other assets	28.8		1.6		(12.6		)	17.8
TOTAL ASSETS	$	4,226.0	$	2,523.5	$	(2,425.5	)	$	4,324.0
LIABILITIES & SHAREHOLDER'S EQUITY	Subsidiary		Parent		Eliminations &
	Guarantors		Company		Reclassifications			Consolidated
Current Liabilities
Accounts payable	$	127.4	$	4.8	$	—		$	132.2
Intercompany payables	12.8		0.7		(13.5		)	—
Payables to other Vectren companies	19.7		—		—			19.7
Refundable fuel & natural gas costs	23.0		—		—			23.0
Accrued liabilities	165.7		17.9		(35.0		)	148.6
Short-term borrowings	—		5.9		—			5.9
Intercompany short-term borrowings	22.4		69.1		(91.5		)	—
Current maturities of long-term debt	15.0		75.0		—			90.0
Current maturities of long-term debt due to VUHI	74.1		—		(74.1		)	—
Total current liabilities	460.1		173.4		(214.1		)	419.4
Long-Term Debt
Long-term debt	362.7		799.7		—			1,162.4
Long-term debt due to VUHI	746.5		—		(746.5		)	—
Total long-term debt - net	1,109.2		799.7		(746.5		)	1,162.4
Deferred Credits & Other Liabilities
Deferred income taxes	668.5		27.9		—			696.4
Regulatory liabilities	415.6		1.5		—			417.1
Deferred credits & other liabilities	120.3		5.5		(12.6		)	113.2
Total deferred credits & other liabilities	1,204.4		34.9		(12.6		)	1,226.7
Common Shareholder's Equity
Common stock (no par value)	808.5		795.3		(808.5		)	795.3
Retained earnings	643.8		720.2		(643.8		)	720.2
Total common shareholder's equity	1,452.3		1,515.5		(1,452.3		)	1,515.5
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	$	4,226.0	$	2,523.5	$	(2,425.5	)	$	4,324.0

Condensed Consolidating Balance Sheet as of December 31, 2014 (in millions):

ASSETS	Subsidiary		Parent		Eliminations &
	Guarantors		Company		Reclassifications			Consolidated
Current Assets
Cash & cash equivalents	$	6.9	$	12.4	$	—		$	19.3
Accounts receivable - less reserves	113.0		—		—			113.0
Intercompany receivables	0.8		186.7		(187.5		)	—
Accrued unbilled revenues	122.4		—		—			122.4
Inventories	113.2		—		—			113.2
Recoverable fuel & natural gas costs	9.8		—		—			9.8
Prepayments & other current assets	94.8		38.1		(49.4		)	83.5
Total current assets	460.9		237.2		(236.9		)	461.2
Utility Plant
Original cost	5,718.7		—		—			5,718.7
Less:  accumulated depreciation & amortization	2,279.7		—		—			2,279.7
Net utility plant	3,439.0		—		—			3,439.0
Investments in consolidated subsidiaries	—		1,416.9		(1,416.9		)	—
Notes receivable from consolidated subsidiaries	—		746.5		(746.5		)	—
Investments in unconsolidated affiliates	0.2		—		—			0.2
Other investments	21.3		4.3		—			25.6
Nonutility plant - net	1.8		147.4		—			149.2
Goodwill - net	205.0		—		—			205.0
Regulatory assets	106.7		21.6		—			128.3
Other assets	29.4		1.7		(11.5		)	19.6
TOTAL ASSETS	$	4,264.3	$	2,575.6	$	(2,411.8	)	$	4,428.1
LIABILITIES & SHAREHOLDER'S EQUITY	Subsidiary		Parent		Eliminations &
	Guarantors		Company		Reclassifications			Consolidated
Current Liabilities
Accounts payable	$	176.2	$	4.2	$	—		$	180.4
Intercompany payables	15.6		0.8		(16.4		)	—
Payables to other Vectren companies	28.6		—		—			28.6
Accrued liabilities	136.7		35.0		(49.4		)	122.3
Short-term borrowings	—		156.4		—			156.4
Intercompany short-term borrowings	97.0		—		(97.0		)	—
Current maturities of long-term debt	20.0		75.0		—			95.0
Current maturities of long-term debt due to VUHI	74.1		—		(74.1		)	—
Total current liabilities	548.2		271.4		(236.9		)	582.7
Long-Term Debt
Long-term debt - net of current maturities &
debt subject to tender	362.6		799.7		—			1,162.3
Long-term debt due to VUHI	746.5		—		(746.5		)	—
Total long-term debt - net	1,109.1		799.7		(746.5		)	1,162.3
Deferred Credits & Other Liabilities
Deferred income taxes	665.8		19.3		—			685.1
Regulatory liabilities	408.8		1.5		—			410.3
Deferred credits & other liabilities	115.5		5.2		(11.5		)	109.2
Total deferred credits & other liabilities	1,190.1		26.0		(11.5		)	1,204.6
Common Shareholder's Equity
Common stock (no par value)	806.9		793.7		(806.9		)	793.7
Retained earnings	610.0		684.8		(610.0		)	684.8
Total common shareholder's equity	1,416.9		1,478.5		(1,416.9		)	1,478.5
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	$	4,264.3	$	2,575.6	$	(2,411.8	)	$	4,428.1

Condensed consolidating statements fo income [Table Text Block]

	Subsidiary Guarantors		Parent Company			Eliminations & Reclassifications			Consolidated
OPERATING REVENUES
Gas utility	$	352.9	$	—		$	—		$	352.9
Electric utility	153.9		—			—			153.9
Other	—		10.2			(10.1		)	0.1
Total operating revenues	506.8		10.2			(10.1		)	506.9
OPERATING EXPENSES
Cost of gas sold	172.0		—			—			172.0
Cost of fuel & purchased power	50.1		—			—			50.1
Other operating	112.4		—			(9.6		)	102.8
Depreciation & amortization	45.6		6.4			0.1			52.1
Taxes other than income taxes	18.7		0.4			—			19.1
Total operating expenses	398.8		6.8			(9.5		)	396.1
OPERATING INCOME	108.0		3.4			(0.6		)	110.8
Other income - net	4.1		10.8			(10.0		)	4.9
Interest expense	15.9		11.3			(10.6		)	16.6
INCOME BEFORE INCOME TAXES	96.2		2.9			—			99.1
Income taxes	36.7		(0.6		)	—			36.1
Equity in earnings of consolidated companies, net of tax	—		59.5			(59.5		)	—
NET INCOME	$	59.5	$	63.0		$	(59.5	)	$	63.0

Condensed Consolidating Statement of Income for the three months ended March 31, 2014 (in millions):

	Subsidiary Guarantors		Parent Company			Eliminations & Reclassifications			Consolidated
OPERATING REVENUES
Gas utility	$	443.6	$	—		$	—		$	443.6
Electric utility	163.0		—			—			163.0
Other	—		9.6			(9.6		)	—
Total operating revenues	606.6		9.6			(9.6		)	606.6
OPERATING EXPENSES
Cost of gas sold	270.9		—			—			270.9
Cost of fuel & purchased power	57.0		—			—			57.0
Other operating	107.5		—			(9.2		)	98.3
Depreciation & amortization	44.4		5.4			0.1			49.9
Taxes other than income taxes	19.6		0.4			0.1			20.1
Total operating expenses	499.4		5.8			(9.0		)	496.2
OPERATING INCOME	107.2		3.8			(0.6		)	110.4
Other income - net	3.0		10.7			(9.8		)	3.9
Interest expense	15.8		11.3			(10.4		)	16.7
INCOME BEFORE INCOME TAXES	94.4		3.2			—			97.6
Income taxes	36.8		(0.5		)	—			36.3
Equity in earnings of consolidated companies, net of tax	—		57.6			(57.6		)	—
NET INCOME	$	57.6	$	61.3		$	(57.6	)	$	61.3

Condensed consolidating statements of cash flows [Table Text Block]

Condensed Consolidating Statement of Cash Flows for the three months endedMarch 31, 2015 (in millions):

	Subsidiary Guarantors			Parent Company			Eliminations			Consolidated
NET CASH PROVIDED BY OPERATING ACTIVITIES	$	240.6		$	0.7		$	—		$	241.3
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from
Additional capital contribution from parent	1.6			1.6			(1.6		)	1.6
Requirements for:
Dividends to parent	(25.8		)	(27.6		)	25.8			(27.6		)
Retirement of long term debt	(5.0		)	—			—			(5.0		)
Net change in intercompany short-term borrowings	(74.6		)	69.1			5.5			—
Net change in short-term borrowings	—			(150.5		)	—			(150.5		)
Net cash used in financing activities	(103.8		)	(107.4		)	29.7			(181.5		)
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from:
Consolidated subsidiary distributions	—			25.8			(25.8		)	—
Other investing activities	—			0.2			—			0.2
Requirements for:
Capital expenditures, excluding AFUDC equity	(64.6		)	(4.3		)	—			(68.9		)
Consolidated subsidiary investments	—			(1.6		)	1.6			—
Net change in short-term intercompany notes receivable	(69.1		)	74.6			(5.5		)	—
Net cash used in investing activities	(133.7		)	94.7			(29.7		)	(68.7		)
Net change in cash & cash equivalents	3.1			(12.0		)	—			(8.9		)
Cash & cash equivalents at beginning of period	6.9			12.4			—			19.3
Cash & cash equivalents at end of period	$	10.0		$	0.4		$	—		$	10.4

Condensed Consolidating Statement of Cash Flows for the three months endedMarch 31, 2014 (in millions):

	Subsidiary Guarantors			Parent Company			Eliminations			Consolidated
NET CASH PROVIDED BY OPERATING ACTIVITIES	$	137.2		$	18.8		$	—		$	156.0
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from:
Long-term debt, net of issuance costs	124.2			—			(124.2		)	—
Additional capital contribution from parent	1.6			1.6			(1.6		)	1.6
Requirements for:
Dividends to parent	(25.4		)	(27.1		)	25.4			(27.1		)
Net change in intercompany short-term borrowings	(73.1		)	85.6			(12.5		)	—
Net change in short-term borrowings	—			(28.6		)	—			(28.6		)
Net cash used in financing activities	27.3			31.5			(112.9		)	(54.1		)
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from:
Consolidated subsidiary distributions	—			25.4			(25.4		)	—
Other investing activities	—			0.1			—			0.1
Requirements for:
Capital expenditures, excluding AFUDC equity	(51.3		)	(6.7		)	—			(58.0		)
Consolidated subsidiary investments	—			(1.6		)	1.6			—
Net change in long-term intercompany notes receivable	—			(124.2		)	124.2			—
Net change in short-term intercompany notes receivable	(85.6		)	73.1			12.5			—
Net cash used in investing activities	(136.9		)	(33.9		)	112.9			(57.9		)
Net change in cash & cash equivalents	27.6			16.4			—			44.0
Cash & cash equivalents at beginning of period	8.2			0.4			—			8.6
Cash & cash equivalents at end of period	$	35.8		$	16.8		$	—		$	52.6