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, 2016

OR

o 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:   1-15467

VECTREN CORPORATION

(Exact name of registrant as specified in its charter)

INDIANA	35-2086905
(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 ý                                                                                                                     Accelerated filer o

Non-accelerated filer o (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	82,806,031	April 29, 2016
Class	Number of Shares	Date

Access to Information

Vectren Corporation makes available all SEC filings and recent annual reports 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: M. Naveed Mughal Treasurer and Vice President, Investor Relations vvcir@vectren.com

Definitions

AFUDC: allowance for funds used during construction	IDEM:  Indiana Department of Environmental Management
ASC: Accounting Standards Codification	IURC:  Indiana Utility Regulatory Commission
ASU: Accounting Standards Update	kV: Kilovolt
BTU / MMBTU:  British thermal units / millions of BTU	MCF / BCF: thousands / billions of cubic feet
DOT:  Department of Transportation	MDth / MMDth: thousands / millions of dekatherms
EPA:  Environmental Protection Agency	MISO: Midcontinent Independent System Operator
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	OUCC:  Indiana Office of the Utility Consumer Counselor
GAAP: Generally Accepted Accounting Principles	PUCO:  Public Utilities Commission of Ohio
GCA: Gas Cost Adjustment	XBRL:  eXtensible Business Reporting Language

Table of Contents

Item Number		Page Number
	PART I.  FINANCIAL INFORMATION
1	Financial Statements (Unaudited)
	Vectren Corporation and Subsidiary Companies
	Condensed Consolidated Balance Sheets	3
	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 Financial Condition and Results of Operations	24
3	Quantitative and Qualitative Disclosures About Market Risk	46
4	Controls and Procedures	47
	PART II.  OTHER INFORMATION
1	Legal Proceedings	47
1A	Risk Factors	47
2	Unregistered Sales of Equity Securities and Use of Proceeds	48
3	Defaults Upon Senior Securities	48
4	Mine Safety Disclosures	48
5	Other Information	48
6	Exhibits	48
	Signatures	49

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PART I.  FINANCIAL INFORMATION

ITEM 1.  FINANCIAL STATEMENTS

VECTREN CORPORATION AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited – In millions)

	March 31, 2016		December 31, 2015
ASSETS
Current Assets
Cash & cash equivalents	$	62.6	$	74.7
Accounts receivable - less reserves of $6.6 & $5.6, respectively	176.5		227.5
Accrued unbilled revenues	104.0		142.5
Inventories	122.6		133.7
Recoverable fuel & natural gas costs	8.9		—
Prepayments & other current assets	47.1		81.0
Total current assets	521.7		659.4
Utility Plant
Original cost	6,172.1		6,090.4
Less:  accumulated depreciation & amortization	2,454.0		2,415.5
Net utility plant	3,718.1		3,674.9
Investments in unconsolidated affiliates	20.7		20.9
Other utility & corporate investments	30.2		31.2
Other nonutility investments	16.2		16.2
Nonutility plant - net	424.6		414.6
Goodwill	293.5		293.5
Regulatory assets	257.7		249.4
Other assets	40.5		39.9
TOTAL ASSETS	$	5,323.2	$	5,400.0

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

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VECTREN CORPORATION AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited – In millions)

	March 31, 2016			December 31, 2015
LIABILITIES & SHAREHOLDERS' EQUITY
Current Liabilities
Accounts payable	$	213.0		$	248.8
Refundable fuel & natural gas costs	—			7.9
Accrued liabilities	183.1			183.6
Short-term borrowings	—			14.5
Current maturities of long-term debt	13.0			73.0
Total current liabilities	409.1			527.8
Long-term Debt - Net of Current Maturities	1,713.2			1,712.9
Deferred Credits & Other Liabilities
Deferred income taxes	827.9			805.4
Regulatory liabilities	440.7			433.9
Deferred credits & other liabilities	231.9			236.2
Total deferred credits & other liabilities	1,500.5			1,475.5
Commitments & Contingencies (Notes 7-11)
Common Shareholders' Equity
Common stock (no par value) – issued & outstanding           82.8 & 82.8, respectively	724.3			722.8
Retained earnings	977.3			962.2
Accumulated other comprehensive (loss)	(1.2		)	(1.2		)
Total common shareholders' equity	1,700.4			1,683.8
TOTAL LIABILITIES & SHAREHOLDERS' EQUITY	$	5,323.2		$	5,400.0

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

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VECTREN CORPORATION AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Unaudited – In millions, except per share amounts)

	Three Months Ended
	March 31,
	2016			2015
OPERATING REVENUES
Gas utility	$	281.2		$	352.9
Electric utility	142.1			153.9
Nonutility	161.5			199.4
Total operating revenues	584.8			706.2
OPERATING EXPENSES
Cost of gas sold	111.6			172.0
Cost of fuel & purchased power	44.2			50.1
Cost of nonutility revenues	55.3			64.3
Other operating	200.0			231.1
Depreciation & amortization	63.9			62.9
Taxes other than income taxes	17.6			19.7
Total operating expenses	492.6			600.1
OPERATING INCOME	92.2			106.1
OTHER INCOME
Equity in earnings (losses) of unconsolidated affiliates	(0.2		)	—
Other income – net	5.7			5.6
Total other income	5.5			5.6
INTEREST EXPENSE	22.1			21.0
INCOME BEFORE INCOME TAXES	75.6			90.7
INCOME TAXES	27.3			33.7
NET INCOME AND COMPREHENSIVE INCOME	$	48.3		$	57.0
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING	82.8			82.6
DILUTED COMMON SHARES OUTSTANDING	82.8			82.6
BASIC AND DILUTED EARNINGS PER SHARE OF COMMON STOCK	$	0.58		$	0.69
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK	$	0.40		$	0.38

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

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VECTREN CORPORATION AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited – In millions)

	Three Months Ended
	March 31,
	2016			2015
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	48.3		$	57.0
Adjustments to reconcile net income to cash from operating activities:
Depreciation & amortization	63.9			62.9
Deferred income taxes & investment tax credits	24.3			14.6
Equity in losses of unconsolidated affiliates	0.2			—
Provision for uncollectible accounts	2.6			3.3
Expense portion of pension & postretirement benefit cost	1.0			1.6
Other non-cash items - net	2.8			1.6
Changes in working capital accounts:
Accounts receivable & accrued unbilled revenues	86.9			(30.2		)
Inventories	11.1			25.8
Recoverable/refundable fuel & natural gas costs	(16.8		)	30.3
Prepayments & other current assets	33.3			61.2
Accounts payable, including to affiliated companies	(38.1		)	(27.6		)
Accrued liabilities	(0.5		)	5.6
Employer contributions to pension & postretirement plans	(16.2		)	(20.9		)
Changes in noncurrent assets	(6.4		)	11.3
Changes in noncurrent liabilities	6.0			3.6
Net cash provided by operating activities	202.4			200.1
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from dividend reinvestment plan & other common stock issuances	1.5			1.6
Requirements for:
Dividends on common stock	(33.2		)	(31.5		)
Retirement of long-term debt	(60.0		)	(5.0		)
Net change in short-term borrowings	(14.5		)	(150.0		)
Net cash used in financing activities	(106.2		)	(184.9		)
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from sale of assets and other collections	0.4			0.8
Requirements for capital expenditures, excluding AFUDC equity	(108.7		)	(85.3		)
Net cash used in investing activities	(108.3		)	(84.5		)
Net change in cash & cash equivalents	(12.1		)	(69.3		)
Cash & cash equivalents at beginning of period	74.7			86.4
Cash & cash equivalents at end of period	$	62.6		$	17.1

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

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VECTREN CORPORATION AND SUBSIDIARY COMPANIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

1. Organization and Nature of Operations

Vectren Corporation (the Company or Vectren), an Indiana corporation, is an energy holding company headquartered in Evansville, Indiana.  The Company’s wholly owned subsidiary, Vectren Utility Holdings, Inc. (Utility Holdings or VUHI), serves as the intermediate holding company for three public utilities:  Indiana Gas Company, Inc. (Indiana Gas or Vectren Energy Delivery of Indiana - North), Southern Indiana Gas and Electric Company (SIGECO or Vectren Energy Delivery of Indiana - South), and Vectren Energy Delivery of Ohio, Inc. (VEDO).  Utility Holdings also has other assets that provide information technology and other services to the three utilities.  Utility Holdings’ consolidated operations are collectively referred to as the Utility Group.  Both Vectren and Utility Holdings are holding companies as defined by the Energy Policy Act of 2005.  Vectren was incorporated under the laws of Indiana on June 10, 1999.

Indiana Gas provides energy delivery services to approximately 590,000 natural gas customers located in central and southern Indiana.  SIGECO provides energy delivery services to approximately 144,000 electric customers and approximately 112,000 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 319,000 natural gas customers located near Dayton in west central Ohio.

The Company, through Vectren Enterprises, Inc. (Enterprises), is involved in nonutility activities in two primary business areas: Infrastructure Services and Energy Services.  Infrastructure Services provides underground pipeline construction and repair services.  Energy Services provides energy performance contracting and sustainable infrastructure, such as renewables, distributed generation, and combined heat and power projects. Enterprises also has other legacy businesses that have investments in energy-related opportunities and services and other investments.  All of the above are collectively referred to as the Nonutility Group. Enterprises supports the Company's regulated utilities by providing infrastructure services.

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 interim condensed consolidated financial statements and related notes should be read in conjunction with the Company’s audited annual consolidated financial statements for the year ended December 31, 2015, filed with the Securities and Exchange Commission on February 23, 2016, on Form 10-K.  Because of the seasonal nature of the Company’s 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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3. Earnings Per Share

The Company uses the two class method to calculate earnings per share (EPS).  The two class method is an earnings allocation formula that treats a participating security as having rights to earnings that otherwise would have been available to common shareholders. Under the two class method, earnings for a period are allocated between common shareholders and participating security holders based on their respective rights to receive dividends as if all undistributed book earnings for the period were distributed.  

Basic EPS is computed by dividing net income attributable to only the common shareholders by the weighted-average number of common shares outstanding for the period.  Diluted EPS includes the impact of stock options and other equity based instruments to the extent the effect is dilutive.  

The following table illustrates the basic and dilutive EPS calculations for the periods presented in these financial statements.

	Three Months Ended
	March 31,
(In millions, except per share data)	2016		2015
Numerator:
Reported net income (Numerator for Basic and Diluted EPS)	$	48.3	$	57.0
Denominator:
Weighted average common shares outstanding           (Denominator for Basic and Diluted EPS)	82.8		82.6
Basic and Diluted EPS	$	0.58	$	0.69

As of March 31, 2016, the Company no longer has any stock options outstanding. For the three months ended March 31, 2015, all stock options were dilutive and immaterial. For both periods presented all equity based instruments were dilutive and immaterial.

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 $9.4 million and $11.7 million in the three months ended March 31,2016 and 2015, respectively, as a component of operating revenues. Expenses associated with excise and utility receipts taxes are recorded as a component of Taxes other than income taxes.

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5. Retirement Plans & Other Postretirement Benefits

The Company maintains three closed qualified defined benefit pension plans, a nonqualified supplemental executive retirement plan (SERP), and a postretirement benefit plan.  The defined benefit pension plans and postretirement benefit plan, which cover eligible full-time regular employees, are primarily noncontributory.  The postretirement health care and life insurance plans are a combination of self-insured and fully insured plans.  The qualified pension plans and the SERP plan are aggregated under the heading “Pension Benefits.”  The postretirement benefit plan is presented under the heading “Other Benefits.”

Net Periodic Benefit Costs

A summary of the components of net periodic benefit cost follows and the amortizations shown below are primarily reflected in Regulatory assets as a majority of pension and other postretirement benefits are being recovered through rates.

	Three Months Ended
	March 31,
	Pension Benefits						Other Benefits
(In millions)	2016			2015			2016			2015
Service cost	$	1.8		$	2.0		$	0.1		$	0.1
Interest cost	3.6			3.6			0.4			0.5
Expected return on plan assets	(5.7		)	(5.6		)	—			—
Amortization of prior service cost	0.1			0.2			(0.7		)	(0.7		)
Amortization of actuarial loss	1.8			2.1			—			0.1
Net periodic cost (benefit)	$	1.6		$	2.3		$	(0.2	)	$	—

Employer Contributions to Qualified Pension Plans

As of March 31, 2016, the Company has made $15 million in contributions to its qualified pension plans.   

6. Supplemental Cash Flow Information

As of March 31, 2016 and December 31, 2015, the Company has accruals related to utility and nonutility plant purchases totaling approximately $16.9 million and $19.4 million, respectively.

7.    Investment in ProLiance Holdings, LLC

The Company has an investment in ProLiance Holdings, LLC (ProLiance or ProLiance Holdings), an affiliate of the Company and Citizens Energy Group (Citizens). On June 18, 2013, ProLiance exited the natural gas marketing business through the disposition of certain of the net assets, along with the long-term pipeline and storage commitments, of its energy marketing business, ProLiance Energy, LLC (ProLiance Energy), to a subsidiary of Energy Transfer Partners, ETC Marketing, Ltd (ETC). Other minor operating results of the remaining ProLiance investments are reflected in Other Businesses. The Company's remaining investment in ProLiance relates primarily to an investment in LA Storage, LLC (LA Storage).  Consistent with its ownership percentage, the Company is allocated 61 percent of ProLiance’s profits and losses; however, governance and voting rights remain at 50 percent for each member, and therefore, the Company accounts for its investment in ProLiance using the equity method of accounting.

9

The Company's investment at March 31, 2016, shown at its 61 percent ownership share of the individual net assets of ProLiance, is as follows.

	As of
	March 31,
(In millions)	2016
Cash	$	2.5
Investment in LA Storage	22.0
Other midstream asset investment	5.0
Total investment in ProLiance	$	29.5
Included in:
Investments in unconsolidated affiliates	19.4
Other nonutility investments	10.1

LA Storage

ProLiance Transportation and Storage, LLC (PT&S), a subsidiary of ProLiance, and Sempra Energy International (SEI), a subsidiary of Sempra Energy (SE), through a joint venture, have a 100 percent interest in a development project for salt-cavern natural gas storage facilities known as LA Storage.  PT&S is the minority member with an approximate 25 percent interest, which it accounts for using the equity method.  The project, which includes a pipeline system, is expected to include 12-19 Bcf of storage capacity, and has the potential for further expansion. This pipeline system is currently connected with several interstate pipelines, including the Cameron Interstate Pipeline operated by Sempra Pipelines & Storage, and will connect area liquefied natural gas regasification terminals to an interstate natural gas transmission system and storage facilities. 

Approximately 12 Bcf of the storage, which comprises three of the four FERC certified caverns, is fully tested but additional work is required to further develop the caverns. The timing and extent of development of these caverns is dependent on market conditions, including pricing, need for storage capacity, and development of the liquefied natural gas market, among other factors. To date, development activity has been modest due to current low demand for storage facilities. The development of the storage market and related pricing are critical assumptions in the analysis of the recoverability of the investment's carrying value. As of March 31, 2016 and December 31, 2015, ProLiance's investment in the joint venture was $36.1 million and $36.4 million, respectively.

8. Commitments & Contingencies

Performance Guarantees & Product Warranties

In the normal course of business, wholly owned subsidiaries, such as Energy Systems Group (ESG), a subsidiary of the Energy Services operating segment, issue payment and performance bonds and other forms of assurance that commit them to timely install infrastructure, operate facilities, pay vendors and subcontractors, and support warranty obligations.  

Specific to ESG, in its role as a general contractor in the performance contracting industry, at March 31, 2016, there are 38 open surety bonds supporting future performance.  The average face amount of these obligations is $10.4 million, and the largest obligation has a face amount of $51.0 million.  The maximum exposure from these obligations is limited to the level of uncompleted work and further limited by bonds issued to ESG by various subcontractors. At March 31, 2016, approximately 54 percent of work was yet to be completed on projects with open surety bonds.  A significant portion of these open surety bonds will be released within one year.  In instances where ESG operates facilities, project guarantees extend over a longer period.  In addition to its performance obligations, ESG also warrants the functionality of certain installed infrastructure generally for one year and the associated energy savings over a specified number of years.  

Based on a history of meeting performance obligations and installed products operating effectively, no liability or cost has been recognized for the periods presented. Since inception, ESG has only had to pay an immaterial amount for payment and performance obligations.

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Corporate Guarantees

The Company issues parent level guarantees to certain vendors and customers of its wholly owned subsidiaries.  These guarantees do not represent incremental consolidated obligations; rather, they represent parental guarantees of subsidiary obligations in order to allow those subsidiaries the flexibility to conduct business without posting other forms of collateral.   At March 31, 2016, parent level guarantees support a maximum of $245 million of ESG’s performance contracting commitments, warranty obligations, project guarantees, and energy savings guarantees.

Further, an energy facility operated by ESG and managed by Keenan Ft. Detrick Energy, LLC (Keenan), is governed by an operations agreement. All payment obligations to Keenan under this agreement are also guaranteed by the Company. The Company guarantee of the Keenan Ft. Detrick Energy operations agreement does not state a maximum guarantee. Due to the nature of work performed under this contract, the Company cannot estimate a maximum potential amount of future payments.

In addition, the Company also has other guarantees outstanding, including letters of credit, supporting other consolidated subsidiary operations.

While there can be no assurance that the Company guarantee provisions will not be called upon, no such provisions have been called on historically, and further, the Company believes that the likelihood of a material amount being triggered under any of these provisions is remote.

Commitments

The Company's regulated utilities have 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 condition, 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 natural gas is delivered in a safe and efficient manner. The Company's natural gas utilities are currently engaged in programs to replace bare steel and cast iron infrastructure and other activities in both Indiana and Ohio to mitigate risk, improve the system, and comply with applicable regulations, many of which are a result of federal pipeline safety requirements. Laws passed in both Indiana and Ohio provide utilities the opportunity to timely recover costs of federally mandated projects and other infrastructure improvement projects outside of a base rate proceeding.

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

In April 2013, Indiana Senate Bill 560 (Senate Bill 560) was signed into Indiana law. This legislation supplements Senate Bill 251 described above, and provides for cost recovery outside of a base rate proceeding for projects that either improve electric and gas system reliability and safety or are economic development projects that provide rural areas with access to gas service. Provisions of the legislation require that, among other things, requests for recovery include a seven-year project plan. Once the plan is approved by the IURC, 80 percent of such costs are eligible for current recovery using a periodic rate adjustment mechanism. Recoverable costs include a return on the investment that reflects the current capital structure and associated

11

costs, with the exception of the rate of return on equity, which remains fixed at the rate determined in the Company's last rate case. Recoverable costs also include recovery of depreciation and other operating expenses. The remaining 20 percent of project costs are deferred and recovered in the utility’s next general rate case, which must be filed before the expiration of the seven-year plan. The adjustment mechanism is capped at an annual increase in retail revenues of no more than two percent.

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

Indiana Recovery and Deferral Mechanisms

The Company's Indiana natural gas utilities received Orders in 2008 and 2007 associated with the most recent base rate cases. These Orders authorized the deferral of financial impacts associated with bare steel and cast iron replacement activities. The Orders provide for the deferral of depreciation and post-in-service carrying costs on qualifying projects totaling $20 million annually at Indiana Gas and $3 million annually at SIGECO. The debt-related post-in-service carrying costs are 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, 2016 and December 31, 2015, the Company has regulatory assets totaling $20.6 million and $19.9 million, respectively, associated with the deferral of depreciation and debt-related post-in-service carrying cost activities. Beginning in 2014, all bare steel and cast iron replacement activities are now part of the Company’s seven-year capital investment plan filed pursuant to Senate Bill 251 and 560, discussed further below.

Requests for Recovery under Indiana Regulatory Mechanisms

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

Subsequent to the August 2014 Order, the Company filed and received Orders on three semi-annual updates, which recover in rates investments associated with the approved programs. In October 2015, the Company submitted its third semi-annual filing, seeking approval of the recovery in rates of investments made through June 30, 2015, and updates to the approved seven-year capital investment plan, now proposed at more than $950 million through 2020, of which $294 million has been spent as of March 31, 2016. On March 30, 2016, the IURC issued an Order (March 2016 Order) re-approving the majority of the Company’s gas infrastructure modernization projects requested in the third update of the Plan, and approving the inclusion in rates of actual investments made through June 30, 2015. Specifically, one project that was excluded for recovery under the Plan is a 20-mile transmission line and other related investments required to support industrial customer growth and ongoing system reliability in the Lafayette, Indiana area. The IURC stated because the project was not in the original plan filed in 2013, it does not qualify for cost recovery under this law. The IURC did pre-approve the project for rate base inclusion upon the filing of the next base rate case. The Company believes that such plan updates should be expected to accommodate new projects that emerge during the term of the plan as ongoing risk assessments determine that new projects are required. The Company filed an appeal of the Order on April 29, 2016 to challenge the IURC's limitation of the scope of the Plan updates. The outcome of the appeal is expected in approximately one year. Through the March 2016 Order, approximately $890 million of the proposed capital spend through 2020 has been approved through the recovery mechanisms supporting these filings.

At March 31, 2016 and December 31, 2015, the Company has regulatory assets totaling $32.8 million and $28.6 million, respectively, associated with the return on investment as well as the deferral of depreciation and other operating expenses.

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Ohio Recovery and Deferral Mechanisms

The PUCO Order approving the Company's 2009 base rate case in the Ohio service territory authorized a distribution replacement rider (DRR). The DRR's primary purpose is recovery of investments in utility plant and related operating expenses associated with replacing bare steel and cast iron pipelines and certain other infrastructure. This rider is updated annually for qualifying capital expenditures and allows for a return on those capital expenditures based on the rate of return approved in the 2009 base rate case. In addition, deferral of depreciation and the ability to accrue debt-related post-in-service carrying costs is also allowed until the related capital expenditures are included in the DRR. The Order also initially established a prospective bill impact evaluation on the annual deferrals. Due to the expiration of the initial five-year term for the DRR in early 2014, the Company filed a request in August 2013 to extend and expand the DRR. On February 19, 2014, the PUCO issued an Order approving a Stipulation entered into by the PUCO Staff and the Company which provided for the extension of the DRR for the recovery of costs incurred through 2017 and expanded the types of investment covered by the DRR to include recovery of 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, the plan 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 August 26, 2015, the Company received an Order approving its adjustment to the DRR for recovery of costs incurred through December 31, 2014. In total, the Company has made capital investments under this rider totaling $208.5 million as of March 31, 2016. Regulatory assets associated with post-in-service carrying costs and depreciation deferrals were $19.7 million and $18.2 million at March 31, 2016 and December 31, 2015, respectively.

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 two-year time frame.

The PUCO has also issued Orders approving the Company's filings under Ohio House Bill 95. These Orders approve deferral of the Company’s Ohio capital expenditure program for items not covered by the DRR as well as expenditures necessary to comply with PUCO rules, regulations, orders, and system expansion to some new customers. Ohio House Bill 95 Orders also have established a prospective bill impact evaluation on the cumulative deferrals, limiting the total deferrals at a level which would equal $1.50 per residential and small general service customer per month. As of March 31, 2016, the Company's deferrals have not reached this bill impact cap. The Company submitted its most recent annual filing on May 2, 2016, which covers the Company’s capital expenditure program through calendar year 2016. The Company expects an order later this year.

Pipeline and Hazardous Materials Safety Administration (PHMSA)

On March 18, 2016, PHMSA published a notice of proposed rulemaking (NPRM) on the safety of gas transmission and gathering lines.  The proposed rule addresses many of the remaining requirements from the 2011 Pipeline Safety Act and sets out more stringent requirements than anticipated. The comment period on the NPRM ends on July 7, 2016. The Company is evaluating the impact the proposed rules would have on the Company's transmission integrity management program and the design, construction, and repair of transmission pipeline assets, including the potential for additional capital expenditures and increase in operation and maintenance expense. The Company believes that such compliance costs would be considered a federally mandated cost of providing natural gas, and therefore, should be recoverable from customers under Senate Bill 251 as referenced above. 

10. Electric Rate & Regulatory Matters

SIGECO Electric Environmental Compliance Filing

On January 28, 2015, the IURC issued an Order (January Order) approving the Company’s request for approval of capital investments on its coal-fired generation units to comply with new EPA mandates related to mercury and air toxic standards (MATS) effective in 2015 and to address an outstanding Notice of Violation (NOV) from the EPA. As of March 31, 2016, approximately $30 million has been spent on equipment to control mercury in both air and water emissions, and $32 million to

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address the issues raised in the NOV proceeding on the increase in sulfur trioxide emissions. The total investment is estimated to be between $75 million and $85 million. The Order approved the Company’s request for deferred accounting treatment, as supported by provisions under Indiana Senate Bill 29 (Senate Bill 29) and Senate Bill 251. The accounting treatment includes the deferral of depreciation and property tax expense related to these investments, accrual of post-in-service carrying costs, and deferral of incremental operating expenses related to compliance with these standards. The initial phase of the projects went into service in 2014, with the remaining investment occurring in 2015 and 2016. As of March 31, 2016, the Company has approximately $3.5 million deferred related to depreciation, property tax, and operating expense, and $1.4 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. In June 2015, Joint Appellants’ Citizens Action Coalition of Indiana, Inc., Sierra Club, Inc., and Valley Watch, Inc. (the appellants) filed a brief which challenged the sufficiency of the findings in the IURC's January Order approving the Company’s investments and proposed accounting treatment in terms of whether that Order made certain findings required by statute. On October 29, 2015, the Indiana Court of Appeals issued its opinion affirming the IURC’s findings with regard to equipment required to comply with MATS and certain national pollutant discharge elimination system rules (approximately $35 million). The Court remanded the case back to the IURC so that it can make the findings required by statute with regard to equipment required by the NOV (approximately $40 million). On February 12, 2016, the appellants filed a petition to reopen the evidentiary record in the case in order to submit additional evidence. The Company has opposed the motion and believes the IURC already has a sufficient record in this case. As it pertains to the equipment required by the NOV, given the Commission’s previous approval of this project, the Company believes the Commission will issue a new order in support of the project. The Company anticipates that the IURC will rule on the motion in the near future.

SIGECO Electric Demand Side Management (DSM) Program Filing

On August 31, 2011, the IURC issued an Order approving an initial three-year DSM plan in the SIGECO electric service territory that complied with the IURC’s energy saving targets. Consistent with the Company’s proposal, the Order approved, among other items, the following: 1) recovery of costs associated with implementing the DSM Plan; 2) the recovery of a performance incentive mechanism based on measured savings related to certain DSM programs; and 3) lost margin recovery associated with the implementation of DSM programs for large customers. On June 20, 2012, the IURC issued an Order approving a small customer lost margin recovery mechanism, inclusive of all previous deferrals. For the three months ended March 31, 2016 and 2015, the Company recognized electric utility revenue of $2.6 million and $2.3 million, respectively, associated with this approved lost margin recovery mechanism.

On March 28, 2014, Indiana Senate Bill 340 was signed into law. This legislation ended electric DSM programs on December 31, 2014 that had been conducted to meet the energy savings requirements established by the IURC in 2009. The legislation also allows for industrial customers to opt out of participating in energy efficiency programs. As of January 1, 2015, approximately 80 percent of the Company’s eligible industrial load has opted out of participation in the applicable energy efficiency programs. The Company filed a request for IURC approval of a new portfolio of DSM programs on May 29, 2014 to be offered in 2015. On October 15, 2014, the IURC issued an Order approving a Settlement between the OUCC and the Company regarding the new portfolio of DSM programs effective January 2015, and new programs were implemented during the first quarter of 2015.

On May 6, 2015, Indiana's governor signed Indiana Senate Bill 412 (Senate Bill 412) into law requiring electricity suppliers to submit energy efficiency plans to the IURC at least once every three years. Senate Bill 412 also permits the recovery of all program costs, including lost revenues and financial incentives associated with those plans and approved by the IURC. The Company made its first filing pursuant to this bill in June 2015, which proposed energy efficiency programs for calendar years 2016 and 2017. In September 2015, the Company received an Order to continue offering and recovering the associated cost of its 2015 programs until March 31, 2016. In October 2015, the OUCC and Citizens Action Coalition of Indiana filed testimony recommending the rejection of the Company’s plan, contending it was not reasonable under the terms of Senate Bill 412 due to the program design and the Company’s proposal to recover lost revenues and incentives associated with the measures. Vectren filed rebuttal testimony in October 2015 defending the plan’s compliance with Senate Bill 412.

On March 23, 2016, the IURC issued an Order approving the Company’s 2016-2017 energy efficiency programs. The Order provides for cost recovery of program and administrative expenses and includes performance incentives for reaching energy

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savings goals. The Order also included a lost margin recovery mechanism that now limits that recovery related to new programs to the shorter of four years or the life of the installed energy efficiency measure. Prior electric energy efficiency orders did not limit lost margin recovery to this four year limit. This ruling follows two other recent IURC decisions implementing the same recovery cap with respect to other electric utilities in Indiana. The Company is committed to continuing to promote and drive participation in its 2016-2017 energy efficiency programs and beyond and has therefore appealed this lost margin recovery restriction.

FERC Return on Equity (ROE) Complaints

On November 12, 2013, certain parties representing a group of industrial customers filed a joint complaint with the FERC under Section 206 of the Federal Power Act against the MISO and various MISO transmission owners, including SIGECO. The joint parties seek to reduce the 12.38 percent ROE used in the MISO transmission owners’ rates, including SIGECO’s formula transmission rates, to 9.15 percent, and to set a capital structure in which the equity component does not exceed 50 percent. A second customer complaint case was filed on February 11, 2015 as the maximum FERC-allowed refund period for the November 12, 2013 case ended February 11, 2015. As of March 31, 2016, the Company had invested approximately $157.7 million in qualifying projects. The net plant balance for these projects totaled $139.4 million at March 31, 2016.

These joint complaints are similar to a complaint against the New England Transmission Owners (NETO) filed in September 2011, which requested that the 11.14 percent incentive return granted on qualifying investments in NETO be lowered. On October 16, 2014, the FERC issued an Order in the NETO case approving a 10.57 percent return on equity and a calculation methodology.

The FERC acknowledged that the pending complaint raised against the MISO transmission owners is reasonable and denied the portion of the complaint addressing the equity component of the capital structure. An initial decision from its administrative law judge was received on December 22, 2015, authorizing the transmission owners to collect a Base ROE of 10.32 percent from November 12, 2013 through February 11, 2015 (the “first refund period”). The FERC is expected to rule on the proposed order in late 2016. A procedural schedule has been established for the second customer complaint case, establishing a target date of June 30, 2016 for the initial decision.

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

The Company has established a reserve considering both the initial decision and the approved 50 basis points adder.

11.  Environmental Matters

The Company's utility operations and properties are subject to extensive environmental regulation pursuant to a variety of federal, state and municipal laws and regulations. These environmental regulations impose, among other things, restrictions, liabilities, and obligations in connection with the storage, transportation, treatment, and disposal of hazardous substances and limit airborne emissions from electric generating facilities including particulate matter, sulfur dioxide (SO₂), nitrogen oxide (NOx), and mercury, among others. Environmental legislation and regulation also requires that facilities, sites, and other properties associated with the Company's operations be operated, maintained, abandoned, and reclaimed to the satisfaction of applicable regulatory authorities. The Company's current costs to comply with these laws and regulations are significant to its results of operations and financial condition.

With the trend toward stricter standards, greater regulation, and more extensive permit requirements, the Company's investment in compliant infrastructure, and the associated operating costs have increased and are expected to increase in the future. Similar to the costs associated with federal mandates in the Pipeline Safety Law, Senate Bill 251 is also applicable to federal environmental mandates impacting SIGECO's electric operations.

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Air Quality

Mercury and Air Toxics (MATS) Rule

On December 21, 2011, the EPA finalized the utility MATS rule. The MATS rule sets emission limits for hazardous air pollutants for existing and new coal-fired power plants and identifies the following broad categories of hazardous air pollutants: mercury, non-mercury hazardous air pollutants (primarily arsenic, chromium, cobalt, and selenium), and acid gases (hydrogen cyanide, hydrogen chloride, and hydrogen fluoride). The rule imposes mercury emission limits for two sub-categories of coal and proposed surrogate limits for non-mercury and acid gas hazardous air pollutants.

In July 2014, a coalition of twenty-one states, including Indiana, filed a petition with the U.S. Supreme Court seeking review of the decision of the appellate court that found the EPA appropriately based its decision to list coal and oil fired generation units as a source of the pollutants at issue solely on those pollutants’ impact on public health. On June 29, 2015, the U.S. Supreme Court reversed the appellate court decision on the basis of the EPA’s failure to consider costs before determining whether it was appropriate and necessary to regulate steam electric generating units under Section 112 of the Clean Air Act. The Court did not vacate the rule, but remanded the MATS rule back to the appellate court for further proceedings consistent with the opinion. MATS compliance was required to commence April 16, 2015, and the Company continues to operate in full compliance with the MATS rule.

Notice of Violation for A.B. Brown Power Plant

The Company received a NOV from the EPA in November 2011 pertaining to its A.B. Brown generating station. The NOV asserts when the facility was equipped with Selective Catalytic Reduction (SCR) systems, the correct permits were not obtained or the best available control technology to control incidental sulfuric acid mist was not installed. While the Company did not agree with notice, it reached a final settlement with the EPA to resolve the NOV in December 2015.

As noted previously, on January 28, 2015, the IURC issued an Order approving the Company’s request for approval of capital investments on its coal-fired generation units to comply with new EPA mandates related to MATS effective in 2015 and to address the outstanding NOV regarding SO₃ emissions from the EPA. The total investment is estimated to be between $75 million and $85 million, roughly half of which has been spent to control mercury in both air and water emissions, and the remaining investment has been made to address the issues raised in the NOV.

In 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. In June 2015, Joint Appellants’ Citizens Action Coalition of Indiana, Inc., Sierra Club, Inc., and Valley Watch, Inc. (the appellants) filed a brief which challenged the sufficiency of the findings in the IURC's January Order approving the Company’s investments and proposed accounting treatment in terms of whether that Order made certain findings required by statute. On October 29, 2015, the Indiana Court of Appeals issued its opinion affirming the IURC’s findings with regard to equipment required to comply with MATS and certain national pollutant discharge elimination system rules (approximately $35 million). The Court remanded the case back to the IURC so that it can make the findings required by statute with regard to equipment required by the NOV (approximately $40 million). On February 12, 2016, the appellants filed a petition to reopen the evidentiary record in the case in order to submit additional evidence. The Company has opposed the motion and believes the IURC already has a sufficient record in this case. As it pertains to the equipment requirement required by the NOV, given the Commission’s previous approval of this project, the Company believes the Commission will make these findings and issue a new order in support of the project. The Company anticipates that the IURC will rule on the motion in the near future.

Ozone NAAQS

On November 26, 2014, the EPA proposed to tighten the current National Ambient Air Quality Standard (NAAQS) for ozone from the current standard of 75 parts per billion (ppb) to a level with the range of 65 to 70 ppb. On October 1, 2015, the EPA finalized a new NAAQS for ozone at the high end of the range, or 70 ppb. The EPA is expected to make final determinations as to whether a region is in attainment for the new NAAQS in 2018 based upon monitoring data from 2014-2016. While it is possible that counties in southwest Indiana could be declared in non-attainment with the new standard, and thus could have an effect on future economic development activities in the Company's service territory, the Company does not anticipate any significant compliance cost impacts from the determination given its previous investment in SCR technology for NOx control on its units.

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One Hour SO2 NAAQS

On February 16, 2016, the EPA notified states of the commencement of a 120 day consultation period between the state and the EPA with respect to the EPA's recommendations for new non-attainment designations for the 2010 One Hour SO2 NAAQS. Identified on the list was Posey County, Indiana, in which the Company's A.B. Brown Generating Station is located. While the Company is in compliance with all applicable SO2 limits in its permits, the Company is currently working with the state of Indiana on voluntary measures that the Company may take without significant incremental costs to ensure that Posey County remains in attainment with the 2010 One Hour SO2 NAAQS. The Company's coal-fired generating fleet is 100 percent scrubbed for SO2 and 90 percent controlled for NOx.

Coal Ash Waste Disposal, Ash Ponds and Water

Coal Combustion Residuals Rule

In December 2014, the EPA released its final Coal Combustion Residuals (CCR) rule which regulates ash as non-hazardous material under Subtitle D of the Resource Conservation and Recovery Act (RCRA). On April 17, 2015, the final rule was published in the Federal Register. The final rule allows beneficial reuse of ash and the majority of the ash generated by the Company’s generating plants will continue to be reused. As it relates to the CCR rule, legislation is currently being considered by Congress that would provide for enforcement of the federal program by states rather than through citizen suits. Additionally, the CCR rule is currently being challenged by multiple parties in judicial review proceedings. Opening briefs were filed by those parties in December of 2015, with full briefing not expected to be complete until later in May 2016.

Under the final CCR rule, the Company is required to complete a series of integrity assessments, including seismic modeling given the Company’s facilities are located within two seismic zones, and groundwater monitoring studies to determine the remaining service life of the ponds and whether a pond must be retrofitted with liners or closed in place, with bottom ash handling conversions completed. In late 2015, using general utility industry data, the Company prepared cost estimates for the retirement of the ash ponds at the end of their useful lives, based on its interpretation of the closure alternatives contemplated in the final rule. The resulting estimates ranged from approximately $35 million to $80 million. These estimates contemplated final capping and monitoring costs of the ponds at both F.B. Culley and A.B. Brown generating stations. These rules have not been applicable to the Company's Warrick generating unit, as this unit has historically been part of a larger generating station that predominantly serves an adjacent industrial facility. The Company is in the process of preparing site specific estimates, using engineering analyses and assumed methods of closure. Significant factors impacting the resulting cost estimates include the closure time frame and the method of closure. Further analysis and the refinement of assumptions may result in estimated costs that could be in excess of the current range of $35 million to $80 million.

At September 30, 2015, the Company recorded an approximate $25 million asset retirement obligation (ARO) and that amount is unchanged at March 31, 2016. The recorded ARO reflected the present value of the approximate $35 million in estimated costs in the range above. These assumptions and estimations are subject to change in the future and could materially impact the amount of the estimated ARO.

Effluent Limitation Guidelines (ELGs)

Under the Clean Water Act, the EPA sets technology-based guidelines for water discharges from new and existing facilities. On September 30, 2015, the EPA released final revisions to the existing steam electric ELGs setting stringent technology-based water discharge limits for the electric power industry. The EPA focused this rulemaking on wastewater generated primarily by pollution control equipment necessitated by the comprehensive air regulations, specifically setting strict water discharge limits for arsenic, mercury and selenium for scrubber waste waters. The ELGs will be implemented when existing water discharge permits for the plants are renewed, with compliance activities expected to commence within the 2018-2023 time frame. Current wastewater discharge permits for the Brown and Culley power plants expire in October and December 2016, respectively. The Company is working with Indiana regulators on permit renewals which will include a compliance schedule for ELGs. In no event will compliance with the ELGs be required prior to November 2018. The ELGs work in tandem with the recently released CCR requirements, effectively prohibiting the use of less costly lined sediment basin options for disposal of coal combustion residuals, and virtually mandate conversions to dry bottom ash handling.

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Cooling Water Intake Structures

Section 316(b) of the Clean Water Act requires that generating facilities use the “best technology available” (BTA) to minimize adverse environmental impacts on a body of water. More specifically, Section 316(b) is concerned with impingement and entrainment of aquatic species in once-through cooling water intake structures used at electric generating facilities. A final rule was issued by the EPA on May 19, 2014. The final rule does not mandate cooling water tower retrofits but requires a state level case-by-case assessment of BTA for each facility. The final rule lists seven presumptive technologies which would qualify as BTA. These technologies range from intake screen modifications to cooling water tower retrofits. Ecological and technology assessment studies must be completed prior to determining BTA for the Company’s facilities. To comply, the Company believes that capital investments will likely be in the range of $4 million to $8 million.

Climate Change

On August 3, 2015, the EPA released its final Clean Power Plan (CPP) rule which requires a 32 percent reduction in carbon emissions from 2005 levels. This results in a final emission rate goal for Indiana of 1,242 lb CO2/MWh to be achieved by 2030. The new rule gives states the option of seeking a two-year extension from the deadline of September 2016 to submit a final state implementation plan (SIP). Under the CPP, states have the flexibility to include energy efficiency and other measures should it choose to implement a SIP as provided in the final rule. While states are given an interim goal (1,451 lb CO2/MWh for Indiana), the final rule gives states the flexibility to shape their own emissions reduction over the 2022-2029 time period. The final rule was published in the Federal Register on October 23, 2015 and that action was immediately followed by litigation initiated by Indiana and 23 other states as a coalition challenging the rule. In January of 2016, the reviewing court denied the states’ and other parties requests to stay the implementation of the CPP pending completion of judicial review. On January 26, 2016, 29 states and state agencies (including the 24 state coalition referenced above) filed a request for immediate stay with the U.S. Supreme Court. On February 9, 2016, the U.S. Supreme Court granted a stay to delay the regulation while being challenged in court. The stay will remain in place while the lower court concludes its review, with oral arguments to be heard in June 2016 under the existing accelerated schedule. Among other things, the stay is anticipated to delay the requirement to submit a final SIP by the September 2016 deadline. Apart from the delay, the Court's action creates additional uncertainty as to the future of the rule and presents further challenges as the Company proceeds with its integrated resource planning process later this year.

In the event that a state does not submit a SIP, the EPA also released a proposed federal implementation plan (FIP), which would be imposed on those states without an approved SIP. The proposed FIP would apply an emission rate requirement directly on generating units. Under the proposed FIP, the CO2 emission rate limit for coal-fired units would start at 1,671 lbs CO2/MWh in 2022 and decrease to a final emission rate cap of 1,305 lbs CO2/MWh by 2030. While the FIP emission rate cap appears to be slightly less stringent than the state reduction goal for Indiana, the cap would apply directly to generating units and these units would not have the benefit of averaging emission rates with rates from zero-carbon sources as would be available in a SIP. Purchases of emission credits from zero-carbon sources can be made for compliance. The FIP will be subject to extensive public comments prior to finalization. Whether Indiana will file a SIP has yet to be determined. Pending that determination, the electric utilities in Indiana will continue to encourage the state's designated agency to analyze various compliance options and the possible integration into a state plan submittal.

At the time of release of the CPP, Indiana was the 5th largest carbon emitter in the nation in tons of CO2 produced from electric generation. The Company’s share of total tons of CO2 generated by Indiana's electric utilities has historically been less than 6 percent. Since 2005, the Company has achieved a reduction in emissions of CO2 of 31 percent (on a tonnage basis) through the retirement of F.B. Culley Unit 1, expiration of municipal contracts, electric conservation, the addition of renewable generation, and the installation of more efficient dense pack turbine technology. Since emissions are further impacted by coal burn reductions and energy efficiency programs, the Company's emissions of CO2 can vary year to year. With respect to renewable generation, in 2008 and 2009, the Company executed long-term purchase power commitments for a total of 80 MW of wind energy. The Company currently has approximately 4 percent of its electricity being provided by 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 1,967 lbs CO2/MWh to 1,922 lbs CO2/MWh, for a reduction of 3 percent. The Company’s CO2 emission rate of 1,922 lbs CO2/MWh is basically the same as Indiana's average CO2 emission rate of 1,923 lbs CO2/MWh. The Company plans to consider these reductions in CO2 emissions and renewable generation in future discussions with the state to develop a possible state implementation plan.

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Impact of Legislative Actions & Other Initiatives is Unknown

At this time, compliance costs and other effects associated with reductions in GHG emissions or obtaining renewable energy sources remain uncertain. The Company has gathered preliminary estimates of the costs to control GHG emissions. A preliminary investigation demonstrated costs to comply would be significant, first with regard to operating expenses and later for capital expenditures as technology becomes available to control GHG emissions. However, these compliance cost estimates were based on highly uncertain assumptions, including allowance prices if a cap and trade approach were employed, and energy efficiency targets. The Company is undertaking a detailed review of the requirements of the CPP and the proposed FIP and a review of potential compliance options. The Company will also continue to remain engaged with the Indiana legislators and regulators to assess the final rule and to develop a plan that is the least cost to its customers.

Integrated Resource Planning Process

As required by the state of Indiana, the Company is currently in the process of completing its 2016 Integrated Resource Plan (IRP). The state requires each electric utility to perform and submit an IRP that details the resources it may rely upon to provide electric service for the next twenty year period to ensure electric reliability throughout the state. During 2016, the Company will hold three public stakeholder meetings to gather input and feedback as well as communicate results of the IRP process as it progresses. The first of three public meetings was held in April 2016. A final IRP report is expected to be submitted to the IURC for review in November 2016. While the IURC reviews these reports, it does not formally approve or reject the plans.

The 2016 IRP will consider the ongoing operation of the 300 MW unit at the Warrick Power Plant (Warrick Unit 4) that SIGECO and Alcoa Generating Corporation (AGC), a subsidiary of Alcoa, Inc. (Alcoa), own as tenants in common. SIGECO's proportionate cost of the unit is included in rate base. In the first quarter of 2016, Alcoa closed its smelter operations. Historically, on-site generation owned and operated by AGC has been used to provide power to the smelter, as well as other mill operations, which will continue. Generation from Alcoa's share of Warrick Unit 4 has historically been sold into the MISO market. Alcoa's operational changes, as described above, lead to a number of uncertainties including its plans regarding the future ownership and operation of Warrick Unit 4 as well as potential environmental regulation implications under the CCR and ELG regulations. The Company is actively working with Alcoa on plans related to continued operation of their generation, anticipating that more will be known toward the end of 2016.

As it relates to water, ash, and carbon regulation, while the Company is exploring various compliance options, the Company cannot reasonably estimate the total cost to comply with the CCR, ELG and CPP regulations for its units at this time. The cost of compliance with these new regulations could be significant. The Company believes that such compliance costs would be considered a federally mandated cost of providing electricity, and therefore if incurred, should be recoverable either from customers through Senate Bill 251 as referenced above, Senate Bill 29, which was used by the Company to recover its initial pollution control investments, or through other forms of rate recovery. Addressing compliance alternatives for CCR, ELG, and CPP, including the impact on customer rates, as well as addressing the uncertainties with Warrick Unit 4, will be fully considered as part of the Company's IRP process conducted in 2016.

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.

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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 $14.8 million of the expected $15.8 million in insurance recoveries.

The costs the Company expects to incur are estimated by management using assumptions based on actual costs incurred, the timing of expected future payments, and inflation factors, among others. While the Company’s utilities have recorded all costs which they presently expect to incur in connection with activities at these sites, it is possible that future events may require remedial activities which are not presently foreseen and those costs may not be subject to PRP or insurance recovery. As of March 31, 2016 and December 31, 2015, approximately $3.0 million and $3.3 million, respectively, of accrued, but not yet spent, costs are included in Other Liabilities related to the Indiana Gas and SIGECO sites.

12. Impact of Recently Issued Accounting Principles

Revenue Recognition Guidance

In May 2014, the FASB issued new accounting guidance to clarify the principles for recognizing revenue and to develop a common revenue standard for GAAP. The amendments in this guidance state that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This new guidance requires improved disclosures to help users of financial statements better understand the nature, amount, timing, and uncertainty of revenue that is recognized.

On July 9, 2015, the FASB approved a one year deferral that became effective through an ASU in August and changed the effective date to annual reporting periods beginning after December 15, 2017, including interim periods, with early adoption permitted, but not before the original effective date of December 15, 2016. The Company is currently evaluating the standard to determine application date, transition method, and impact the standard will have on the financial statements.

Simplifying the Presentation of Debt Issuance Costs

In April 2015, the FASB issued new accounting guidance on accounting for debt issuance costs which changes the presentation of debt issuance costs in financial statements. This ASU requires an entity to present such costs in the balance sheet as a direct 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. The guidance was adopted for March 31, 2016, and has been applied retrospectively to all periods presented. The effect of the change on the December 31, 2015 balance sheet was the reclassification of $8.6 million from regulatory assets to long-term debt and the reclassification of $1.3 million from other assets to long-term debt. The reclassification had no material impact on the Company's financial condition, results of operations, or cash flows as a result of the adoption.

Leases

In February 2016, the FASB issued new accounting guidance for the recognition, measurement, presentation and disclosure of leasing arrangements. This ASU requires the recognition of lease assets and liabilities for those leases currently classified as operating leases while also refining the definition of a lease. In addition, lessees will be required to disclose key information about the amount, timing, and uncertainty of cash flows arising from leasing arrangements. This ASU is effective for the interim and annual reporting periods beginning January 1, 2019, although it can be early adopted, with a modified retrospective approach for leases that commenced prior to the date of adoption. The Company is currently evaluating the standard to determine the impact it will have on the financial statements.

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Stock Compensation

In March 2016, the FASB issued new accounting guidance which is intended to simplify several aspects of accounting for share-based payment transactions, including the income tax consequences. This ASU is effective for annual periods beginning after December 15, 2016, and interim periods therein. Early application is permitted. The Company is currently evaluating the standard to determine the impact it will have on the financial statements, if any.

Management believes that other recently issued standards, which are not yet effective, will not have a material impact on the Company's financial condition, results of operations, or cash flows upon adoption.

13. 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, 2016				December 31, 2015
(In millions)	Carrying Amount		Est. Fair Value		Carrying Amount		Est. Fair Value
Long-term debt	$	1,726.2	$	1,881.4	$	1,785.9	$	1,899.6
Short-term borrowings	—		—		14.5		14.5
Cash & cash equivalents	62.6		62.6		74.7		74.7
Restricted cash	5.9		5.9		5.9		5.9

For the balance sheet dates presented in these financial statements, the Company had no material assets or liabilities marked to fair value.

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

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

Because of the nature of certain other investments and lack of a readily available market, it is not practical to estimate the fair value of these financial instruments at specific dates without considerable effort and cost.  At March 31, 2016 and December 31, 2015, the fair value for these financial instruments was not estimated.  The carrying value of these investments at March 31, 2016 and December 31, 2015 was approximately $16.2 million, and is included in Other nonutility investments.

The Company has reclassified its debt issuance costs, in accordance with ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs. The adoption of the accounting standard update changes the presentation of debt issuance costs in financial statements by requiring an entity to present such costs in the balance sheet as a direct deduction from the related debt liability rather than as an asset. Amortization of the costs will continue to be reported as interest expense. The guidance was adopted as of January 1, 2016, and has been applied retrospectively to all periods presented. The effect of the change on the December 31, 2015 balance sheet was the reclassification of $8.6 million from regulatory assets to long-term debt and the reclassification of $1.3 million from other assets to long-term debt. The adoption of the standard had no material impact on the Company's financial condition, results of operations, or cash flows.

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14. Segment Reporting

The Company segregates its operations into three groups: 1) Utility Group, 2) Nonutility Group, and 3) Corporate and Other.

The Utility Group is comprised of Vectren Utility Holdings, Inc.’s operations, which consist of the Company’s 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 Utility Group reports three operating segments:  Gas Utility Services, Electric Utility Services, and Other operations.

The Nonutility Group reports the following segments:  Energy Services, Infrastructure Services, and Other Businesses.  Energy Services provides energy performance contracting and sustainable infrastructure, such as renewables, distributed generation, and combined heat and power projects. The Infrastructure Services segment through wholly owned subsidiaries Miller Pipeline, LLC and Minnesota Limited, LLC, provide underground pipeline construction and repair services for customers that include Vectren Utility Holdings' utilities. Fees incurred by Vectren Utility Holdings and its subsidiaries for these pipeline construction and repair services totaled $19.6 million and $17.7 million for the three months endedMarch 31, 2016 and 2015, respectively.

In 2016, the estimated depreciable lives for certain pieces of equipment at Minnesota Limited, LLC were reevaluated and extended due to a change in service life of the equipment. As a result of this evaluation, the Company extended the estimated useful life of certain pieces of equipment effective January 1 of the current year. The effect of this change in estimate is an anticipated reduction of annual depreciation expense of approximately $9.6 million in 2016.

Corporate and Other includes unallocated corporate expenses such as advertising and certain charitable contributions, among other activities, that benefit the Company’s operations.  Net income is the measure of profitability used by management for all operations.  

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

	Three Months Ended
	March 31,
(In millions)	2016			2015
Revenues
Utility Group
Gas Utility Services	$	281.2		$	352.9
Electric Utility Services	142.1			153.9
Other Operations	10.6			10.2
Eliminations	(10.5		)	(10.1		)
Total Utility Group	423.4			506.9
Nonutility Group
Infrastructure Services	112.5			176.9
Energy Services	49.4			23.1
Total Nonutility Group	161.9			200.0
Corporate & Other Group	0.1			0.2
Eliminations	(0.6		)	(0.9		)
Consolidated Revenues	$	584.8		$	706.2
Profitability Measure - Net Income (Loss)
Utility Group Net Income
Gas Utility Services	$	40.4		$	40.4
Electric Utility Services	16.6			19.2
Other Operations	4.1			3.4
Utility Group Net Income	61.1			63.0
Nonutility Group Net Income (Loss)
Infrastructure Services	(12.6		)	(2.6		)
Energy Services	0.1			(3.1		)
Other Businesses	(0.2		)	(0.2		)
Nonutility Group Net Income (Loss)	(12.7		)	(5.9		)
Corporate & Other Group Net Income (Loss)	(0.1		)	(0.1		)
Consolidated Net Income	$	48.3		$	57.0

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

Vectren Corporation (the Company or Vectren), an Indiana corporation, is an energy holding company headquartered in Evansville, Indiana.  The Company’s wholly owned subsidiary, Vectren Utility Holdings, Inc. (Utility Holdings or VUHI), serves as the intermediate holding company for three public utilities: Indiana Gas Company, Inc. (Indiana Gas or Vectren Energy Delivery of Indiana - North), Southern Indiana Gas and Electric Company (SIGECO or Vectren Energy Delivery of Indiana - South), and Vectren Energy Delivery of Ohio, Inc. (VEDO).  Utility Holdings also has other assets that provide information technology and other services to the three utilities.  Utility Holdings’ consolidated operations are collectively referred to as the Utility Group.  Both Vectren and Utility Holdings are holding companies as defined by the Energy Policy Act of 2005.  Vectren was incorporated under the laws of Indiana on June 10, 1999.

Indiana Gas provides energy delivery services to approximately 590,000 natural gas customers located in central and southern Indiana.  SIGECO provides energy delivery services to approximately 144,000 electric customers and approximately 112,000 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 319,000 natural gas customers located near Dayton in west central Ohio.

The Company, through Vectren Enterprises, Inc. (Enterprises), is involved in nonutility activities in two primary business areas:  Infrastructure Services and Energy Services.  Infrastructure Services provides underground pipeline construction and repair services.  Energy Services provides energy performance contracting and sustainable infrastructure, such as renewables, distributed generation, and combined heat and power projects. Enterprises has other legacy businesses that have investments in energy-related opportunities and services, among other investments. All of the above is collectively referred to as the Nonutility Group.  Enterprises supports the Company's regulated utilities by providing infrastructure services.

The Company has in place a disclosure committee that consists of senior management as well as financial management.  The committee is actively involved in the preparation and review of the Company’s SEC filings. 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 2015 annual report filed on Form 10-K.

Executive Summary of Consolidated Results of Operations

In this discussion and analysis, the Company analyzes contributions to consolidated earnings and earnings per share from its Utility Group and Nonutility Group separately. Because each group operates independently and offers different energy-related products and services, the analysis separately addresses the opportunities and risks that arise from each group's distinct competencies and business strategies.

The Utility Group generates revenue primarily from the delivery of natural gas and electric service to its customers.  The primary source of cash flow for the Utility Group results from the collection of customer bills and the payment for goods and services procured for the delivery of gas and electric services.  The Company segregates its regulatory utility operations between a Gas Utility Services operating segment and an Electric Utility Services operating segment. The activities of, and revenues and cash flows generated by, the Nonutility Group are closely linked to the utility industry, and the results of those operations are generally impacted by factors similar to those impacting the overall utility industry.  In addition, there are other operations, referred to herein as Corporate and Other, that include unallocated corporate expenses such as advertising and certain charitable contributions, among other activities.

Results for the three months endedMarch 31, 2016 were earnings of $48.3 million, or $0.58 per share, compared to earnings of $57.0 million, or $0.69 per share for the three months ended March 31, 2015.

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Consolidated Results

Net income (loss) and earnings per share, in total and by group, for the three months endedMarch 31, 2016 and 2015 follow:

	Three Months Ended
	March 31,
(In millions, except per share data)	2016			2015
Net income (loss)	$	48.3		$	57.0
Attributed to:
Utility Group	61.1			63.0
Nonutility Group	(12.7		)	(5.9		)
Corporate & other	(0.1		)	(0.1		)
Basic EPS	$	0.58		$	0.69
Attributed to:
Utility Group	0.74			0.76
Nonutility Group	(0.16		)	(0.07		)

Utility Group

In the first quarter of 2016, the Utility Group earnings were $61.1 million, compared to $63.0 million in 2015. The decrease is largely driven by decreases in electric utility margin due to warmer weather in the first quarter of 2016 compared to the first quarter of 2015. Decreases in large customer usage, some of which is likely due to weather, also contributed to a decrease in both gas and electric utility margin and results reflect lower wholesale power margin due to lower market pricing compared to first quarter of 2015. Earnings were also unfavorably impacted by increased performance-based compensation expense primarily driven by an increase in the Company's stock price. These decreases were somewhat offset by increases in gas utility margin from returns on the Indiana and Ohio infrastructure replacement programs. Other decreases in operating expenses, primarily related to the timing of power plant maintenance costs, also favorably impacted earnings.

Nonutility Group

The Nonutility group results for the first quarter of 2016 were a loss of $12.7 million, compared to a loss of $5.9 million in the prior year. Results in 2016 are significantly lower than 2015 due to two large transmission station projects in early 2015 not repeated in 2016 as well as lower margin on completed work, which is attributable to the increasingly competitive environment in the transmission business as other contractors continue to adjust crews and work load in the current lower oil price environment. Offsetting a portion of this decrease was an increase in earnings from Energy Services due to increased revenues.

Dividends

Dividends declared for the three months endedMarch 31, 2016, were $0.40 per share, compared to $0.38 per share for the same period in 2015.

Use of Non-GAAP Performance Measures and Per Share Measures

Contribution to Vectren's Basic EPS

Per share earnings contributions of the Utility Group, Nonutility Group, and Corporate and Other are presented and are non-GAAP measures.  Such per share amounts are based on the earnings contribution of each group included in the Company’s consolidated results divided by the Company’s basic average shares outstanding during the period.  The earnings per share of the groups do not represent a direct legal interest in the assets and liabilities allocated to the groups, but rather represent a direct equity interest in Vectren Corporation's assets and liabilities as a whole.  These non-GAAP measures are used by management to evaluate the performance of individual businesses.  In addition, other items giving rise to period over period variances, such as weather, may be presented on an after tax and per share basis.  These amounts are calculated at a statutory tax rate divided by the Company’s basic average shares outstanding during the period.  Accordingly, management believes these measures are useful to investors in understanding each business’ contribution to consolidated earnings per share and in analyzing consolidated period to period changes and the potential for earnings per share contributions in future periods.  Per

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share amounts of the Utility Group and the Nonutility Group are reconciled to the GAAP financial measure of basic EPS by adding the two together. If there is a difference, that difference results from corporate and other operations. The non-GAAP financial measures disclosed by the Company should not be considered a substitute for, or superior to, financial measures calculated in accordance with GAAP, and the financial results calculated in accordance with GAAP.

Detailed Discussion of Results of Operations

Following is a more detailed discussion of the results of operations of the Company’s Utility and Nonutility operations.  The detailed results of operations for these groups are presented and analyzed before the reclassification and elimination of certain intersegment transactions necessary to consolidate those results into the Company’s Condensed Consolidated Statements of Income.

Results of Operations of the Utility Group

The Utility Group is comprised of Utility Holdings’ operations, which consists of the Company’s regulated utility operations and other operations that provide information technology and other support services to those regulated operations.  Regulated operations consist of a natural gas distribution business and an electric transmission and distribution business. The natural gas distribution business provides natural gas distribution and transportation services to nearly two-thirds of Indiana and about 20 percent of Ohio, primarily in the west-central area. The electric transmission and distribution business provides electric distribution services primarily to southwestern Indiana, and its power generating and wholesale power operations. In total, these regulated operations supply natural gas and/or electricity to over one million customers.Utility Group operating results before certain intersegment eliminations and reclassifications for the three months ended March 31, 2016 and 2015, follow:

	Three Months Ended
	March 31,
(In millions, except per share data)	2016		2015
OPERATING REVENUES
Gas utility	$	281.2	$	352.9
Electric utility	142.1		153.9
Other	0.1		0.1
Total operating revenues	423.4		506.9
OPERATING EXPENSES
Cost of gas sold	111.6		172.0
Cost of fuel & purchased power	44.2		50.1
Other operating	89.4		102.8
Depreciation & amortization	53.6		52.1
Taxes other than income taxes	17.1		19.1
Total operating expenses	315.9		396.1
OPERATING INCOME	107.5		110.8
OTHER INCOME - NET	5.6		4.9
INTEREST EXPENSE	17.5		16.6
INCOME BEFORE INCOME TAXES	95.6		99.1
INCOME TAXES	34.5		36.1
NET INCOME	$	61.1	$	63.0
CONTRIBUTION TO VECTREN BASIC EPS	$	0.74	$	0.76

Utility Group 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.  

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

Gas Utility Margin

Gas Utility margin and throughput by customer type follows:

	Three Months Ended
	March 31,
(In millions)	2016		2015
Gas utility revenues	$	281.2	$	352.9
Cost of gas sold	111.6		172.0
Total gas utility margin	$	169.6	$	180.9
Margin attributed to:
Residential & commercial customers	$	130.0	$	126.3
Industrial customers	19.0		19.3
Other	2.9		3.4
Regulatory expense recovery mechanisms	17.7		31.9
Total gas utility margin	$	169.6	$	180.9
Sold & transported volumes in MMDth attributed to:
Residential & commercial customers	47.0		62.2
Industrial customers	35.9		38.0
Total sold & transported volumes	82.9		100.2

Gas utility margins were $169.6 million for the three months endedMarch 31, 2016, and compared to 2015, decreased $11.3 million in the quarter. Margin was favorably impacted by increased returns on infrastructure replacement programs in Indiana and Ohio of $3.3 million and $1.6 million, respectively. Customer margin from large customer usage decreased $1.0 million compared to 2015, primarily due to warmer than normal weather. With rate designs that substantially limit the impact of weather on small customer margin, heating degree days that were 97 percent of normal in Ohio and 92 percent of normal in Indiana during the first quarter of 2016, compared to 109 percent of normal in Ohio and 104 percent of normal in Indiana in the first quarter of 2015, had only a slight unfavorable impact on small customer margin. However, the warmer weather did decrease sold and transported volumes, resulting in lower regulatory expense recovery margin and a corresponding decrease in operating expenses. Margin from regulatory expense recovery mechanisms decreased $14.2 million in the first quarter 2016 compared to 2015.

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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)	2016		2015
Electric utility revenues	$	142.1	$	153.9
Cost of fuel & purchased power	44.2		50.1
Total electric utility margin	$	97.9	$	103.8
Margin attributed to:
Residential & commercial customers	$	60.0	$	63.7
Industrial customers	26.0		26.8
Other	1.3		1.0
Regulatory expense recovery mechanisms	4.0		3.3
Subtotal: retail	$	91.3	$	94.8
Wholesale power & transmission system margin	6.6		9.0
Total electric utility margin	$	97.9	$	103.8
Electric volumes sold in GWh attributed to:
Residential & commercial customers	639.8		702.6
Industrial customers	654.2		672.9
Other customers	6.1		6.1
Total retail volumes sold	1,300.1		1,381.6

Retail

Electric retail utility margins were $91.3 million for the three months endedMarch 31, 2016, and compared to 2015, decreased by $3.5 million in the quarter. Electric results, which are not protected by weather normalizing mechanisms, reflect a $3.6 million decrease in customer margin related to weather as annualized heating degree days in the first quarter of 2016 were 92 percent of normal compared to 104 percent of normal in 2015. Additionally, results reflect a decrease in large customer usage of $0.8 million, largely driven by less production as a result of customer plant shut downs for maintenance. Margin from regulatory expense recovery mechanisms increased $0.7 million in the first quarter 2016 compared to the first quarter 2015, driven primarily by a corresponding increase in operating expenses associated with the electric efficiency programs.

On December 3, 2013, SABIC Innovative Plastics (SABIC), a large industrial utility customer of the Company, announced its plans to build a cogeneration (cogen) facility to be operational at the end of 2016 or early in 2017, in order to generate power to meet a significant portion of its ongoing power needs.  Electric service was provided to SABIC by the Company under a long-term contract that expired on May 3, 2016. At that date, SABIC became a tariff customer. SABIC's historical peak electric usage has been approximately 120 megawatts (MW).  The cogen facility is expected to provide approximately 80 MW of capacity.  Therefore, the Company will continue to provide all of SABIC's power requirements above the approximate 80 MW capacity of the cogen. Once the cogen is operational, backup power will be provided under approved tariff rates.

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)	2016		2015
MISO Transmission system margin	$	5.6	$	6.5
MISO Off-system margin	1.0		2.5
Total wholesale margin	$	6.6	$	9.0

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Transmission system margin associated with qualifying projects, including the reconciliation of recovery mechanisms and other transmission system operations, totaled $5.6 million and $6.5 million during the three months endedMarch 31, 2016 and 2015, respectively. As of March 31, 2016, the Company has invested $157.7 million in qualifying projects. The net plant balance for these projects totaled $139.4 million at March 31, 2016. These projects include an interstate 345 kV transmission line that connects the Company’s A.B. Brown Generating Station to a generating station in Indiana owned by Duke Energy to the north and to a generating station in Kentucky owned by Big Rivers Electric Corporation to the south; a substation; and another transmission line. Although the allowed return is currently being challenged as discussed below in Rate and Regulatory Matters, once placed into service, these projects earn a FERC approved equity rate of return of 12.38 percent on the net plant balance. The Company has established a reserve pending the outcome of these complaints. Operating expenses are also recovered. The 345 kV project is the largest of these qualifying projects, with a cost of $106.8 million that earned the FERC approved equity rate of return, including while under construction. The last segment of that project was placed into service in December 2012.

For the three months endedMarch 31, 2016, margin from off-system sales was $1.0 million compared to $2.5 million in 2015. 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 is shared equally with customers.  Results in the first quarter 2016 compared to the first quarter 2015 reflect lower market pricing due to low natural gas prices, net of sharing.  

Utility Group Operating Expenses

Other Operating

During the first quarter of 2016, other operating expenses were $89.4 million, and decreased $13.4 million, compared to the first quarter of 2015. The decrease in other operating costs is primarily due to decreases in costs that are recovered directly in margin. Excluding these pass through costs, other operating expenses decreased $3.5 million. The decrease in the first quarter 2016 compared to first quarter 2015 is driven primarily by the timing of power plant maintenance costs and lower energy delivery expenses due to the colder weather in 2015. These decreases were slightly offset by increases in performance-based compensation driven by an increase in the Company's stock price.

Depreciation & Amortization

In the first quarter of 2016, depreciation and amortization expense was $53.6 million compared to $52.1 million in 2015. The increase reflects increased plant placed in service, which is largely driven by increased gas utility plant as a result of the Indiana and Ohio infrastructure programs.

Taxes Other Than Income Taxes

Taxes other than income taxes decreased $2.0 million in the first quarter of 2016 compared to the same period in 2015. The decrease is primarily due to decreased gas costs and thus lower revenues and related revenue taxes.

Other Income - Net

Other income-net reflects income of $5.6 millionfor the first quarter of 2016, an increase of $0.7 million, compared to 2015. The increase reflects increased allowance for funds used during construction (AFUDC) driven by increased capital expenditures related to gas utility infrastructure replacement investments. This increase in AFUDC is somewhat offset by decreased returns on assets that fund certain benefit plans.

Gas Rate & Regulatory Matters

Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement

The Company monitors and maintains its natural gas distribution system to ensure natural gas is delivered in a safe and efficient manner. The Company's natural gas utilities are currently engaged in programs to replace bare steel and cast iron infrastructure and other activities in both Indiana and Ohio to mitigate risk, improve the system, and comply with applicable regulations, many of which are a result of federal pipeline safety requirements. Laws passed in both Indiana and Ohio provide utilities the opportunity to timely recover costs of federally mandated projects and other infrastructure improvement projects outside of a base rate proceeding.

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

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

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

Indiana Recovery and Deferral Mechanisms

The Company's Indiana natural gas utilities received Orders in 2008 and 2007 associated with the most recent base rate cases. These Orders authorized the deferral of financial impacts associated with bare steel and cast iron replacement activities. The Orders provide for the deferral of depreciation and post-in-service carrying costs on qualifying projects totaling $20 million annually at Indiana Gas and $3 million annually at SIGECO. The debt-related post-in-service carrying costs are 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, 2016 and December 31, 2015, the Company has regulatory assets totaling $20.6 million and $19.9 million, respectively, associated with the deferral of depreciation and debt-related post-in-service carrying cost activities. Beginning in 2014, all bare steel and cast iron replacement activities are now part of the Company’s seven-year capital investment plan filed pursuant to Senate Bill 251 and 560, discussed further below.

Requests for Recovery under Indiana Regulatory Mechanisms

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

Subsequent to the August 2014 Order, the Company filed and received Orders on three semi-annual updates, which recover in rates investments associated with the approved programs. In October 2015, the Company submitted its third semi-annual filing, seeking approval of the recovery in rates of investments made through June 30, 2015, and updates to the approved seven-year capital investment plan, now proposed at more than $950 million through 2020, of which $294 million has been spent as of March 31, 2016. On March 30, 2016, the IURC issued an Order (March 2016 Order) re-approving the majority of the Company’s gas infrastructure modernization projects requested in the third update of the Plan, and approving the inclusion in rates of actual investments made through June 30, 2015. Specifically, one project that was excluded for recovery under the Plan is a 20-mile transmission line and other related investments required to support industrial customer growth and ongoing

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system reliability in the Lafayette, Indiana area. The IURC stated because the project was not in the original plan filed in 2013, it does not qualify for cost recovery under this law. The IURC did pre-approve the project for rate base inclusion upon the filing of the next base rate case. The Company believes that such plan updates should be expected to accommodate new projects that emerge during the term of the plan as ongoing risk assessments determine that new projects are required. The Company filed an appeal of the Order on April 29, 2016 to challenge the IURC's limitation of the scope of the Plan updates. The outcome of the appeal is expected in approximately one year. Through the March 2016 Order, approximately $890 million of the proposed capital spend through 2020 has been approved through the recovery mechanisms supporting these filings.

At March 31, 2016 and December 31, 2015, the Company has regulatory assets totaling $32.8 million and $28.6 million, respectively, associated with the return on investment as well as the deferral of depreciation and other operating expenses.

Ohio Recovery and Deferral Mechanisms

The PUCO Order approving the Company's 2009 base rate case in the Ohio service territory authorized a distribution replacement rider (DRR). The DRR's primary purpose is recovery of investments in utility plant and related operating expenses associated with replacing bare steel and cast iron pipelines and certain other infrastructure. This rider is updated annually for qualifying capital expenditures and allows for a return on those capital expenditures based on the rate of return approved in the 2009 base rate case. In addition, deferral of depreciation and the ability to accrue debt-related post-in-service carrying costs is also allowed until the related capital expenditures are included in the DRR. The Order also initially established a prospective bill impact evaluation on the annual deferrals. Due to the expiration of the initial five-year term for the DRR in early 2014, the Company filed a request in August 2013 to extend and expand the DRR. On February 19, 2014, the PUCO issued an Order approving a Stipulation entered into by the PUCO Staff and the Company which provided for the extension of the DRR for the recovery of costs incurred through 2017 and expanded the types of investment covered by the DRR to include recovery of 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, the plan 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 August 26, 2015, the Company received an Order approving its adjustment to the DRR for recovery of costs incurred through December 31, 2014. In total, the Company has made capital investments under this rider totaling $208.5 million as of March 31, 2016. Regulatory assets associated with post-in-service carrying costs and depreciation deferrals were $19.7 million and $18.2 million at March 31, 2016 and December 31, 2015, respectively.

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 two-year time frame.

The PUCO has also issued Orders approving the Company's filings under Ohio House Bill 95. These Orders approve deferral of the Company’s Ohio capital expenditure program for items not covered by the DRR as well as expenditures necessary to comply with PUCO rules, regulations, orders, and system expansion to some new customers. Ohio House Bill 95 Orders also have established a prospective bill impact evaluation on the cumulative deferrals, limiting the total deferrals at a level which would equal $1.50 per residential and small general service customer per month. As of March 31, 2016, the Company's deferrals have not reached this bill impact cap. The Company submitted its most recent annual filing on May 2, 2016, which covers the Company’s capital expenditure program through calendar year 2016. The Company expects an order later this year.

Pipeline and Hazardous Materials Safety Administration (PHMSA)

On March 18, 2016, PHMSA published a notice of proposed rulemaking (NPRM) on the safety of gas transmission and gathering lines.  The proposed rule addresses many of the remaining requirements from the 2011 Pipeline Safety Act and sets out more stringent requirements than anticipated. The comment period on the NPRM ends on July 7, 2016. The Company is evaluating the impact the proposed rules would have on the Company's transmission integrity management program and the design, construction, and repair of transmission pipeline assets, including the potential for additional capital expenditures and increase in operation and maintenance expense. The Company believes that such compliance costs would be considered a

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federally mandated cost of providing natural gas, and therefore, should be recoverable from customers under Senate Bill 251 as referenced above.

Electric Rate & Regulatory Matters

SIGECO Electric Environmental Compliance Filing

On January 28, 2015, the IURC issued an Order (January Order) approving the Company’s request for approval of capital investments on its coal-fired generation units to comply with new EPA mandates related to mercury and air toxic standards (MATS) effective in 2015 and to address an outstanding Notice of Violation (NOV) from the EPA. As of March 31, 2016, approximately $30 million has been spent on equipment to control mercury in both air and water emissions, and $32 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 $75 million and $85 million. The Order approved the Company’s request for deferred accounting treatment, as supported by provisions under Indiana Senate Bill 29 (Senate Bill 29) and Senate Bill 251. The accounting treatment includes the deferral of depreciation and property tax expense related to these investments, accrual of post-in-service carrying costs, and deferral of incremental operating expenses related to compliance with these standards. The initial phase of the projects went into service in 2014, with the remaining investment occurring in 2015 and 2016. As of March 31, 2016, the Company has approximately $3.5 million deferred related to depreciation, property tax, and operating expense, and $1.4 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. In June 2015, Joint Appellants’ Citizens Action Coalition of Indiana, Inc., Sierra Club, Inc., and Valley Watch, Inc. (the appellants) filed a brief which challenged the sufficiency of the findings in the IURC's January Order approving the Company’s investments and proposed accounting treatment in terms of whether that Order made certain findings required by statute. On October 29, 2015, the Indiana Court of Appeals issued its opinion affirming the IURC’s findings with regard to equipment required to comply with MATS and certain national pollutant discharge elimination system rules (approximately $35 million). The Court remanded the case back to the IURC so that it can make the findings required by statute with regard to equipment required by the NOV (approximately $40 million). On February 12, 2016, the appellants filed a petition to reopen the evidentiary record in the case in order to submit additional evidence. The Company has opposed the motion and believes the IURC already has a sufficient record in this case. As it pertains to the equipment required by the NOV, given the Commission’s previous approval of this project, the Company believes the Commission will issue a new order in support of the project. The Company anticipates that the IURC will rule on the motion in the near future.

SIGECO Electric Demand Side Management (DSM) Program Filing

On August 31, 2011, the IURC issued an Order approving an initial three-year DSM plan in the SIGECO electric service territory that complied with the IURC’s energy saving targets. Consistent with the Company’s proposal, the Order approved, among other items, the following: 1) recovery of costs associated with implementing the DSM Plan; 2) the recovery of a performance incentive mechanism based on measured savings related to certain DSM programs; and 3) lost margin recovery associated with the implementation of DSM programs for large customers. On June 20, 2012, the IURC issued an Order approving a small customer lost margin recovery mechanism, inclusive of all previous deferrals. For the three months ended March 31, 2016 and 2015, the Company recognized electric utility revenue of $2.6 million and $2.3 million, respectively, associated with this approved lost margin recovery mechanism.

On March 28, 2014, Indiana Senate Bill 340 was signed into law. This legislation ended electric DSM programs on December 31, 2014 that had been conducted to meet the energy savings requirements established by the IURC in 2009. The legislation also allows for industrial customers to opt out of participating in energy efficiency programs. As of January 1, 2015, approximately 80 percent of the Company’s eligible industrial load has opted out of participation in the applicable energy efficiency programs. The Company filed a request for IURC approval of a new portfolio of DSM programs on May 29, 2014 to be offered in 2015. On October 15, 2014, the IURC issued an Order approving a Settlement between the OUCC and the Company regarding the new portfolio of DSM programs effective January 2015, and new programs were implemented during the first quarter of 2015.

On May 6, 2015, Indiana's governor signed Indiana Senate Bill 412 (Senate Bill 412) into law requiring electricity suppliers to submit energy efficiency plans to the IURC at least once every three years. Senate Bill 412 also permits the recovery of all

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program costs, including lost revenues and financial incentives associated with those plans and approved by the IURC. The Company made its first filing pursuant to this bill in June 2015, which proposed energy efficiency programs for calendar years 2016 and 2017. In September 2015, the Company received an Order to continue offering and recovering the associated cost of its 2015 programs until March 31, 2016. In October 2015, the OUCC and Citizens Action Coalition of Indiana filed testimony recommending the rejection of the Company’s plan, contending it was not reasonable under the terms of Senate Bill 412 due to the program design and the Company’s proposal to recover lost revenues and incentives associated with the measures. Vectren filed rebuttal testimony in October 2015 defending the plan’s compliance with Senate Bill 412.

On March 23, 2016, the IURC issued an Order approving the Company’s 2016-2017 energy efficiency programs. The Order provides for cost recovery of program and administrative expenses and includes performance incentives for reaching energy savings goals. The Order also included a lost margin recovery mechanism that now limits that recovery related to new programs to the shorter of four years or the life of the installed energy efficiency measure. Prior electric energy efficiency orders did not limit lost margin recovery to this four year limit. This ruling follows two other recent IURC decisions implementing the same recovery cap with respect to other electric utilities in Indiana. The Company is committed to continuing to promote and drive participation in its 2016-2017 energy efficiency programs and beyond and has therefore appealed this lost margin recovery restriction.

FERC Return on Equity (ROE) Complaints

On November 12, 2013, certain parties representing a group of industrial customers filed a joint complaint with the FERC under Section 206 of the Federal Power Act against the MISO and various MISO transmission owners, including SIGECO. The joint parties seek to reduce the 12.38 percent ROE used in the MISO transmission owners’ rates, including SIGECO’s formula transmission rates, to 9.15 percent, and to set a capital structure in which the equity component does not exceed 50 percent. A second customer complaint case was filed on February 11, 2015 as the maximum FERC-allowed refund period for the November 12, 2013 case ended February 11, 2015. As of March 31, 2016, the Company had invested approximately $157.7 million in qualifying projects. The net plant balance for these projects totaled $139.4 million at March 31, 2016.

These joint complaints are similar to a complaint against the New England Transmission Owners (NETO) filed in September 2011, which requested that the 11.14 percent incentive return granted on qualifying investments in NETO be lowered. On October 16, 2014, the FERC issued an Order in the NETO case approving a 10.57 percent return on equity and a calculation methodology.

The FERC acknowledged that the pending complaint raised against the MISO transmission owners is reasonable and denied the portion of the complaint addressing the equity component of the capital structure. An initial decision from its administrative law judge was received on December 22, 2015, authorizing the transmission owners to collect a Base ROE of 10.32 percent from November 12, 2013 through February 11, 2015 (the “first refund period”). The FERC is expected to rule on the proposed order in late 2016. A procedural schedule has been established for the second customer complaint case, establishing a target date of June 30, 2016 for the initial decision.

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

The Company has established a reserve considering both the initial decision and the approved 50 basis points adder.

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Environmental Matters

The Company's utility operations and properties are subject to extensive environmental regulation pursuant to a variety of federal, state and municipal laws and regulations. These environmental regulations impose, among other things, restrictions, liabilities, and obligations in connection with the storage, transportation, treatment, and disposal of hazardous substances and limit airborne emissions from electric generating facilities including particulate matter, sulfur dioxide (SO₂), nitrogen oxide (NOx), and mercury, among others. Environmental legislation and regulation also requires that facilities, sites, and other properties associated with the Company's operations be operated, maintained, abandoned, and reclaimed to the satisfaction of applicable regulatory authorities. The Company's current costs to comply with these laws and regulations are significant to its results of operations and financial condition.

With the trend toward stricter standards, greater regulation, and more extensive permit requirements, the Company's investment in compliant infrastructure, and the associated operating costs have increased and are expected to increase in the future. Similar to the costs associated with federal mandates in the Pipeline Safety Law, Senate Bill 251 is also applicable to federal environmental mandates impacting SIGECO's electric operations.

Air Quality

Mercury and Air Toxics (MATS) Rule

On December 21, 2011, the EPA finalized the utility MATS rule. The MATS rule sets emission limits for hazardous air pollutants for existing and new coal-fired power plants and identifies the following broad categories of hazardous air pollutants: mercury, non-mercury hazardous air pollutants (primarily arsenic, chromium, cobalt, and selenium), and acid gases (hydrogen cyanide, hydrogen chloride, and hydrogen fluoride). The rule imposes mercury emission limits for two sub-categories of coal and proposed surrogate limits for non-mercury and acid gas hazardous air pollutants.

In July 2014, a coalition of twenty-one states, including Indiana, filed a petition with the U.S. Supreme Court seeking review of the decision of the appellate court that found the EPA appropriately based its decision to list coal and oil fired generation units as a source of the pollutants at issue solely on those pollutants’ impact on public health. On June 29, 2015, the U.S. Supreme Court reversed the appellate court decision on the basis of the EPA’s failure to consider costs before determining whether it was appropriate and necessary to regulate steam electric generating units under Section 112 of the Clean Air Act. The Court did not vacate the rule, but remanded the MATS rule back to the appellate court for further proceedings consistent with the opinion. MATS compliance was required to commence April 16, 2015, and the Company continues to operate in full compliance with the MATS rule.

Notice of Violation for A.B. Brown Power Plant

The Company received a NOV from the EPA in November 2011 pertaining to its A.B. Brown generating station. The NOV asserts when the facility was equipped with Selective Catalytic Reduction (SCR) systems, the correct permits were not obtained or the best available control technology to control incidental sulfuric acid mist was not installed. While the Company did not agree with notice, it reached a final settlement with the EPA to resolve the NOV in December 2015.

As noted previously, on January 28, 2015, the IURC issued an Order approving the Company’s request for approval of capital investments on its coal-fired generation units to comply with new EPA mandates related to MATS effective in 2015 and to address the outstanding NOV regarding SO₃ emissions from the EPA. The total investment is estimated to be between $75 million and $85 million, roughly half of which has been spent to control mercury in both air and water emissions, and the remaining investment has been made to address the issues raised in the NOV.

In 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. In June 2015, Joint Appellants’ Citizens Action Coalition of Indiana, Inc., Sierra Club, Inc., and Valley Watch, Inc. (the appellants) filed a brief which challenged the sufficiency of the findings in the IURC's January Order approving the Company’s investments and proposed accounting treatment in terms of whether that Order made certain findings required by statute. On October 29, 2015, the Indiana Court of Appeals issued its opinion affirming the IURC’s findings with regard to equipment required to comply with MATS and certain national pollutant discharge elimination system rules

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(approximately $35 million). The Court remanded the case back to the IURC so that it can make the findings required by statute with regard to equipment required by the NOV (approximately $40 million). On February 12, 2016, the appellants filed a petition to reopen the evidentiary record in the case in order to submit additional evidence. The Company has opposed the motion and believes the IURC already has a sufficient record in this case. As it pertains to the equipment requirement required by the NOV, given the Commission’s previous approval of this project, the Company believes the Commission will make these findings and issue a new order in support of the project. The Company anticipates that the IURC will rule on the motion in the near future.

Ozone NAAQS

On November 26, 2014, the EPA proposed to tighten the current National Ambient Air Quality Standard (NAAQS) for ozone from the current standard of 75 parts per billion (ppb) to a level with the range of 65 to 70 ppb. On October 1, 2015, the EPA finalized a new NAAQS for ozone at the high end of the range, or 70 ppb. The EPA is expected to make final determinations as to whether a region is in attainment for the new NAAQS in 2018 based upon monitoring data from 2014-2016. While it is possible that counties in southwest Indiana could be declared in non-attainment with the new standard, and thus could have an effect on future economic development activities in the Company's service territory, the Company does not anticipate any significant compliance cost impacts from the determination given its previous investment in SCR technology for NOx control on its units.

One Hour SO2 NAAQS

On February 16, 2016, the EPA notified states of the commencement of a 120 day consultation period between the state and the EPA with respect to the EPA's recommendations for new non-attainment designations for the 2010 One Hour SO2 NAAQS. Identified on the list was Posey County, Indiana, in which the Company's A.B. Brown Generating Station is located. While the Company is in compliance with all applicable SO2 limits in its permits, the Company is currently working with the state of Indiana on voluntary measures that the Company may take without significant incremental costs to ensure that Posey County remains in attainment with the 2010 One Hour SO2 NAAQS. The Company's coal-fired generating fleet is 100 percent scrubbed for SO2 and 90 percent controlled for NOx.

Coal Ash Waste Disposal, Ash Ponds and Water

Coal Combustion Residuals Rule

In December 2014, the EPA released its final Coal Combustion Residuals (CCR) rule which regulates ash as non-hazardous material under Subtitle D of the Resource Conservation and Recovery Act (RCRA). On April 17, 2015, the final rule was published in the Federal Register. The final rule allows beneficial reuse of ash and the majority of the ash generated by the Company’s generating plants will continue to be reused. As it relates to the CCR rule, legislation is currently being considered by Congress that would provide for enforcement of the federal program by states rather than through citizen suits. Additionally, the CCR rule is currently being challenged by multiple parties in judicial review proceedings. Opening briefs were filed by those parties in December of 2015, with full briefing not expected to be complete until later in May 2016.

Under the final CCR rule, the Company is required to complete a series of integrity assessments, including seismic modeling given the Company’s facilities are located within two seismic zones, and groundwater monitoring studies to determine the remaining service life of the ponds and whether a pond must be retrofitted with liners or closed in place, with bottom ash handling conversions completed. In late 2015, using general utility industry data, the Company prepared cost estimates for the retirement of the ash ponds at the end of their useful lives, based on its interpretation of the closure alternatives contemplated in the final rule. The resulting estimates ranged from approximately $35 million to $80 million. These estimates contemplated final capping and monitoring costs of the ponds at both F.B. Culley and A.B. Brown generating stations. These rules have not been applicable to the Company's Warrick generating unit, as this unit has historically been part of a larger generating station that predominantly serves an adjacent industrial facility. The Company is in the process of preparing site specific estimates, using engineering analyses and assumed methods of closure. Significant factors impacting the resulting cost estimates include the closure time frame and the method of closure. Further analysis and the refinement of assumptions may result in estimated costs that could be in excess of the current range of $35 million to $80 million.

At September 30, 2015, the Company recorded an approximate $25 million asset retirement obligation (ARO) and that amount is unchanged at March 31, 2016. The recorded ARO reflected the present value of the approximate $35 million in

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estimated costs in the range above. These assumptions and estimations are subject to change in the future and could materially impact the amount of the estimated ARO.

Effluent Limitation Guidelines (ELGs)

Under the Clean Water Act, the EPA sets technology-based guidelines for water discharges from new and existing facilities. On September 30, 2015, the EPA released final revisions to the existing steam electric ELGs setting stringent technology-based water discharge limits for the electric power industry. The EPA focused this rulemaking on wastewater generated primarily by pollution control equipment necessitated by the comprehensive air regulations, specifically setting strict water discharge limits for arsenic, mercury and selenium for scrubber waste waters. The ELGs will be implemented when existing water discharge permits for the plants are renewed, with compliance activities expected to commence within the 2018-2023 time frame. Current wastewater discharge permits for the Brown and Culley power plants expire in October and December 2016, respectively. The Company is working with Indiana regulators on permit renewals which will include a compliance schedule for ELGs. In no event will compliance with the ELGs be required prior to November 2018. The ELGs work in tandem with the recently released CCR requirements, effectively prohibiting the use of less costly lined sediment basin options for disposal of coal combustion residuals, and virtually mandate conversions to dry bottom ash handling.

Cooling Water Intake Structures

Section 316(b) of the Clean Water Act requires that generating facilities use the “best technology available” (BTA) to minimize adverse environmental impacts on a body of water. More specifically, Section 316(b) is concerned with impingement and entrainment of aquatic species in once-through cooling water intake structures used at electric generating facilities. A final rule was issued by the EPA on May 19, 2014. The final rule does not mandate cooling water tower retrofits but requires a state level case-by-case assessment of BTA for each facility. The final rule lists seven presumptive technologies which would qualify as BTA. These technologies range from intake screen modifications to cooling water tower retrofits. Ecological and technology assessment studies must be completed prior to determining BTA for the Company’s facilities. To comply, the Company believes that capital investments will likely be in the range of $4 million to $8 million.

Climate Change

Vectren 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 baseload generation including effective energy conservation, demand side management, and generation efficiency measures;

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

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Reporting Initiative. This certification creates shared value, demonstrates the Company's commitment to sustainability and denotes transparency in operations;

• Implementing home and business energy efficiency initiatives in the Company’s Indiana and Ohio gas utility service territories such as offering rebates on high efficiency furnaces, programmable thermostats, and insulation and duct sealing;

• Implementing home and business energy efficiency initiatives in the electric service territory such as rebate programs on central air conditioning units, LED lighting, home weatherization and energy audits;

• 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;

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

• Reducing methane emissions through becoming a founding partner in the EPA Natural Gas STAR Methane Challenge Program. The Company's primary method for reducing methane emissions is through continued replacement of bare steel and cast iron gas distribution pipeline assets;

• Developing renewable energy and energy efficiency performance contracting projects through its Energy Services segment; and

• Helping energy producers install pipes that allow for more natural gas power generation and reduce gas flaring through its Infrastructure Services segment.

On August 3, 2015, the EPA released its final Clean Power Plan (CPP) rule which requires a 32 percent reduction in carbon emissions from 2005 levels. This results in a final emission rate goal for Indiana of 1,242 lb CO2/MWh to be achieved by 2030. The new rule gives states the option of seeking a two-year extension from the deadline of September 2016 to submit a final state implementation plan (SIP). Under the CPP, states have the flexibility to include energy efficiency and other measures should it choose to implement a SIP as provided in the final rule. While states are given an interim goal (1,451 lb CO2/MWh for Indiana), the final rule gives states the flexibility to shape their own emissions reduction over the 2022-2029 time period. The final rule was published in the Federal Register on October 23, 2015 and that action was immediately followed by litigation initiated by Indiana and 23 other states as a coalition challenging the rule. In January of 2016, the reviewing court denied the states’ and other parties requests to stay the implementation of the CPP pending completion of judicial review. On January 26, 2016, 29 states and state agencies (including the 24 state coalition referenced above) filed a request for immediate stay with the U.S. Supreme Court. On February 9, 2016, the U.S. Supreme Court granted a stay to delay the regulation while being challenged in court. The stay will remain in place while the lower court concludes its review, with oral arguments to be heard in June 2016 under the existing accelerated schedule. Among other things, the stay is anticipated to delay the requirement to submit a final SIP by the September 2016 deadline. Apart from the delay, the Court's action creates additional uncertainty as to the future of the rule and presents further challenges as the Company proceeds with its integrated resource planning process later this year.

In the event that a state does not submit a SIP, the EPA also released a proposed federal implementation plan (FIP), which would be imposed on those states without an approved SIP. The proposed FIP would apply an emission rate requirement directly on generating units. Under the proposed FIP, the CO2 emission rate limit for coal-fired units would start at 1,671 lbs CO2/MWh in 2022 and decrease to a final emission rate cap of 1,305 lbs CO2/MWh by 2030. While the FIP emission rate cap appears to be slightly less stringent than the state reduction goal for Indiana, the cap would apply directly to generating units and these units would not have the benefit of averaging emission rates with rates from zero-carbon sources as would be available in a SIP. Purchases of emission credits from zero-carbon sources can be made for compliance. The FIP will be subject to extensive public comments prior to finalization. Whether Indiana will file a SIP has yet to be determined. Pending that determination, the electric utilities in Indiana will continue to encourage the state's designated agency to analyze various compliance options and the possible integration into a state plan submittal.

At the time of release of the CPP, Indiana was the 5th largest carbon emitter in the nation in tons of CO2 produced from electric generation. The Company’s share of total tons of CO2 generated by Indiana's electric utilities has historically been less than 6 percent. Since 2005, the Company has achieved a reduction in emissions of CO2 of 31 percent (on a tonnage basis) through the retirement of F.B. Culley Unit 1, expiration of municipal contracts, electric conservation, the addition of renewable generation,

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and the installation of more efficient dense pack turbine technology. Since emissions are further impacted by coal burn reductions and energy efficiency programs, the Company's emissions of CO2 can vary year to year. With respect to renewable generation, in 2008 and 2009, the Company executed long-term purchase power commitments for a total of 80 MW of wind energy. The Company currently has approximately 4 percent of its electricity being provided by 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 1,967 lbs CO2/MWh to 1,922 lbs CO2/MWh, for a reduction of 3 percent. The Company’s CO2 emission rate of 1,922 lbs CO2/MWh is basically the same as Indiana's average CO2 emission rate of 1,923 lbs CO2/MWh. The Company plans to consider these reductions in CO2 emissions and renewable generation in future discussions with the state to develop a possible state implementation plan.

Impact of Legislative Actions & Other Initiatives is Unknown

At this time, compliance costs and other effects associated with reductions in GHG emissions or obtaining renewable energy sources remain uncertain. The Company has gathered preliminary estimates of the costs to control GHG emissions. A preliminary investigation demonstrated costs to comply would be significant, first with regard to operating expenses and later for capital expenditures as technology becomes available to control GHG emissions. However, these compliance cost estimates were based on highly uncertain assumptions, including allowance prices if a cap and trade approach were employed, and energy efficiency targets. The Company is undertaking a detailed review of the requirements of the CPP and the proposed FIP and a review of potential compliance options. The Company will also continue to remain engaged with the Indiana legislators and regulators to assess the final rule and to develop a plan that is the least cost to its customers.

Integrated Resource Planning Process

As required by the state of Indiana, the Company is currently in the process of completing its 2016 Integrated Resource Plan (IRP). The state requires each electric utility to perform and submit an IRP that details the resources it may rely upon to provide electric service for the next twenty year period to ensure electric reliability throughout the state. During 2016, the Company will hold three public stakeholder meetings to gather input and feedback as well as communicate results of the IRP process as it progresses. The first of three public meetings was held in April 2016. A final IRP report is expected to be submitted to the IURC for review in November 2016. While the IURC reviews these reports, it does not formally approve or reject the plans.

The 2016 IRP will consider the ongoing operation of the 300 MW unit at the Warrick Power Plant (Warrick Unit 4) that SIGECO and Alcoa Generating Corporation (AGC), a subsidiary of Alcoa, Inc. (Alcoa), own as tenants in common. SIGECO's proportionate cost of the unit is included in rate base. In the first quarter of 2016, Alcoa closed its smelter operations. Historically, on-site generation owned and operated by AGC has been used to provide power to the smelter, as well as other mill operations, which will continue. Generation from Alcoa's share of Warrick Unit 4 has historically been sold into the MISO market. Alcoa's operational changes, as described above, lead to a number of uncertainties including its plans regarding the future ownership and operation of Warrick Unit 4 as well as potential environmental regulation implications under the CCR and ELG regulations. The Company is actively working with Alcoa on plans related to continued operation of their generation, anticipating that more will be known toward the end of 2016.

As it relates to water, ash, and carbon regulation, while the Company is exploring various compliance options, the Company cannot reasonably estimate the total cost to comply with the CCR, ELG and CPP regulations for its units at this time. The cost of compliance with these new regulations could be significant. The Company believes that such compliance costs would be considered a federally mandated cost of providing electricity, and therefore if incurred, should be recoverable either from customers through Senate Bill 251 as referenced above, Senate Bill 29, which was used by the Company to recover its initial pollution control investments, or through other forms of rate recovery. Addressing compliance alternatives for CCR, ELG, and CPP, including the impact on customer rates, as well as addressing the uncertainties with Warrick Unit 4, will be fully considered as part of the Company's IRP process conducted in 2016.

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.

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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 $14.8 million of the expected $15.8 million in insurance recoveries.

The costs the Company expects to incur are estimated by management using assumptions based on actual costs incurred, the timing of expected future payments, and inflation factors, among others. While the Company’s utilities have recorded all costs which they presently expect to incur in connection with activities at these sites, it is possible that future events may require remedial activities which are not presently foreseen and those costs may not be subject to PRP or insurance recovery. As of March 31, 2016 and December 31, 2015, approximately $3.0 million and $3.3 million, respectively, of accrued, but not yet spent, costs are included in Other Liabilities related to the Indiana Gas and SIGECO sites.

Results of Operations of the Nonutility Group

The Nonutility Group operates in two primary business areas: Infrastructure Services and Energy Services.  Infrastructure Services provides underground pipeline construction and repair services.  Energy Services provides energy performance contracting and sustainable infrastructure, such as renewables, distributed generation, and combined heat and power projects.    Enterprises has other legacy businesses that have investments in energy-related opportunities and services, among other investments.  All of the above is collectively referred to as the Nonutility Group.

The Nonutility Group results for the first quarter of 2016 were a loss of $12.7 million, compared to a loss of $5.9 million in the prior year.

	Three Months Ended
	March 31,
(In millions, except per share amounts)	2016			2015
NET INCOME (LOSS)	$	(12.7	)	$	(5.9	)
CONTRIBUTION TO VECTREN BASIC EPS	$	(0.16	)	$	(0.07	)
NET INCOME (LOSS) ATTRIBUTED TO:
Infrastructure Services	$	(12.6	)	$	(2.6	)
Energy Services	0.1			(3.1		)
Other Businesses	(0.2		)	(0.2		)

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Infrastructure Services

Infrastructure Services provides underground pipeline construction and repair services through wholly owned subsidiaries Miller Pipeline, LLC (Miller or Miller Pipeline) and Minnesota Limited, LLC (Minnesota Limited).  Inclusive of holding company costs, results for Infrastructure Services' operations for the first quarter of 2016 were a loss of $12.6 million, compared to a loss of $2.6 million for the same period in the prior year.

The distribution portion of the infrastructure operation is performing well as gas utilities across the country continue to make significant investments in their gas infrastructure systems. The lower results from the transmission portion of the business are due largely to two large station projects completed in the first quarter of 2015 and lower margin on awarded transmission contracts, as well as fewer transmission maintenance projects being awarded. The lower margin on projects, coupled with a reduction in the projects awarded, is reflective of a more competitive environment as other contractors continue to adjust crews and work load as some large gas and oil projects have been delayed due to the lengthening environmental and regulatory approval process and the current low oil price environment. Those contractors continue to compete aggressively in the repair and maintenance market, resulting in fewer projects awarded to Infrastructure Services and lower margins on projects won. The strong and growing demand in the distribution services business has helped offset some of the decline in transmission services' results. The growth trend in the distribution services business is expected to continue as utilities expand their infrastructure replacement programs. Finally, though it is possible that the start date of some of the announced pipeline projects is further delayed, primarily due to environmental or regulatory review, the fundamental business model related to the long cycle of repair and maintenance work in the transmission sector remains unchanged as the demand remains high due to aging infrastructure and evolving safety and reliability regulations. Total Infrastructure Services gross revenues in the first quarter of 2016 were $112.5 million compared to gross revenues of $176.9 million in the first quarter of 2015.

At March 31, 2016, Infrastructure Services had an estimated backlog of blanket contracts of $440 million and bid contracts of $215 million, for a total backlog of $655 million. This compares to an estimated backlog at December 31, 2015 of $475 million for blanket contracts and $190 million for bid contracts, for a total of $665 million.

The long-term outlook for construction activity remains strong as utilities, municipalities and pipeline operators repair and replace aging natural gas and oil pipelines and related infrastructure, and as pipeline operators construct new pipelines due to the continued significant demand for shale gas and oil infrastructure. The drop in oil prices has resulted in some production cuts that have been predominately related to the drilling of new wells. There are still significant new pipeline projects totaling approximately 14,000 miles announced for 2016 through 2018 that, even if delayed, are ultimately expected to absorb resources and equipment. The result should be a gradual increase in opportunities for pipeline maintenance work and an increase in margins as the competition for maintenance work decreases. Pipelines are still being built for producing wells and, as such, the demand for this work is still strong. While the drop in oil prices could have greater impact if prices do not continue to rebound, the mix of activity should improve and the long-term trends remain positive.

In 2016, the estimated depreciable lives for certain pieces of equipment at Minnesota Limited, LLC were reevaluated and extended due to a change in service life of the equipment. As a result of this evaluation, the Company extended the estimated useful life of certain pieces of equipment effective January 1 of the current year. The effect of this change in estimate is an anticipated reduction of annual depreciation expense of approximately $9.6 million in 2016 but is not expected to have a material impact on net income as these costs are fully reflected in bids as costs to recover.

Energy Services

Energy Services provides energy performance contracting and sustainable infrastructure, such as distributed generation, renewables, and combined heat and power projects through its wholly owned subsidiary Energy Systems Group, LLC (ESG).  Inclusive of holding company costs, Energy Services' operations were earnings of $0.1 million during the first quarter of 2016, compared to a loss of $3.1 million during the first quarter of 2015. Energy Services achieved record first quarter revenues of $49.4 million in 2016, compared to revenues of $23.1 million in the first quarter of 2015.

At March 31, 2016, the backlog of signed fixed price contracts remains high at $208 million compared to $226 million at December 31, 2015. The backlog at March 31, 2016 is down slightly due to the significant number of contracts signed in the

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fourth quarter of 2015 and, further, the first quarter is not historically a large contract signing period. The Company's long-term view of the performance contracting and sustainable infrastructure opportunities remains strong as the national focus on energy conservation and security, renewable energy, and sustainability continues to grow given the expected rise in power prices across the country and customer focus on efficiency and clean energy. Expected activity in the federal sector, as well as positive indications in the public sector and sustainable infrastructure business, is reflected in the strong backlog and sales funnel. Consistent with the national focus on energy conservation and efficiency, in December 2015, the tax code section (Section 179D) allowing for federal tax deductions related to energy efficiency savings achieved was retroactively extended for 2015 through 2016. The impact of these tax deductions reflected in first quarter 2016 results, net of consulting fees, was $0.7 million. Given the timing of the extension in 2015, there was no impact in first quarter 2015.

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. The amendments in this guidance state that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This new guidance requires improved disclosures to help users of financial statements better understand the nature, amount, timing, and uncertainty of revenue that is recognized.

On July 9, 2015, the FASB approved a one year deferral that became effective through an ASU in August and changed the effective date to annual reporting periods beginning after December 15, 2017, including interim periods, with early adoption permitted, but not before the original effective date of December 15, 2016. The Company is currently evaluating the standard to determine application date, transition method, and impact the standard will have on the financial statements.

Simplifying the Presentation of Debt Issuance Costs

In April 2015, the FASB issued new accounting guidance on accounting for debt issuance costs which changes the presentation of debt issuance costs in financial statements. This ASU requires an entity to present such costs in the balance sheet as a direct 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. The guidance was adopted for March 31, 2016, and has been applied retrospectively to all periods presented. The effect of the change on the December 31, 2015 balance sheet was the reclassification of $8.6 million from regulatory assets to long-term debt and the reclassification of $1.3 million from other assets to long-term debt. The reclassification had no material impact on the Company's financial condition, results of operations, or cash flows as a result of the adoption.

Leases

In February 2016, the FASB issued new accounting guidance for the recognition, measurement, presentation and disclosure of leasing arrangements. This ASU requires the recognition of lease assets and liabilities for those leases currently classified as operating leases while also refining the definition of a lease. In addition, lessees will be required to disclose key information about the amount, timing, and uncertainty of cash flows arising from leasing arrangements. This ASU is effective for the interim and annual reporting periods beginning January 1, 2019, although it can be early adopted, with a modified retrospective approach for leases that commenced prior to the date of adoption. The Company is currently evaluating the standard to determine the impact it will have on the financial statements.

Stock Compensation

In March 2016, the FASB issued new accounting guidance which is intended to simplify several aspects of accounting for share-based payment transactions, including the income tax consequences. This ASU is effective for annual periods beginning after December 15, 2016, and interim periods therein. Early application is permitted. The Company is currently evaluating the standard to determine the impact it will have on the financial statements, if any.

Management believes that other recently issued standards, which are not yet effective, will not have a material impact on the Company's financial condition, results of operations, or cash flows upon adoption.

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Financial Condition

Within the Company’s consolidated group, Utility Holdings primarily funds the short-term and long-term financing needs of the Utility Group operations, and Vectren Capital funds short-term and long-term financing needs of the Nonutility Group and corporate operations.  Vectren Corporation guarantees Vectren Capital’s debt, but does not guarantee Utility Holdings’ debt.  Vectren Capital’s long-term debt, including current maturities, at March 31, 2016 approximated $334 million. As of March 31, 2016, Vectren Capital had no short-term borrowings outstanding.  Utility Holdings’ outstanding long-term and short-term borrowing arrangements are jointly and severally guaranteed by its wholly owned subsidiaries and regulated utilities SIGECO, Indiana Gas, and VEDO.  Utility Holdings’ long-term debt, including current maturities, outstanding at March 31, 2016 approximated $995 million. As of March 31, 2016, Utility Holdings had no 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 new 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, 2016, was approximately $397 million.

The Company’s common stock dividends are primarily funded by utility operations.  Nonutility operations have demonstrated profitability and the ability to generate cash flows.  These cash flows are primarily reinvested in other nonutility ventures, but are also used to fund a portion of the Company’s dividends, and from time to time may be reinvested in utility operations or used for corporate expenses.

Vectren Corporation's corporate credit rating is A-, as rated by Standard and Poor's Ratings Services (Standard and Poor's). Moody's Investor Services (Moody's) does not provide a rating for Vectren Corporation. The credit ratings of the senior unsecured debt of Utility Holdings, SIGECO and Indiana Gas, at March 31, 2016, are A-/A2, as rated by Standard and Poor's and 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 45-55 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 50 percent and 49 percent of long-term capitalization at March 31, 2016 and December 31, 2015, respectively.  Long-term capitalization includes long-term debt, including current maturities, as well as common shareholders’ 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, 2016, 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 as evidenced by past financing transactions, the Company believes it will have the ability to continue to do so.  The Company anticipates funding future capital expenditures and dividends principally through internally generated funds, supplemented with incremental external debt financing and cash flow generated from nonutility businesses. However, it has considered access to both short-term and long-term capital markets as a significant source of funding for capital requirements as the resources required for capital investment remain uncertain for a variety of factors including, but not limited to, expanded environmental regulations, growth of the regulated business, and growth of Infrastructure Services and Energy Services. These regulations may result in the need to raise additional capital in the coming years. To the extent that events beyond the Company's control create uncertainty in capital markets, cost of capital and ability to access capital markets may be affected.

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Consolidated Short-Term Borrowing Arrangements

At March 31, 2016, the Company has $600 million of short-term borrowing capacity, including $350 million for the Utility Group and $250 million for the wholly owned Nonutility Group and corporate operations.  As no short-term borrowings are outstanding as of March 31, 2016, the full capacities of $350 million and $250 million are available for the Utility Group and the wholly owned Nonutility Group and corporate operations, respectively. Both Vectren Capital’s and Utility Holdings’ short-term credit facilities were amended on October 31, 2014 to extend their maturity until October 31, 2019.  These facilities are used to supplement working capital needs and also to fund capital investments and debt redemptions.  

The Company has historically funded the short-term borrowing needs of Utility Holdings’ operations through the commercial paper market and has the ability to use the Utility Holdings short-term borrowing facility. Following is certain information regarding these short-term borrowing arrangements.

	Utility Group Borrowings		Nonutility Group Borrowings
(In millions)	2016	2015	2016	2015
As of March 31
Balance Outstanding	—	$5.9	—	$0.5
Weighted Average Interest Rate	—	0.39%	—	1.30%
Quarterly Average - March 31
Balance Outstanding	$3.0	$69.2	—	$0.1
Weighted Average Interest Rate	0.56%	0.39%	—	1.32%
Maximum Month End Balance Outstanding	$10.8	$121.5	—	$0.5

New Share Issues

The Company may periodically issue new common shares to satisfy the dividend reinvestment plan, stock option plan and other employee benefit plan requirements.  New issuances added additional liquidity of $1.5 million and $1.6 million for the three months endedMarch 31, 2016 and 2015 periods.

California Department of Insurance

The California Department of Insurance issued a press release in January 2016 calling for all insurance companies doing business in California to voluntarily divest of their investments in thermal coal. The position taken by the California Insurance Commissioner, as defined, applies to electric utilities that derive more than 50 percent of their energy from thermal coal plants. The Company has a significant portion of its outstanding long term debt held by various insurance companies and placed through the private debt markets. The Company continues to monitor development in this area but anticipates no immediate impact.

Potential Uses of Liquidity

Pension Funding Obligations

For the three months ended March 31, 2016, the Company had contributed $15 million to its qualified pension plans. The Company does not anticipate making further contributions in 2016.  

Performance Guarantees & Product Warranties

In the normal course of business, wholly owned subsidiaries, such as Energy Systems Group (ESG), a subsidiary of the Energy Services operating segment, issue payment and performance bonds and other forms of assurance that commit them to timely install infrastructure, operate facilities, pay vendors and subcontractors, and support warranty obligations.  

Specific to ESG, in its role as a general contractor in the performance contracting industry, at March 31, 2016, there are 38 open surety bonds supporting future performance.  The average face amount of these obligations is $10.4 million, and the largest obligation has a face amount of $51.0 million.  The maximum exposure from these obligations is limited to the level of uncompleted work and further limited by bonds issued to ESG by various subcontractors. At March 31, 2016, approximately 54 percent of work was yet to be completed on projects with open surety bonds.  A significant portion of these open surety bonds will be released within one year.  In instances where ESG operates facilities, project guarantees extend over a longer period.  In

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addition to its performance obligations, ESG also warrants the functionality of certain installed infrastructure generally for one year and the associated energy savings over a specified number of years.  

Based on a history of meeting performance obligations and installed products operating effectively, no liability or cost has been recognized for the periods presented. Since inception, ESG has only had to pay an immaterial amount for payment and performance obligations.

Corporate Guarantees

The Company issues parent level guarantees to certain vendors and customers of its wholly owned subsidiaries.  These guarantees do not represent incremental consolidated obligations; rather, they represent parental guarantees of subsidiary obligations in order to allow those subsidiaries the flexibility to conduct business without posting other forms of collateral.   At March 31, 2016, parent level guarantees support a maximum of $245 million of ESG’s performance contracting commitments, warranty obligations, project guarantees, and energy savings guarantees.

Further, an energy facility operated by ESG and managed by Keenan Ft. Detrick Energy, LLC (Keenan), is governed by an operations agreement. All payment obligations to Keenan under this agreement are also guaranteed by the Company. The Company guarantee of the Keenan Ft. Detrick Energy operations agreement does not state a maximum guarantee. Due to the nature of work performed under this contract, the Company cannot estimate a maximum potential amount of future payments.

In addition, the Company also has other guarantees outstanding, including letters of credit, supporting other consolidated subsidiary operations.

While there can be no assurance that the Company guarantee provisions will not be called upon, no such provisions have been called on historically, and further, the Company believes that the likelihood of a material amount being triggered under any of these provisions is remote.

Planned Capital Expenditures & Investments

Utility capital expenditures are estimated at $420 million for the remainder of 2016.  Nonutility capital expenditures and investments are estimated at $53 million for the remainder of 2016.

Contractual Obligations

The Company’s contractual obligations primarily consist of debt issued by SIGECO, Indiana Gas, Utility Holdings, and Vectren Capital; certain plant and nonutility plant purchase commitments, and other long-term liabilities. For the three months ended March 31, 2016, there were no significant changes to the Company’s contractual obligations from those identified in the Company’s Annual Report on Form 10-K for the year ended December 31, 2015, other than those which occur in the normal and ordinary course of business and those mentioned below.

The Company’s regulated utilities have 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.  Because of the pass through nature of these costs, they have not been included in the listing of contractual obligations.

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 $202.4 million and $200.1 million for the three months endedMarch 31, 2016 and 2015, respectively. The relatively flat cash flow from operations in 2016 compared to 2015 are driven primarily by offsetting changes in certain working capital accounts due to weather. Weather related impacts include the fluctuation in the recoverable/refundable natural gas and fuel cost as well as the change in accounts receivable. Additionally a significant decrease in prepaid taxes in 2015 was due to a federal refund received in 2015 related to the timing of the extension of bonus depreciation late in 2014.

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Financing Cash Flow

Net cash flow required for financing activities was $106.2 million during the three months endedMarch 31, 2016 compared to requirements of $184.9 million in 2015. Financing activity in both periods presented reflects the payment of dividends. The decrease in cash flow required for financing activities was primarily related to less payment of short-term borrowings in first quarter 2016 compared to the first quarter of 2015. This decrease was partially offset by a retirement of an increased amount of long-term debt in the current period.

Investing Cash Flow

Cash flow required for investing activities was $108.3 million and $84.5 million during the three months endedMarch 31, 2016 and 2015, respectively.  The primary use of cash in both periods reflects expenditures for utility and nonutility capital expenditures.

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.

• New legislation, litigation and government regulation, such as changes in or additions to tax laws or rates, pipeline safety regulation and environmental laws, including laws governing air emissions, including carbon, waste water discharges and the handling and disposal of coal combustion residuals that could impact the continued operation, and/or cost recovery of our generation plants and related assets. These compliance costs could substantially change the nature of the Company's generation fleet.

• Catastrophic events such as fires, earthquakes, explosions, floods, ice storms, tornadoes, terrorist acts, physical attacks, 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, interpretation of regulatory-related legislation by the IURC and/or PUCO and appellate courts that review decisions issued by the agencies, 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; economic impacts of changes in business

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strategy on both gas and electric large customers; lower residential and commercial customer counts; higher operating expenses; and further reductions in the value of certain nonutility investments.

• 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.

• The performance of projects undertaken by the Company’s nonutility businesses and the success of efforts to realize value from, invest in and develop new opportunities, including but not limited to, the Company’s Infrastructure Services, Energy Services, and remaining ProLiance Holdings assets.

• Factors affecting Infrastructure Services, including the level of success in bidding contracts; fluctuations in volume of contracted work; unanticipated cost increases in completion of the contracted work; funding requirements associated with multiemployer pension and benefit plans; changes in legislation and regulations impacting the industries in which the customers served operate; the effects of weather; failure to properly estimate the cost to construct projects; the ability to attract and retain qualified employees in a fast growing market where skills are critical; cancellation and/or reductions in the scope of projects by customers; credit worthiness of customers; ability to obtain materials and equipment required to perform services; and changing market conditions, including changes in the market prices of oil and natural gas that would affect the demand for infrastructure construction.

• Factors affecting Energy Services, including unanticipated cost increases in completion of the contracted work; changes in legislation and regulations impacting the industries in which the customers served operate; changes in economic influences impacting customers served; failure to properly estimate the cost to construct projects; risks associated with projects owned or operated; failure to appropriately design, construct, or operate projects; the ability to attract and retain qualified employees; cancellation and/or reductions in the scope of projects by customers; changes in the timing of being awarded projects; credit worthiness of customers; lower energy prices negatively impacting the economics of performance contracting business; and changing market conditions.

• 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.

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 interest rates, counter-party credit, and commodity prices.  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.

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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 2015 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, 2016, 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, 2016, 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, 2016, 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.

PART II

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, and 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 and moved to dismiss the case. In April 2016, the court dismissed part of the compliant but allowed the remaining claims to proceed.

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 2015 Form 10-K and are therefore not presented herein.

47

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

Periodically, the Company purchases shares from the open market to satisfy share requirements associated with the Company’s share-based compensation plans; however, no such open market purchases were made during the quarter ended March 31, 2016.

ITEM 3.  DEFAULTS UPON SENIOR SECURITIES

Not Applicable

ITEM 4.  MINE SAFETY DISCLOSURES

Not Applicable

ITEM 5.  OTHER INFORMATION

Not Applicable

ITEM 6.  EXHIBITS

Exhibits and Certifications

31.1	Certification Pursuant To Section 302 of The Sarbanes-Oxley Act Of 2002- Chief Executive Officer
31.2	Certification Pursuant To Section 302 of The Sarbanes-Oxley Act Of 2002- Chief Financial Officer
32	Certification Pursuant To Section 906 of The Sarbanes-Oxley Act Of 2002
101	Interactive Data File
101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema
101.CAL	XBRL Taxonomy Extension Calculation Linkbase
101.DEF	XBRL Taxonomy Extension Definition Linkbase
101.LAB	XBRL Taxonomy Extension Labels Linkbase
101.PRE	XBRL Taxonomy Extension Presentation Linkbase

48

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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 CORPORATION
	Registrant
May 10, 2016	/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)

49

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 Corporation;

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 10, 2016

/s/ Carl L. Chapman

Carl L. Chapman

Chairman, President, and 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 Corporation;

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 10, 2016

/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 Corporation.

Signed this 10th day of May, 2016.

/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	Chairman, President, and Chief Executive Officer
(Title)	(Title)

XML

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2016	Apr. 29, 2016
Document and Entity Information [Abstract]
Entity Registrant Name	VECTREN CORP
Entity Central Index Key	0001096385
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-Q
Document Period End Date	Mar. 31, 2016
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	Q1
Amendment Flag	false
Entity Common Stock, Shares Outstanding		82,806,031

XML

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Current Assets [Abstract]
Cash & cash equivalents	$ 62.6	$ 74.7
Accounts receivable - less reserves of $6.6 & $5.6, respectively	176.5	227.5
Accrued unbilled revenues	104.0	142.5
Inventories	122.6	133.7
Recoverable fuel & natural gas costs	8.9	0.0
Prepayments & other current assets	47.1	81.0
Total current assets	521.7	659.4
Utility Plant [Abstract]
Original cost	6,172.1	6,090.4
Less: accumulated depreciation & amortization	2,454.0	2,415.5
Net utility plant	3,718.1	3,674.9
Investments in unconsolidated affiliates	20.7	20.9
Other utility & corporate investments	30.2	31.2
Other nonutility investments	16.2	16.2
Nonutility plant - net	424.6	414.6
Goodwill	293.5	293.5
Regulatory assets	257.7	249.4
Other assets	40.5	39.9
TOTAL ASSETS	5,323.2	5,400.0
Current Liabilities [Abstract]
Accounts payable	213.0	248.8
Refundable fuel & natural gas costs	0.0	7.9
Accrued liabilities	183.1	183.6
Short-term borrowings	0.0	14.5
Current maturities of long-term debt	13.0	73.0
Total current liabilities	409.1	527.8
Long-term Debt - Net of Current Maturities	1,713.2	1,712.9
Deferred Credits & Other Liabilities [Abstract]
Deferred income taxes	827.9	805.4
Regulatory liabilities	440.7	433.9
Deferred credits & other liabilities	231.9	236.2
Total deferred credits & other liabilities	$ 1,500.5	$ 1,475.5
Common Shareholders' Equity [Abstract]
Commitments & Contingencies (Notes 7-11)
Common stock (no par value) – issued & outstanding 82.8 & 82.8, respectively	$ 724.3	$ 722.8
Retained earnings	977.3	962.2
Accumulated other comprehensive (loss)	(1.2)	(1.2)
Total common shareholders' equity	1,700.4	1,683.8
TOTAL LIABILITIES & SHAREHOLDERS' EQUITY	$ 5,323.2	$ 5,400.0

XML

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) - USD ($) shares in Millions, $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Current Assets [Abstract]
Reserves	$ 6.6	$ 5.6
Common Shareholders' Equity [Abstract]
Common Stock, Shares, Issued	82.8	82.8
Common Stock, Shares, Outstanding	82.8	82.8

XML

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited) - USD ($) shares in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
OPERATING REVENUES [Abstract]
Gas utility	$ 281.2	$ 352.9
Electric utility	142.1	153.9
Nonutility	161.5	199.4
Total operating revenues	584.8	706.2
OPERATING EXPENSES [Abstract]
Cost of gas sold	111.6	172.0
Cost of fuel & purchased power	44.2	50.1
Cost of nonutility revenues	55.3	64.3
Other operating	200.0	231.1
Depreciation & amortization	63.9	62.9
Taxes other than income taxes	17.6	19.7
Total operating expenses	492.6	600.1
OPERATING INCOME	92.2	106.1
OTHER INCOME [Abstract]
Equity in earnings (losses) of unconsolidated affiliates	(0.2)	0.0
Other income - net	5.7	5.6
Total other income	5.5	5.6
INTEREST EXPENSE	22.1	21.0
INCOME BEFORE INCOME TAXES	75.6	90.7
INCOME TAXES	27.3	33.7
NET INCOME AND COMPREHENSIVE INCOME	$ 48.3	$ 57.0
AVERAGE COMMON SHARES OUTSTANDING	82.8	82.6
DILUTED COMMOM SHARES OUTSTANDING	82.8	82.6
BASIC AND DILUTED EARNINGS PER SHARE OF COMMON STOCK
BASIC	$ 0.58	$ 0.69
DILUTED	0.58	0.69
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK	$ 0.40	$ 0.38

XML

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
CASH FLOWS FROM OPERATING ACTIVITES [Abstract]
Net income	$ 48.3	$ 57.0
Adjustments to reconcile net income to cash from operating activities:
Depreciation & amortization	63.9	62.9
Deferred income taxes & investment tax credits	24.3	14.6
Equity in losses of unconsolidated affiliates	0.2	0.0
Provision for uncollectible accounts	2.6	3.3
Expense portion of pension & postretirement benefit cost	1.0	1.6
Other non-cash items - net	2.8	1.6
Changes in working capital accounts [Abstract]
Accounts receivable & accrued unbilled revenues	86.9	(30.2)
Inventories	11.1	25.8
Recoverable/refundable fuel & natural gas costs	(16.8)	30.3
Prepayments & other current assets	33.3	61.2
Accounts payable, including to affiliated companies	(38.1)	(27.6)
Accrued liabilities	(0.5)	5.6
Employer contributions to pension & postretirement plans	(16.2)	(20.9)
Changes in noncurrent assets	(6.4)	11.3
Changes in noncurrent liabilities	6.0	3.6
Net cash provided by operating activities	202.4	200.1
Proceeds from:
Dividend reinvestment plan & other common stock issuances	1.5	1.6
Requirements for:
Dividends on common stock	(33.2)	(31.5)
Retirement of long-term debt	(60.0)	(5.0)
Net change in short-term borrowings	(14.5)	(150.0)
Net cash used in financing activities	(106.2)	(184.9)
Proceeds from:
Sale of assets and other collections	0.4	0.8
Requirements for:
Capital expenditures, excluding AFUDC equity	(108.7)	(85.3)
Net cash used in investing activities	(108.3)	(84.5)
Net change in cash & cash equivalents	(12.1)	(69.3)
Cash & cash equivalents at beginning of period	74.7	86.4
Cash & cash equivalents at end of period	$ 62.6	$ 17.1

XML

Organization and Nature of Operations

3 Months Ended

Mar. 31, 2016

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Organization and Nature of Operations

Organization and Nature of Operations

Vectren Corporation (the Company or Vectren), an Indiana corporation, is an energy holding company headquartered in Evansville, Indiana.  The Company’s wholly owned subsidiary, Vectren Utility Holdings, Inc. (Utility Holdings or VUHI), serves as the intermediate holding company for three public utilities:  Indiana Gas Company, Inc. (Indiana Gas or Vectren Energy Delivery of Indiana - North), Southern Indiana Gas and Electric Company (SIGECO or Vectren Energy Delivery of Indiana - South), and Vectren Energy Delivery of Ohio, Inc. (VEDO).  Utility Holdings also has other assets that provide information technology and other services to the three utilities.  Utility Holdings’ consolidated operations are collectively referred to as the Utility Group.  Both Vectren and Utility Holdings are holding companies as defined by the Energy Policy Act of 2005.  Vectren was incorporated under the laws of Indiana on June 10, 1999.

Indiana Gas provides energy delivery services to approximately 590,000 natural gas customers located in central and southern Indiana.  SIGECO provides energy delivery services to approximately 144,000 electric customers and approximately 112,000 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 319,000 natural gas customers located near Dayton in west central Ohio.

The Company, through Vectren Enterprises, Inc. (Enterprises), is involved in nonutility activities in two primary business areas: Infrastructure Services and Energy Services.  Infrastructure Services provides underground pipeline construction and repair services.  Energy Services provides energy performance contracting and sustainable infrastructure, such as renewables, distributed generation, and combined heat and power projects. Enterprises also has other legacy businesses that have investments in energy-related opportunities and services and other investments.  All of the above are collectively referred to as the Nonutility Group. Enterprises supports the Company's regulated utilities by providing infrastructure services.

XML

Basis of Presentation

3 Months Ended

Mar. 31, 2016

Basis of Presentation [Abstract]

Basis of Presentation

Basis of Presentation

The interim condensed consolidated financial statements included in this report have been prepared by the Company, without audit, as provided in the rules and regulations of the Securities and Exchange Commission and include a review of subsequent events through the date the financial statements were issued.  Certain information and note disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States have been omitted as provided in such rules and regulations.  The information in this report reflects all adjustments which are, in the opinion of management, necessary to fairly state the interim periods presented, inclusive of adjustments that are normal and recurring in nature.  These interim condensed consolidated financial statements and related notes should be read in conjunction with the Company’s audited annual consolidated financial statements for the year ended December 31, 2015, filed with the Securities and Exchange Commission on February 23, 2016, on Form 10-K.  Because of the seasonal nature of the Company’s 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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Earnings Per Share

3 Months Ended

Mar. 31, 2016

Earnings Per Share [Abstract]

Earnings Per Share

Earnings Per Share

The Company uses the two class method to calculate earnings per share (EPS).  The two class method is an earnings allocation formula that treats a participating security as having rights to earnings that otherwise would have been available to common shareholders. Under the two class method, earnings for a period are allocated between common shareholders and participating security holders based on their respective rights to receive dividends as if all undistributed book earnings for the period were distributed.  

Basic EPS is computed by dividing net income attributable to only the common shareholders by the weighted-average number of common shares outstanding for the period.  Diluted EPS includes the impact of stock options and other equity based instruments to the extent the effect is dilutive.  

The following table illustrates the basic and dilutive EPS calculations for the periods presented in these financial statements.

	Three Months Ended
	March 31,
(In millions, except per share data)	2016		2015
Numerator:
Reported net income (Numerator for Basic and Diluted EPS)	$	48.3	$	57.0
Denominator:
Weighted average common shares outstanding           (Denominator for Basic and Diluted EPS)	82.8		82.6
Basic and Diluted EPS	$	0.58	$	0.69

As of March 31, 2016, the Company no longer has any stock options outstanding. For the three months ended March 31, 2015, all stock options were dilutive and immaterial. For both periods presented all equity based instruments were dilutive and immaterial.

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Excise and Utility Receipts Taxes

3 Months Ended

Mar. 31, 2016

Excise and Utility Receipts Taxes [Abstract]

Excise and Utility Receipts Taxes

Excise and Utility Receipts Taxes

Excise taxes and a portion of utility receipts taxes are included in rates charged to customers.  Accordingly, the Company records these taxes received, which totaled $9.4 million and $11.7 million in the three months ended March 31,2016 and 2015, respectively, as a component of operating revenues. Expenses associated with excise and utility receipts taxes are recorded as a component of Taxes other than income taxes.

XML

Retirement Plans and Other Postretirement Benefits

3 Months Ended

Mar. 31, 2016

Pension and Other Postretirement Benefit Expense [Abstract]

Retirement Plans and Other Postretirement Benefits

Retirement Plans & Other Postretirement Benefits

The Company maintains three closed qualified defined benefit pension plans, a nonqualified supplemental executive retirement plan (SERP), and a postretirement benefit plan.  The defined benefit pension plans and postretirement benefit plan, which cover eligible full-time regular employees, are primarily noncontributory.  The postretirement health care and life insurance plans are a combination of self-insured and fully insured plans.  The qualified pension plans and the SERP plan are aggregated under the heading “Pension Benefits.”  The postretirement benefit plan is presented under the heading “Other Benefits.”

Net Periodic Benefit Costs

A summary of the components of net periodic benefit cost follows and the amortizations shown below are primarily reflected in Regulatory assets as a majority of pension and other postretirement benefits are being recovered through rates.

	Three Months Ended
	March 31,
	Pension Benefits						Other Benefits
(In millions)	2016			2015			2016			2015
Service cost	$	1.8		$	2.0		$	0.1		$	0.1
Interest cost	3.6			3.6			0.4			0.5
Expected return on plan assets	(5.7		)	(5.6		)	—			—
Amortization of prior service cost	0.1			0.2			(0.7		)	(0.7		)
Amortization of actuarial loss	1.8			2.1			—			0.1
Net periodic cost (benefit)	$	1.6		$	2.3		$	(0.2	)	$	—

Employer Contributions to Qualified Pension Plans

As of March 31, 2016, the Company has made $15 million in contributions to its qualified pension plans.

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Supplemental Cash Flow Information

3 Months Ended

Mar. 31, 2016

Supplemental Cash Flow Information [Abstract]

Supplemental Cash Flow Information

Supplemental Cash Flow Information

As of March 31, 2016 and December 31, 2015, the Company has accruals related to utility and nonutility plant purchases totaling approximately $16.9 million and $19.4 million, respectively.

XML

ProLiance Holdings, LLC

3 Months Ended

Mar. 31, 2016

Equity Method Investments and Joint Ventures [Abstract]

ProLiance Holdings, LLC

ProLiance Holdings, LLC

The Company has an investment in ProLiance Holdings, LLC (ProLiance or ProLiance Holdings), an affiliate of the Company and Citizens Energy Group (Citizens). On June 18, 2013, ProLiance exited the natural gas marketing business through the disposition of certain of the net assets, along with the long-term pipeline and storage commitments, of its energy marketing business, ProLiance Energy, LLC (ProLiance Energy), to a subsidiary of Energy Transfer Partners, ETC Marketing, Ltd (ETC). Other minor operating results of the remaining ProLiance investments are reflected in Other Businesses. The Company's remaining investment in ProLiance relates primarily to an investment in LA Storage, LLC (LA Storage).  Consistent with its ownership percentage, the Company is allocated 61 percent of ProLiance’s profits and losses; however, governance and voting rights remain at 50 percent for each member, and therefore, the Company accounts for its investment in ProLiance using the equity method of accounting.

The Company's investment at March 31, 2016, shown at its 61 percent ownership share of the individual net assets of ProLiance, is as follows.

	As of
	March 31,
(In millions)	2016
Cash	$	2.5
Investment in LA Storage	22.0
Other midstream asset investment	5.0
Total investment in ProLiance	$	29.5
Included in:
Investments in unconsolidated affiliates	19.4
Other nonutility investments	10.1

LA Storage

ProLiance Transportation and Storage, LLC (PT&S), a subsidiary of ProLiance, and Sempra Energy International (SEI), a subsidiary of Sempra Energy (SE), through a joint venture, have a 100 percent interest in a development project for salt-cavern natural gas storage facilities known as LA Storage.  PT&S is the minority member with an approximate 25 percent interest, which it accounts for using the equity method.  The project, which includes a pipeline system, is expected to include 12-19 Bcf of storage capacity, and has the potential for further expansion. This pipeline system is currently connected with several interstate pipelines, including the Cameron Interstate Pipeline operated by Sempra Pipelines & Storage, and will connect area liquefied natural gas regasification terminals to an interstate natural gas transmission system and storage facilities. 

Approximately 12 Bcf of the storage, which comprises three of the four FERC certified caverns, is fully tested but additional work is required to further develop the caverns. The timing and extent of development of these caverns is dependent on market conditions, including pricing, need for storage capacity, and development of the liquefied natural gas market, among other factors. To date, development activity has been modest due to current low demand for storage facilities. The development of the storage market and related pricing are critical assumptions in the analysis of the recoverability of the investment's carrying value. As of March 31, 2016 and December 31, 2015, ProLiance's investment in the joint venture was $36.1 million and $36.4 million, respectively.

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Commitments and Contingencies

3 Months Ended

Mar. 31, 2016

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments & Contingencies

Performance Guarantees & Product Warranties

In the normal course of business, wholly owned subsidiaries, such as Energy Systems Group (ESG), a subsidiary of the Energy Services operating segment, issue payment and performance bonds and other forms of assurance that commit them to timely install infrastructure, operate facilities, pay vendors and subcontractors, and support warranty obligations.  

Specific to ESG, in its role as a general contractor in the performance contracting industry, at March 31, 2016, there are 38 open surety bonds supporting future performance.  The average face amount of these obligations is $10.4 million, and the largest obligation has a face amount of $51.0 million.  The maximum exposure from these obligations is limited to the level of uncompleted work and further limited by bonds issued to ESG by various subcontractors. At March 31, 2016, approximately 54 percent of work was yet to be completed on projects with open surety bonds.  A significant portion of these open surety bonds will be released within one year.  In instances where ESG operates facilities, project guarantees extend over a longer period.  In addition to its performance obligations, ESG also warrants the functionality of certain installed infrastructure generally for one year and the associated energy savings over a specified number of years.  

Based on a history of meeting performance obligations and installed products operating effectively, no liability or cost has been recognized for the periods presented. Since inception, ESG has only had to pay an immaterial amount for payment and performance obligations.

Corporate Guarantees

The Company issues parent level guarantees to certain vendors and customers of its wholly owned subsidiaries.  These guarantees do not represent incremental consolidated obligations; rather, they represent parental guarantees of subsidiary obligations in order to allow those subsidiaries the flexibility to conduct business without posting other forms of collateral.   At March 31, 2016, parent level guarantees support a maximum of $245 million of ESG’s performance contracting commitments, warranty obligations, project guarantees, and energy savings guarantees.

Further, an energy facility operated by ESG and managed by Keenan Ft. Detrick Energy, LLC (Keenan), is governed by an operations agreement. All payment obligations to Keenan under this agreement are also guaranteed by the Company. The Company guarantee of the Keenan Ft. Detrick Energy operations agreement does not state a maximum guarantee. Due to the nature of work performed under this contract, the Company cannot estimate a maximum potential amount of future payments.

In addition, the Company also has other guarantees outstanding, including letters of credit, supporting other consolidated subsidiary operations.

While there can be no assurance that the Company guarantee provisions will not be called upon, no such provisions have been called on historically, and further, the Company believes that the likelihood of a material amount being triggered under any of these provisions is remote.

Commitments

The Company's regulated utilities have 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 condition, results of operations or cash flows.

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Gas Rate & Regulatory Matters

3 Months Ended

Mar. 31, 2016

Public Utilities, General Disclosures [Abstract]

Gas Rate and Regulatory Matters

Gas Rate & Regulatory Matters

Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement

The Company monitors and maintains its natural gas distribution system to ensure natural gas is delivered in a safe and efficient manner. The Company's natural gas utilities are currently engaged in programs to replace bare steel and cast iron infrastructure and other activities in both Indiana and Ohio to mitigate risk, improve the system, and comply with applicable regulations, many of which are a result of federal pipeline safety requirements. Laws passed in both Indiana and Ohio provide utilities the opportunity to timely recover costs of federally mandated projects and other infrastructure improvement projects outside of a base rate proceeding.

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

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

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

Indiana Recovery and Deferral Mechanisms

The Company's Indiana natural gas utilities received Orders in 2008 and 2007 associated with the most recent base rate cases. These Orders authorized the deferral of financial impacts associated with bare steel and cast iron replacement activities. The Orders provide for the deferral of depreciation and post-in-service carrying costs on qualifying projects totaling $20 million annually at Indiana Gas and $3 million annually at SIGECO. The debt-related post-in-service carrying costs are 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, 2016 and December 31, 2015, the Company has regulatory assets totaling $20.6 million and $19.9 million, respectively, associated with the deferral of depreciation and debt-related post-in-service carrying cost activities. Beginning in 2014, all bare steel and cast iron replacement activities are now part of the Company’s seven-year capital investment plan filed pursuant to Senate Bill 251 and 560, discussed further below.

Requests for Recovery under Indiana Regulatory Mechanisms

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

Subsequent to the August 2014 Order, the Company filed and received Orders on three semi-annual updates, which recover in rates investments associated with the approved programs. In October 2015, the Company submitted its third semi-annual filing, seeking approval of the recovery in rates of investments made through June 30, 2015, and updates to the approved seven-year capital investment plan, now proposed at more than $950 million through 2020, of which $294 million has been spent as of March 31, 2016. On March 30, 2016, the IURC issued an Order (March 2016 Order) re-approving the majority of the Company’s gas infrastructure modernization projects requested in the third update of the Plan, and approving the inclusion in rates of actual investments made through June 30, 2015. Specifically, one project that was excluded for recovery under the Plan is a 20-mile transmission line and other related investments required to support industrial customer growth and ongoing system reliability in the Lafayette, Indiana area. The IURC stated because the project was not in the original plan filed in 2013, it does not qualify for cost recovery under this law. The IURC did pre-approve the project for rate base inclusion upon the filing of the next base rate case. The Company believes that such plan updates should be expected to accommodate new projects that emerge during the term of the plan as ongoing risk assessments determine that new projects are required. The Company filed an appeal of the Order on April 29, 2016 to challenge the IURC's limitation of the scope of the Plan updates. The outcome of the appeal is expected in approximately one year. Through the March 2016 Order, approximately $890 million of the proposed capital spend through 2020 has been approved through the recovery mechanisms supporting these filings.

At March 31, 2016 and December 31, 2015, the Company has regulatory assets totaling $32.8 million and $28.6 million, respectively, associated with the return on investment as well as the deferral of depreciation and other operating expenses.

Ohio Recovery and Deferral Mechanisms

The PUCO Order approving the Company's 2009 base rate case in the Ohio service territory authorized a distribution replacement rider (DRR). The DRR's primary purpose is recovery of investments in utility plant and related operating expenses associated with replacing bare steel and cast iron pipelines and certain other infrastructure. This rider is updated annually for qualifying capital expenditures and allows for a return on those capital expenditures based on the rate of return approved in the 2009 base rate case. In addition, deferral of depreciation and the ability to accrue debt-related post-in-service carrying costs is also allowed until the related capital expenditures are included in the DRR. The Order also initially established a prospective bill impact evaluation on the annual deferrals. Due to the expiration of the initial five-year term for the DRR in early 2014, the Company filed a request in August 2013 to extend and expand the DRR. On February 19, 2014, the PUCO issued an Order approving a Stipulation entered into by the PUCO Staff and the Company which provided for the extension of the DRR for the recovery of costs incurred through 2017 and expanded the types of investment covered by the DRR to include recovery of 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, the plan 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 August 26, 2015, the Company received an Order approving its adjustment to the DRR for recovery of costs incurred through December 31, 2014. In total, the Company has made capital investments under this rider totaling $208.5 million as of March 31, 2016. Regulatory assets associated with post-in-service carrying costs and depreciation deferrals were $19.7 million and $18.2 million at March 31, 2016 and December 31, 2015, respectively.

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 two-year time frame.

The PUCO has also issued Orders approving the Company's filings under Ohio House Bill 95. These Orders approve deferral of the Company’s Ohio capital expenditure program for items not covered by the DRR as well as expenditures necessary to comply with PUCO rules, regulations, orders, and system expansion to some new customers. Ohio House Bill 95 Orders also have established a prospective bill impact evaluation on the cumulative deferrals, limiting the total deferrals at a level which would equal $1.50 per residential and small general service customer per month. As of March 31, 2016, the Company's deferrals have not reached this bill impact cap. The Company submitted its most recent annual filing on May 2, 2016, which covers the Company’s capital expenditure program through calendar year 2016. The Company expects an order later this year.

Pipeline and Hazardous Materials Safety Administration (PHMSA)

On March 18, 2016, PHMSA published a notice of proposed rulemaking (NPRM) on the safety of gas transmission and gathering lines.  The proposed rule addresses many of the remaining requirements from the 2011 Pipeline Safety Act and sets out more stringent requirements than anticipated. The comment period on the NPRM ends on July 7, 2016. The Company is evaluating the impact the proposed rules would have on the Company's transmission integrity management program and the design, construction, and repair of transmission pipeline assets, including the potential for additional capital expenditures and increase in operation and maintenance expense. The Company believes that such compliance costs would be considered a federally mandated cost of providing natural gas, and therefore, should be recoverable from customers under Senate Bill 251 as referenced above.

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Electric Rate and Regulatory Matters

3 Months Ended

Mar. 31, 2016

Public Utilities, General Disclosures [Abstract]

Electric Rate and Regulatory Matters

Electric Rate & Regulatory Matters

SIGECO Electric Environmental Compliance Filing

On January 28, 2015, the IURC issued an Order (January Order) approving the Company’s request for approval of capital investments on its coal-fired generation units to comply with new EPA mandates related to mercury and air toxic standards (MATS) effective in 2015 and to address an outstanding Notice of Violation (NOV) from the EPA. As of March 31, 2016, approximately $30 million has been spent on equipment to control mercury in both air and water emissions, and $32 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 $75 million and $85 million. The Order approved the Company’s request for deferred accounting treatment, as supported by provisions under Indiana Senate Bill 29 (Senate Bill 29) and Senate Bill 251. The accounting treatment includes the deferral of depreciation and property tax expense related to these investments, accrual of post-in-service carrying costs, and deferral of incremental operating expenses related to compliance with these standards. The initial phase of the projects went into service in 2014, with the remaining investment occurring in 2015 and 2016. As of March 31, 2016, the Company has approximately $3.5 million deferred related to depreciation, property tax, and operating expense, and $1.4 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. In June 2015, Joint Appellants’ Citizens Action Coalition of Indiana, Inc., Sierra Club, Inc., and Valley Watch, Inc. (the appellants) filed a brief which challenged the sufficiency of the findings in the IURC's January Order approving the Company’s investments and proposed accounting treatment in terms of whether that Order made certain findings required by statute. On October 29, 2015, the Indiana Court of Appeals issued its opinion affirming the IURC’s findings with regard to equipment required to comply with MATS and certain national pollutant discharge elimination system rules (approximately $35 million). The Court remanded the case back to the IURC so that it can make the findings required by statute with regard to equipment required by the NOV (approximately $40 million). On February 12, 2016, the appellants filed a petition to reopen the evidentiary record in the case in order to submit additional evidence. The Company has opposed the motion and believes the IURC already has a sufficient record in this case. As it pertains to the equipment required by the NOV, given the Commission’s previous approval of this project, the Company believes the Commission will issue a new order in support of the project. The Company anticipates that the IURC will rule on the motion in the near future.

SIGECO Electric Demand Side Management (DSM) Program Filing

On August 31, 2011, the IURC issued an Order approving an initial three-year DSM plan in the SIGECO electric service territory that complied with the IURC’s energy saving targets. Consistent with the Company’s proposal, the Order approved, among other items, the following: 1) recovery of costs associated with implementing the DSM Plan; 2) the recovery of a performance incentive mechanism based on measured savings related to certain DSM programs; and 3) lost margin recovery associated with the implementation of DSM programs for large customers. On June 20, 2012, the IURC issued an Order approving a small customer lost margin recovery mechanism, inclusive of all previous deferrals. For the three months ended March 31, 2016 and 2015, the Company recognized electric utility revenue of $2.6 million and $2.3 million, respectively, associated with this approved lost margin recovery mechanism.

On March 28, 2014, Indiana Senate Bill 340 was signed into law. This legislation ended electric DSM programs on December 31, 2014 that had been conducted to meet the energy savings requirements established by the IURC in 2009. The legislation also allows for industrial customers to opt out of participating in energy efficiency programs. As of January 1, 2015, approximately 80 percent of the Company’s eligible industrial load has opted out of participation in the applicable energy efficiency programs. The Company filed a request for IURC approval of a new portfolio of DSM programs on May 29, 2014 to be offered in 2015. On October 15, 2014, the IURC issued an Order approving a Settlement between the OUCC and the Company regarding the new portfolio of DSM programs effective January 2015, and new programs were implemented during the first quarter of 2015.

On May 6, 2015, Indiana's governor signed Indiana Senate Bill 412 (Senate Bill 412) into law requiring electricity suppliers to submit energy efficiency plans to the IURC at least once every three years. Senate Bill 412 also permits the recovery of all program costs, including lost revenues and financial incentives associated with those plans and approved by the IURC. The Company made its first filing pursuant to this bill in June 2015, which proposed energy efficiency programs for calendar years 2016 and 2017. In September 2015, the Company received an Order to continue offering and recovering the associated cost of its 2015 programs until March 31, 2016. In October 2015, the OUCC and Citizens Action Coalition of Indiana filed testimony recommending the rejection of the Company’s plan, contending it was not reasonable under the terms of Senate Bill 412 due to the program design and the Company’s proposal to recover lost revenues and incentives associated with the measures. Vectren filed rebuttal testimony in October 2015 defending the plan’s compliance with Senate Bill 412.

On March 23, 2016, the IURC issued an Order approving the Company’s 2016-2017 energy efficiency programs. The Order provides for cost recovery of program and administrative expenses and includes performance incentives for reaching energy savings goals. The Order also included a lost margin recovery mechanism that now limits that recovery related to new programs to the shorter of four years or the life of the installed energy efficiency measure. Prior electric energy efficiency orders did not limit lost margin recovery to this four year limit. This ruling follows two other recent IURC decisions implementing the same recovery cap with respect to other electric utilities in Indiana. The Company is committed to continuing to promote and drive participation in its 2016-2017 energy efficiency programs and beyond and has therefore appealed this lost margin recovery restriction.

FERC Return on Equity (ROE) Complaints

On November 12, 2013, certain parties representing a group of industrial customers filed a joint complaint with the FERC under Section 206 of the Federal Power Act against the MISO and various MISO transmission owners, including SIGECO. The joint parties seek to reduce the 12.38 percent ROE used in the MISO transmission owners’ rates, including SIGECO’s formula transmission rates, to 9.15 percent, and to set a capital structure in which the equity component does not exceed 50 percent. A second customer complaint case was filed on February 11, 2015 as the maximum FERC-allowed refund period for the November 12, 2013 case ended February 11, 2015. As of March 31, 2016, the Company had invested approximately $157.7 million in qualifying projects. The net plant balance for these projects totaled $139.4 million at March 31, 2016.

These joint complaints are similar to a complaint against the New England Transmission Owners (NETO) filed in September 2011, which requested that the 11.14 percent incentive return granted on qualifying investments in NETO be lowered. On October 16, 2014, the FERC issued an Order in the NETO case approving a 10.57 percent return on equity and a calculation methodology.

The FERC acknowledged that the pending complaint raised against the MISO transmission owners is reasonable and denied the portion of the complaint addressing the equity component of the capital structure. An initial decision from its administrative law judge was received on December 22, 2015, authorizing the transmission owners to collect a Base ROE of 10.32 percent from November 12, 2013 through February 11, 2015 (the “first refund period”). The FERC is expected to rule on the proposed order in late 2016. A procedural schedule has been established for the second customer complaint case, establishing a target date of June 30, 2016 for the initial decision.

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

The Company has established a reserve considering both the initial decision and the approved 50 basis points adder.

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Environmental Matters

3 Months Ended

Mar. 31, 2016

Environmental Matters Disclosure [Abstract]

Environmental Matters

Environmental Matters

The Company's utility operations and properties are subject to extensive environmental regulation pursuant to a variety of federal, state and municipal laws and regulations. These environmental regulations impose, among other things, restrictions, liabilities, and obligations in connection with the storage, transportation, treatment, and disposal of hazardous substances and limit airborne emissions from electric generating facilities including particulate matter, sulfur dioxide (SO₂), nitrogen oxide (NOx), and mercury, among others. Environmental legislation and regulation also requires that facilities, sites, and other properties associated with the Company's operations be operated, maintained, abandoned, and reclaimed to the satisfaction of applicable regulatory authorities. The Company's current costs to comply with these laws and regulations are significant to its results of operations and financial condition.

With the trend toward stricter standards, greater regulation, and more extensive permit requirements, the Company's investment in compliant infrastructure, and the associated operating costs have increased and are expected to increase in the future. Similar to the costs associated with federal mandates in the Pipeline Safety Law, Senate Bill 251 is also applicable to federal environmental mandates impacting SIGECO's electric operations.

Air Quality

Mercury and Air Toxics (MATS) Rule

On December 21, 2011, the EPA finalized the utility MATS rule. The MATS rule sets emission limits for hazardous air pollutants for existing and new coal-fired power plants and identifies the following broad categories of hazardous air pollutants: mercury, non-mercury hazardous air pollutants (primarily arsenic, chromium, cobalt, and selenium), and acid gases (hydrogen cyanide, hydrogen chloride, and hydrogen fluoride). The rule imposes mercury emission limits for two sub-categories of coal and proposed surrogate limits for non-mercury and acid gas hazardous air pollutants.

In July 2014, a coalition of twenty-one states, including Indiana, filed a petition with the U.S. Supreme Court seeking review of the decision of the appellate court that found the EPA appropriately based its decision to list coal and oil fired generation units as a source of the pollutants at issue solely on those pollutants’ impact on public health. On June 29, 2015, the U.S. Supreme Court reversed the appellate court decision on the basis of the EPA’s failure to consider costs before determining whether it was appropriate and necessary to regulate steam electric generating units under Section 112 of the Clean Air Act. The Court did not vacate the rule, but remanded the MATS rule back to the appellate court for further proceedings consistent with the opinion. MATS compliance was required to commence April 16, 2015, and the Company continues to operate in full compliance with the MATS rule.

Notice of Violation for A.B. Brown Power Plant

The Company received a NOV from the EPA in November 2011 pertaining to its A.B. Brown generating station. The NOV asserts when the facility was equipped with Selective Catalytic Reduction (SCR) systems, the correct permits were not obtained or the best available control technology to control incidental sulfuric acid mist was not installed. While the Company did not agree with notice, it reached a final settlement with the EPA to resolve the NOV in December 2015.

As noted previously, on January 28, 2015, the IURC issued an Order approving the Company’s request for approval of capital investments on its coal-fired generation units to comply with new EPA mandates related to MATS effective in 2015 and to address the outstanding NOV regarding SO₃ emissions from the EPA. The total investment is estimated to be between $75 million and $85 million, roughly half of which has been spent to control mercury in both air and water emissions, and the remaining investment has been made to address the issues raised in the NOV.

In 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. In June 2015, Joint Appellants’ Citizens Action Coalition of Indiana, Inc., Sierra Club, Inc., and Valley Watch, Inc. (the appellants) filed a brief which challenged the sufficiency of the findings in the IURC's January Order approving the Company’s investments and proposed accounting treatment in terms of whether that Order made certain findings required by statute. On October 29, 2015, the Indiana Court of Appeals issued its opinion affirming the IURC’s findings with regard to equipment required to comply with MATS and certain national pollutant discharge elimination system rules (approximately $35 million). The Court remanded the case back to the IURC so that it can make the findings required by statute with regard to equipment required by the NOV (approximately $40 million). On February 12, 2016, the appellants filed a petition to reopen the evidentiary record in the case in order to submit additional evidence. The Company has opposed the motion and believes the IURC already has a sufficient record in this case. As it pertains to the equipment requirement required by the NOV, given the Commission’s previous approval of this project, the Company believes the Commission will make these findings and issue a new order in support of the project. The Company anticipates that the IURC will rule on the motion in the near future.

Ozone NAAQS

On November 26, 2014, the EPA proposed to tighten the current National Ambient Air Quality Standard (NAAQS) for ozone from the current standard of 75 parts per billion (ppb) to a level with the range of 65 to 70 ppb. On October 1, 2015, the EPA finalized a new NAAQS for ozone at the high end of the range, or 70 ppb. The EPA is expected to make final determinations as to whether a region is in attainment for the new NAAQS in 2018 based upon monitoring data from 2014-2016. While it is possible that counties in southwest Indiana could be declared in non-attainment with the new standard, and thus could have an effect on future economic development activities in the Company's service territory, the Company does not anticipate any significant compliance cost impacts from the determination given its previous investment in SCR technology for NOx control on its units.

One Hour SO2 NAAQS

On February 16, 2016, the EPA notified states of the commencement of a 120 day consultation period between the state and the EPA with respect to the EPA's recommendations for new non-attainment designations for the 2010 One Hour SO2 NAAQS. Identified on the list was Posey County, Indiana, in which the Company's A.B. Brown Generating Station is located. While the Company is in compliance with all applicable SO2 limits in its permits, the Company is currently working with the state of Indiana on voluntary measures that the Company may take without significant incremental costs to ensure that Posey County remains in attainment with the 2010 One Hour SO2 NAAQS. The Company's coal-fired generating fleet is 100 percent scrubbed for SO2 and 90 percent controlled for NOx.

Coal Ash Waste Disposal, Ash Ponds and Water

Coal Combustion Residuals Rule

In December 2014, the EPA released its final Coal Combustion Residuals (CCR) rule which regulates ash as non-hazardous material under Subtitle D of the Resource Conservation and Recovery Act (RCRA). On April 17, 2015, the final rule was published in the Federal Register. The final rule allows beneficial reuse of ash and the majority of the ash generated by the Company’s generating plants will continue to be reused. As it relates to the CCR rule, legislation is currently being considered by Congress that would provide for enforcement of the federal program by states rather than through citizen suits. Additionally, the CCR rule is currently being challenged by multiple parties in judicial review proceedings. Opening briefs were filed by those parties in December of 2015, with full briefing not expected to be complete until later in May 2016.

Under the final CCR rule, the Company is required to complete a series of integrity assessments, including seismic modeling given the Company’s facilities are located within two seismic zones, and groundwater monitoring studies to determine the remaining service life of the ponds and whether a pond must be retrofitted with liners or closed in place, with bottom ash handling conversions completed. In late 2015, using general utility industry data, the Company prepared cost estimates for the retirement of the ash ponds at the end of their useful lives, based on its interpretation of the closure alternatives contemplated in the final rule. The resulting estimates ranged from approximately $35 million to $80 million. These estimates contemplated final capping and monitoring costs of the ponds at both F.B. Culley and A.B. Brown generating stations. These rules have not been applicable to the Company's Warrick generating unit, as this unit has historically been part of a larger generating station that predominantly serves an adjacent industrial facility. The Company is in the process of preparing site specific estimates, using engineering analyses and assumed methods of closure. Significant factors impacting the resulting cost estimates include the closure time frame and the method of closure. Further analysis and the refinement of assumptions may result in estimated costs that could be in excess of the current range of $35 million to $80 million.

At September 30, 2015, the Company recorded an approximate $25 million asset retirement obligation (ARO) and that amount is unchanged at March 31, 2016. The recorded ARO reflected the present value of the approximate $35 million in estimated costs in the range above. These assumptions and estimations are subject to change in the future and could materially impact the amount of the estimated ARO.

Effluent Limitation Guidelines (ELGs)

Under the Clean Water Act, the EPA sets technology-based guidelines for water discharges from new and existing facilities. On September 30, 2015, the EPA released final revisions to the existing steam electric ELGs setting stringent technology-based water discharge limits for the electric power industry. The EPA focused this rulemaking on wastewater generated primarily by pollution control equipment necessitated by the comprehensive air regulations, specifically setting strict water discharge limits for arsenic, mercury and selenium for scrubber waste waters. The ELGs will be implemented when existing water discharge permits for the plants are renewed, with compliance activities expected to commence within the 2018-2023 time frame. Current wastewater discharge permits for the Brown and Culley power plants expire in October and December 2016, respectively. The Company is working with Indiana regulators on permit renewals which will include a compliance schedule for ELGs. In no event will compliance with the ELGs be required prior to November 2018. The ELGs work in tandem with the recently released CCR requirements, effectively prohibiting the use of less costly lined sediment basin options for disposal of coal combustion residuals, and virtually mandate conversions to dry bottom ash handling.

Cooling Water Intake Structures

Section 316(b) of the Clean Water Act requires that generating facilities use the “best technology available” (BTA) to minimize adverse environmental impacts on a body of water. More specifically, Section 316(b) is concerned with impingement and entrainment of aquatic species in once-through cooling water intake structures used at electric generating facilities. A final rule was issued by the EPA on May 19, 2014. The final rule does not mandate cooling water tower retrofits but requires a state level case-by-case assessment of BTA for each facility. The final rule lists seven presumptive technologies which would qualify as BTA. These technologies range from intake screen modifications to cooling water tower retrofits. Ecological and technology assessment studies must be completed prior to determining BTA for the Company’s facilities. To comply, the Company believes that capital investments will likely be in the range of $4 million to $8 million.

Climate Change

On August 3, 2015, the EPA released its final Clean Power Plan (CPP) rule which requires a 32 percent reduction in carbon emissions from 2005 levels. This results in a final emission rate goal for Indiana of 1,242 lb CO2/MWh to be achieved by 2030. The new rule gives states the option of seeking a two-year extension from the deadline of September 2016 to submit a final state implementation plan (SIP). Under the CPP, states have the flexibility to include energy efficiency and other measures should it choose to implement a SIP as provided in the final rule. While states are given an interim goal (1,451 lb CO2/MWh for Indiana), the final rule gives states the flexibility to shape their own emissions reduction over the 2022-2029 time period. The final rule was published in the Federal Register on October 23, 2015 and that action was immediately followed by litigation initiated by Indiana and 23 other states as a coalition challenging the rule. In January of 2016, the reviewing court denied the states’ and other parties requests to stay the implementation of the CPP pending completion of judicial review. On January 26, 2016, 29 states and state agencies (including the 24 state coalition referenced above) filed a request for immediate stay with the U.S. Supreme Court. On February 9, 2016, the U.S. Supreme Court granted a stay to delay the regulation while being challenged in court. The stay will remain in place while the lower court concludes its review, with oral arguments to be heard in June 2016 under the existing accelerated schedule. Among other things, the stay is anticipated to delay the requirement to submit a final SIP by the September 2016 deadline. Apart from the delay, the Court's action creates additional uncertainty as to the future of the rule and presents further challenges as the Company proceeds with its integrated resource planning process later this year.

In the event that a state does not submit a SIP, the EPA also released a proposed federal implementation plan (FIP), which would be imposed on those states without an approved SIP. The proposed FIP would apply an emission rate requirement directly on generating units. Under the proposed FIP, the CO2 emission rate limit for coal-fired units would start at 1,671 lbs CO2/MWh in 2022 and decrease to a final emission rate cap of 1,305 lbs CO2/MWh by 2030. While the FIP emission rate cap appears to be slightly less stringent than the state reduction goal for Indiana, the cap would apply directly to generating units and these units would not have the benefit of averaging emission rates with rates from zero-carbon sources as would be available in a SIP. Purchases of emission credits from zero-carbon sources can be made for compliance. The FIP will be subject to extensive public comments prior to finalization. Whether Indiana will file a SIP has yet to be determined. Pending that determination, the electric utilities in Indiana will continue to encourage the state's designated agency to analyze various compliance options and the possible integration into a state plan submittal.

At the time of release of the CPP, Indiana was the 5th largest carbon emitter in the nation in tons of CO2 produced from electric generation. The Company’s share of total tons of CO2 generated by Indiana's electric utilities has historically been less than 6 percent. Since 2005, the Company has achieved a reduction in emissions of CO2 of 31 percent (on a tonnage basis) through the retirement of F.B. Culley Unit 1, expiration of municipal contracts, electric conservation, the addition of renewable generation, and the installation of more efficient dense pack turbine technology. Since emissions are further impacted by coal burn reductions and energy efficiency programs, the Company's emissions of CO2 can vary year to year. With respect to renewable generation, in 2008 and 2009, the Company executed long-term purchase power commitments for a total of 80 MW of wind energy. The Company currently has approximately 4 percent of its electricity being provided by 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 1,967 lbs CO2/MWh to 1,922 lbs CO2/MWh, for a reduction of 3 percent. The Company’s CO2 emission rate of 1,922 lbs CO2/MWh is basically the same as Indiana's average CO2 emission rate of 1,923 lbs CO2/MWh. The Company plans to consider these reductions in CO2 emissions and renewable generation in future discussions with the state to develop a possible state implementation plan.

Impact of Legislative Actions & Other Initiatives is Unknown

At this time, compliance costs and other effects associated with reductions in GHG emissions or obtaining renewable energy sources remain uncertain. The Company has gathered preliminary estimates of the costs to control GHG emissions. A preliminary investigation demonstrated costs to comply would be significant, first with regard to operating expenses and later for capital expenditures as technology becomes available to control GHG emissions. However, these compliance cost estimates were based on highly uncertain assumptions, including allowance prices if a cap and trade approach were employed, and energy efficiency targets. The Company is undertaking a detailed review of the requirements of the CPP and the proposed FIP and a review of potential compliance options. The Company will also continue to remain engaged with the Indiana legislators and regulators to assess the final rule and to develop a plan that is the least cost to its customers.

Integrated Resource Planning Process

As required by the state of Indiana, the Company is currently in the process of completing its 2016 Integrated Resource Plan (IRP). The state requires each electric utility to perform and submit an IRP that details the resources it may rely upon to provide electric service for the next twenty year period to ensure electric reliability throughout the state. During 2016, the Company will hold three public stakeholder meetings to gather input and feedback as well as communicate results of the IRP process as it progresses. The first of three public meetings was held in April 2016. A final IRP report is expected to be submitted to the IURC for review in November 2016. While the IURC reviews these reports, it does not formally approve or reject the plans.

The 2016 IRP will consider the ongoing operation of the 300 MW unit at the Warrick Power Plant (Warrick Unit 4) that SIGECO and Alcoa Generating Corporation (AGC), a subsidiary of Alcoa, Inc. (Alcoa), own as tenants in common. SIGECO's proportionate cost of the unit is included in rate base. In the first quarter of 2016, Alcoa closed its smelter operations. Historically, on-site generation owned and operated by AGC has been used to provide power to the smelter, as well as other mill operations, which will continue. Generation from Alcoa's share of Warrick Unit 4 has historically been sold into the MISO market. Alcoa's operational changes, as described above, lead to a number of uncertainties including its plans regarding the future ownership and operation of Warrick Unit 4 as well as potential environmental regulation implications under the CCR and ELG regulations. The Company is actively working with Alcoa on plans related to continued operation of their generation, anticipating that more will be known toward the end of 2016.

As it relates to water, ash, and carbon regulation, while the Company is exploring various compliance options, the Company cannot reasonably estimate the total cost to comply with the CCR, ELG and CPP regulations for its units at this time. The cost of compliance with these new regulations could be significant. The Company believes that such compliance costs would be considered a federally mandated cost of providing electricity, and therefore if incurred, should be recoverable either from customers through Senate Bill 251 as referenced above, Senate Bill 29, which was used by the Company to recover its initial pollution control investments, or through other forms of rate recovery. Addressing compliance alternatives for CCR, ELG, and CPP, including the impact on customer rates, as well as addressing the uncertainties with Warrick Unit 4, will be fully considered as part of the Company's IRP process conducted in 2016.

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 $14.8 million of the expected $15.8 million in insurance recoveries.

The costs the Company expects to incur are estimated by management using assumptions based on actual costs incurred, the timing of expected future payments, and inflation factors, among others. While the Company’s utilities have recorded all costs which they presently expect to incur in connection with activities at these sites, it is possible that future events may require remedial activities which are not presently foreseen and those costs may not be subject to PRP or insurance recovery. As of March 31, 2016 and December 31, 2015, approximately $3.0 million and $3.3 million, respectively, of accrued, but not yet spent, costs are included in Other Liabilities related to the Indiana Gas and SIGECO sites.

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Impact of Recently Issued Accounting Guidance

3 Months Ended

Mar. 31, 2016

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

Impact of Recently Issued Accounting Principles

Impact of Recently Issued Accounting Principles

Revenue Recognition Guidance

In May 2014, the FASB issued new accounting guidance to clarify the principles for recognizing revenue and to develop a common revenue standard for GAAP. The amendments in this guidance state that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This new guidance requires improved disclosures to help users of financial statements better understand the nature, amount, timing, and uncertainty of revenue that is recognized.

On July 9, 2015, the FASB approved a one year deferral that became effective through an ASU in August and changed the effective date to annual reporting periods beginning after December 15, 2017, including interim periods, with early adoption permitted, but not before the original effective date of December 15, 2016. The Company is currently evaluating the standard to determine application date, transition method, and impact the standard will have on the financial statements.

Simplifying the Presentation of Debt Issuance Costs

In April 2015, the FASB issued new accounting guidance on accounting for debt issuance costs which changes the presentation of debt issuance costs in financial statements. This ASU requires an entity to present such costs in the balance sheet as a direct 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. The guidance was adopted for March 31, 2016, and has been applied retrospectively to all periods presented. The effect of the change on the December 31, 2015 balance sheet was the reclassification of $8.6 million from regulatory assets to long-term debt and the reclassification of $1.3 million from other assets to long-term debt. The reclassification had no material impact on the Company's financial condition, results of operations, or cash flows as a result of the adoption.

Leases

In February 2016, the FASB issued new accounting guidance for the recognition, measurement, presentation and disclosure of leasing arrangements. This ASU requires the recognition of lease assets and liabilities for those leases currently classified as operating leases while also refining the definition of a lease. In addition, lessees will be required to disclose key information about the amount, timing, and uncertainty of cash flows arising from leasing arrangements. This ASU is effective for the interim and annual reporting periods beginning January 1, 2019, although it can be early adopted, with a modified retrospective approach for leases that commenced prior to the date of adoption. The Company is currently evaluating the standard to determine the impact it will have on the financial statements.

Stock Compensation

In March 2016, the FASB issued new accounting guidance which is intended to simplify several aspects of accounting for share-based payment transactions, including the income tax consequences. This ASU is effective for annual periods beginning after December 15, 2016, and interim periods therein. Early application is permitted. The Company is currently evaluating the standard to determine the impact it will have on the financial statements, if any.

Management believes that other recently issued standards, which are not yet effective, will not have a material impact on the Company's financial condition, results of operations, or cash flows upon adoption.

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Fair Value Measurements

3 Months Ended

Mar. 31, 2016

Fair Value Disclosures [Abstract]

Fair Value Measurements

Fair Value Measurements

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

	March 31, 2016				December 31, 2015
(In millions)	Carrying Amount		Est. Fair Value		Carrying Amount		Est. Fair Value
Long-term debt	$	1,726.2	$	1,881.4	$	1,785.9	$	1,899.6
Short-term borrowings	—		—		14.5		14.5
Cash & cash equivalents	62.6		62.6		74.7		74.7
Restricted cash	5.9		5.9		5.9		5.9

For the balance sheet dates presented in these financial statements, the Company had no material assets or liabilities marked to fair value.

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

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

Because of the nature of certain other investments and lack of a readily available market, it is not practical to estimate the fair value of these financial instruments at specific dates without considerable effort and cost.  At March 31, 2016 and December 31, 2015, the fair value for these financial instruments was not estimated.  The carrying value of these investments at March 31, 2016 and December 31, 2015 was approximately $16.2 million, and is included in Other nonutility investments.

The Company has reclassified its debt issuance costs, in accordance with ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs. The adoption of the accounting standard update changes the presentation of debt issuance costs in financial statements by requiring an entity to present such costs in the balance sheet as a direct deduction from the related debt liability rather than as an asset. Amortization of the costs will continue to be reported as interest expense. The guidance was adopted as of January 1, 2016, and has been applied retrospectively to all periods presented. The effect of the change on the December 31, 2015 balance sheet was the reclassification of $8.6 million from regulatory assets to long-term debt and the reclassification of $1.3 million from other assets to long-term debt. The adoption of the standard had no material impact on the Company's financial condition, results of operations, or cash flows.

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Segment Reporting

3 Months Ended

Mar. 31, 2016

Segment Reporting [Abstract]

Segment Reporting

Segment Reporting

The Company segregates its operations into three groups: 1) Utility Group, 2) Nonutility Group, and 3) Corporate and Other.

The Utility Group is comprised of Vectren Utility Holdings, Inc.’s operations, which consist of the Company’s 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 Utility Group reports three operating segments:  Gas Utility Services, Electric Utility Services, and Other operations.

The Nonutility Group reports the following segments:  Energy Services, Infrastructure Services, and Other Businesses.  Energy Services provides energy performance contracting and sustainable infrastructure, such as renewables, distributed generation, and combined heat and power projects. The Infrastructure Services segment through wholly owned subsidiaries Miller Pipeline, LLC and Minnesota Limited, LLC, provide underground pipeline construction and repair services for customers that include Vectren Utility Holdings' utilities. Fees incurred by Vectren Utility Holdings and its subsidiaries for these pipeline construction and repair services totaled $19.6 million and $17.7 million for the three months endedMarch 31, 2016 and 2015, respectively.

In 2016, the estimated depreciable lives for certain pieces of equipment at Minnesota Limited, LLC were reevaluated and extended due to a change in service life of the equipment. As a result of this evaluation, the Company extended the estimated useful life of certain pieces of equipment effective January 1 of the current year. The effect of this change in estimate is an anticipated reduction of annual depreciation expense of approximately $9.6 million in 2016.

Corporate and Other includes unallocated corporate expenses such as advertising and certain charitable contributions, among other activities, that benefit the Company’s 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)	2016			2015
Revenues
Utility Group
Gas Utility Services	$	281.2		$	352.9
Electric Utility Services	142.1			153.9
Other Operations	10.6			10.2
Eliminations	(10.5		)	(10.1		)
Total Utility Group	423.4			506.9
Nonutility Group
Infrastructure Services	112.5			176.9
Energy Services	49.4			23.1
Total Nonutility Group	161.9			200.0
Corporate & Other Group	0.1			0.2
Eliminations	(0.6		)	(0.9		)
Consolidated Revenues	$	584.8		$	706.2
Profitability Measure - Net Income (Loss)
Utility Group Net Income
Gas Utility Services	$	40.4		$	40.4
Electric Utility Services	16.6			19.2
Other Operations	4.1			3.4
Utility Group Net Income	61.1			63.0
Nonutility Group Net Income (Loss)
Infrastructure Services	(12.6		)	(2.6		)
Energy Services	0.1			(3.1		)
Other Businesses	(0.2		)	(0.2		)
Nonutility Group Net Income (Loss)	(12.7		)	(5.9		)
Corporate & Other Group Net Income (Loss)	(0.1		)	(0.1		)
Consolidated Net Income	$	48.3		$	57.0

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Earnings Per Share (Tables)

3 Months Ended

Mar. 31, 2016

Earnings Per Share [Abstract]

Basic and dilutive EPS

The following table illustrates the basic and dilutive EPS calculations for the periods presented in these financial statements.

	Three Months Ended
	March 31,
(In millions, except per share data)	2016		2015
Numerator:
Reported net income (Numerator for Basic and Diluted EPS)	$	48.3	$	57.0
Denominator:
Weighted average common shares outstanding           (Denominator for Basic and Diluted EPS)	82.8		82.6
Basic and Diluted EPS	$	0.58	$	0.69

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Retirement Plans and Other Postretirement Benefits (Tables)

3 Months Ended

Mar. 31, 2016

Pension and Other Postretirement Benefit Expense [Abstract]

Schedule of Defined Benefit Plans Disclosures [Table Text Block]

A summary of the components of net periodic benefit cost follows and the amortizations shown below are primarily reflected in Regulatory assets as a majority of pension and other postretirement benefits are being recovered through rates.

	Three Months Ended
	March 31,
	Pension Benefits						Other Benefits
(In millions)	2016			2015			2016			2015
Service cost	$	1.8		$	2.0		$	0.1		$	0.1
Interest cost	3.6			3.6			0.4			0.5
Expected return on plan assets	(5.7		)	(5.6		)	—			—
Amortization of prior service cost	0.1			0.2			(0.7		)	(0.7		)
Amortization of actuarial loss	1.8			2.1			—			0.1
Net periodic cost (benefit)	$	1.6		$	2.3		$	(0.2	)	$	—

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ProLiance Holdings, LLC (Tables)

3 Months Ended

Mar. 31, 2016

Equity Method Investments and Joint Ventures [Abstract]

Summarized Financial Information of Equity Investment [Table Text Block]

The Company's investment at March 31, 2016, shown at its 61 percent ownership share of the individual net assets of ProLiance, is as follows.

	As of
	March 31,
(In millions)	2016
Cash	$	2.5
Investment in LA Storage	22.0
Other midstream asset investment	5.0
Total investment in ProLiance	$	29.5
Included in:
Investments in unconsolidated affiliates	19.4
Other nonutility investments	10.1

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Fair Value Measurements (Tables)

3 Months Ended

Mar. 31, 2016

Fair Value Disclosures [Abstract]

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

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

	March 31, 2016				December 31, 2015
(In millions)	Carrying Amount		Est. Fair Value		Carrying Amount		Est. Fair Value
Long-term debt	$	1,726.2	$	1,881.4	$	1,785.9	$	1,899.6
Short-term borrowings	—		—		14.5		14.5
Cash & cash equivalents	62.6		62.6		74.7		74.7
Restricted cash	5.9		5.9		5.9		5.9

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Segment Reporting (Tables)

3 Months Ended

Mar. 31, 2016

Segment Reporting [Abstract]

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

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

	Three Months Ended
	March 31,
(In millions)	2016			2015
Revenues
Utility Group
Gas Utility Services	$	281.2		$	352.9
Electric Utility Services	142.1			153.9
Other Operations	10.6			10.2
Eliminations	(10.5		)	(10.1		)
Total Utility Group	423.4			506.9
Nonutility Group
Infrastructure Services	112.5			176.9
Energy Services	49.4			23.1
Total Nonutility Group	161.9			200.0
Corporate & Other Group	0.1			0.2
Eliminations	(0.6		)	(0.9		)
Consolidated Revenues	$	584.8		$	706.2
Profitability Measure - Net Income (Loss)
Utility Group Net Income
Gas Utility Services	$	40.4		$	40.4
Electric Utility Services	16.6			19.2
Other Operations	4.1			3.4
Utility Group Net Income	61.1			63.0
Nonutility Group Net Income (Loss)
Infrastructure Services	(12.6		)	(2.6		)
Energy Services	0.1			(3.1		)
Other Businesses	(0.2		)	(0.2		)
Nonutility Group Net Income (Loss)	(12.7		)	(5.9		)
Corporate & Other Group Net Income (Loss)	(0.1		)	(0.1		)
Consolidated Net Income	$	48.3		$	57.0

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Organization and Nature of Operations (Details)	3 Months Ended
	Mar. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of public utility subsidiaries owned by wholly owned subsidiary, Vectren Utility Holdings, Inc. (in number of subsidiaries)	3
Estimated number of natural gas customers located in central and southern Indiana serviced by Indiana Gas Company, Inc. (in number of customers)	590,000
Estimated number of electric customers located near Evansville in southwestern Indiana serviced by Southern Indiana Gas and Electric Company (in number of customers)	144,000
Estimated number of natural gas customers located near Evansville in southwestern Indiana serviced by Southern Indiana Gas and Electric Company (in number of customers)	112,000
Estimated number of natural gas customers located near Dayton in west central Ohio serviced by the Ohio operations (in number of customers)	319,000

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Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Numerator [Abstract]
Net income	$ 48.3	$ 57.0
Denominator [Abstract]
Weighted average common shares outstanding (Denominator for Basic EPS) (in shares)	82.8	82.6
Adjusted weighted average shares outstanding and assumed conversions outstanding (Denominator for Diluted EPS) (in shares)	82.8	82.6
Basic EPS (in dollars per share)	$ 0.58	$ 0.69
Diluted EPS (in dollars per share)	$ 0.58	$ 0.69

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Excise and Utility Receipts Taxes (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Excise and Utility Receipts Taxes [Abstract]
Excise and utility taxes collected and reported in operating revenue	$ 9.4	$ 11.7

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Retirement Plans and Other Postretirement Benefits (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Number of qualified defined benefit pension plans	3
Expected contribution to defined benefit plans for current year by employer	$ 15.0
Pension Benefits [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service cost	1.8	$ 2.0
Interest cost	3.6	3.6
Expected return on plan assets	(5.7)	(5.6)
Amortization of prior service cost	0.1	0.2
Amortization of actuarial loss	1.8	2.1
Net periodic benefit cost	1.6	2.3
Other Benefits [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service cost	0.1	0.1
Interest cost	0.4	0.5
Expected return on plan assets	0.0	0.0
Amortization of prior service cost	(0.7)	(0.7)
Amortization of actuarial loss	0.0	0.1
Net periodic benefit cost	$ (0.2)	$ 0.0

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Supplemental Cash Flow Information (Details) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Supplemental Cash Flow Information [Abstract]
Accruals related to utility and nonutility plant purchases	$ 16.9	$ 19.4

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ProLiance Holdings, LLC (Details) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Equity Method Investment, Ownership Percentage	61.00%
Equity method investment,governance and voting rights percentage (in hundredths)	50.00%
Summarized balance sheet information [Abstract]
Equity method investment, investment in equity method investee's subsidiary (ProLiance Energy)	$ 2.5
Equity method investment, investment in storage assets and cash from sale of storage assets	22.0
Equity method investment, minority interest in joint venture, investor's portion of interest	5.0
Equity method investment, gross investment in equity method investee	29.5
Investments in unconsolidated affiliates	20.7	$ 20.9
Other nonutility investments	$ 16.2	16.2
LA Storage [Member]
Combined Joint Venture Ownership Percentage	100.00%
Summarized balance sheet information [Abstract]
Equity method investment holding minority interest in equity method investment (in hundredths)	25.00%
Equity method investment minority interest in joint ventures	$ 36.1	$ 36.4
Proliance Holdings LLC [Member]
Summarized balance sheet information [Abstract]
Investments in unconsolidated affiliates	19.4
Other nonutility investments	$ 10.1

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Commitments and Contingencies (Details) $ in Millions	3 Months Ended
	Mar. 31, 2016 USD ($)
Performance Guarantees and Product Warranties [Abstract]
Product Warranty Accrual	$ 0.0
Energy Systems Group [Member]
Corporate Guarantees [Abstract]
Maximum exposure by parent company on guarantees	$ 245.0
Energy Systems Group [Member] | Performance Guarantee [Member]
Performance Guarantees and Product Warranties [Abstract]
Number of surety bonds wholly owned subsidiary has outstanding in role as general contractor (in number of surety bonds)	38
Average face amount of surety bonds wholly owned subsidiary has outstanding	$ 10.4
Maximum face amount of surety bond wholly owned subsidiary has outstanding	$ 51.0
Percentage Of Work Yet to be Completed On Projects With Open Surety Bonds	54.00%
Timeframe when significant portion of performance guarantee commitments will be fulfilled	P1Y

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Gas Rate & Regulatory Matters (Details) - USD ($)	3 Months Ended
	Mar. 31, 2016	Dec. 31, 2015
INDIANA | Indiana Recovery and Deferral Mechanisms [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Asset balance associated with Vectren north and south programs	$ 20,600,000	$ 19,900,000
Length of project plan required for recovery under new legislation	7 years
INDIANA | Senate Bill 251 and 560 [Member]
Public Utilities, General Disclosures [Line Items]
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%
Expected Seven Year Period Modernization Investment	$ 950,000,000
Project spend life to date	294,000,000
Capital Expenditure Increases	890,000,000
Regulatory Asset associated with DRR deferrals of depreciation and post in-service carrying costs	32,800,000	28,600,000
INDIANA | SIGECO [Member] | Indiana Recovery and Deferral Mechanisms [Member]
Public Utilities, General Disclosures [Line Items]
Allowable capital expenditures under Vectren programs	$ 3,000,000
Limitations of deferrals of debt-related post in service carrying costs	P3Y
INDIANA | Indiana Gas [Member] | Indiana Recovery and Deferral Mechanisms [Member]
Public Utilities, General Disclosures [Line Items]
Allowable capital expenditures under Vectren programs	$ 20,000,000
Limitations of deferrals of debt-related post in service carrying costs	P4Y
OHIO | Ohio Recovery and Deferral Mechanisms [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Asset associated with DRR deferrals of depreciation and post in-service carrying costs	$ 19,700,000	$ 18,200,000
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
Cumulative gross plant invesment made under Distribution Replacement Rider	208,500,000
OHIO | Ohio House Bill95 [Member]
Public Utilities, General Disclosures [Line Items]
Bill impact per customer per month	$ 1.50

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Electric Rate and Regulatory Matters (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Vectren South Electric Environmental Compliance Filing [Abstract]
Amount of capital investments to date in equipment for mercury control	$ 30.0
Amount of capital investments to date in equipment to control sulfur trioxide emissions	32.0
Lower range of request for approval of capital investments on coal-fired generation units	75.0
Upper range of request for approval of capital investments on coal-fired generation units	85.0
Amount of deferred costs to date related to depreciation, property tax, and operating expenses under Senate Bill 29 and Senate Bill 251	3.5
Amount of deferred costs to date related to post in-service carrying costs under Senate Bill 29 and Senate Bill 251.	1.4
Estimated cost of equipment to comply with MATS	35.0
Estimated cost of equipment required by the NOV	$ 40.0
Vectren South Electric Demand Side Management Program Filing [Abstract]
Number of Years in Initial Demand Side Management Program	3 years
Electric revenue recognized associated with lost margin recovery	$ 2.6	$ 2.3
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	$ 139.4
Incentive return granted on qualifying investments in NETO	11.14%
Percentage return approved by FERC on ROE complaint against NETO	10.57%
FERC authorized base ROE percentage for first refund period	10.32%
Number of incentive basis point above and beyond approved FERC approved ROE	50

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Environmental Matters (Details) $ in Millions	3 Months Ended
	Mar. 31, 2016 USD ($) MW	Dec. 31, 2015 USD ($)
Air Quality [Abstract]
Percentage of coal fired generating fleet currently controlled for NOx (in hundredths)	90.00%
Percentage of coal fired generating fleet currently being scrubbed for SO2 (in hundredths)	100.00%
Coal Ash Waste Disposal, Ash Ponds and Water [Abstract]
Estimated Capital Expenditures to Comply With Ash Pond and Coal Ash Disposal Regulations - Lower Range	$ 35.0
Estimated Capital Expenditures to Comply With Ash Pond and Coal Ash Disposal Regulations - Upper Range	80.0
Asset Retirement Obligation	25.0
Estimated capital expenditures to comply with Clean Water Act (Lower Range)	4.0
Estimated capital expenditures to comply with Clean Water Act (Upper Range)	$ 8.0
Climate Changes [Abstract]
Vectren's share of Indiana's CO2 emissions in 2013 (as a percent)	6.00%
Percent reduction of Vectren's CO2 emissions since 2005	31.00%
Long term contract for purchase of electric power generated by wind energy (in megawatts) | MW	80
Percentage of total electricity obtained by the supplier to meet the energy needs of its retail customers provided by clean energy sources (in hundredths)	4.00%
Vectren's emission rate (as measured in lbs CO2/MWh) prior to installation of new technology	1,967
Vectren's emission rate (as measured in lbs CO2/MWh) after installation of new technology	1,922
Percentage reduction of lbs CO2/MWh since 2005	3.00%
Manufactured Gas Plants
Site contingency, accrual, undiscounted amount	$ 43.4
Accrual for Environmental Loss Contingencies	$ 3.0	$ 3.3
Indiana Gas [Member]
Manufactured Gas Plants
Number of sites identified with potential remedial responsibility for entity (in number of sites)	26
Site contingency, accrual, undiscounted amount	$ 23.2
Environmental cost recognized, recover from insurance carriers credited to expense	$ 20.8
SIGECO [Member]
Manufactured Gas Plants
Number of sites identified with potential remedial responsibility for entity (in number of sites)	5
Site contingency, accrual, undiscounted amount	$ 20.2
Environmental cost recognized, recover from insurance carriers credited to expense	14.8
Expected Site Contingency Recovery from Insurance Carriers of Environmental Remediation Costs	$ 15.8

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Impact of Recently Issued Accounting Guidance (Details) - Accounting Standards Update 2015-03 [Member] $ in Millions	3 Months Ended
	Dec. 31, 2015 USD ($)
Impact on Regulatory Assets [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification	$ 8.6
Other Assets [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification	$ 1.3

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Fair Value Measurements (Details) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Notes Receivable, Fair Value Disclosure	$ 16.2	$ 16.2
Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	1,726.2	1,785.9
Short-term borrowings	0.0	14.5
Cash and cash equivalents	62.6	74.7
Restricted cash	5.9	5.9
Estimated Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	1,881.4	1,899.6
Short-term borrowings	0.0	14.5
Cash and cash equivalents	62.6	74.7
Restricted cash	$ 5.9	$ 5.9

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Segment Reporting (Details) $ in Millions	3 Months Ended
	Mar. 31, 2016 USD ($)	Mar. 31, 2015 USD ($)
Segment Reporting [Abstract]
Portion of Indiana that is provided natural gas distribution and transportation services by the Gas Utility Services segment (in hundredths)	66.67%
Segment Reporting Information [Line Items]
Number of operational groups	3
Revenues	$ 584.8	$ 706.2
Net income	$ 48.3	57.0
Number of reportable segments	3
Utility Group [Member]
Segment Reporting Information [Line Items]
Revenues	$ 423.4	506.9
Net income	$ 61.1	63.0
Number of reportable segments	3
Related Party Transaction, Expenses from Transactions with Related Party	$ 19.6	17.7
Utility Group [Member] | Gas Utility Services [Member]
Segment Reporting Information [Line Items]
Revenues	281.2	352.9
Net income	40.4	40.4
Utility Group [Member] | Electric Utility Services [Member]
Segment Reporting Information [Line Items]
Revenues	142.1	153.9
Net income	16.6	19.2
Utility Group [Member] | Other Segments [Member]
Segment Reporting Information [Line Items]
Revenues	10.6	10.2
Net income	4.1	3.4
Utility Group [Member] | Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues	(10.5)	(10.1)
Nonutility Group [Member]
Segment Reporting Information [Line Items]
Revenues	161.9	200.0
Net income	$ (12.7)	(5.9)
Number of reportable segments	3
Nonutility Group [Member] | Infrastructure Services [Member]
Segment Reporting Information [Line Items]
Revenues	$ 112.5	176.9
Net income	(12.6)	(2.6)
Nonutility Group [Member] | Infrastructure Services [Member] | Change in Accounting Method Accounted for as Change in Estimate [Member]
Segment Reporting Information [Line Items]
Depreciation	9.6
Nonutility Group [Member] | Energy Services [Member]
Segment Reporting Information [Line Items]
Revenues	49.4	23.1
Net income	0.1	(3.1)
Nonutility Group [Member] | Other Businesses [Member]
Segment Reporting Information [Line Items]
Net income	(0.2)	(0.2)
Corporate and Other [Member]
Segment Reporting Information [Line Items]
Revenues	0.1	0.2
Net income	$ (0.1)	(0.1)
Number of reportable segments	1
Consolidation, Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues	$ (0.6)	$ (0.9)