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EX-32 - EXHIBIT 32 - VECTREN CORPvvc6302015ex32.htm
EX-31.1 - EXHIBIT 31.1 - VECTREN CORPvvc6302015ex311.htm
EX-31.2 - EXHIBIT 31.2 - VECTREN CORPvvc6302015ex312.htm
                                                
                                                                    

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 June 30, 2015

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
 
82,663,908
 
July 31, 2015
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


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


                                                
                                                                    

Table of Contents



2

                                                
                                                                    

PART I.  FINANCIAL INFORMATION

ITEM 1.  FINANCIAL STATEMENTS


VECTREN CORPORATION AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited – In millions)

 
June 30,
2015
 
December 31,
2014
ASSETS
 
 
 
Current Assets
 
 
 
Cash & cash equivalents
$
11.3

 
$
86.4

     Accounts receivable - less reserves of $7.1 & $6.0, respectively
207.8

 
196.0

Accrued unbilled revenues
123.9

 
164.8

Inventories
112.5

 
118.5

Recoverable fuel & natural gas costs

 
9.8

Prepayments & other current assets
51.1

 
110.9

Total current assets
506.6

 
686.4

Utility Plant
 

 
 

Original cost
5,887.1

 
5,718.7

Less:  accumulated depreciation & amortization
2,352.3

 
2,279.7

Net utility plant
3,534.8

 
3,439.0

Investments in unconsolidated affiliates
23.4

 
23.4

Other utility & corporate investments
37.3

 
37.2

Other nonutility investments
31.9

 
33.6

Nonutility plant - net
401.5

 
378.0

Goodwill - net
293.6

 
289.9

Regulatory assets
243.5

 
233.6

Other assets
42.6

 
41.2

TOTAL ASSETS
$
5,115.2

 
$
5,162.3













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


3

                                                
                                                                    

VECTREN CORPORATION AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited – In millions)

 
June 30,
2015
 
December 31,
2014
LIABILITIES & SHAREHOLDERS' EQUITY
 
 
 
Current Liabilities
 
 
 
Accounts payable
$
180.8

 
$
248.9

Refundable fuel & natural gas costs
22.7

 
2.5

Accrued liabilities
173.7

 
184.9

Short-term borrowings
96.4

 
156.4

Current maturities of long-term debt
88.0

 
170.0

Total current liabilities
561.6

 
762.7

Long-term Debt - Net of Current Maturities
1,484.5

 
1,407.3

Deferred Credits & Other Liabilities
 
 
 

Deferred income taxes
769.1

 
741.2

Regulatory liabilities
424.3

 
410.3

Deferred credits & other liabilities
235.7

 
234.2

Total deferred credits & other liabilities
1,429.1

 
1,385.7

Commitments & Contingencies (Notes 7, 10-13)


 


Common Shareholders' Equity
 

 
 

     Common stock (no par value) – issued & outstanding
          82.7 & 82.6, respectively
719.1

 
715.7

Retained earnings
922.2

 
892.2

Accumulated other comprehensive (loss)
(1.3
)
 
(1.3
)
Total common shareholders' equity
1,640.0

 
1,606.6

TOTAL LIABILITIES & SHAREHOLDERS' EQUITY
$
5,115.2

 
$
5,162.3



















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



4

                                                
                                                                    

VECTREN CORPORATION AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited – In millions, except per share amounts)

 
Three Months Ended
Six Months Ended
 
June 30,
June 30,
 
2015
 
2014
2015
 
2014
OPERATING REVENUES
 
 
 
 
 
 
Gas utility
$
128.6

 
$
132.4

$
481.5

 
$
576.0

Electric utility
147.8

 
152.0

301.7

 
315.0

Nonutility
274.6

 
258.1

474.0

 
448.3

Total operating revenues
551.0

 
542.5

1,257.2

 
1,339.3

OPERATING EXPENSES
 

 
 

 

 
 

Cost of gas sold
36.4

 
43.7

208.4

 
314.6

Cost of fuel & purchased power
47.0

 
48.1

97.0

 
105.1

Cost of nonutility revenues
93.4

 
79.6

157.7

 
147.3

Other operating
225.0

 
247.9

456.2

 
455.5

Depreciation & amortization
63.7

 
75.8

126.6

 
149.6

Taxes other than income taxes
12.6

 
13.5

32.3

 
34.3

Total operating expenses
478.1

 
508.6

1,078.2

 
1,206.4

OPERATING INCOME
72.9

 
33.9

179.0

 
132.9

OTHER INCOME
 

 
 

 

 
 

Equity in earnings of unconsolidated affiliates

 
0.2


 
0.1

Other income – net
5.0

 
4.2

10.5

 
8.5

Total other income
5.0

 
4.4

10.5

 
8.6

INTEREST EXPENSE
20.9

 
21.9

41.9

 
44.0

INCOME BEFORE INCOME TAXES
57.0

 
16.4

147.6

 
97.5

INCOME TAXES
21.2

 
4.5

54.8

 
34.4

NET INCOME AND COMPREHENSIVE INCOME
$
35.8

 
$
11.9

$
92.8

 
$
63.1

AVERAGE COMMON SHARES OUTSTANDING
82.6

 
82.5

82.6

 
82.5

DILUTED COMMON SHARES OUTSTANDING
82.6

 
82.5

82.6

 
82.5

EARNINGS PER SHARE OF COMMON STOCK:
 
 
 

 
 
 

BASIC
$
0.43

 
$
0.14

$
1.12

 
$
0.76

DILUTED
$
0.43

 
$
0.14

$
1.12

 
$
0.76

DIVIDENDS DECLARED PER SHARE OF COMMON STOCK
$
0.38

 
$
0.36

$
0.76

 
$
0.72










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



5

                                                
                                                                    


VECTREN CORPORATION AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited – In millions)
 
Six Months Ended
 
June 30,
 
2015
 
2014
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
 
Net income
$
92.8

 
$
63.1

Adjustments to reconcile net income to cash from operating activities:
 
 
 
Depreciation & amortization
126.6

 
149.6

Deferred income taxes & investment tax credits
28.7

 
0.4

Provision for uncollectible accounts
4.5

 
3.2

Expense portion of pension & postretirement benefit cost
3.1

 
3.9

Other non-cash items - net
3.1

 
3.8

Loss on assets held for sale (pretax)

 
32.4

Changes in working capital accounts:
 

 
 

Accounts receivable & accrued unbilled revenues
26.1

 
132.5

Inventories
6.0

 
0.5

Recoverable/refundable fuel & natural gas costs
30.0

 
(22.7
)
Prepayments & other current assets
59.4

 
(3.6
)
Accounts payable, including to affiliated companies
(71.7
)
 
(80.3
)
Accrued liabilities
(11.5
)
 
(5.2
)
Employer contributions to pension & postretirement plans
(22.3
)
 
(2.5
)
Changes in noncurrent assets
(5.1
)
 
0.8

Changes in noncurrent liabilities
(3.1
)
 
(2.0
)
Net cash provided by operating activities
266.6

 
273.9

CASH FLOWS FROM FINANCING ACTIVITIES
 

 
 

Proceeds from dividend reinvestment plan & other common stock issuances
3.0

 
3.3

Requirements for:
 

 
 

Dividends on common stock
(62.8
)
 
(59.4
)
Retirement of long-term debt
(5.0
)
 
(30.0
)
Net change in short-term borrowings
(60.0
)
 
10.5

Net cash used in financing activities
(124.8
)
 
(75.6
)
CASH FLOWS FROM INVESTING ACTIVITIES
 

 
 

Proceeds from the sale of assets and other collections
4.1

 
2.2

Requirements for:
 

 
 
         Capital expenditures, excluding AFUDC equity
(207.9
)
 
(195.1
)
Business acquisitions
(13.1
)
 
(18.5
)
Net cash used in investing activities
(216.9
)
 
(211.4
)
Net change in cash & cash equivalents
(75.1
)
 
(13.1
)
Cash & cash equivalents at beginning of period
86.4

 
21.5

Cash & cash equivalents at end of period
$
11.3

 
$
8.4





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

6

                                                
                                                                    

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 (Energy Act).  Vectren was incorporated under the laws of Indiana on June 10, 1999.

Indiana Gas provides energy delivery services to approximately 583,000 natural gas customers located in central and southern Indiana.  SIGECO provides energy delivery services to approximately 144,000 electric customers and over 111,000 gas customers located near Evansville in southwestern Indiana.  SIGECO also owns and operates electric generation assets to serve its electric customers and optimizes those assets in the wholesale power market.  Indiana Gas and SIGECO generally do business as Vectren Energy Delivery of Indiana.  VEDO provides energy delivery services to approximately 316,000 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.  Prior to August 29, 2014, the Company had activities in its Coal Mining business. Results in the financial statements include the results of Vectren Fuels, Inc. (Vectren Fuels) through the date of sale of August 29, 2014, when the Company exited the coal mining business through the sale of Vectren Fuels. Enterprises has other legacy businesses that have invested in energy-related opportunities and services, real estate, and a leveraged lease, among other investments.  All of the above are collectively referred to as the Nonutility Group.  

2.
Basis of Presentation

The interim condensed consolidated financial statements included in this report have been prepared by the Company, without audit, as provided in the rules and regulations of the Securities and Exchange Commission and include a review of subsequent events through the date the financial statements were issued.  Certain information and note disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States have been omitted as provided in such rules and regulations.  The information in this report reflects all adjustments which are, in the opinion of management, necessary to fairly state the interim periods presented, inclusive of adjustments that are normal and recurring in nature.  These condensed consolidated financial statements and related notes should be read in conjunction with the Company’s audited annual consolidated financial statements for the year ended December 31, 2014, filed with the Securities and Exchange Commission on February 17, 2015, 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.



7

                                                
                                                                    

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
 
Six Months Ended
 
June 30,
 
June 30,
(In millions, except per share data)
2015
 
2014
 
2015
 
2014
Numerator:
 
 
 
 
 
 
 
Reported net income (Numerator for Basic and Diluted EPS)
$
35.8

 
$
11.9

 
$
92.8

 
$
63.1

Denominator:
 

 
 

 
 
 
 
     Weighted average common shares outstanding
          (Denominator for Basic EPS)
82.6

 
82.5

 
82.6

 
82.5

     Conversion of share based compensation arrangements
0.0

 
0.0

 
0.0

 
0.0

Adjusted weighted-average shares outstanding and assumed
 
 
 
 
 
 
 
conversions outstanding (Denominator for Diluted EPS)
82.6

 
82.5

 
82.6

 
82.5

 
 
 
 
 
 
 
 
Basic EPS
$
0.43

 
$
0.14

 
$
1.12

 
$
0.76

Diluted EPS
$
0.43

 
$
0.14

 
$
1.12

 
$
0.76


For the three and six months ended June 30, 2015 and 2014, all options and 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 $5.4 million and $5.5 million in the three months ended June 30, 2015 and 2014, respectively, as a component of operating revenues. During the six months ended June 30, 2015 and 2014, these taxes totaled $17.1 million and $18.4 million, respectively. Expenses associated with excise and utility receipts taxes are recorded as a component of Taxes other than income taxes.


8

                                                
                                                                    

5.
Retirement Plans & Other Postretirement Benefits

The Company maintains three 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
 
June 30,
 
Pension Benefits
 
Other Benefits
(In millions)
2015
 
2014
 
2015
 
2014
Service cost
$
2.0

 
$
1.9

 
$
0.1

 
$
0.1

Interest cost
3.7

 
4.0

 
0.5

 
0.6

Expected return on plan assets
(5.7
)
 
(5.8
)
 

 

Amortization of prior service cost
0.2

 
0.2

 
(0.8
)
 
(0.8
)
Amortization of transitional obligation

 

 

 

Amortization of actuarial loss
2.1

 
1.2

 
0.2

 
0.1

Settlement charge

 
2.6

 

 

Net periodic benefit cost
$
2.3

 
$
4.1

 
$

 
$

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Six Months Ended
 
June 30,
 
Pension Benefits
 
Other Benefits
(In millions)
2015
 
2014
 
2015
 
2014
Service cost
$
4.0

 
$
3.7

 
$
0.2

 
$
0.2

Interest cost
7.3

 
7.9

 
1.0

 
1.1

Expected return on plan assets
(11.3
)
 
(11.5
)
 

 

Amortization of prior service cost
0.4

 
0.5

 
(1.5
)
 
(1.5
)
Amortization of transitional obligation

 

 

 

Amortization of actuarial loss
4.2

 
2.4

 
0.3

 
0.2

Settlement charge

 
2.6

 

 

Net periodic benefit cost
$
4.6

 
$
5.6

 
$

 
$


Employer Contributions to Qualified Pension Plans
As of June 30, 2015, the Company has made $20.0 million in contributions to its qualified pension plans. The Company did not make any contributions to its qualified pension plans in 2014.  

6.
Supplemental Cash Flow Information

As of June 30, 2015 and December 31, 2014, the Company has accruals related to utility and nonutility plant purchases totaling approximately $21.7 million and $20.2 million, respectively.


9

                                                
                                                                    

7.    Investment in ProLiance Holdings, LLC

The Company has a remaining investment in ProLiance Holdings, LLC (ProLiance or ProLiance Holdings), an affiliate of the Company and Citizens Energy Group (Citizens). Much of the ProLiance business was sold on June 18, 2013 when ProLiance exited the natural gas marketing business through the disposition of certain of the net assets of its energy marketing business, ProLiance Energy, LLC. 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 in ProLiance at June 30, 2015, shown at its 61 percent ownership share, is as follows.

 
As of
 
June 30,
(In millions)
2015
    Cash
$
4.4

    Investment in LA Storage
21.7

    Other midstream asset investment
4.4

    Total investment in ProLiance
$
30.5

    Included in:
 
       Investments in unconsolidated affiliates
20.4

       Other nonutility investments
10.1


LA Storage
ProLiance Transportation and Storage, LLC (PT&S), a subsidiary of ProLiance, and Sempra Energy International, a subsidiary of Sempra Energy, 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 a 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. As of June 30, 2015 and December 31, 2014, ProLiance's investment in the joint venture was $35.5 million and $35.4 million, respectively.
 
The joint venture received a demand for arbitration from Williams Midstream Natural Gas Liquids, Inc. (Williams) in February 2011 related to a sublease agreement.  Williams alleges that the joint venture was negligent in its attempt to convert certain salt caverns to natural gas storage and seeks damages of $56.7 million.  The joint venture intends to vigorously defend itself and has asserted counterclaims substantially in excess of the amounts asserted by Williams.  The parties have agreed to arbitration and a panel has been selected, with an initial hearing to establish a schedule expected in August 2015. While the outcome cannot be predicted, it is not expected to have a material impact on the results of operations or statement of financial condition of the Company.

8. Sale of Vectren Fuels, Inc.

On July 1, 2014, the Company announced that it had reached an agreement to sell its wholly owned coal mining subsidiary, Vectren Fuels, to Sunrise Coal, LLC (Sunrise Coal), an Indiana-based wholly owned subsidiary of Hallador Energy Company and on August 29, 2014, the transaction closed. At June 30, 2014, the Company reported the coal mining business as held for sale and recorded an estimated loss in other operating expenses, including costs to sell, of approximately $32 million, or $20

10

                                                
                                                                    

million after tax. The sale of Vectren Fuels did not meet the requirements under GAAP to qualify as discontinued operations since Vectren has significant continuing cash flows related to the purchase of coal from the buyer of these mines. After the exit of the coal mining business by Vectren, Sunrise assumed Vectren Fuels' supply contracts and also negotiated new contracts for similar quality coal that will result in the Company purchasing most of its coal supply from Sunrise.

9.    Financing Activities

Indiana Gas Unsecured Note Retirement
On March 15, 2015, a $5.0 million Indiana Gas senior unsecured note matured. The Series E note carried a fixed interest rate of 7.15%. The repayment of debt was funded by the Company's commercial paper program.

Vectren Utility Holdings and Vectren Capital Debt Transactions
On June 11, 2015, Vectren Utility Holdings entered into a private placement Note Purchase Agreement pursuant to which institutional investors have agreed to purchase the following tranches of notes: (i) $25 million of 3.90% Guaranteed Senior Notes, Series A, due December 15, 2035, (ii) $135 million of 4.36% Guaranteed Senior Notes, Series B, due December, 15, 2045, and (iii) $40 million of 4.51% Guaranteed Senior Notes, Series C, due December 15, 2055. The notes will be unconditionally guaranteed by Indiana Gas Company, Inc., Southern Indiana Gas and Electric Company and Vectren Energy Delivery of Ohio, Inc.

Additionally, on June 11, 2015, Vectren Capital, Corp. entered into a private placement Note Purchase Agreement pursuant to which institutional investors have agreed to purchase the following tranches of notes: (i) $75 million of 3.33% Guaranteed Senior Notes, Series A, due December 15, 2022 and (ii) $75 million of 3.90% Guaranteed Senior Notes, Series B, due December 15, 2030. The notes will be guaranteed by Vectren Corporation.

Subject to the satisfaction of customary conditions precedent, both financings are scheduled to close on or about December 15, 2015.

10.
Commitments & Contingencies

Performance Guarantees & Product Warranties
In the normal course of business, wholly owned subsidiaries, including Energy Systems Group (ESG), issue payment and performance bonds and other forms of assurance that commit them to timely install infrastructure, operate facilities, pay vendors and subcontractors, and/or support warranty obligations.  

Specific to ESG, in its role as a general contractor in the performance contracting industry, at June 30, 2015, there are 48 open surety bonds supporting future performance.  The average face amount of these obligations is $7.6 million, and the largest obligation has a face amount of $57.3 million, where construction related to the project is 97 percent complete.  The maximum exposure from these obligations is limited by the level of work already completed and bonds issued to ESG by various subcontractors. At June 30, 2015, approximately 40 percent of work was 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 significant liability or cost has been recognized for the periods presented.

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 June 30, 2015, parent level guarantees support a maximum of $190 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

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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 be called upon, 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 position, results of operations or cash flows.

11.
Gas Rate & Regulatory Matters

Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement

The Company monitors and maintains its natural gas distribution system to ensure that natural gas is delivered in a safe and efficient manner. The Company's natural gas utilities are currently engaged in programs to replace bare steel and cast iron infrastructure and other activities in both Indiana and Ohio to mitigate risk, improve the system, and comply with applicable regulations, many of which are a result of federal pipeline safety requirements. Laws 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 Commission, 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 is deferred and recovered in the utility’s next general rate case, which must be filed before the expiration of the seven year plan. The adjustment mechanism is capped at an annual increase in retail revenues of no more than two percent.

In June 2011, Ohio House Bill 95 (House Bill 95) was signed into law. Outside of a base rate proceeding, this legislation permits a natural gas utility to apply for recovery of much of its capital expenditure program. 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 Ohio Commission.

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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 projects to three years after being placed into service at SIGECO and four years after being placed into service at Indiana Gas. At June 30, 2015 and December 31, 2014, the Company has regulatory assets totaling $18.3 million and $16.4 million, respectively, associated with the deferral of depreciation and debt-related post-in-service carrying cost activities. Beginning in 2014, all bare steel and cast iron replacement activities are now part of the Company’s seven-year capital investment plan filed pursuant to Senate Bill 251, discussed further below.

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

On September 26, 2014, the OUCC filed an appeal of the IURC's finding that the remaining value of retired assets replaced during the infrastructure projects should not be netted against the cost being recovered in the tracking mechanism. In June 2015, the Indiana Court of Appeals issued an opinion in favor of the Company that agreed with the IURC finding as issued in its original August 2014 Order.

On January 14, 2015, the IURC issued an Order approving the Company’s initial request for recovery of the revenue requirement through June 30, 2014 as part of its approved seven-year plan. As the next step of the recovery process, as outlined in the legislation, this Order initiates the rates and charges necessary to begin cash recovery of 80 percent of the revenue requirement, with the remaining 20 percent deferred for recovery in the Company's next rate cases. Also, consistent with the guidelines set forth in the original August 2014 Order, the IURC approved the Company’s update to its seven-year plan, to reflect changes to project prioritization as a result of both additional risk modeling and cost fluctuations. The updated plan reflects capital expenditures of approximately $900 million, an increase of $35 million from the previous plan and is inclusive of an estimated $30 million of economic development related expenditures, over the seven-year period beginning in 2014. The plan also includes approximately $15 million of annual operating costs associated with federal pipeline safety rules.
In April 2015, a group of industrial customers intervened as part of the pending appeal of the Company's Order referenced above, asking the Court of Appeals in light of a court decision related to another utility's seven-year plan, to consider whether the Company had failed to provide sufficient detail regarding its planned projects after year one of the plan. In the June 2015 decision, the Indiana Court of Appeals denied this request given that this issue was not raised during the Company's case or on appeal during the briefing period. As a result, the Company's Order approving its plan is final.

On April 1, 2015, the Company filed its second request for recovery of the revenue requirement associated with capital investment and applicable operating costs through December 31, 2014. On June 1, 2015, the Company amended its case to delay the recovery of a portion of the investment associated with the Senate Bill 560 approved investment made from July 2014 to December 2014, until its next filing in October 2015. The Company has offered to provide additional detail related to its seven-year plan in its update to be filed October 1, 2015. On July 22, 2015, the IURC issued an Order, approving the recovery of these investments consistent with the Company's proposal, with modification, specifically to the rate of return applicable to the Senate Bill 251 compliance component. The IURC found that the overall rate of return to be applied to the investment in determining the revenue requirement is to be updated with each filing, reflecting 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 base

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rate case. This IURC interpretation of the overall rate of return to be used is the same as that already in place for the Senate Bill 560 component.

Ohio Recovery and Deferral Mechanisms
The PUCO Order approving the Company's 2009 base rate case in the Ohio service territory authorized a distribution replacement rider (DRR). The DRR's primary purpose is recovery of investments in utility plant and related operating expenses associated with replacing bare steel and cast iron pipelines and certain other infrastructure. This rider is updated annually for qualifying capital expenditures and allows for a return to be earned on those capital expenditures based on the rate of return approved in the 2009 base rate case. In addition, deferral of depreciation and the ability to accrue debt-related post-in-service carrying costs is also allowed until the related capital expenditures are included in the DRR. The Order also initially established a prospective bill impact evaluation on the annual deferrals. To date, the Company has made capital investments under this rider totaling $167.2 million. Regulatory assets associated with post-in-service carrying costs and depreciation deferrals were $15.6 million and $13.1 million at June 30, 2015 and December 31, 2014, respectively. Due to the expiration of the initial five-year term for the DRR in early 2014, the Company filed a request in August 2013 to extend and expand the DRR. On February 19, 2014, the PUCO issued an Order approving a Stipulation entered into by the PUCO Staff and the Company which provided for the extension of the DRR for the recovery of costs incurred through 2017 and expanded the types of investment covered by the DRR to include recovery of other infrastructure investments. The Order limits the resulting DRR fixed charge per month for residential and small general service customers to specific graduated levels over the next five years. The Company's five-year capital expenditure plan related to these infrastructure investments for calendar years 2013 through 2017 totals approximately $200 million. The capital expenditure plan is subject to the graduated caps on the fixed DRR monthly charge applicable to residential and small general service customers approved in the Order however, is not expected to exceed those caps. In addition, the Order approved the Company's commitment that the DRR can only be further extended as part of a base rate case. On May 1, 2015, the Company filed its annual request to adjust the DRR for recovery of costs incurred through December 31, 2014. A procedural schedule has been set in this proceeding, and the Company expects an order by September 2015.

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

The PUCO has also issued Orders approving the Company's filings under Ohio House Bill 95. These Orders approve deferral of the Company’s Ohio capital expenditure program for items not covered by the DRR as well as expenditures necessary to comply with PUCO rules, regulations, orders, and system expansion to some new customers. Ohio House Bill 95 Orders also have established a prospective bill impact evaluation on the cumulative deferrals, limiting the total deferrals at a level which would equal $1.50 per residential and small general service customer per month. As of June 30, 2015, the Company's deferrals have not reached this bill impact cap. In addition, the Orders approved the Company's proposal that subsequent requests for accounting authority will be filed annually in April. The Company submitted its most recent annual filing on April 30, 2015, which covers the Company’s capital expenditure program through calendar year 2015.

Other Regulatory Matters

Indiana Gas GCA Cost Recovery Issue
On July 1, 2014, Indiana Gas filed its recurring quarterly Gas Cost Adjustment (GCA) mechanism, which included recovery of gas cost variances incurred for the period January through March 2014. In August 2014, the OUCC filed testimony opposing the recovery of approximately $3.9 million of natural gas commodity purchases incurred during this period on the basis that a gas cost incentive calculation had not been properly performed. The calculation at issue is performed by the Company's supply administrator. In the winter period at issue, a pipeline force majeure event caused the gas to be priced at a location that was impacted by the extreme winter temperatures. After further review, the OUCC modified its position in testimony filed on November 5, 2014, and suggested a reduced disallowance of $3 million. The IURC moved this specific issue to a sub-docket proceeding. On April 1, 2015, a stipulation and settlement agreement between the Company, the OUCC, and the Company’s supply administrator was filed in this proceeding. The IURC issued an Order on June 10, 2015 which approved the stipulation and settlement agreement, which resulted in recovery of approximately $1.4 million of the disputed amount via the Company’s GCA mechanism, with the remaining $1.6 million received from the gas supply administrator.

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Indiana Gas & SIGECO Gas Decoupling Extension Filing
On August 18, 2011, the IURC issued an Order granting the extension of the current decoupling mechanism in place at both Indiana gas companies and recovery of new conservation program costs through December 2015. The Companies have reached an agreement in principle with the OUCC to extend the decoupling mechanism through 2020. The settlement was filed for approval on March 1, 2015. The settlement was unopposed and a hearing was held in May 2015. The Company expects an order later in 2015.

12. Electric Rate & Regulatory Matters

SIGECO Electric Environmental Compliance Filing
On January 28, 2015, the IURC issued an Order approving the Company’s request for approval of capital investments on its coal-fired generation units to comply with new EPA mandates related to mercury and air toxin standards effective in 2015 and to address an outstanding Notice of Violation (NOV) from the EPA. As of June 30, 2015, approximately $30 million has been spent on equipment to control mercury in both air and water emissions, and $21 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 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 expected to occur in 2015 and 2016. As of June 30, 2015, the Company has approximately $1.4 million deferred related to depreciation, property tax, and operating expense, and $0.5 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. 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. The Company believes the IURC’s Order satisfies applicable legal standards and will file its response in the third quarter of 2015. The Court is expected to decide on these issues later this year.

Coal Procurement Procedures
Entering 2014, SIGECO had in place staggered term coal contracts with Vectren Fuels and one other supplier to provide supply for its generating units. During 2014, SIGECO entered into separate negotiations with Vectren Fuels and Sunrise Coal to modify its existing contracts as well as enter into new long-term contracts in order to secure its supply of coal with specifications that support its compliance with the Mercury and Air Toxins Rule. Subsequent to the sale of Vectren Fuels to Sunrise Coal in August 2014, all such contracts have been assigned to Sunrise Coal. Those contracts were submitted to the IURC for review as part of the 2014 annual sub docket proceeding. In December 2014, the IURC determined that the terms of the coal contracts were reasonable. The annual sub docket proceeding is no longer required.

On December 5, 2011 within the quarterly FAC filing, SIGECO submitted a joint proposal with the OUCC to reduce its fuel costs billed to customers by accelerating into 2012 the impact of lower cost coal under new term contracts effective after 2012. The cost difference was deferred to a regulatory asset and is being recovered over a 6 year period without interest beginning in 2014. The IURC approved this proposal on January 25, 2012, with the reduction to customer’s rates effective February 1, 2012. The total balance deferred for recovery through the Company’s FAC, which began February 2014, was $42.4 million, of which $31.8 million remains as of June 30, 2015.

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

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the Company. On June 20, 2012, the IURC issued an Order approving a small customer lost margin recovery mechanism, inclusive of all previous deferrals. This mechanism is an alternative to the electric decoupling proposal that was denied by the IURC in the Company's last base rate proceeding. For the six months ended June 30, 2015 and 2014, the Company recognized Electric utility revenue of $4.8 million and $4.4 million, respectively, associated with this approved lost margin recovery mechanism.

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

On May 6, 2015, Indiana's governor signed Indiana Senate Bill 412 into law requiring electricity suppliers to create and submit energy efficiency plans to the IURC at least one time every three years. Senate Bill 412 also supports the recovery of all program costs, including lost revenues and financial incentives associated with those plans and approved by the IURC. The Company made its first filing pursuant to this bill in June 2015, which proposed energy efficiency programs for calendar years 2016 and 2017. As defined within the procedural schedule to be set in August 2015, the OUCC and other stakeholders will be afforded an opportunity to comment on Vectren's plan.

FERC Return on Equity (ROE) Complaint
On November 12, 2013, certain parties representing a group of industrial customers filed a joint complaint with the FERC under Section 206 of the Federal Power Act against MISO and various MISO transmission owners, including SIGECO. The joint parties seek to reduce the 12.38 percent return on equity used in the MISO transmission owners’ rates, including SIGECO’s formula transmission rates, to 9.15 percent, and to set a capital structure in which the equity component does not exceed 50 percent. The MISO transmission owners filed their response to the complaint on January 6, 2014, opposing any change to the return. As of June 30, 2015, the Company had invested approximately $157.7 million in qualifying projects. The net plant balance for these projects totaled $141.9 million at June 30, 2015.

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

In addition to the NETO ruling, the FERC acknowledged that the pending complaint raised against the MISO transmission owners is reasonable, and ordered the initiation of a formal settlement discussion, mediated by a FERC appointed judge, in November 2014. A settlement has not been reached, and the case will move to a formal evidentiary hearing before the FERC. A procedural schedule was set on January 22, 2015, which defines a targeted date of final resolution from the FERC. An initial decision is expected later in 2015, but the timing of the final order from the FERC is unknown at this time. The Company has established a reserve pending the outcome of these complaints.

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


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13.  Environmental Matters                                    
Indiana Senate Bill 251
Senate Bill 251 is also applicable to federal environmental mandates impacting SIGECO electric operations in addition to the impact on its gas utility operations. The Company continues with its ongoing evaluation of the impact Senate Bill 251 may have on its operations, including applicability of the stricter regulations the EPA is currently pursuing involving carbon and air quality, fly ash disposal, cooling tower intake facilities, waste water discharges, and greenhouse gases. These issues are further discussed below.

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

Mercury and Air Toxics (MATS) Rule
On December 21, 2011, the EPA finalized the utility MATS Rule. The MATS Rule sets emission limits for hazardous air pollutants for existing and new coal-fired power plants and identifies the following broad categories of hazardous air
pollutants: mercury, non-mercury hazardous air pollutants (primarily arsenic, chromium, cobalt, and selenium), and acid gases (hydrogen cyanide, hydrogen chloride, and hydrogen fluoride). The rule imposes mercury emission limits for two sub-categories of coal and proposed surrogate limits for non-mercury and acid gas hazardous air pollutants. Reductions are to be achieved within three years of publication of the final rule in the Federal Register. MATS compliance was required to commence April 16, 2015, and the Company is in full compliance with all requirements of MATS.
 
Legal challenges to the MATS Rule continue. 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 that 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. The parties to the litigation are expected to be asked by the appellate court for briefing as to whether the court should vacate the rule, or leave it in place while the EPA supplements the rulemaking record pursuant to the Supreme Court opinion. Vectren continues to operate in full compliance with the MATS rule during the pendency of the appellate court remand which could take several months.

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

Ozone NAAQS
On November 26, 2014, the EPA proposed to tighten the current National Ambient Air Quality Standard (NAAQS) for ozone from the current standard of 75 parts per billion (ppb) to a level with the range of 65 to 70 ppb. The EPA has stated that it

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intends to finalize the rule by October 2015. Upon finalization, the EPA will then determine whether a particular region is in attainment with the new standard. While it is possible that counties in southwest Indiana could be declared in non-attainment with the new standard, and thus may have an effect on future economic development activities in the Company's service territory, the Company does not anticipate any significant compliance cost impacts from the determination given its previous investment in SCR technology for NOx control on its units.

Water
Section 316(b) of the Clean Water Act requires that generating facilities use the “best technology available” (BTA) to minimize adverse environmental impacts on a body of water. More specifically, Section 316(b) is concerned with impingement and entrainment of aquatic species in once-through cooling water intake structures used at electric generating facilities. A final rule was issued by the EPA on May 19, 2014. The final rule does not mandate cooling water tower retrofits but requires a state level case-by-case assessment of BTA for each facility. The final rule lists seven presumptive technologies which would qualify as BTA. These technologies range from intake screen modifications to cooling water tower retrofits. Ecological and technology assessment studies must be completed prior to determining BTA for the Company’s facilities. To comply, the Company believes that capital investments will likely be in the range of $4 million to $8 million. Costs for compliance with these final regulations should qualify as federally mandated regulatory requirements and be recoverable under Indiana Senate Bill 251 referenced above.

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

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

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

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

Coal Ash Waste Disposal & Ash Ponds
In December 2014 the EPA released its final Coal 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 Company will continue to reuse a majority of its ash. Legislation is currently being considered by Congress that would provide for enforcement of the federal program by states.

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Under the final CCR rule, the Company is required to complete a series of integrity assessments and groundwater monitoring studies to determine whether one or more of the Company's ash ponds can continue in service, or whether a pond must be retrofitted with liners or closed and bottom ash handling conversions completed. The Company estimates capital expenditures to comply with the alternatives in the final rule could range from approximately $30 million for final capping and monitoring costs if the ponds are permitted to continue to operate to the end of the life of the generating units, to $100 million if existing ponds at both F.B. Culley and A.B. Brown generating stations are required to be closed and bottom ash conversions completed at each generating unit.

In the second quarter 2015, the Company recorded an asset retirement obligation (ARO) in the amount of $15.6 million which reflects the current present value of the costs to cap the existing ponds at the end of the life of the generating units. The estimated obligation is based on assumptions such as future ash levels, existing life of generating units, compliance assessments within the final rule at future dates, and costs for future construction services. These assumptions and estimations are subject to change in the future and could materially impact the amount of the estimated ARO. It is expected that any costs for compliance with these regulations should qualify as federally mandated regulatory requirements and be recoverable under Senate Bill 251 referenced above.

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

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

In July 2013, the President announced a Climate Action Plan, which called on the EPA to finalize the rule for new construction expeditiously and, by June 2015 finalize, New Source Performance Standards (NSPS) for GHG's for existing electric generating units which would apply to the Company's power plants. On June 2, 2014, the EPA proposed its rule for states to regulate CO2 emissions from existing electric generating units. The rule required states to adopt plans to reduce CO2 emissions by 30 percent from 2005 levels by 2030. The proposal set state-specific CO2 emission rate-based CO2 goals (measured in lb CO2/MWh) and guidelines for the development, submission and implementation of state plans to achieve the state goals. These state-specific goals were calculated based upon 2012 average emission rates aggregated for all fossil fuel-based units in the state. For Indiana, the proposal used a 2012 emission rate of 1,923 lb CO2/MWh, and set an interim goal of 1,607 lb CO2/MWh and a final emission goal of 1,531 lb CO2/MWh, or a 20 percent reduction in Indiana’s total CO2 emission rate, that must be met by 2030. Under this proposal, these CO2 emission rate goals do not apply directly to individual units or generating systems, but are instead state goals. As such, the state would be required to establish a framework that would guide how compliance would be met on a statewide basis. Indiana’s interim, or “phase in”, goal of 1,607 lb CO2/MWh must be met as averaged over a ten-year period (2020 - 2029) with progress toward this goal to be demonstrated for every two rolling calendar years starting in 2020, with the first report due in 2022. These individual state goals were based upon the application of four “building blocks” of emission rate improvements identified as the Best System of Emission Reduction, which defines EPA’s authority under Section 111(d).

The Company timely filed comments to the Clean Power Plan (CPP) proposal on December 1, 2014. The State of Indiana also filed public comments, asking that the proposal be withdrawn. On July 31, 2014, litigation was filed by the state of Indiana and other parties challenging the rule prior to finalization by the EPA. In June 2015 these consolidated challenges were determined to be premature by the reviewing court, but the court’s decision did not preclude the parties from raising the arguments against the final rulemaking after EPA has published the final CPP in the Federal Register.

19

                                                
                                                                    


On August 3, 2015, the EPA released its final CPP which requires a 32 percent reduction in carbon emissions from 2005 levels. The original proposal in June 2014 called for a 30 percent reduction. The final CPP is significantly different in many respects from the June 2014 proposal. The EPA removed the energy efficiency block in the final rule and increased the assumption related to reliance upon renewables for compliance. In addition to the change in energy efficiency and renewables assumptions, the EPA also incorporated a new emission rate factor as a means of leveling the emission reduction requirements across the states. This resulted in the final emission rate reduction goal for Indiana of 1,242 lb CO2 / MWh to be achieved by 2030, as compared to a goal of 1,531 lb CO2/ MWh as proposed in June of 2014. Final state goals now fall within a narrower, lower range (between 771 lb CO2/MWh and 1305 lb CO2/MWh), with states having higher percentages of coal-fired generation receiving more stringent emission rate goals than those in the original proposal. The new rule also gives states an additional year to submit a state implementation plan, now September of 2018. Under the CPP, states have the flexibility to include energy efficiency and other measures should it choose to implement a state measures plan 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 glide path over the 2022-29 time period.

In the event that a state does not submit a state implementation plan (SIP), the EPA also released a proposed federal implementation plan (FIP), which would be imposed in those states without an approved SIP. The proposed FIP would apply an emission rate requirement directly on affected units. Under the proposed FIP the CO2 emission rate limit for coal-fired units would start at 1671 lbs CO2 / MWh in 2022 and decrease to a final emission rate cap of 1305 lbs CO2 / MWh by 2030. While the FIP emission rate cap appears to be slightly less stringent, the cap would apply directly to affected units and these units would not have the benefit of averaging emission rates with rates from zero-carbon sources as in a SIP. Purchases of emission credits from zero-carbon sources can be made for compliance. Since the FIP has just been proposed, it will be subject to extensive public comments prior to finalization.

Indiana is the 5th largest carbon emitter in the nation in tons of CO2 produced from electric generation. In 2013, Indiana’s electric utilities generated 105.6 million tons of CO2. The Company’s share of that total was 6.3 million, or less than 6 percent. Since 2005, the Company’s emissions of CO2 have declined 23 percent (on a tonnage basis). These reductions have come from the retirement of F.B. Culley Unit 1, expiration of municipal contracts, electric conservation and the addition of renewable generation and the installation of more efficient dense pack turbine technology. With respect to renewable generation, in 2008 and 2009, the Company executed long-term purchase power commitments for a total of 80 MW of wind energy. The Company currently has approximately 4 percent of its electricity being provided by clean energy sources due to the long-term wind contracts and landfill gas investment. With respect to CO2 emission rate, since 2005 the Company has lowered its CO2 emission rate (as measured in lbs CO2/MWh) from 1967 lbs CO2/MWh to 1922 lbs CO2/MWh, for a reduction of 3 percent. The Company’s CO2 emission rate of 1922 lbs/MWh is basically the same as the State’s average CO2 emission rate of 1923 lb CO2/MWh.

Impact of Legislative Actions & Other Initiatives is Unknown

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 will undertake a detailed review of the requirements of the CPP and the proposed FIP and commence a review of potential compliance options for Vectren’s affected units. In 2016 the Company will file its next integrated resource plan that will model compliance assumptions and costs and evaluate possible compliance alternatives. The Company will also continue to remain engaged with the State of Indiana to assess the final rule and to develop a plan that is the least cost to its customers. Costs to purchase allowances that cap GHG emissions or expenditures made to control emissions or lower carbon emission rates should be considered a federally mandated cost of providing electricity, and as such, the Company believes such costs and expenditures should be recoverable from customers through Senate Bill 251 as referenced above or Senate Bill 29, which was used by the Company to recover its initial pollution control investments.


20

                                                
                                                                    

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

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

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

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

The costs the Company expects to incur are estimated by management using assumptions based on actual costs incurred, the timing of expected future payments, and inflation factors, among others. While the Company’s utilities have recorded all costs which they presently expect to incur in connection with activities at these sites, it is possible that future events may require remedial activities which are not presently foreseen and those costs may not be subject to PRP or insurance recovery. As of June 30, 2015 and December 31, 2014, approximately $3.4 million and $3.6 million, respectively, of accrued, but not yet spent, costs are included in Other Liabilities related to the Indiana Gas and SIGECO sites.

14.
Impact of Recently Issued Accounting Principles

Revenue Recognition Guidance
In May 2014, the FASB issued new accounting guidance to clarify the principles for recognizing revenue and to develop a common revenue standard for GAAP and IFRS. The amendments in this guidance state that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This new guidance requires improved disclosures to help users of financial statements better understand the nature, amount, timing, and uncertainty of revenue that is recognized. On July 9, 2015, the FASB approved a one year deferral of the effective date to December 15, 2017 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.
Financial Reporting of Discontinued Operations
In April 2014, the FASB issued new accounting guidance on reporting discontinued operations and disclosures of disposals of a company or entity. The guidance changes the criteria for reporting discontinued operations and provides for enhanced disclosures in this area. Under the new guidance, only disposals representing a strategic shift in operations should be presented as discontinued operations. Those strategic shifts should have a major effect on the organization's operations and financial results. Additionally, the new guidance requires expanded disclosures about discontinued operations to provide more information about the assets, liabilities, income, and expenses of discontinued operations. The new guidance also requires disclosure of the pre-tax income attributable to a disposal of a significant part of an organization that does not qualify for

21

                                                
                                                                    

discontinued operations reporting. This guidance is effective for fiscal years beginning on or after December 15, 2014, with early adoption permitted. The Company adopted this guidance on January 1, 2015. The Company did not early adopt this guidance in accounting for the sale of its Coal Mining assets. The adoption of this guidance had no impact on the Company's financial statements.

Amendments to the Consolidation Analysis
In February 2015, the FASB issued new accounting guidance on amendments to the consolidation analysis, which is intended to improve certain areas of consolidation guidance for legal entities such as limited partnerships, limited liability companies, and securitization structures. The ASU will reduce the number of consolidation models and will be effective for annual reporting periods beginning after December 15, 2015. Early adoption is permitted, including adoption in an interim period. The Company is currently evaluating the standard to understand the overall impact it will have on the financial statements, if any.

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

15.
Fair Value Measurements

The carrying values and estimated fair values using primarily Level 2 assumptions of the Company's other financial instruments follow:
 
June 30, 2015
 
December 31, 2014
(In millions)
Carrying
Amount
 
Est. Fair
Value
 
Carrying
Amount
 
Est. Fair
Value
Long-term debt
$
1,572.5

 
$
1,726.9

 
$
1,577.3

 
$
1,754.5

Short-term borrowings
96.4

 
96.4

 
156.4

 
156.4

Cash & cash equivalents
11.3

 
11.3

 
86.4

 
86.4


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 or over a 15-year period.  Accordingly, any reacquisition of this debt would not be expected to have a material effect on the Company's results of operations.

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 June 30, 2015 and December 31, 2014, the fair value for these financial instruments was not estimated.  The carrying value of these investments at June 30, 2015 and December 31, 2014 was approximately $16.2 million and $10.4 million, respectively, and is included in Other nonutility

22

                                                
                                                                    

investments. The increase in carrying value from December 31, 2014 is related to a debt security and note received from the sale of a commercial real estate investment in June 2015.

16.
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 transmission and 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 has historically reported the following segments:  Infrastructure Services, Energy Services, Coal Mining, and Other Businesses.  In the 2015 periodic reports, the 2014 results for the Coal Mining segment include the results of Vectren Fuels through August 29, 2014 when it exited the coal mining business through the sale of Vectren Fuels (see Note 8 for additional information on this transaction).
     
Corporate and Other includes unallocated corporate expenses such as advertising and certain charitable contributions, among other activities, that benefit the Company’s other operations.  Net income is the measure of profitability used by management for all operations.  

23

                                                
                                                                    


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

 
Three Months Ended
 
Six Months Ended
 
June 30,
 
June 30,
(In millions)
2015
 
2014
 
2015
 
2014
Revenues
 
 
 
 
 
 
 
Utility Group
 
 
 
 
 
 
 
Gas Utility Services
$
128.6

 
$
132.4

 
$
481.5

 
$
576.0

Electric Utility Services
147.8

 
152.0

 
301.7

 
315.0

Other Operations
10.2

 
9.5

 
20.4

 
19.1

Eliminations
(10.1
)
 
(9.4
)
 
(20.2
)
 
(19.0
)
Total Utility Group
276.5

 
284.5

 
783.4

 
891.1

Nonutility Group
 

 
 

 
 
 
 
Infrastructure Services
231.4

 
178.0

 
408.3

 
301.0

Energy Services
43.7

 
32.7

 
66.8

 
50.2

Coal Mining

 
85.6

 

 
167.1

Total Nonutility Group
275.1

 
296.3

 
475.1

 
518.3

Corporate & Other Group
0.2

 
0.2

 
0.4

 
0.5

Eliminations
(0.8
)
 
(38.5
)
 
(1.7
)
 
(70.6
)
Consolidated Revenues
$
551.0

 
$
542.5

 
$
1,257.2

 
$
1,339.3

 
 
 
 
 
 
 
 
Profitability Measure - Net Income (Loss)
 

 
 

 
 
 
 
Utility Group Net Income
 

 
 

 
 
 
 
Gas Utility Services
$
3.4

 
$
0.7

 
$
43.8

 
$
39.0

Electric Utility Services
19.7

 
19.9

 
38.9

 
39.2

Other Operations
1.3

 
2.3

 
4.7

 
6.0

Utility Group Net Income
24.4

 
22.9

 
87.4

 
84.2

Nonutility Group Net Income (Loss)
 

 
 

 
 
 


Infrastructure Services
12.3

 
9.4

 
9.7

 
4.1

Energy Services
(0.4
)
 
(1.8
)
 
(3.5
)
 
(4.8
)
Coal Mining

 
(18.2
)
 

 
(19.3
)
Other Businesses
(0.3
)
 
(0.2
)
 
(0.5
)
 
(0.5
)
Nonutility Group Net Income (Loss)
11.6

 
(10.8
)
 
5.7

 
(20.5
)
Corporate & Other Group Net Income (Loss)
(0.2
)
 
(0.2
)
 
(0.3
)
 
(0.6
)
Consolidated Net Income
$
35.8

 
$
11.9

 
$
92.8

 
$
63.1


24

                                                
                                                                    

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 (Energy Act).  Vectren was incorporated under the laws of Indiana on June 10, 1999.

Indiana Gas provides energy delivery services to approximately 583,000 natural gas customers located in central and southern Indiana.  SIGECO provides energy delivery services to approximately 144,000 electric customers and over 111,000 gas customers located near Evansville in southwestern Indiana.  SIGECO also owns and operates electric generation assets to serve its electric customers and optimizes those assets in the wholesale power market.  Indiana Gas and SIGECO generally do business as Vectren Energy Delivery of Indiana.  VEDO provides energy delivery services to approximately 316,000 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. Prior to August 29, 2014, the Company had activities in a Coal Mining business through Vectren Fuels, Inc. (Vectren Fuels). Results in the financial statements include the results of Coal Mining through the date of sale of August 29, 2014, when the Company exited the coal mining business through the sale of Vectren Fuels. Enterprises has other legacy businesses that have investments in energy-related opportunities and services, real estate, and a leveraged lease, 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 2014 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 since each operates independently requiring distinct competencies and business strategies, offers different energy and energy-related products and services, and experiences different opportunities and risks.

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 charitable contributions, among other activities.

Results for the three months ended June 30, 2015 were earnings of $35.8 million, or $0.43 per share, compared to earnings of $11.9 million, or $0.14 per share for the three months ended June 30, 2014. For the six months ended June 30, 2015, consolidated net income was $92.8 million, or $1.12 per share, compared to $63.1 million, or $0.76 per share for the six months ended June 30, 2014.


25

                                                
                                                                    

In 2014, excluding the results attributable to the Company's Coal Mining business, consolidated net income for the three and six months ended June 30, 2014 was $30.1 million, or $0.37 per share, and $82.4 million, or $1.00 per share, respectively.

Results Related to the Coal Mining Business

On July 1, 2014, the Company announced that it had reached an agreement to sell its wholly owned coal mining subsidiary, Vectren Fuels, to Sunrise Coal, LLC (Sunrise Coal), an Indiana-based wholly owned subsidiary of Hallador Energy Company. Sunrise Coal owns and operates coal mines in the Illinois Basin. On August 29, 2014, the transaction closed.  Results from Coal Mining for the three and six months ended June 30, 2014 were losses of $18.2 million and $19.3 million, respectively.

Consolidated Results Excluding the Results From Coal Mining in the Year of Disposition (See below regarding the Use of Non-GAAP Measures)

Net income (loss) and earnings per share, excluding results from Coal Mining in 2014, the year of disposition, in total and by group, for the three and six months ended June 30, 2015 and 2014 follow:
 
Three Months Ended
 
Six Months Ended
 
June 30,
 
June 30,
(In millions, except per share data)
2015
 
2014
 
2015
 
2014
Net income (loss)*
$
35.8

 
$
30.1

 
$
92.8

 
$
82.4

Attributed to:
 
 
 
 
 
 
 
Utility Group
24.4

 
22.9

 
87.4

 
84.2

Nonutility Group*
11.6

 
7.4

 
5.7

 
(1.2
)
Corporate & other
(0.2
)
 
(0.2
)
 
(0.3
)
 
(0.6
)
 
 
 
 
 
 
 
 
Basic EPS*
$
0.43

 
$
0.37

 
$
1.12

 
$
1.00

Attributed to:
 
 
 
 
 
 
 
Utility Group
0.29

 
0.28

 
1.06

 
1.02

Nonutility Group*
0.14

 
0.09

 
0.07

 
(0.01
)
Corporate & other

 

 
(0.01
)
 
(0.01
)
*Excludes Coal Mining results in 2014

Utility Group
In the second quarter of 2015, the Utility Group earnings were $24.4 million, compared to $22.9 million in 2014. In the six months ended June 30, 2015, the Utility Group earned $87.4 million, compared to $84.2 million in 2014. The quarter and year to date increases are largely driven by increases in gas utility margin from returns on the Indiana and Ohio infrastructure replacement programs, small customer growth, and large customer usage. Decreases in operating expenses related to performance-based compensation also favorably impacted earnings in both the quarter and year to date periods. Quarter and year to date results in 2015 were unfavorably impacted by a decrease in wholesale electric margin due primarily to lower market pricing compared to 2014 periods.

Gas Utility Services
During the second quarter of 2015, Gas Utility Services earned $3.4 million compared to earnings of $0.7 million in the second quarter of 2014. In the six months ended June 30, 2015, Gas Utility Services earnings were $43.8 million, compared to earnings of $39.0 million in 2014. Customer margin increased in 2015 from small customer growth, large customer usage, and the returns from the Indiana and Ohio infrastructure replacement programs. Overall, operating expenses were favorably impacted by a decrease in performance-based compensation compared to the 2014 periods.

Electric Utility Services
During the second quarter of 2015, Electric Utility Services' earnings were $19.7 million, compared to $19.9 million in the second quarter of 2014. Electric Utility Services earned $38.9 million year to date in 2015, compared to earnings of $39.2 million for the six months ended June 30, 2014. The decreases in the quarter and year to date periods are driven by the impact of weather on retail electric margin, which management estimates the unfavorable after tax impact to be approximately $0.5 million in the

26

                                                
                                                                    

second quarter of 2015 and $1.1 million year to date, as compared to the 2014 periods. Quarter and year to date results were also unfavorably impacted by decreases in wholesale margin due primarily to lower market pricing. These decreases were offset somewhat by lower operating expenses in 2015 driven by the timing of power supply maintenance as well as increased performance-based compensation expense in 2014.

Nonutility Group
The Nonutility group results for the second quarter of 2015 were earnings of $11.6 million, compared to earnings of $7.4 million in the prior year. For the six months ended June 30, 2015, the Nonutility Group reported earnings of $5.7 million, compared to a loss of $1.2 million in the prior year period. The 2014 periods exclude Coal Mining results. Results reflect strong demand for infrastructure services in the first half of 2015 and increased results compared to 2014 due to the inability of work crews to complete their work as planned because of the adverse winter weather and related road restrictions during the first half in 2014.

Dividends

Dividends declared for the three months ended June 30, 2015, were $0.38 per share, compared to $0.36 per share for the same period in 2014. Dividends declared for the six months ended June 30, 2015, were $0.76 per share, compared to $0.72 per share for the same period in 2014.

Use of Non-GAAP Performance Measures and Per Share Measures

Results Excluding Coal Mining
This discussion and analysis contains non-GAAP financial measures that exclude the results related to Coal Mining in 2014 since the Company exited the coal mining business in 2014.

Management uses consolidated net income, consolidated earnings per share, and Nonutility Group net income (loss), excluding results from Coal Mining in 2014, to evaluate its results. Coal Mining results that are excluded from the GAAP measures are inclusive of holding company costs (corporate allocations, interest and taxes). Management believes analyzing underlying and ongoing business trends is aided by the removal of Coal Mining results in 2014 and the rationale for using such non-GAAP measures is that, through the disposition of the Coal Mining segment, the Company has exited the coal mining business. Management believes this presentation provides the best representation of the overall results of the ongoing operations.

A material limitation associated with the use of these measures is that the measures that exclude Coal Mining results do not include all costs recognized in accordance with GAAP. Management compensates for this limitation by prominently displaying a reconciliation of these non-GAAP performance measures to their closest GAAP performance measures. This display also provides financial statement users the option of analyzing results as management does or by analyzing GAAP results.

Contribution to Vectren's Basic EPS
Per share earnings contributions of the Utility Group, Nonutility Group excluding Coal Mining results in 2014, 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.  Reconciliations of the non-GAAP measures to their most closely related GAAP measure of consolidated earnings per share are included throughout this discussion and analysis.  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.
 

27

                                                
                                                                    

The following table reconciles consolidated net income (loss), consolidated basic EPS, and Nonutility Group net income (loss) to those results excluding Coal Mining results in 2014.
 
Three Months Ended
 
Six Months Ended
 
June 30, 2014
 
June 30, 2014
(In millions, except EPS)
GAAP
Measure
Exclude Coal Mining Results
Non-GAAP
Measure
 
GAAP
Measure
Exclude Coal Mining
Results
Non-GAAP
Measure
Consolidated
 
 
 
 
 
 
 
Net Income (Loss)
$
11.9

$
(18.2
)
$
30.1

 
$
63.1

$
(19.3
)
$
82.4

Basic EPS
$
0.14

$
(0.23
)
$
0.37

 
$
0.76

$
(0.24
)
$
1.00

Nonutility Group Net Income (Loss)
$
(10.8
)
$
(18.2
)
$
7.4

 
$
(20.5
)
$
(19.3
)
$
(1.2
)

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 consist 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 that provides natural gas distribution and transportation services to nearly two-thirds of Indiana and to west-central Ohio and an electric transmission and distribution business, which provides electric transmission and distribution services 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 and six months ended June 30, 2015 and 2014, follow:

 
Three Months Ended
 
Six Months Ended
 
June 30,
 
June 30,
(In millions, except per share data)
2015
 
2014
 
2015
 
2014
OPERATING REVENUES
 
 
 
 
 
 
 
Gas utility
$
128.6

 
$
132.4

 
$
481.5

 
$
576.0

Electric utility
147.8

 
152.0

 
301.7

 
315.0

Other
0.1

 
0.1

 
0.2

 
0.1

Total operating revenues
276.5

 
284.5

 
783.4

 
891.1

OPERATING EXPENSES
 

 
 

 
 
 
 
Cost of gas sold
36.4

 
43.7

 
208.4

 
314.6

Cost of fuel & purchased power
47.0

 
48.1

 
97.0

 
105.1

Other operating
78.5

 
81.5

 
181.3

 
179.8

Depreciation & amortization
52.0

 
50.6

 
104.2

 
100.5

Taxes other than income taxes
12.1

 
12.5

 
31.2

 
32.6

Total operating expenses
226.0

 
236.4

 
622.1

 
732.6

OPERATING INCOME
50.5

 
48.1

 
161.3

 
158.5

OTHER INCOME - NET
4.3

 
3.7

 
9.2

 
7.6

INTEREST EXPENSE
16.4

 
16.7

 
33.0

 
33.4

INCOME BEFORE INCOME TAXES
38.4

 
35.1

 
137.5

 
132.7

INCOME TAXES
14.0

 
12.2

 
50.1

 
48.5

NET INCOME
$
24.4

 
$
22.9

 
$
87.4

 
$
84.2

 
 
 
 
 
 
 
 
CONTRIBUTION TO VECTREN BASIC EPS
$
0.29

 
$
0.28

 
$
1.06

 
$
1.02


28

                                                
                                                                    


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.  

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

Gas Utility Margin (Gas utility revenues less Cost of gas sold)
Gas Utility margin and throughput by customer type follows:
 
Three Months Ended
Six Months Ended
 
June 30,
June 30,
(In millions)
2015
 
2014
2015
 
2014
Gas utility revenues
$
128.6

 
$
132.4

$
481.5

 
$
576.0

Cost of gas sold
36.4

 
43.7

208.4

 
314.6

Total gas utility margin
$
92.2

 
$
88.7

$
273.1

 
$
261.4

Margin attributed to:
 

 
 

 
 
 
Residential & commercial customers
$
69.7

 
$
67.5

$
196.0

 
$
190.7

Industrial customers
13.0

 
12.1

32.3

 
30.9

Other
2.5

 
2.8

5.9

 
6.4

Regulatory expense recovery mechanisms
7.0

 
6.3

38.9

 
33.4

Total gas utility margin
$
92.2

 
$
88.7

$
273.1

 
$
261.4

Sold & transported volumes in MMDth attributed to:
 
 
 
Residential & commercial customers
10.7

 
12.0

72.9

 
77.6

Industrial customers
28.3

 
23.7

66.3

 
59.7

Total sold & transported volumes
39.0

 
35.7

139.2

 
137.3


Gas Utility margins were $92.2 million and $273.1 million for the three and six months ended June 30, 2015, and compared to 2014, increased $3.5 million quarter over quarter and $11.7 million year to date. Customer margin from small customer growth and large customer usage increased $1.1 million quarter over quarter and $1.9 million year to date compared to 2014. Additionally quarter over quarter margin was favorably impacted by increased return from infrastructure replacement programs in Indiana and Ohio of $2.2 million. Year to date margin was also favorably impacted by increased return from infrastructure replacement programs of $5.1 million. Year to date pass through margin increased $5.5 million in 2015 compared to 2014 due to increases in costs recovered through regulatory expense mechanisms.
 

29

                                                
                                                                    

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
 
Six Months Ended
 
June 30,
 
June 30,
(In millions)
2015
 
2014
 
2015
 
2014
Electric utility revenues
$
147.8

 
$
152.0

 
$
301.7

 
$
315.0

Cost of fuel & purchased power
47.0

 
48.1

 
97.0

 
105.1

Total electric utility margin
$
100.8

 
$
103.9

 
$
204.7

 
$
209.9

Margin attributed to:
 

 
 

 
 
 
 
Residential & commercial customers
$
62.8

 
$
64.4

 
$
126.5

 
$
128.7

Industrial customers
28.4

 
27.9

 
55.2

 
53.9

Other
0.5

 
1.1

 
1.5

 
2.0

Regulatory expense recovery mechanisms
1.9

 
1.8

 
5.3

 
6.6

Subtotal: retail
$
93.6

 
$
95.2

 
$
188.5

 
$
191.2

Wholesale power & transmission system margin
7.2

 
8.7

 
16.2

 
18.7

Total electric utility margin
$
100.8

 
$
103.9

 
$
204.7

 
$
209.9

Electric volumes sold in GWh attributed to:
 

 
 

 
 
 
 
Residential & commercial customers
643.1

 
658.4

 
1,345.7

 
1,377.5

Industrial customers
719.4

 
692.4

 
1,392.3

 
1,352.5

Other customers
4.8

 
4.9

 
10.9

 
10.9

Total retail volumes sold
1,367.3

 
1,355.7

 
2,748.9

 
2,740.9


Retail
Electric retail utility margins were $93.6 million and $188.5 million for the three and six months ended June 30, 2015, and compared to 2014, decreased by $1.6 million in the quarter and $2.7 million year to date. Electric results, which are not protected by weather normalizing mechanisms, reflect a $0.9 million decrease in small customer margin related to weather as annualized cooling degree days in the second quarter of 2015 were 107 percent of normal compared to 109 percent of normal in 2014. Similarly for the year to date period, electric results were unfavorably impacted by weather and resulted in a year to date decrease of $1.8 million in small customer margin. Small customer margin also decreased $0.6 million quarter over quarter and $0.8 million year to date compared to 2014 related to decreased electric volumes sold primarily related to continued customer conservation. Margin from regulatory expense recovery mechanisms decreased $1.3 million in the 2015 year to date period compared to 2014, driven primarily by a corresponding decrease in operating expenses associated with the electric conservation programs. Additionally, results reflect an increase in large customer usage of $0.6 million quarter over quarter and $1.3 million year to date, largely driven by large customer growth.

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 is currently provided to SABIC by the Company under a long-term contract that expires in May of 2016. SABIC's historical peak electric usage has been approximately 120 megawatts (MW).  The cogen facility is expected to provide 80 MW of capacity.  Therefore, the Company will continue to provide all of SABIC's power requirements above the 80 MW capacity of the cogen, which is projected to be 40 MW.  The Company also expects to provide back-up power, when required. The Company is actively working with SABIC on a transitional contractual arrangement. The Company continues to pursue and respond to economic development opportunities, among other things, as offsets to the margin lost from SABIC's cogeneration decision and as such, does not anticipate any significant impact on its future financial results.
 
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:


30

                                                
                                                                    

 
Three Months Ended
Six Months Ended
 
June 30,
June 30,
(In millions)
2015
 
2014
2015
 
2014
MISO Transmission system sales
$
6.4

 
$
6.6

$
12.9

 
$
12.7

MISO Off-system sales
0.8

 
2.1

3.3

 
6.0

Total wholesale margin
$
7.2

 
$
8.7

$
16.2

 
$
18.7


Transmission system margin associated with qualifying projects, including the reconciliation of recovery mechanisms, and other transmission system operations, totaled $12.9 million and $12.7 million during the six months ended June 30, 2015 and 2014, respectively. As of June 30, 2015, the Company had invested approximately $157.7 million in qualifying projects. The net plant balance for these projects totaled $141.9 million at June 30, 2015. These projects include an interstate 345 kV transmission line that connects the Company’s A.B. Brown Generating Station to a generating station in Indiana owned by Duke Energy to the north and to a generating station in Kentucky owned by Big Rivers Electric Corporation to the south; a substation; and another transmission line. Although the allowed return is currently being challenged as discussed below in Rate and Regulatory Matters, once placed into service, these projects earn a FERC approved equity rate of return of 12.38 percent on the net plant balance. Operating expenses are also recovered. The Company has established a reserve pending the outcome of this complaint. The 345 kV project is the largest of these qualifying projects, with a cost of $106.8 million that earned the FERC approved equity rate of return, including while under construction.

For the six months ended June 30, 2015, margin from off-system sales was $3.3 million compared to $6.0 million in 2014. The base rate changes implemented in May 2011 require that wholesale margin from off-system sales earned above or below $7.5 million per year be shared equally with customers.  Results for the periods presented reflect the impact of that sharing as well as a decrease in volumes sold due to lower market pricing.  

Utility Group Operating Expenses

Other Operating
During the second quarter of 2015, other operating expenses were $78.5 million, a decrease of $3.0 million, compared to 2014. For the six months ended June 30, 2015, other operating expenses were $181.3 million, an increase of $1.5 million, compared to 2014. The increase in other operating costs for the year to date period is primarily due to increases in costs that are recovered directly in margin. Excluding these pass through costs, other operating expenses decreased $4.3 million in 2015, compared to the same period in 2014. Both quarter and year to date periods reflect decreased performance-based compensation expense, as well as lower operating expenses in 2015 due to the timing of power supply maintenance in 2014.

Depreciation & Amortization
In the second quarter of 2015, depreciation and amortization expense was $52.0 million compared to $50.6 million in 2014. For the six months ended June 30, 2015, depreciation and amortization expense was $104.2 million, which represents an increase of $3.7 million compared to 2014. Both quarter and year to date periods reflect increased plant placed in service.

Taxes Other Than Income Taxes
Taxes other than income taxes were $12.1 million for the second quarter of 2015, a decrease of $0.4 million compared to 2014. Year to date, taxes other than income taxes were $31.2 million compared to $32.6 million for the year to date period in 2014. The decrease in both the year to date and quarter periods is primarily due to decreased revenue taxes. These taxes are offset dollar-for-dollar with lower gas utility and electric utility revenues reflected in margin attributable to regulatory expense recovery mechanisms.

Other Income - Net

Other income-net reflects income of $4.3 million for the second quarter of 2015, an increase of $0.6 million, compared to 2014. Year to date, other income-net reflects income of $9.2 million compared to $7.6 million in 2014. The increase is primarily due to higher AFUDC driven by increased capital expenditures related to gas utility infrastructure replacement investments, as well as higher AFUDC rates.


31

                                                
                                                                    

Gas Rate & Regulatory Matters

Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement

The Company monitors and maintains its natural gas distribution system to ensure that natural gas is delivered in a safe and efficient manner. The Company's natural gas utilities are currently engaged in programs to replace bare steel and cast iron infrastructure and other activities in both Indiana and Ohio to mitigate risk, improve the system, and comply with applicable regulations, many of which are a result of federal pipeline safety requirements. Laws 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 Commission, 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 is deferred and recovered in the utility’s next general rate case, which must be filed before the expiration of the seven year plan. The adjustment mechanism is capped at an annual increase in retail revenues of no more than two percent.

In June 2011, Ohio House Bill 95 (House Bill 95) was signed into law. Outside of a base rate proceeding, this legislation permits a natural gas utility to apply for recovery of much of its capital expenditure program. 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 Ohio Commission.

Indiana Recovery and Deferral Mechanisms
The Company's Indiana natural gas utilities received Orders in 2008 and 2007 associated with the most recent base rate cases. These Orders authorized the deferral of financial impacts associated with bare steel and cast iron replacement activities. The Orders provide for the deferral of depreciation and post in service carrying costs on qualifying projects totaling $20 million annually at Indiana Gas and $3 million annually at SIGECO. The debt-related post-in-service carrying costs are recognized in the Condensed Consolidated Statements of Income currently. The recording of post-in-service carrying costs and depreciation deferral is limited by individual qualifying projects to three years after being placed into service at SIGECO and four years after being placed into service at Indiana Gas. At June 30, 2015 and December 31, 2014, the Company has regulatory assets totaling $18.3 million and $16.4 million, respectively, associated with the deferral of depreciation and debt-related post-in-service carrying cost activities. Beginning in 2014, all bare steel and cast iron replacement activities are now part of the Company’s seven-year capital investment plan filed pursuant to Senate Bill 251, discussed further below.

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

32

                                                
                                                                    


On September 26, 2014, the OUCC filed an appeal of the IURC's finding that the remaining value of retired assets replaced during the infrastructure projects should not be netted against the cost being recovered in the tracking mechanism. In June 2015, the Indiana Court of Appeals issued an opinion in favor of the Company that agreed with the IURC finding as issued in its original August 2014 Order.

On January 14, 2015, the IURC issued an Order approving the Company’s initial request for recovery of the revenue requirement through June 30, 2014 as part of its approved seven-year plan. As the next step of the recovery process, as outlined in the legislation, this Order initiates the rates and charges necessary to begin cash recovery of 80 percent of the revenue requirement, with the remaining 20 percent deferred for recovery in the Company's next rate cases. Also, consistent with the guidelines set forth in the original August 2014 Order, the IURC approved the Company’s update to its seven-year plan, to reflect changes to project prioritization as a result of both additional risk modeling and cost fluctuations. The updated plan reflects capital expenditures of approximately $900 million, an increase of $35 million from the previous plan and is inclusive of an estimated $30 million of economic development related expenditures, over the seven-year period beginning in 2014. The plan also includes approximately $15 million of annual operating costs associated with federal pipeline safety rules.
In April 2015, a group of industrial customers intervened as part of the pending appeal of the Company's Order referenced above, asking the Court of Appeals in light of a court decision related to another utility's seven-year plan, to consider whether the Company had failed to provide sufficient detail regarding its planned projects after year one of the plan. In the June 2015 decision, the Indiana Court of Appeals denied this request given that this issue was not raised during the Company's case or on appeal during the briefing period. As a result, the Company's Order approving its plan is final.
On April 1, 2015, the Company filed its second request for recovery of the revenue requirement associated with capital investment and applicable operating costs through December 31, 2014. On June 1, 2015, the Company amended its case to delay the recovery of a portion of the investment associated with the Senate Bill 560 approved investment made from July 2014 to December 2014, until its next filing in October 2015. The Company has offered to provide additional detail related to its seven-year plan in its update to be filed October 1, 2015. On July 22, 2015, the IURC issued an Order, approving the recovery of these investments consistent with the Company's proposal, with modification, specifically to the rate of return applicable to the Senate Bill 251 compliance component. The IURC found that the overall rate of return to be applied to the investment in determining the revenue requirement is to be updated with each filing, reflecting 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 base rate case. This IURC interpretation of the overall rate of return to be used is the same as that already in place for the Senate Bill 560 component.
Ohio Recovery and Deferral Mechanisms
The PUCO Order approving the Company's 2009 base rate case in the Ohio service territory authorized a distribution replacement rider (DRR). The DRR's primary purpose is recovery of investments in utility plant and related operating expenses associated with replacing bare steel and cast iron pipelines and certain other infrastructure. This rider is updated annually for qualifying capital expenditures and allows for a return to be earned on those capital expenditures based on the rate of return approved in the 2009 base rate case. In addition, deferral of depreciation and the ability to accrue debt-related post-in-service carrying costs is also allowed until the related capital expenditures are included in the DRR. The Order also initially established a prospective bill impact evaluation on the annual deferrals. To date, the Company has made capital investments under this rider totaling $167.2 million. Regulatory assets associated with post-in-service carrying costs and depreciation deferrals were $15.6 million and $13.1 million at June 30, 2015 and December 31, 2014, respectively. Due to the expiration of the initial five-year term for the DRR in early 2014, the Company filed a request in August 2013 to extend and expand the DRR. On February 19, 2014, the PUCO issued an Order approving a Stipulation entered into by the PUCO Staff and the Company which provided for the extension of the DRR for the recovery of costs incurred through 2017 and expanded the types of investment covered by the DRR to include recovery of other infrastructure investments. The Order limits the resulting DRR fixed charge per month for residential and small general service customers to specific graduated levels over the next five years. The Company's five-year capital expenditure plan related to these infrastructure investments for calendar years 2013 through 2017 totals approximately $200 million. The capital expenditure plan is subject to the graduated caps on the fixed DRR monthly charge applicable to residential and small general service customers approved in the Order however, is not expected to exceed those caps. In addition, the Order approved the Company's commitment that the DRR can only be further extended as part of a base rate case.

33

                                                
                                                                    

On May 1, 2015, the Company filed its annual request to adjust the DRR for recovery of costs incurred through December 31, 2014. A procedural schedule has been set in this proceeding, and the Company expects an order by September 2015.

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

The PUCO has also issued Orders approving the Company's filings under Ohio House Bill 95. These Orders approve deferral of the Company’s Ohio capital expenditure program for items not covered by the DRR as well as expenditures necessary to comply with PUCO rules, regulations, orders, and system expansion to some new customers. Ohio House Bill 95 Orders also have established a prospective bill impact evaluation on the cumulative deferrals, limiting the total deferrals at a level which would equal $1.50 per residential and small general service customer per month. As of June 30, 2015, the Company's deferrals have not reached this bill impact cap. In addition, the Orders approved the Company's proposal that subsequent requests for accounting authority will be filed annually in April. The Company submitted its most recent annual filing on April 30, 2015, which covers the Company’s capital expenditure program through calendar year 2015.

Other Regulatory Matters

Indiana Gas GCA Cost Recovery Issue
On July 1, 2014, Indiana Gas filed its recurring quarterly Gas Cost Adjustment (GCA) mechanism, which included recovery of gas cost variances incurred for the period January through March 2014. In August 2014, the OUCC filed testimony opposing the recovery of approximately $3.9 million of natural gas commodity purchases incurred during this period on the basis that a gas cost incentive calculation had not been properly performed. The calculation at issue is performed by the Company's supply administrator. In the winter period at issue, a pipeline force majeure event caused the gas to be priced at a location that was impacted by the extreme winter temperatures. After further review, the OUCC modified its position in testimony filed on November 5, 2014, and suggested a reduced disallowance of $3 million. The IURC moved this specific issue to a sub-docket proceeding. On April 1, 2015, a stipulation and settlement agreement between the Company, the OUCC, and the Company’s supply administrator was filed in this proceeding. The IURC issued an Order on June 10, 2015 which approved the stipulation and settlement agreement, which resulted in recovery of approximately $1.4 million of the disputed amount via the Company’s GCA mechanism, with the remaining $1.6 million received from the gas supply administrator.

Indiana Gas & SIGECO Gas Decoupling Extension Filing
On August 18, 2011, the IURC issued an Order granting the extension of the current decoupling mechanism in place at both Indiana gas companies and recovery of new conservation program costs through December 2015. The Companies have reached an agreement in principle with the OUCC to extend the decoupling mechanism through 2020. The settlement was filed for approval on March 1, 2015. The settlement was unopposed and a hearing was held in May 2015. The Company expects an order later in 2015.


34

                                                
                                                                    

Electric Rate & Regulatory Matters

SIGECO Electric Environmental Compliance Filing
On January 28, 2015, the IURC issued an Order approving the Company’s request for approval of capital investments on its coal-fired generation units to comply with new EPA mandates related to mercury and air toxin standards effective in 2015 and to address an outstanding Notice of Violation (NOV) from the EPA. As of June 30, 2015, approximately $30 million has been spent on equipment to control mercury in both air and water emissions, and $21 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 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 expected to occur in 2015 and 2016. As of June 30, 2015, the Company has approximately $1.4 million deferred related to depreciation, property tax, and operating expense, and $0.5 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. 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. The Company believes the IURC’s Order satisfies applicable legal standards and will file its response in the third quarter of 2015. The Court is expected to decide on these issues later this year.

Coal Procurement Procedures
Entering 2014, SIGECO had in place staggered term coal contracts with Vectren Fuels and one other supplier to provide supply for its generating units. During 2014, SIGECO entered into separate negotiations with Vectren Fuels and Sunrise Coal to modify its existing contracts as well as enter into new long-term contracts in order to secure its supply of coal with specifications that support its compliance with the Mercury and Air Toxins Rule. Subsequent to the sale of Vectren Fuels to Sunrise Coal in August 2014, all such contracts have been assigned to Sunrise Coal. Those contracts were submitted to the IURC for review as part of the 2014 annual sub docket proceeding. In December 2014, the IURC determined that the terms of the coal contracts were reasonable. The annual sub docket proceeding is no longer required.

On December 5, 2011 within the quarterly FAC filing, SIGECO submitted a joint proposal with the OUCC to reduce its fuel costs billed to customers by accelerating into 2012 the impact of lower cost coal under new term contracts effective after 2012. The cost difference was deferred to a regulatory asset and is being recovered over a 6 year period without interest beginning in 2014. The IURC approved this proposal on January 25, 2012, with the reduction to customer’s rates effective February 1, 2012. The total balance deferred for recovery through the Company’s FAC, which began February 2014, was $42.4 million, of which $31.8 million remains as of June 30, 2015.

SIGECO Electric Demand Side Management (DSM) Program Filing
On August 31, 2011 the IURC issued an Order approving an initial three-year DSM plan in the SIGECO electric service territory that complied with the IURC’s energy saving targets. Consistent with the Company’s proposal, the Order approved, among other items, the following: 1) recovery of costs associated with implementing the DSM Plan; 2) the recovery of a performance incentive mechanism based on measured savings related to certain DSM programs; 3) lost margin recovery associated with the implementation of DSM programs for large customers; and 4) deferral of lost margin up to $3 million in 2012 and $1 million in 2011 associated with small customer DSM programs for subsequent recovery under a tracking mechanism to be proposed by the Company. On June 20, 2012, the IURC issued an Order approving a small customer lost margin recovery mechanism, inclusive of all previous deferrals. This mechanism is an alternative to the electric decoupling proposal that was denied by the IURC in the Company's last base rate proceeding. For the six months ended June 30, 2015 and 2014, the Company recognized Electric utility revenue of $4.8 million and $4.4 million, respectively, associated with this approved lost margin recovery mechanism.

On March 28, 2014, Indiana Senate Bill 340 was signed into law. This legislation ended electric DSM programs on December 31, 2014 that have been conducted to meet the energy savings requirements established in the IURC's December 2009 Order.

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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 2015.

On May 6, 2015, Indiana's governor signed Indiana Senate Bill 412 into law requiring electricity suppliers to create and submit energy efficiency plans to the IURC at least one time every three years. Senate Bill 412 also supports the recovery of all program costs, including lost revenues and financial incentives associated with those plans and approved by the IURC. The Company made its first filing pursuant to this bill in June 2015, which proposed energy efficiency programs for calendar years 2016 and 2017. As defined within the procedural schedule to be set in August 2015, the OUCC and other stakeholders will be afforded an opportunity to comment on Vectren's plan.

FERC Return on Equity (ROE) Complaint
On November 12, 2013, certain parties representing a group of industrial customers filed a joint complaint with the FERC under Section 206 of the Federal Power Act against MISO and various MISO transmission owners, including SIGECO. The joint parties seek to reduce the 12.38 percent return on equity used in the MISO transmission owners’ rates, including SIGECO’s formula transmission rates, to 9.15 percent, and to set a capital structure in which the equity component does not exceed 50 percent. The MISO transmission owners filed their response to the complaint on January 6, 2014, opposing any change to the return. As of June 30, 2015, the Company had invested approximately $157.7 million in qualifying projects. The net plant balance for these projects totaled $141.9 million at June 30, 2015.

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

In addition to the NETO ruling, the FERC acknowledged that the pending complaint raised against the MISO transmission owners is reasonable, and ordered the initiation of a formal settlement discussion, mediated by a FERC appointed judge, in November 2014. A settlement has not been reached, and the case will move to a formal evidentiary hearing before the FERC. A procedural schedule was set on January 22, 2015, which defines a targeted date of final resolution from the FERC. An initial decision is expected later in 2015, but the timing of the final order from the FERC is unknown at this time. The Company has established a reserve pending the outcome of these complaints.

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

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


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

Mercury and Air Toxics (MATS) Rule
On December 21, 2011, the EPA finalized the utility MATS Rule. The MATS Rule sets emission limits for hazardous air pollutants for existing and new coal-fired power plants and identifies the following broad categories of hazardous air
pollutants: mercury, non-mercury hazardous air pollutants (primarily arsenic, chromium, cobalt, and selenium), and acid gases (hydrogen cyanide, hydrogen chloride, and hydrogen fluoride). The rule imposes mercury emission limits for two sub-categories of coal and proposed surrogate limits for non-mercury and acid gas hazardous air pollutants. Reductions are to be achieved within three years of publication of the final rule in the Federal Register. MATS compliance was required to commence April 16, 2015, and the Company is in full compliance with all requirements of MATS.
 
Legal challenges to the MATS Rule continue. 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 that 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. The parties to the litigation are expected to be asked by the appellate court for briefing as to whether the court should vacate the rule, or leave it in place while the EPA supplements the rulemaking record pursuant to the Supreme Court opinion. Vectren continues to operate in full compliance with the MATS rule during the pendency of the appellate court remand which could take several months.

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

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


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Water
Section 316(b) of the Clean Water Act requires that generating facilities use the “best technology available” (BTA) to minimize adverse environmental impacts on a body of water. More specifically, Section 316(b) is concerned with impingement and entrainment of aquatic species in once-through cooling water intake structures used at electric generating facilities. A final rule was issued by the EPA on May 19, 2014. The final rule does not mandate cooling water tower retrofits but requires a state level case-by-case assessment of BTA for each facility. The final rule lists seven presumptive technologies which would qualify as BTA. These technologies range from intake screen modifications to cooling water tower retrofits. Ecological and technology assessment studies must be completed prior to determining BTA for the Company’s facilities. To comply, the Company believes that capital investments will likely be in the range of $4 million to $8 million. Costs for compliance with these final regulations should qualify as federally mandated regulatory requirements and be recoverable under Indiana Senate Bill 251 referenced above.

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

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

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

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

Coal Ash Waste Disposal & Ash Ponds
In December 2014 the EPA released its final Coal 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 Company will continue to reuse a majority of its ash. Legislation is currently being considered by Congress that would provide for enforcement of the federal program by states.

Under the final CCR rule, the Company is required to complete a series of integrity assessments and groundwater monitoring studies to determine whether one or more of the Company's ash ponds can continue in service, or whether a pond must be retrofitted with liners or closed and bottom ash handling conversions completed. The Company estimates capital expenditures to comply with the alternatives in the final rule could range from approximately $30 million for final capping and monitoring costs if the ponds are permitted to continue to operate to the end of the life of the generating units, to $100 million if existing

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ponds at both F.B. Culley and A.B. Brown generating stations are required to be closed and bottom ash conversions completed at each generating unit.

In the second quarter 2015, the Company recorded an asset retirement obligation (ARO) in the amount of $15.6 million which reflects the current present value of the costs to cap the existing ponds at the end of the life of the generating units. The estimated obligation is based on assumptions such as future ash levels, existing life of generating units, compliance assessments within the final rule at future dates, and costs for future construction services. These assumptions and estimations are subject to change in the future and could materially impact the amount of the estimated ARO. It is expected that any costs for compliance with these regulations should qualify as federally mandated regulatory requirements and be recoverable under Senate Bill 251 referenced above.

Climate Change
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 investment in advanced clean coal technology and support for research and development; and
A strategy supporting alternative energy technologies and biofuels and continued increase in the domestic supply of natural gas and oil to reduce dependence on foreign oil.

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

Current Initiatives to Increase Conservation & Reduce Emissions
The Company is committed to a policy that reduces greenhouse gas emissions and conserves energy usage. Evidence of this commitment includes:
Focusing the Company’s mission statement and purpose on corporate sustainability and the need to help customers conserve and manage energy costs. Vectren's annual sustainability report received C level certification by the Global Reporting Initiative. This certification creates shared value, demonstrates the Company's commitment to sustainability and denotes transparency in operations;
Implementing conservation initiatives in the Company’s Indiana and Ohio gas utility service territories;
Implementing conservation and demand side management initiatives in the electric service territory;
Building a renewable energy portfolio to complement base load generation in advance of mandated renewable energy portfolio standards;
Evaluating potential carbon requirements with regard to new generation, other fuel supply sources, and future environmental compliance plans;
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 continued replacement of bare steel and cast iron gas distribution pipeline;
Developing renewable energy and energy efficiency performance contracting projects through its wholly owned subsidiary, Energy Systems Group; and
Helping energy producers install pipes that allow for more natural gas power generation and reduce gas flaring through its Infrastructure Services segment.


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

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

In July 2013, the President announced a Climate Action Plan, which called on the EPA to finalize the rule for new construction expeditiously and, by June 2015 finalize, New Source Performance Standards (NSPS) for GHG's for existing electric generating units which would apply to the Company's power plants. On June 2, 2014, the EPA proposed its rule for states to regulate CO2 emissions from existing electric generating units. The rule required states to adopt plans to reduce CO2 emissions by 30 percent from 2005 levels by 2030. The proposal set state-specific CO2 emission rate-based CO2 goals (measured in lb CO2/MWh) and guidelines for the development, submission and implementation of state plans to achieve the state goals. These state-specific goals were calculated based upon 2012 average emission rates aggregated for all fossil fuel-based units in the state. For Indiana, the proposal used a 2012 emission rate of 1,923 lb CO2/MWh, and set an interim goal of 1,607 lb CO2/MWh and a final emission goal of 1,531 lb CO2/MWh, or a 20 percent reduction in Indiana’s total CO2 emission rate, that must be met by 2030. Under this proposal, these CO2 emission rate goals do not apply directly to individual units or generating systems, but are instead state goals. As such, the state would be required to establish a framework that would guide how compliance would be met on a statewide basis. Indiana’s interim, or “phase in”, goal of 1,607 lb CO2/MWh must be met as averaged over a ten-year period (2020 - 2029) with progress toward this goal to be demonstrated for every two rolling calendar years starting in 2020, with the first report due in 2022. These individual state goals were based upon the application of four “building blocks” of emission rate improvements identified as the Best System of Emission Reduction, which defines EPA’s authority under Section 111(d).

The Company timely filed comments to the Clean Power Plan (CPP) proposal on December 1, 2014. The State of Indiana also filed public comments, asking that the proposal be withdrawn. On July 31, 2014, litigation was filed by the state of Indiana and other parties challenging the rule prior to finalization by the EPA. In June 2015 these consolidated challenges were determined to be premature by the reviewing court, but the court’s decision did not preclude the parties from raising the arguments against the final rulemaking after EPA has published the final CPP in the Federal Register.

On August 3, 2015, the EPA released its final CPP which requires a 32 percent reduction in carbon emissions from 2005 levels. The original proposal in June 2014 called for a 30 percent reduction. The final CPP is significantly different in many respects from the June 2014 proposal. The EPA removed the energy efficiency block in the final rule and increased the assumption related to reliance upon renewables for compliance. In addition to the change in energy efficiency and renewables assumptions, the EPA also incorporated a new emission rate factor as a means of leveling the emission reduction requirements across the states. This resulted in the final emission rate reduction goal for Indiana of 1,242 lb CO2 / MWh to be achieved by 2030, as compared to a goal of 1,531 lb CO2/ MWh as proposed in June of 2014. Final state goals now fall within a narrower, lower range (between 771 lb CO2/MWh and 1305 lb CO2/MWh), with states having higher percentages of coal-fired generation receiving more stringent emission rate goals than those in the original proposal. The new rule also gives states an additional year to submit a state implementation plan, now September of 2018. Under the CPP, states have the flexibility to include energy efficiency and other measures should it choose to implement a state measures plan 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 glide path over the 2022-29 time period.

In the event that a state does not submit a state implementation plan (SIP), the EPA also released a proposed federal implementation plan (FIP), which would be imposed in those states without an approved SIP. The proposed FIP would apply an emission rate requirement directly on affected units. Under the proposed FIP the CO2 emission rate limit for coal-fired units

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would start at 1671 lbs CO2 / MWh in 2022 and decrease to a final emission rate cap of 1305 lbs CO2 / MWh by 2030. While the FIP emission rate cap appears to be slightly less stringent, the cap would apply directly to affected units and these units would not have the benefit of averaging emission rates with rates from zero-carbon sources as in a SIP. Purchases of emission credits from zero-carbon sources can be made for compliance. Since the FIP has just been proposed, it will be subject to extensive public comments prior to finalization.

Indiana is the 5th largest carbon emitter in the nation in tons of CO2 produced from electric generation. In 2013, Indiana’s electric utilities generated 105.6 million tons of CO2. The Company’s share of that total was 6.3 million, or less than 6 percent. Since 2005, the Company’s emissions of CO2 have declined 23 percent (on a tonnage basis). These reductions have come from the retirement of F.B. Culley Unit 1, expiration of municipal contracts, electric conservation and the addition of renewable generation and the installation of more efficient dense pack turbine technology. With respect to renewable generation, in 2008 and 2009, the Company executed long-term purchase power commitments for a total of 80 MW of wind energy. The Company currently has approximately 4 percent of its electricity being provided by clean energy sources due to the long-term wind contracts and landfill gas investment. With respect to CO2 emission rate, since 2005 the Company has lowered its CO2 emission rate (as measured in lbs CO2/MWh) from 1967 lbs CO2/MWh to 1922 lbs CO2/MWh, for a reduction of 3 percent. The Company’s CO2 emission rate of 1922 lbs/MWh is basically the same as the State’s average CO2 emission rate of 1923 lb CO2/MWh.

Impact of Legislative Actions & Other Initiatives is Unknown