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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549


FORM 10-Q

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


For the quarterly period ended June 30, 2010

OR

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

For the transition period from __________________ to __________________

Commission file number:   1-15467

VECTREN CORPORATION
(Exact name of registrant as specified in its charter)

Vectren Logo
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.  x 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).
x  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 x                                                                                                                  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    x 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
81,355,524
July 31, 2010
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:
Steven M. Schein
Vice President, Investor Relations
sschein@vectren.com

Definitions


BTU:  British thermal units
 
MSHA:  Mine Safety and Health Administration
FASB:  Financial Accounting Standards Board
 
MW:  megawatts
FERC:  Federal Energy Regulatory Commission
 
MWh / GWh:  megawatt hours / thousands of megawatt hours (gigawatt hours)
 
IDEM:  Indiana Department of Environmental Management
 
OUCC:  Indiana Office of the Utility Consumer Counselor
IURC:  Indiana Utility Regulatory Commission
 
PUCO:  Public Utilities Commission of Ohio
BCF:  billions of cubic feet
USEPA:  United States Environmental Protection Agency
 
MISO: Midwest Independent System Operator
Throughput:  combined gas sales and gas transportation volumes



Table of Contents



PART I.  FINANCIAL INFORMATION

ITEM 1.  FINANCIAL STATEMENTS

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



             
   
June 30,
   
December 31,
 
   
2010
   
2009
 
             
ASSETS
           
             
Current Assets
           
     Cash & cash equivalents
  $ 16.8     $ 11.9  
     Accounts receivable - less reserves of $4.7 &
          $5.2, respectively
    138.7       162.4  
     Accrued unbilled revenues
    58.2       144.7  
     Inventories
    160.3       167.8  
     Recoverable fuel & natural gas costs
    3.2       -  
     Prepayments & other current assets
    76.3       95.1  
          Total current assets
    453.5       581.9  
                 
Utility Plant
               
     Original cost
    4,697.1       4,601.4  
     Less:  accumulated depreciation & amortization
    1,779.7       1,722.6  
          Net utility plant
    2,917.4       2,878.8  
                 
Investments in unconsolidated affiliates
    169.9       186.2  
Other utility & corporate investments
    32.8       33.2  
Other nonutility investments
    40.6       46.2  
Nonutility plant - net
    486.0       482.6  
Goodwill - net
    242.0       242.0  
Regulatory assets
    174.8       187.9  
Other assets
    29.5       33.0  
TOTAL ASSETS
  $ 4,546.5     $ 4,671.8  







The accompanying notes are an integral part of these consolidated condensed financial statements.
 
VECTREN CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED CONDENSED BALANCE SHEETS
(Unaudited – In millions)



             
   
June 30,
   
December 31,
 
   
2010
   
2009
 
             
LIABILITIES & SHAREHOLDERS' EQUITY
           
             
Current Liabilities
           
     Accounts payable
  $ 115.5     $ 183.8  
     Accounts payable to affiliated companies
    25.4       54.1  
     Refundable fuel & natural gas costs
    1.3       22.3  
     Accrued liabilities
    186.0       174.7  
     Short-term borrowings
    145.6       213.5  
     Current maturities of long-term debt
    49.1       48.0  
     Long-term debt subject to tender
    41.3       51.3  
          Total current liabilities
    564.2       747.7  
                 
                 
Long-term Debt - Net of Current Maturities &
     Debt Subject to Tender
    1,549.4       1,540.5  
                 
Deferred Income Taxes & Other Liabilities
               
     Deferred income taxes
    480.2       458.7  
     Regulatory liabilities
    327.8       322.1  
     Deferred credits & other liabilities
    205.8       205.6  
          Total deferred credits & other liabilities
    1,013.8       986.4  
                 
Commitments & Contingencies (Notes 9-12)
               
                 
Common Shareholders' Equity
               
     Common stock (no par value) – issued & outstanding
          81.2 & 81.1, respectively
    670.7       666.8  
     Retained earnings
    754.1       737.2  
     Accumulated other comprehensive income (loss)
    (5.7 )     (6.8 )
          Total common shareholders' equity
    1,419.1       1,397.2  
                 
TOTAL LIABILITIES & SHAREHOLDERS' EQUITY
  $ 4,546.5     $ 4,671.8  







The accompanying notes are an integral part of these consolidated condensed financial statements.
 
VECTREN CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED CONDENSED STATEMENTS OF INCOME
(Unaudited – In millions, except per share data)



                         
   
Three Months
   
Six Months
 
   
Ended June 30,
   
Ended June 30,
 
   
2010
   
2009
   
2010
   
2009
 
OPERATING REVENUES
                       
     Gas utility
  $ 122.9     $ 139.1     $ 591.0     $ 666.5  
     Electric utility
    151.0       132.7       295.9       257.7  
     Nonutility revenues
    128.5       103.7       255.8       246.5  
          Total operating revenues
    402.4       375.5       1,142.7       1,170.7  
OPERATING EXPENSES
                               
     Cost of gas sold
    41.5       58.0       339.3       412.6  
     Cost of fuel & purchased power
    57.8       50.3       115.8       97.3  
     Cost of nonutility revenues
    49.4       43.3       109.9       117.5  
     Other operating
    132.3       125.3       261.2       248.0  
     Depreciation & amortization
    57.2       53.0       113.0       104.4  
     Taxes other than income taxes
    12.1       13.2       35.2       36.7  
          Total operating expenses
    350.3       343.1       974.4       1,016.5  
OPERATING INCOME
    52.1       32.4       168.3       154.2  
OTHER INCOME (EXPENSE)
                               
     Equity in earnings (losses) of unconsolidated affiliates
    (13.9 )     (23.3 )     (5.7 )     (10.7 )
     Other income – net
    0.9       4.1       0.4       6.5  
          Total other income (expense)
    (13.0 )     (19.2 )     (5.3 )     (4.2 )
                                 
INTEREST EXPENSE
    26.0       25.5       52.0       48.2  
                                 
INCOME (LOSS) BEFORE INCOME TAXES
    13.1       (12.3 )     111.0       101.8  
                                 
INCOME TAXES
    4.4       (5.6 )     39.1       35.7  
                                 
NET INCOME (LOSS)
  $ 8.7     $ (6.7 )   $ 71.9     $ 66.1  
                                 
AVERAGE COMMON SHARES OUTSTANDING
    81.0       80.7       81.0       80.7  
DILUTED COMMON SHARES OUTSTANDING
    81.2       80.7       81.2       80.7  
                                 
EARNINGS (LOSS) PER SHARE OF COMMON STOCK:
                 
     BASIC
  $ 0.11     $ (0.08 )   $ 0.89     $ 0.82  
     DILUTED
  $ 0.11     $ (0.08 )   $ 0.89     $ 0.82  
                                 
 
                               
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK
  $ 0.340     $ 0.335     $ 0.680     $ 0.670  





The accompanying notes are an integral part of these consolidated condensed financial statements.
 
VECTREN CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
(Unaudited – In millions)

             
   
Six Months Ended June 30,
 
   
2010
   
2009
 
CASH FLOWS FROM OPERATING ACTIVITIES
           
     Net income
  $ 71.9     $ 66.1  
Adjustments to reconcile net income to cash from operating activities:
 
          Depreciation & amortization
    113.0       104.4  
          Deferred income taxes & investment tax credits
    17.6       20.5  
          Equity in losses of unconsolidated affiliates
    5.7       10.7  
          Provision for uncollectible accounts
    10.2       9.4  
          Expense portion of pension & postretirement benefit cost
    4.5       5.9  
          Other non-cash charges - net
    14.5       (0.8 )
          Changes in working capital accounts:
               
               Accounts receivable & accrued unbilled revenues
    100.0       232.3  
               Inventories
    7.5       23.8  
               Recoverable/refundable fuel & natural gas costs
    (24.2 )     26.5  
               Prepayments & other current assets
    17.6       67.5  
               Accounts payable, including to affiliated companies
    (98.8 )     (185.2 )
               Accrued liabilities
    14.0       (2.6 )
          Unconsolidated affiliate dividends
    12.2       10.9  
          Employer contributions to pension & postretirement plans
    (8.2 )     (16.4 )
          Changes in noncurrent assets
    9.5       5.0  
          Changes in noncurrent liabilities
    (8.3 )     (10.1 )
               Net cash flows from operating activities
    258.7       367.9  
CASH FLOWS FROM FINANCING ACTIVITIES
               
     Proceeds from:
               
          Dividend reinvestment plan & other
    3.1       3.1  
          Long-term debt, net of issuance costs
    -       290.8  
     Requirements for:
               
          Dividends on common stock
    (55.1 )     (54.1 )
          Retirement of long-term debt
    (1.6 )     (1.7 )
     Net change in short-term borrowings
    (67.9 )     (430.7 )
               Net cash flows from financing activities
    (121.5 )     (192.6 )
CASH FLOWS FROM INVESTING ACTIVITIES
               
     Proceeds from:
               
          Unconsolidated affiliate distributions
    0.5       -  
          Other collections
    6.8       1.1  
     Requirements for:
               
          Capital expenditures, excluding AFUDC equity
    (137.2 )     (213.6 )
          Unconsolidated affiliate investments
    (0.1 )     (0.1 )
          Other investments
    (2.3 )     (0.8 )
               Net cash flows from investing activities
    (132.3 )     (213.4 )
Net change in cash & cash equivalents
    4.9       (38.1 )
Cash & cash equivalents at beginning of period
    11.9       93.2  
Cash & cash equivalents at end of period
  $ 16.8     $ 55.1  
 
The accompanying notes are an integral part of these consolidated condensed financial statements.
 
VECTREN CORPORATION AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED CONDENSED 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), serves as the intermediate holding company for three public utilities:  Indiana Gas Company, Inc. (Indiana Gas or Vectren North), Southern Indiana Gas and Electric Company (SIGECO or Vectren South), and the Ohio operations.  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 over 563,000 natural gas customers located in central and southern Indiana.  SIGECO provides energy delivery services to over 141,000 electric customers and approximately 110,000 gas customers located near Evansville in southwestern Indiana.  SIGECO also owns and operates electric generation assets to serve its electric customers and optimizes those assets in the wholesale power market.  Indiana Gas and SIGECO generally do business as Vectren Energy Delivery of Indiana.  The Ohio operations provide energy delivery services to approximately 313,000 natural gas customers located near Dayton in west central Ohio.  The Ohio operations are owned as a tenancy in common by Vectren Energy Delivery of Ohio, Inc. (VEDO), a wholly owned subsidiary of Utility Holdings (53 percent ownership), and Indiana Gas (47 percent ownership).  The Ohio operations generally do business as Vectren Energy Delivery of Ohio.

The Company, through Vectren Enterprises, Inc. (Enterprises), is involved in nonutility activities in three primary business areas:  Energy Marketing and Services, Coal Mining, and Energy Infrastructure Services.  Energy Marketing and Services markets and supplies natural gas and provides energy management services.  Coal Mining mines and sells coal.  Energy Infrastructure Services provides underground construction and repair services and performance contracting and renewable energy services.  Enterprises also has other legacy businesses that have invested in energy-related opportunities and services, real estate, and leveraged leases, among other investments.  These operations are collectively referred to as the Nonutility Group.  Enterprises supports the Company’s regulated utilities pursuant to service contracts by providing natural gas supply services, coal, and infrastructure services.

2.    
Basis of Presentation

The interim consolidated condensed 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 consolidated condensed 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, 2009, filed with the Securities and Exchange Commission on February 26, 2010, on Form 10-K.  Because of the seasonal nature of the Company’s utility operations, the results shown on a quarterly basis are not necessarily indicative of annual results.

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

3.    
Comprehensive Income

Comprehensive income consists of the following:

                         
   
Three Months
   
Six Months
 
   
Ended June 30,
   
Ended June 30,
 
(In millions)
 
2010
   
2009
   
2010
   
2009
 
Net income (loss)
  $ 8.7     $ (6.7 )   $ 71.9     $ 66.1  
Comprehensive income of unconsolidated affiliates
    9.0       35.2       1.9       13.2  
Cash flow hedges
                               
     Unrealized gains
    0.7       -       0.2       0.1  
     Reclassifications to net income
    -       -       -       (0.1 )
Income taxes
    (4.1 )     (14.3 )     (1.0 )     (5.3 )
Total comprehensive income
  $ 14.3     $ 14.2     $ 73.0     $ 74.0  
 
Accumulated other comprehensive income arising from unconsolidated affiliates is primarily the Company’s portion of ProLiance Holdings, LLC’s accumulated comprehensive income related to use of cash flow hedges.  (See Note 8 for more information on ProLiance.)

4.    
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
   
Six Months
 
   
Ended June 30,
   
Ended June 30,
 
(In millions, except per share data)
 
2010
   
2009
   
2010
   
2009
 
                         
Numerator:
                       
     Numerator for basic EPS
  $ 8.7     $ (6.7 )   $ 71.9     $ 66.0  
     Add back earnings attributable to participating securities
    -       -       -       0.1  
     Reported net income (Numerator for Diluted EPS)
  $ 8.7     $ (6.7 )   $ 71.9     $ 66.1  
                                 
Denominator:
                               
     Weighted average common shares outstanding (Basic EPS)
    81.0       80.7       81.0       80.7  
     Conversion of share based compensation arrangements
    0.2       -       0.2       -  
 Adjusted weighted average shares outstanding and
     assumed conversions outstanding (Diluted EPS)
    81.2       80.7       81.2       80.7  
                                 
Basic EPS
  $ 0.11     $ (0.08 )   $ 0.89     $ 0.82  
Diluted EPS
  $ 0.11     $ (0.08 )   $ 0.89     $ 0.82  
                                 

For the three and six months ended June 30, 2010, options to purchase 517,800  of additional shares of the Company’s common stock were outstanding, but were not included in the computation of diluted EPS because their effect would be antidilutive, compared to 1,329,562 and 906,645 shares for the three and six months ended June 30, 2009, respectively.  The exercise prices for these options ranged from $24.74 to $27.15 for the three and six months ended June 30, 2010.  The exercise prices for these options ranged from $22.37 to $27.15 for the three months ended June 30, 2009 and $22.54 to $27.15 for the six months ended June 30, 2009.

5.    
Retirement Plans & Other Postretirement Benefits

The Company maintains three qualified defined benefit pension plans, a nonqualified supplemental executive retirement plan (SERP), and three other postretirement benefit plans.  The defined benefit pension and other postretirement benefit plans, 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 Company has a Voluntary Employee Beneficiary Association (VEBA) Trust Agreement for the partial funding of postretirement health benefits for retirees and their eligible dependents and beneficiaries in one of the three plans.  Annual VEBA funding is discretionary.  The qualified pension plans and the SERP are aggregated under the heading “Pension Benefits.”  Other postretirement benefit plans are aggregated under the heading “Other Benefits.”

Net Periodic Benefit Costs
A summary of the components of net periodic benefit cost follows:
                         
   
Three Months Ended June 30,
   
Pension Benefits
   
Other Benefits
(In millions)
 
2010
   
2009
   
2010
   
2009
 
Service cost
  $ 1.6     $ 1.6     $ 0.1     $ 0.1  
Interest cost
    4.0       3.9       1.2       1.1  
Expected return on plan assets
    (4.6 )     (4.1 )     (0.1 )     (0.1 )
Amortization of prior service cost
    0.4       0.4       (0.2 )     (0.2 )
Amortization of transitional obligation
    -       -       0.3       0.3  
Amortization of actuarial loss
    0.5       0.6       0.1       0.1  
     Net periodic benefit cost
  $ 1.9     $ 2.4     $ 1.4     $ 1.3  
                                 
   
Six Months Ended June 30,
   
Pension Benefits
   
Other Benefits
(In millions)
    2010       2009       2010       2009  
Service cost
  $ 3.2     $ 3.2     $ 0.2     $ 0.2  
Interest cost
    7.9       7.9       2.3       2.2  
Expected return on plan assets
    (9.2 )     (8.2 )     (0.2 )     (0.2 )
Amortization of prior service cost
    0.8       0.8       (0.4 )     (0.4 )
Amortization of transitional obligation
    -       -       0.6       0.6  
Amortization of actuarial loss
    1.0       1.1       0.3       0.2  
     Net periodic benefit cost
  $ 3.7     $ 4.8     $ 2.8     $ 2.6  

Employer Contributions to Qualified Pension Plans
Currently, the Company expects to contribute approximately $12 million to its pension plan trusts for 2010.  Through June 30, 2010, contributions of $5.8 million have been made.

Impact of Recent Healthcare Legislation
In March 2010, the President signed into law comprehensive health care reform legislation under the Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act of 2010.  Included among the major provisions of the law is a change in the federal income tax treatment of a subsidy received by the Company to offset the cost of providing Medicare equivalent retiree prescription drug benefits, commonly referred to as the Medicare Part D subsidy.  Prior to the change in law, the deduction for retiree drug benefits excluded the government subsidy, effectively making the subsidy tax free.  Due to the change in tax treatment, the Company recorded a $2.3 million increase in its deferred tax liabilities, during the first quarter of 2010, related to the estimated $6.1 million accrued subsidy receivable.  Like tax law changes in the past, it is expected that the impact of this change will be reflected in customer rates in the future.  As a result, the Company has recorded a $4.6 million regulatory asset related to this matter in its financial statements at June 30, 2010.

6.    
Excise and Utility Receipts Taxes

Excise taxes and a portion of utility receipts taxes are included in rates charged to customers.  Accordingly, the Company records these taxes received as a component of operating revenues, which totaled $5.1 million and $5.8 million in the three months ended June 30, 2010 and 2009, respectively.  For the six months ended June 30, 2010 and 2009, these taxes totaled $20.4 million and $21.7 million, respectively.  Expenses associated with excise and utility receipts taxes are recorded as a component of Taxes other than income taxes.

7.    
Supplemental Cash Flow Information

As of June 30, 2010 and December 31, 2009, the Company has accruals related to utility and nonutility plant purchases totaling approximately $9.4 million and $12.4 million, respectively.  In addition, during the six months ended June 30, 2010, the Company purchased equipment totaling approximately $1.4 million using seller financed debt.

8.    
ProLiance Holdings, LLC

ProLiance Holdings, LLC (ProLiance), a nonutility energy marketing affiliate of Vectren and Citizens Energy Group (Citizens), provides services to a broad range of municipalities, utilities, industrial operations, schools, and healthcare institutions located throughout the Midwest and Southeast United States.  ProLiance’s customers include Vectren’s Indiana utilities and nonutility gas supply operations as well as Citizens’ utilities.  ProLiance’s primary businesses include gas marketing, gas portfolio optimization, and other portfolio and energy management services.  Consistent with its ownership percentage, Vectren 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.

Summarized Financial Information

                         
   
Three Months
   
Six Months
   
Ended June 30,
   
Ended June 30,
(In millions)
 
2010
   
2009
   
2010
   
2009
 
Summarized statement of income information:
                       
     Revenues
  $ 267.5     $ 300.2     $ 805.7     $ 959.0  
     Operating income (loss)
  $ (13.7 )   $ (7.4 )   $ 0.5     $ 13.9  
     Charge related to Investment in Liberty Gas Storage
  $ -     $ (32.7 )   $ -     $ (32.7 )
     ProLiance's earnings (loss)
  $ (13.7 )   $ (39.2 )   $ 0.6     $ (17.5 )
 
 
 
             
   
As of
 
   
June 30,
   
December 31,
 
(In millions)
 
2010
   
2009
 
Summarized balance sheet information:
           
     Current assets
  $ 383.2     $ 477.6  
     Noncurrent assets
  $ 60.1     $ 61.7  
     Current liabilities
  $ 183.7     $ 264.5  
     Noncurrent liabilities
  $ 4.9     $ 4.0  
     Members' equity
  $ 263.1     $ 282.4  
     Accumulated other comprehensive income (loss)
  $ (8.4 )   $ (11.6 )

Vectren records its 61 percent share of ProLiance’s earnings after income taxes, interest expense and cost allocations.

Investment in Liberty Gas Storage
Liberty Gas Storage, LLC (Liberty), a joint venture between a subsidiary of ProLiance and a subsidiary of Sempra Energy (SE), is a development project for salt-cavern natural gas storage facilities.  ProLiance is the minority member with a 25 percent interest, which it accounts for using the equity method.  The project was expected to include 17 Bcf of capacity in its north facility, and an additional 17 Bcf of capacity in its south facility. In 2009, the joint venture, with SE as the majority member, determined that only the south facility will be completed by the joint venture.  As a result, during the second quarter of 2009 the Company recorded an $11.9 million after tax charge associated with the north facility due to well-completion problems.  ProLiance’s investment in Liberty is $37.3 million at June 30, 2010.

Transactions with ProLiance
Purchases from ProLiance for resale and for injections into storage for the three months ended June 30, 2010 and 2009, totaled $77.8 and $99.3 million, respectively, and for the six months ended June 30, 2010 and 2009, totaled $241.2 and $302.3 million.  Amounts owed to ProLiance at June 30, 2010 and December 31, 2009 for those purchases were $25.4 million and $54.1 million, respectively, and are included in Accounts payable to affiliated companies in the Consolidated Balance Sheets.  Vectren received regulatory approval on April 25, 2006, from the IURC for ProLiance to provide natural gas supply services to the Company’s Indiana utilities through March 2011.  Amounts charged by ProLiance for gas supply services are established by supply agreements with each utility.

Subsequent Event
Subsequent to June 30, 2010, ProLiance declared a special dividend of $50 million to its members.  The Company received its share of the dividend totaling approximately $30 million in July 2010.

9.    
Haddington Energy Partnerships

The Company has an approximate 40 percent ownership interest in Haddington Energy Partners, LP (Haddington I) and Haddington Energy Partners II, LP (Haddington II).  These Haddington ventures have interests in two remaining mid-stream energy related investments.  Both Haddington ventures are investment companies accounted for using the equity method of accounting. 

As part of its second quarter closing procedures, the Company was notified by Haddington’s management that the fair value of its investment in a liquefied natural gas facility (LNG) had declined, and Haddington reflected that decline in its financial statements.  The Company recorded its share of the decline in fair value and also impaired a note receivable associated with the LNG investment.  In total, the charge was approximately $6.5 million, of which, $6.1 million is reflected in Equity in earnings of unconsolidated affiliates and $0.4 million is reflected in Other-net, for both the three and six months ended June 30, 2010.  At June 30, 2010, the Company’s remaining $3.3 million investment in the Haddington ventures is related to payments to be received associated with the sale of a compressed air storage facility sold in 2009.  The Company has no further commitments to invest in either Haddington I or II.  

10.  
Commitments & Contingencies

Corporate Guarantees
The Company issues corporate guarantees to certain vendors and customers of its wholly owned subsidiaries and unconsolidated affiliates.  These guarantees do not represent incremental consolidated obligations; rather, they represent parental guarantees of subsidiary and unconsolidated affiliate obligations in order to allow those subsidiaries and affiliates the flexibility to conduct business without posting other forms of collateral.  At June 30, 2010, corporate issued guarantees support a portion of Energy Systems Group’s (ESG) performance contracting commitments and warranty obligations described below.  In addition, the Company has approximately $66 million of other guarantees outstanding supporting other consolidated subsidiary operations, of which $53 million support non-regulated retail gas supply operations.  Guarantees issued and outstanding on behalf of unconsolidated affiliates approximated $3 million at June 30, 2010.  These guarantees relate primarily to arrangements between ProLiance and various natural gas pipeline operators.  The Company has not been called upon to satisfy any obligations pursuant to these parental guarantees and has accrued no significant liabilities related to these guarantees.

Performance Guarantees & Product Warranties
In the normal course of business, ESG and other wholly owned subsidiaries issue performance bonds or other forms of assurance that commit them to timely install infrastructure, operate facilities, pay vendors or subcontractors, and/or support warranty obligations.  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.
 
 
Specific to ESG, in its role as a general contractor in the performance contracting industry, at June 30, 2010, there are 73 open surety bonds supporting future performance.  The average face amount of these obligations is $3.4 million, and the largest obligation has a face amount of $30.4 million. These surety bonds are guaranteed by Vectren Corporation.  The maximum exposure of these obligations is less than these amounts for several factors, including the level of work already completed.  At June 30, 2010, approximately 58 percent of work was completed on projects with open surety bonds.  A significant portion of these commitments will be fulfilled 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.  In certain instances, these warranty obligations are also backed by Vectren Corporation.  The Company has no significant accruals for these warranty obligations as of June 30, 2010.

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.  
Environmental Matters

Clean Air Act
The Clean Air Interstate Rule (CAIR) is 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.  On July 11, 2008, the US Court of Appeals for the District of Columbia vacated the federal CAIR regulations.  Various parties filed motions for reconsideration, and on December 23, 2008, the Court reinstated the CAIR regulations and remanded the regulations back to the USEPA for promulgation of revisions in accordance with the Court’s July 11, 2008 order.  Thus, the original version of CAIR promulgated in March of 2005 remains effective while USEPA revises it per the Court’s guidance.  It is possible that a revised CAIR will require further reductions in NOx and SO2 from SIGECO’s generating units.  SIGECO is in compliance with the current CAIR Phase I annual NOx reduction requirements in effect on January 1, 2009 and the Phase I annual SO2 reduction requirements in effect on January 1, 2010.  Utilization of the Company’s inventory of NOx and SO2  allowances may also be impacted if CAIR is further revised.  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.

Similarly, in March of 2005, USEPA promulgated the Clean Air Mercury Rule (CAMR).  CAMR is an allowance cap and trade program requiring further reductions in mercury emissions from coal-burning power plants.  The CAMR regulations were vacated by the US Court of Appeals for the DC Circuit in July 2008.  In response to the court decision, USEPA has announced that it intends to publish proposed Maximum Achievable Control Technology standards for mercury in 2010.  It is uncertain what emission limit the USEPA is considering, and whether they will address hazardous pollutants in addition to mercury.  It is also possible that the vacatur of the CAMR regulations will lead to increased support for the passage of a multi-pollutant bill in Congress.

To comply with Indiana’s implementation plan of the Clean Air Act of 1990, the CAIR regulations, and to comply with potential future regulations of mercury and further NOx and SO2  reductions, SIGECO has IURC authority to invest in clean coal technology.  Using this authorization, SIGECO has invested approximately $411 million in pollution control equipment, including Selective Catalytic Reduction (SCR) systems, fabric filters, and an SO2 scrubber at its generating facility that is jointly owned with ALCOA (the Company’s portion is 150 MW).  Of the $411 million, $312 million was included in rate base for purposes of determining SIGECO’s new electric base rates that went into effect on August 15, 2007 and $99 million is currently recovered through a rider mechanism which is periodically updated for actual costs incurred including post in-service depreciation expense. As part of its recent rate proceeding, the Company has requested to also include these more recent expenditures in rate base as well.  SCR technology is the most effective method of reducing NOx emissions where high removal efficiencies are required and fabric filters control particulate matter emissions.  With the SO2 scrubber fully operational, SIGECO is in compliance with the additional SO2 reductions required by Phase I CAIR that commenced on January 1, 2010.

SIGECO’s coal fired generating fleet is 100 percent scrubbed for SO2 and 90 percent controlled for NOx.  SIGECO's investments in scrubber, SCR and fabric filter technology allows for compliance with existing regulations and should position it to comply with future reasonable mercury pollution control legislation, if and when, reductions are promulgated by USEPA.  On July 6, 2010, the USEPA issued its proposed revisions to CAIR, renamed the Transport Rule, for public comment.  The Transport Rule proposes a 71 percent reduction of SO2 over 2005 national levels and a 52 percent reduction of NOx over 2005 national levels.  The Company is currently reviewing the sufficiency of its existing pollution control equipment in relation to the requirements proposed in the Transport Rule.

Climate Change
The U.S. House of Representatives has passed a comprehensive energy bill that includes a carbon cap and trade program in which there is a progressive cap on greenhouse gas emissions and an auctioning and subsequent trading of allowances among those that emit greenhouse gases, a federal renewable portfolio standard, and utility energy efficiency targets.  Current proposed legislation also requires local natural gas distribution companies to hold allowances for the benefit of their customers.  As of the date of this filing, the Senate has not passed a bill, and the House bill is not law.  The U.S. Senate introduced a draft cap and trade proposal that is similar in structure to the House bill.  Numerous competing legislative proposals have also been introduced that involve carbon, energy efficiency, and renewable energy.

In the absence of federal legislation, several regional initiatives throughout the United States are in the process of establishing regional cap and trade programs.  While no climate change legislation is pending in Indiana, the state is an observer to the Midwestern Regional Greenhouse Gas Reduction Accord and the state’s legislature debated, but did not pass, a renewable energy portfolio standard in 2009.

In advance of a federal or state renewable portfolio standard, SIGECO received regulatory approval to purchase a 3 MW landfill gas generation facility from a related entity.  The facility was purchased in 2009 and is directly interconnected to the Company’s distribution system.  In 2009, the Company also executed a long term purchase power commitment for 50 MW of wind energy.  These transactions supplement a 30 MW wind energy purchase power agreement executed in 2008.

In April of 2007, the US Supreme Court determined that greenhouse gases meet the definition of "air pollutant" under the Clean Air Act and ordered the USEPA to determine whether greenhouse gas emissions from motor vehicles cause or contribute to air pollution that may reasonably be anticipated to endanger public health or welfare. In April of 2009, the USEPA published its proposed endangerment finding for public comment.  The proposed endangerment finding concludes that carbon emissions from mobile sources pose an endangerment to public health and the environment.  The endangerment finding was finalized in December of 2009, and is the first step toward USEPA regulating carbon emissions through the existing Clean Air Act in the absence of specific carbon legislation from Congress.  Therefore, any new regulations would likely also impact major stationary sources of greenhouse gases.  The USEPA has recently finalized a mandatory greenhouse gas emissions registry which will require reporting of emissions beginning in 2011 (for the emission year 2010).  The USEPA has also recently proposed a revision to the Prevention of Significant Deterioration (PSD) and Title V permitting rules which would require facilities that emit 25,000 tons or more of greenhouse gases a year to obtain a PSD permit for new construction or a significant modification of an existing facility.  If these proposed rules were adopted, they would apply to SIGECO’s generating facilities.

Impact of Legislative Actions & Other Initiatives is Unknown
If legislation requiring reductions in CO2 and other greenhouse gases or legislation mandating a renewable energy portfolio standard is adopted, such regulation could substantially affect both the costs and operating characteristics of the Company’s fossil fuel generating plants, nonutility coal mining operations, and natural gas distribution businesses.  Further, any legislation would likely impact the Company’s generation resource planning decisions.  At this time and in the absence of final legislation, compliance costs and other effects associated with reductions in greenhouse gas emissions or obtaining renewable energy sources remain uncertain.  The Company has gathered preliminary estimates of the costs to comply with a cap and trade approach to controlling greenhouse gas emissions.  A preliminary investigation demonstrated costs to comply would be significant, first with regard to operating expenses for the purchase of allowances, and later for capital expenditures as technology becomes available to control greenhouse gas emissions.  However, these compliance cost estimates are based on highly uncertain assumptions, including allowance prices and energy efficiency targets.  Costs to purchase allowances that cap greenhouse gas emissions or expenditures made to control emissions should be considered a cost of providing electricity, and as such, the Company believes recovery should be timely reflected in rates charged to customers.  Customer rates may also be impacted should decisions be made to reduce the level of sales to municipal and other wholesale customers in order to meet emission targets.

Ash Ponds & Coal Ash Disposal Regulations
In June 2010, the USEPA issued proposed regulations affecting the management and disposal of coal combustion products, such as ash generated by the Company’s coal-fired power plants.  The proposed rules more stringently regulate these byproducts and would likely increase the cost of operating or expanding existing ash ponds and the development of new ash ponds.   The USEPA did not offer a preferred alternative, but is taking public comment on multiple alternative regulations.  The alternatives include regulating coal combustion by-products as hazardous waste.  At this time, the majority of the Company’s ash is being beneficially reused.  The proposals offered by USEPA allow for the beneficial reuse of ash in certain circumstances. 

Environmental Remediation Efforts
In the past, Indiana Gas, SIGECO, and others operated facilities for the manufacture of gas.  Given the availability of natural gas transported by pipelines, these facilities have not been operated for many years.  Under currently applicable 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 at these sites.

Indiana Gas identified the existence, location, and certain general characteristics of 26 gas manufacturing and storage sites for which it may have some remedial responsibility.  Indiana Gas completed a remedial investigation/feasibility study (RI/FS) at one of the sites under an agreed order between Indiana Gas and the IDEM, and a Record of Decision was issued by the IDEM in January 2000.  Indiana Gas submitted the remainder of the sites to the IDEM's Voluntary Remediation Program  (VRP) and is currently conducting some level of remedial activities, including groundwater monitoring at certain sites, where deemed appropriate, and will continue remedial activities at the sites as appropriate and necessary.

Indiana Gas 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, Indiana Gas has recorded cumulative costs that it reasonably expects to incur totaling approximately $23.3 million.  The estimated accrued costs are limited to Indiana Gas’ share of the remediation efforts.  Indiana Gas has arrangements in place for 19 of the 26 sites with other potentially responsible parties (PRP), which limit Indiana Gas’ costs at these 19 sites to between 20 percent and 50 percent.

With respect to insurance coverage, Indiana Gas has settled with all known insurance carriers under insurance policies in effect when these plants were in operation in an aggregate amount approximating $20.8 million.

In October 2002, SIGECO received a formal information request letter from the IDEM regarding five manufactured gas plants that it owned and/or operated and were not enrolled in the IDEM’s VRP.  In October 2003, SIGECO filed applications to enter four of the manufactured gas plant sites in IDEM's VRP.  The remaining site is currently being addressed in the VRP by another Indiana utility.  SIGECO added those four sites into the renewal of the global Voluntary Remediation Agreement that Indiana Gas has in place with IDEM for its manufactured gas plant sites.  That renewal was approved by the IDEM in February 2004.  SIGECO was also named in a lawsuit filed in federal district court in May 2007, involving another waste disposal site subject to potential environmental remediation efforts.  With respect to that lawsuit, in May 2010, SIGECO settled with the plaintiff mitigating any future claims at this site.  SIGECO has filed a declaratory judgment action against its insurance carriers seeking a judgment finding its carriers liable under the policies for coverage of further investigation and any necessary remediation costs that SIGECO may accrue under the VRP program and/or related to the site subject to the recently settled lawsuit.

SIGECO has recorded cumulative costs that it reasonably expects to incur related to these environmental matters, including the recent settlement, totaling approximately $15.8 million.  However, the total costs that may be incurred in connection with addressing all of these sites cannot be determined at this time.  With respect to insurance coverage, SIGECO has recorded approximately $12.6 million in insurance proceeds from certain of its insurance carriers under insurance policies in effect when these sites were in operation.  While negotiations are ongoing with certain carriers, settlements have been reached with some carriers and $8.1 million in proceeds have been received.  SIGECO has undertaken significant remediation efforts at two MGP sites.

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 some level of additional remedial activities which are not presently foreseen and those costs may not be subject to PRP or insurance recovery.  As of June 30, 2010 and December 31, 2009, approximately $9.5 million and $6.5 million of accrued, but not yet spent, costs are included in Other Liabilities related to both the Indiana Gas and SIGECO sites.

12.  
Rate & Regulatory Matters

Vectren South Electric Base Rate Filings
On December 11, 2009, Vectren South filed a request with the IURC to adjust its electric base rates in its south service territory.  The requested increase in base rates addresses capital investments, a modified electric rate design that facilitates a partnership between Vectren South and customers to pursue energy efficiency and conservation, and new energy efficiency programs to complement those currently offered for natural gas customers.  On July 30, 2010, Vectren South revised its increase requested through the filing of its rebuttal position to approximately $34 million. The request addresses the roughly $325 million spent in infrastructure construction since its last base rate increase in August 2007 that was needed to continue to provide reliable service and updates to operating costs and revenues.  The rate design proposed in the filing would break the link between small residential and commercial customers’ consumption and the utility’s margin, thereby aligning the utility’s and customers’ interests in using less energy.  The revised request assumes an overall rate of return of 7.42 percent on rate base of approximately $1.3 billion and an allowed return on equity (ROE) of 10.7 percent.  The OUCC and SIGECO Industrial Group separately filed testimony in this case, proposing an increase of approximately $11 million and $18 million, respectively.  Furthermore, the intervening parties in the case took differing views on, among other matters, the proposed rate design and the level and price of coal inventory.  A hearing on all matters in the case is scheduled for late August 2010.  Based on the current procedural schedule, an order is likely in the first quarter of 2011.

Vectren South Electric Fuel Adjustment Filings
Electric retail rates contain a fuel adjustment clause (FAC) that allows for periodic adjustment in energy to reflect changes in the cost of fuel and purchased power.  These FAC procedures involve periodic filings and IURC hearings to approve the recovery of Vectren South’s fuel and purchased power costs.

In its latest FAC hearing, the OUCC requested the IURC order Vectren South to renegotiate its coal contracts because they are currently above market prices.  This request is consistent with the OUCC’s position taken in Vectren South’s base rate proceeding referred to above.  Vectren South purchases the majority of its coal from Vectren Fuels, Inc. (a nonutility wholly owned subsidiary of the Company) under coal contracts entered into in 2008.  Vectren South states in its filed position that the prices in the coal contracts were at or below the market at the time of contract execution.  Further, Vectren South has already engaged in some contract renegotiations allowing for contract deferrals and reducing volumes in 2011, with negotiation to come for market pricing under the terms of the contracts for 2012 or later deliveries.  Moreover, the IURC has already found in a number of FAC proceedings since 2008 that the costs incurred under these coal contracts are reasonable.

The OUCC also raised concerns regarding Vectren South’s generating unit “must run” policy.  Under that policy, for reliability reasons, Vectren South instructs the MISO that certain units must be dispatched regardless of current market conditions.  The OUCC is reviewing data related to Vectren South’s “must run” policy.
  
To allow the FAC to be approved on a timely basis, the parties agreed to the creation of a sub docket proceeding to address the specific issues noted above.  At this point, both the timing and potential impacts of the sub docket proceeding, if any, are not known.  An order establishing the sub docket was issued by the IURC on July 28, 2010 and noted that the parties to the FAC proceeding agreed that the recovery of fuel costs in the current FAC would not be subject to refund.

Straight Fixed Variable Rate Design Fully Implemented in Vectren Ohio’s Service Territory
On January 7, 2009 the PUCO issued a rate Order allowing for a two-phase transition to a straight fixed variable rate design to be fully implemented by February 22, 2010 for all residential and some commercial customers.  This type of rate design places substantially all of the fixed cost recovery in the customer service charge; and, therefore, mitigates most weather risk as well as the effects of declining usage.  Starting in February 2010, nearly 90 percent of the combined residential and commercial base rate margins are recovered through the customer service charge.  The OCC has appealed this rate order to the Ohio Supreme Court.  The appeal is substantially the same as appeals filed by the OCC in two other cases in which the PUCO approved similar rate designs.  The Ohio Supreme Court affirmed the PUCO orders authorizing straight fixed variable rate design in the other two cases. The OCC’s appeal related to the Company’s case has not yet been decided. 

Vectren Ohio Continues the Process to Exit the Merchant Function
The second phase of VEDO’s exiting the merchant function began on April 1, 2010.  During this phase, the Company no longer sells natural gas directly to customers.  Rather, state-certified Competitive Retail Natural Gas Suppliers, that were successful bidders in a regulatory-approved auction, sell the gas commodity to specific customers for a 12 month period at auction-determined standard pricing.  That auction was conducted on January 12, 2010, and the auction results were approved by the PUCO on January 13.  Vectren Source, the Company’s nonutility retail gas marketer, was a successful bidder on one tranche of customers.  The plan approved by the PUCO requires that the Company conduct at least two auctions during this phase.  As such, the Company will conduct another auction in advance of the second 12-month term, which will commence on April 1, 2011.  Consistent with current practice, customers will continue to receive one bill for the delivery of natural gas service. 

The PUCO provided for an Exit Transition Cost rider, which allows the Company to recover costs associated with the transition process.  The impact of exiting the merchant function should not have a material impact on Company earnings or financial condition.  It, however, has and will continue to reduce Gas utility revenues and have an equal and offsetting impact to Cost of gas sold as VEDO no longer purchases gas for resale to these customers.

MISO
The Company is a member of the MISO, a FERC approved regional transmission organization.  When the Company is a net seller of its generation, such net revenues, which totaled $3.8 million and $3.0 million for the three months ended June 30, 2010 and 2009, respectively, are included in Electric utility revenues.  For the six months ended June 30, 2010 and 2009, such net revenues totaled $13.6 million and $13.2 million, respectively.  When the Company is a net purchaser such net purchases, which totaled $12.5 million and $12.2 million for the three months ended June 30, 2010 and 2009, respectively, are included in Cost of fuel & purchased power.  For the six months ended June 30, 2010 and 2009, such purchases totaled $21.5 million and $16.5 million, respectively.  Net positions are determined on an hourly basis.

The Company also receives transmission revenue from the MISO, which is included in Electric utility revenues and totaled $5.8 million and $3.6 million for the three months ended June 30, 2010 and 2009, respectively.  For the six months ended June 30, 2010 and 2009, transmission revenue from the MISO totaled $10.6 million and $6.6 million, respectively.  These revenues result from other MISO members’ use of the Company’s transmission system, as well as the recovery of the Company’s investment in certain new electric transmission projects meeting MISO’s transmission expansion plan criteria.

13.  
Fair Value Measurements

The carrying values and estimated fair values of the Company's other financial instruments follow:

                         
   
June 30, 2010
   
December 31, 2009
 
(In millions)
 
Carrying
Amount
 
Est. Fair Value
   
Carrying
Amount
 
Est. Fair Value
 
     Long-term debt
  $ 1,639.8     $ 1,792.9     $ 1,639.8     $ 1,720.1  
     Short-term borrowings & notes payable
    145.6       145.6       213.5       213.5  
     Cash & cash equivalents
    16.8       16.8       11.9       11.9  

For the balance sheet dates presented in these financial statements, other than $13.6 million invested in money market funds and included in Cash and cash equivalents as of June 30, 2010, the Company had no material assets or liabilities recorded at fair value outstanding, and no material assets or liabilities valued using Level 2 or Level 3 inputs.  The money market investments were valued using Level 1 inputs.

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

Under current regulatory treatment, call premiums on reacquisition of utility 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 would not be expected to have a material effect on the Company's results of operations.

Because of the customized nature of notes receivable 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, 2010 and December 31, 2009, the fair value for these financial instruments was not estimated.  The carrying value of notes receivable, inclusive of any accrued interest and net of impairment reserves, was approximately $10.9 million at June 30, 2010 and $16.7 million at December 31, 2009.

14.  
Impact of Other Newly Adopted and Newly Issued Accounting Guidance

Variable Interest Entities
In June 2009, the FASB issued new accounting guidance regarding variable interest entities (VIE’s).  This new guidance is effective for annual reporting periods beginning after November 15, 2009.  This guidance requires a qualitative analysis of which holder of a variable interest controls the VIE and if that interest holder must consolidate a VIE.  Additionally, it requires additional disclosures and an ongoing reassessment of who must consolidate a VIE.  The Company adopted this guidance on January 1, 2010. The adoption did not have any impact on the consolidated financial statements.

Fair Value Measurements & Disclosures
In January 2010, the FASB issued new accounting guidance on improving disclosures about fair market value.  This guidance amends prior disclosure requirements involving fair value measurements to add new requirements for disclosures about transfers into and out of Levels 1 and 2 and separate disclosures about purchases, sales, issuances, and settlements relating to Level 3 measurements. The guidance also clarifies existing fair value disclosures in regard to the level of disaggregation and about inputs and valuation techniques used to measure fair value.  The guidance also amends prior disclosure requirements regarding postretirement benefit plan assets to require that disclosures be provided by classes of assets instead of major categories of assets.  This guidance is effective for the first reporting period beginning after December 15, 2009.  The Company adopted this guidance for its 2010 reporting.  Due to the low level of items carried at fair value in the Company’s financial statements, the adoption has not had any material impact.

15.  
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 into a Gas Utility Services operating segment and an Electric Utility Services operating segment.  The Gas Utility Services segment provides natural gas distribution and transportation services to nearly two-thirds of Indiana and to west central Ohio.  The Electric Utility Services segment provides electric distribution services primarily to southwestern Indiana, and includes the Company’s power generating and wholesale power operations.  The Company manages its regulated operations as separated between Energy Delivery, which includes the gas and electric transmission and distribution functions, and Power Supply, which includes the power generating and wholesale power operations.  In total, regulated operations supply natural gas and /or electricity to over one million customers.

The Nonutility Group is comprised of one operating segment that includes various subsidiaries and affiliates investing in energy marketing and services, coal mining, and energy infrastructure services, among other energy-related opportunities.

Corporate and Other includes unallocated corporate expenses such as advertising and charitable contributions, among other activities, that benefit the Company’s other operating segments.  Net income is the measure of profitability used by management for all operations.  Information related to the Company’s business segments is summarized below:

                         
   
Three Months
   
Six Months
 
   
Ended June 30,
   
Ended June 30,
 
(In millions)
 
2010
   
2009
   
2010
   
2009
 
Revenues
                       
     Utility Group
                       
          Gas Utility Services
  $ 122.9     $ 139.1     $ 591.0     $ 666.5  
          Electric Utility Services
    151.0       132.7       295.9       257.7  
          Other Operations
    11.1       10.7       22.2       21.4  
          Eliminations
    (10.7 )     (10.3 )     (21.4 )     (20.6 )
               Total Utility Group
    274.3       272.2       887.7       925.0  
     Nonutility Group
    168.0       137.2       352.8       328.4  
     Eliminations
    (39.9 )     (33.9 )     (97.8 )     (82.7 )
     Consolidated Revenues
  $ 402.4     $ 375.5     $ 1,142.7     $ 1,170.7  
                                 
Profitability Measure - Net Income (Loss)
                               
     Utility Group
                               
          Gas Utility Services
  $ 0.1     $ (3.3 )   $ 39.9     $ 37.9  
          Electric Utility Services
    14.3       8.3       26.7       20.2  
          Other Operations
    1.8       1.6       5.0       4.7  
               Utility Group Net Income
    16.2       6.6       71.6       62.8  
     Nonutility Group Net Income (Loss)
    (7.5 )     (13.0 )     0.3       3.5  
     Corporate & Other Group Net Income (Loss)
    -       (0.3 )     -       (0.2 )
     Consolidated Net Income (Loss)
  $ 8.7     $ (6.7 )   $ 71.9     $ 66.1  

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

Description of the Business

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), serves as the intermediate holding company for three public utilities:  Indiana Gas Company, Inc. (Indiana Gas or Vectren North), Southern Indiana Gas and Electric Company (SIGECO or Vectren South), and the Ohio operations.  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 over 563,000 natural gas customers located in central and southern Indiana.  SIGECO provides energy delivery services to over 141,000 electric customers and approximately 110,000 gas customers located near Evansville in southwestern Indiana.  SIGECO also owns and operates electric generation assets to serve its electric customers and optimizes those assets in the wholesale power market.  Indiana Gas and SIGECO generally do business as Vectren Energy Delivery of Indiana.  The Ohio operations provide energy delivery services to approximately 313,000 natural gas customers located near Dayton in west central Ohio.  The Ohio operations are owned as a tenancy in common by Vectren Energy Delivery of Ohio, Inc. (VEDO), a wholly owned subsidiary of Utility Holdings (53 percent ownership), and Indiana Gas (47 percent ownership).  The Ohio operations generally do business as Vectren Energy Delivery of Ohio.

The Company, through Vectren Enterprises, Inc. (Enterprises), is involved in nonutility activities in three primary business areas:  Energy Marketing and Services, Coal Mining, and Energy Infrastructure Services.  Energy Marketing and Services markets and supplies natural gas and provides energy management services.  Coal Mining mines and sells coal.  Energy Infrastructure Services provides underground construction and repair services and performance contracting and renewable energy services.  Enterprises also has other legacy businesses that have invested in energy-related opportunities and services, real estate, and leveraged leases, among other investments.  These operations are collectively referred to as the Nonutility Group.  Enterprises supports the Company’s regulated utilities pursuant to service contracts by providing natural gas supply services, coal, and infrastructure services.

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.  Nonutility Group operations are discussed below as primary operations and other operations.  Primary nonutility operations denote areas of management’s forward looking focus.

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 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.

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 2009 annual report filed on Form 10-K.

Summary results for the three and six months ended June 30, 2010 and 2009 follow:
                         
   
Three Months
   
Six Months
 
   
Ended June 30,
   
Ended June 30,
 
(In millions, except per share data)
 
2010
   
2009
   
2010
   
2009
 
Net income (loss)
  $ 8.7     $ (6.7 )   $ 71.9     $ 66.1  
     Attributed to:
                               
          Utility Group
    16.2       6.6       71.6       62.8  
          Nonutility Group
    (7.5 )     (13.0 )     0.3       3.5  
          Corporate & other
    -       (0.3 )     -       (0.2 )
                                 
Basic EPS
  $ 0.11     $ (0.08 )   $ 0.89     $ 0.82  
     Attributed to:
                               
          Utility Group
    0.20       0.08       0.89       0.78  
          Nonutility Group
    (0.09 )     (0.16 )     -       0.04  
          Corporate & other
    -       -       -       -  

Results
For the three months ended June 30, 2010, net income was $8.7 million, or $0.11 per share, compared to a net loss $6.7 million, or $0.08 per share for the three months ended June 30, 2009.  For the six months ended June 30, 2010, net income was $71.9 million, or $0.89 per share, compared to net income $66.1 million, or $0.82 per share in the six months ended June 30, 2009.  The 2010 second quarter and year to date periods were impacted by charges related to legacy investments totaling $4.0 million after tax, or $0.05 per share, and $6.8 million after tax, or $0.08 per share, respectively.  The 2009 results for both the quarter and year to date periods include an $11.9 million after tax, or $0.15 per share, charge related to an investment by ProLiance Energy, LLC in Liberty Gas Storage, LLC.

Utility Group
In the second quarter of 2010, the Utility Group’s earnings were $16.2 million, compared to $6.6 million in 2009, an increase of $9.6 million.  Year to date, 2010 utility earnings were $71.6 million, compared to $62.8 million in 2009, an increase of $8.8 million.  The increases result from large customer usage and summer weather significantly warmer than normal and the prior year and lower operating costs.  Results during the periods presented have also been impacted by rate design changes in the Ohio service territory and volumetric margins from other regulatory initiatives. Depreciation and interest expense associated with rate base growth and the long-term financing associated with those investments have increased over the prior year periods.

The rate design approved by the PUCO on January 7, 2009, and initially implemented on February 22, 2009, allowed for the phased movement toward a straight fixed variable rate design, which places substantially all of the fixed cost recovery in the customer service charge.  This rate design mitigates most weather risk as well as the effects of declining usage, similar to the Company’s lost margin recovery mechanism in place in the Indiana natural gas service territories and the mechanism in place in Ohio prior to this rate order.  Starting in February 2010, nearly 90 percent of the combined residential and commercial base rate margins began being recovered through the customer service charge.  As a result, some margin previously recovered during the peak delivery winter months is more ratably recognized throughout the year.  Though there have been quarterly variances in 2010, year to date, the impact of this rate design change is essentially flat compared to the prior year.  By year end results are expected to increase by $0.02 per share representing the full impact of the base rate change compared to the partial year of the new rates in the prior year.

In the Company’s electric territory, management estimates the margin impact of weather to be approximately $4.8 million favorable, or $0.04 per share, compared to normal temperatures in the second quarter of 2010 and $5.6 million favorable, or $0.04 per share, compared to normal temperatures year to date in 2010.  This compares to 2009, where management estimated a $2.2 million, or $0.02 per share, favorable impact on margin compared to normal in the second quarter and $1.6 million, or $0.01 per share, year to date.

Nonutility Group
The Nonutility Group’s 2010 second quarter loss was $7.5 million compared to a loss of $13.0 million in 2009.  Year to date in 2010, nonutility earnings were $0.3 million compared to earnings of $3.5 million in 2009.  The 2010 second quarter and year to date periods were impacted by charges related to legacy investments totaling $4.0 million after tax and $6.8 million after tax, respectively.  The 2009 results for both the quarter and year to date periods contain the $11.9 million after tax Liberty Charge.  After the impacts of these charges, other operating results decreased by approximately $2.4 million in the quarter and $8.3 million year to date in 2010 compared to 2009.  These decreases were driven primarily by lower results from Energy Marketing and Services, primarily at ProLiance, offset by earnings growth in primarily coal mining operations.   

Dividends

Dividends declared for the three months ended June 30, 2010, were $0.340 per share compared to $0.335 per share for the same period in 2009.  Dividends declared for the six months ended June 30, 2010, were $0.680 per share compared to $0.670 per share for the same period in 2009.

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 operations are presented and analyzed before the reclassification and elimination of certain intersegment transactions necessary to consolidate those results into the Company’s Consolidated Statements of Income.
 
Results of Operations of the Utility Group

The Utility Group is comprised of Utility Holdings’ operations.  The operations of the Utility Group consist of the Company’s regulated 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 distribution services primarily to southwestern Indiana, and the Company’s 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, 2010 and 2009 follow:
                         
   
Three Months
   
Six Months
 
   
Ended June 30,
   
Ended June 30,
 
(In millions, except per share data)
 
2010
   
2009
   
2010
   
2009
 
OPERATING REVENUES
                       
     Gas utility
  $ 122.9     $ 139.1     $ 591.0     $ 666.5  
     Electric utility
    151.0       132.7       295.9       257.7  
     Other
    0.4       0.4       0.8       0.8  
          Total operating revenues
    274.3       272.2       887.7       925.0  
OPERATING EXPENSES
                               
     Cost of gas sold
    41.5       58.0       339.3       412.6  
     Cost of fuel & purchased power
    57.8       50.3       115.8       97.3  
     Other operating
    71.2       78.7       152.8       158.0  
     Depreciation & amortization
    46.8       45.0       93.3       88.9  
     Taxes other than income taxes
    11.6       12.6       33.9       35.4  
          Total operating expenses
    228.9       244.6       735.1       792.2  
                                 
OPERATING INCOME
    45.4       27.6       152.6       132.8  
                                 
OTHER INCOME - NET
    0.8       2.5       3.0       4.0  
                                 
INTEREST EXPENSE
    20.3       20.0       40.6       38.7  
                                 
INCOME BEFORE INCOME TAXES
    25.9       10.1       115.0       98.1  
                                 
INCOME TAXES
    9.7       3.5       43.4       35.3  
                                 
NET INCOME
  $ 16.2     $ 6.6     $ 71.6     $ 62.8  
                                 
CONTRIBUTION TO VECTREN BASIC EPS
  $ 0.20     $ 0.08     $ 0.89     $ 0.78  

Trends in Utility Operations

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.

Rate Design Strategies
Sales of natural gas and electricity to residential and commercial customers are seasonal and are impacted by weather.  Trends in average use among natural gas residential and commercial customers have tended to decline in recent years as more efficient appliances and furnaces are installed and the price of natural gas has been volatile.  In the Company’s two Indiana natural gas service territories, normal temperature adjustment (NTA) and decoupling mechanisms largely mitigate the effect on Gas Utility margin that would otherwise be caused by variations in volumes sold to these customers due to weather and changing consumption patterns.  The Ohio natural gas service territory has a straight fixed variable rate design.  This rate design, which was fully implemented in February 2010, mitigates most of the Ohio service territory’s weather risk and risk of decreasing consumption.  In all natural gas service territories, commissions have authorized bare steel and cast iron replacement programs.  SIGECO’s electric service territory has neither an NTA nor decoupling mechanisms; however, rate designs proposed in a recently filed rate case would limit weather risk and provide a decoupling mechanism that works in tandem with the conservation initiative, similar to rate designs in place in the Indiana natural gas service territories. 

Tracked Operating Expenses
Margin is also impacted by the collection of state mandated taxes, which fluctuate with gas and fuel costs, as well as other tracked expenses.  In Indiana, gas pipeline integrity management costs, costs to fund energy efficiency programs, MISO transmission revenues and costs, unaccounted for gas, and the gas cost component of uncollectible accounts expense based on historical experience are tracked.  Certain operating costs, including depreciation, associated with operating environmental compliance equipment at electric generation facilities and regional electric transmission investments are also tracked.  In Ohio expenses such as uncollectible accounts expense, percent of income payment plan expenses, costs associated with exiting the merchant function, costs to perform service riser replacement , and unaccounted for gas are subject to tracking mechanisms.

Recessionary Impacts
Gas and electric margin generated from sales to large customers (generally industrial and other contract customers) is primarily impacted by overall economic conditions and changes in demand for those customers’ products.  The impact of the recession has had and may continue to have some negative impact on sales to and usage by both gas and electric large customers.  This impact has included, and may continue to include, tempered growth, significant conservation measures, and increased plant closures and bankruptcies.  Deteriorating economic conditions also resulted in lower residential and commercial customer counts.  Further, resulting from the lower wholesale power prices, decreased demand for electricity and higher coal prices, the Company’s coal-fired generation has been dispatched less often by the MISO.  This has resulted in lower wholesale sales, more power being purchased from the MISO for native load requirements, and larger coal inventories.  During the first half of 2010, the Company has experienced some improvement in economic conditions, but stability of the economy in general remains uncertain.

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
   
Six Months
 
   
Ended June 30,
   
Ended June 30,
 
(In millions)
 
2010
   
2009
   
2010
   
2009
 
Gas utility revenues
  $ 122.9     $ 139.1     $ 591.0     $ 666.5  
Cost of gas sold
    41.5       58.0       339.3       412.6  
     Total gas utility margin
  $ 81.4     $ 81.1     $ 251.7     $ 253.9  
Margin attributed to:
                               
     Residential & commercial customers
  $ 68.1     $ 68.5     $ 218.1     $ 221.1  
     Industrial customers
    10.2       9.3       26.4       24.4  
     Other
    3.1       3.3       7.2       8.4  
     Total gas utility margin
  $ 81.4     $ 81.1     $ 251.7     $ 253.9  
Sold & transported volumes in MMDth attributed to:
         
     Residential & commercial customers
    8.9       12.6       63.5       65.2  
     Industrial customers
    19.2       15.7       45.8       39.8  
          Total sold & transported volumes
    28.1       28.3       109.3       105.0  
 
Gas utility margins were $81.4 million and $251.7 million for the three and six months ended June 30, 2010, and compared to 2009 increased $0.3 million in the quarter and decreased $2.2 million year to date.  Management estimates a $2.0 million increase in margin during the quarter and a $0.4 million decrease year to date due to the Ohio rate design change.  Large customer margin increased by $1.1 million in the quarter and $2.1 million year to date due primarily to increased volumes sold.  Margin decreased $2.4 million quarter over quarter and $2.0 million year to date due to changes in operating expenses directly recovered in margin.  The remaining decrease is primarily due to lower miscellaneous revenues and other revenues associated with lower gas costs.  The average cost per dekatherm of gas purchased for the six months ended June 30, 2010 was $6.42 compared to $6.53 in 2009.

Electric Utility Margin (Electric utility revenues less Cost of fuel & purchased power)
Electric utility margin and volumes sold by customer type follows:

                         
   
Three Months
   
Six Months
   
Ended June 30,
   
Ended June 30,
 
(In millions)
 
2010
   
2009
   
2010
   
2009
 
                         
Electric utility revenues
  $ 151.0     $ 132.7     $ 295.9     $ 257.7  
Cost of fuel & purchased power
    57.8       50.3       115.8       97.3  
     Total electric utility margin
  $ 93.2     $ 82.4     $ 180.1     $ 160.4  
Margin attributed to:
                               
     Residential & commercial customers
  $ 60.4     $ 56.9     $ 115.8     $ 109.0  
     Industrial customers
    24.8       20.3       47.2       38.9  
     Other customers
    1.4       1.2       3.1       2.8  
     Subtotal: retail
  $ 86.6     $ 78.4     $ 166.1     $ 150.7  
     Wholesale power & transmission system margin
    6.6       4.0       14.0       9.7  
     Total electric utility margin
  $ 93.2     $ 82.4     $ 180.1     $ 160.4  
                                 
Electric volumes sold in GWh attributed to:
                               
     Residential & commercial customers
    716.5       680.5       1,428.4       1,352.1  
     Industrial customers
    697.1       557.4       1,307.5       1,066.4  
     Other customers
    5.1       4.5       11.1       9.6  
          Total retail volumes sold
    1,418.7       1,242.4       2,747.0       2,428.1  
 
Retail
Electric retail utility margins were $­­­­86.6 million and $166.1 million for the three and six months ended June 30, 2010, and compared to 2009 increased over the prior year periods by $8.2 million and $15.4 million, respectively.  Increased margin among the customer classes associated with returns on pollution control investments totaled $1.0 million quarter over quarter and $2.6 million year to date, and margin associated with tracked costs such as recovery of MISO and pollution control operating expenses increased $0.7 million quarter over quarter and $2.0 million year to date.  Management estimates the impact of warmer than normal weather to have increased residential and commercial margin $2.6 million in the second quarter and $4.0 million year to date compared to the prior year periods.  Management also estimates industrial margins, net of the impacts of regulatory initiatives and recovery of tracked costs, to have increased approximately $3.5 million in the quarter and $6.7 million year to date due primarily to increased volumes.

Margin from Wholesale Electric Activities
Periodically, generation capacity is in excess of native load.  The Company markets and sells this unutilized generating and transmission capacity to optimize the return on its owned assets.  Substantially all off-system sales occur into the MISO Day Ahead and Real Time markets.

Further detail of Wholesale activity follows:
                         
   
Three Months
   
Six Months
 
   
Ended June 30,
   
Ended June 30,
 
(In millions)
 
2010
   
2009
   
2010
   
2009
 
Off-system sales
  $ 0.8     $ 0.4     $ 3.4     $ 3.1  
Transmission system sales
    5.8       3.6       10.6       6.6  
     Total wholesale margin
  $ 6.6     $ 4.0     $ 14.0     $ 9.7  

For the three and six months ended June 30, 2010, wholesale margin was $6.6 million and $14.0 million, representing an increase of $2.6 million and $4.3 million, respectively, compared to 2009.

The Company earns a return on electric transmission projects constructed by the Company in its service territory that meet the criteria of Midwest Independent System Operator’s (MISO) transmission expansion plans.  Margin associated with these projects and other transmission system operations totaled $5.8 million and $10.6 million for the three and six months ended June 30, 2010, respectively, compared to $3.6 million and $6.6 million in both the three and six months ended June 30, 2009.  Increases are primarily due to increased investment in qualifying projects.

During 2010, margin from off-system sales retained by the company was generally flat compared to the prior year periods.  The base rate case effective August 17, 2007, requires that wholesale margin from off-system sales earned above or below $10.5 million be shared equally with customers as measured on a fiscal year ending in August, and results reflect the impact of that sharing.

Purchased Power
As a result of being dispatched less often by the MISO and executing long-term purchased power agreements with nearby wind farms, the Company has more frequently been a purchaser of power.  For the three and six months ended June 30, 2010, the Company purchased approximately 337 GWh and 578 GWh of power from the MISO and other sources, compared to 336 GWh and 451 GWh for the same periods in 2009.  The total cost associated with these volumes of purchased power is approximately $15.0 million and $27.1 million for the three and six months ended June 30, 2010, respectively, and is included in the Cost of fuel & purchased power.  For the three and six months ended June 30, 2009, the total cost was $14.5 million and $21.2 million, respectively.

Utility Group Operating Expenses

Other Operating
For the three and six months ended June 30, 2010, other operating expenses were $ 71.2 million and $152.8 million, which reflect decreases of $7.5 million and $5.2 million, respectively, compared to 2009.  Excluding expenses recovered directly in margin, operating costs have decreased $6.7 million in the quarter and $6.6 million year to date.  The primary drivers of the decreases result from lower power supply operating expenses due to the timing of maintenance and outages compared to 2009, lower levels of Indiana uncollectible accounts expenses due in part to lower gas costs, and the level of expense associated with deferred compensation plans.

Depreciation & Amortization
For the three and six months ended June 30, 2010, depreciation expense was $46.8 million and $93.3 million, which represents increases of $1.8 million and $4.4 million compared to 2009.  This increase is reflective of  utility expenditures placed into service.

Taxes Other Than Income Taxes
For the three and six months ended June 30, 2010, taxes other than income taxes were $11.6 million and $33.9 million, respectively, which reflect decreases of $1.0 million for the quarter and $1.5 million year over year.  The decreases are primarily attributable to lower utility receipts, excise, and usage taxes that are directly offset in margin.

Other Income-Net

Other income-net reflects income of $0.8 million and $3.0 million for the three and six months ended June 30, 2010, compared to $2.5 million and $4.0 million for the same periods in 2009. The decreases are primarily attributable to the change in market values associated with investments related to benefit plans.

Interest Expense

For the three and six months ended June 30, 2010, interest expense was $20.3 million and $40.6 million, which represents increases of $0.3 million in the quarter and $1.9 million year over year compared to 2009.  These small increases reflect the impact of long-term financing transactions completed in 2009, offset by lower interest from less debt outstanding overall.  The long-term financing transactions include a second quarter issuance by Utility Holdings of $100 million in unsecured eleven year notes with an interest rate of 6.28 percent and a third quarter completion by SIGECO of a $22.3 million debt issuance of 31 year tax exempt first mortgage bonds with an interest rate of 5.4 percent.

Income Taxes

For the three and six months ended June 30, 2010, federal and state income taxes were $9.7 million and $43.4 million, which represent increases of $6.2 million and $8.1 million compared to 2009.  The higher taxes are primarily due to increased pretax income.  The year to date increase is also reflective of a lower effective rate in 2009 due to tax adjustments recorded in 2009.

During the first quarter of 2010, the Company recorded a $2.3 million increase to its deferred tax liabilities associated with a change in the federal tax treatment of the Medicare Part D subsidy as a result of the Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act of 2010 signed by the President as of the end of March 2010.  Like tax law changes in the past, it is expected that the impact of this change will be reflected in customer rates in the future.  As a result, the Company has recorded a $4.6 million regulatory asset related to this matter in its financial statements at June 30, 2010.

Environmental Matters

Clean Air Act
The Clean Air Interstate Rule (CAIR) is 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.  On July 11, 2008, the US Court of Appeals for the District of Columbia vacated the federal CAIR regulations.  Various parties filed motions for reconsideration, and on December 23, 2008, the Court reinstated the CAIR regulations and remanded the regulations back to the USEPA for promulgation of revisions in accordance with the Court’s July 11, 2008 order.  Thus, the original version of CAIR promulgated in March of 2005 remains effective while USEPA revises it per the Court’s guidance.  It is possible that a revised CAIR will require further reductions in NOx and SO2 from SIGECO’s generating units.  SIGECO is in compliance with the current CAIR Phase I annual NOx reduction requirements in effect on January 1, 2009 and the Phase I annual SO2 reduction requirements in effect on January 1, 2010.  Utilization of the Company’s inventory of NOx and SO2  allowances may also be impacted if CAIR is further revised.  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.

Similarly, in March of 2005, USEPA promulgated the Clean Air Mercury Rule (CAMR).  CAMR is an allowance cap and trade program requiring further reductions in mercury emissions from coal-burning power plants.  The CAMR regulations were vacated by the US Court of Appeals for the DC Circuit in July 2008.  In response to the court decision, USEPA has announced that it intends to publish proposed Maximum Achievable Control Technology standards for mercury in 2010.  It is uncertain what emission limit the USEPA is considering, and whether they will address hazardous pollutants in addition to mercury.  It is also possible that the vacatur of the CAMR regulations will lead to increased support for the passage of a multi-pollutant bill in Congress.

To comply with Indiana’s implementation plan of the Clean Air Act of 1990, the CAIR regulations, and to comply with potential future regulations of mercury and further NOx and SO2  reductions, SIGECO has IURC authority to invest in clean coal technology.  Using this authorization, SIGECO has invested approximately $411 million in pollution control equipment, including Selective Catalytic Reduction (SCR) systems, fabric filters, and an SO2 scrubber at its generating facility that is jointly owned with ALCOA (the Company’s portion is 150 MW).  Of the $411 million, $312 million was included in rate base for purposes of determining SIGECO’s new electric base rates that went into effect on August 15, 2007 and $99 million is currently recovered through a rider mechanism which is periodically updated for actual costs incurred including post in-service depreciation expense. As part of its recent rate proceeding, the Company has requested to also include these more recent expenditures in rate base as well.  SCR technology is the most effective method of reducing NOx emissions where high removal efficiencies are required and fabric filters control particulate matter emissions.  With the SO2 scrubber fully operational, SIGECO is in compliance with the additional SO2 reductions required by Phase I CAIR that commenced on January 1, 2010.

SIGECO’s coal fired generating fleet is 100 percent scrubbed for SO2 and 90 percent controlled for NOx.  SIGECO's investments in scrubber, SCR and fabric filter technology allows for compliance with existing regulations and should position it to comply with future reasonable mercury pollution control legislation, if and when, reductions are promulgated by USEPA.  On July 6, 2010, the USEPA issued its proposed revisions to CAIR, renamed the Transport Rule, for public comment.  The Transport Rule proposes a 71 percent reduction of SO2 over 2005 national levels and a 52 percent reduction of NOx over 2005 national levels.  The Company is currently reviewing the sufficiency of its existing pollution control equipment in relation to the requirements proposed in the Transport Rule.

Climate Change
The U.S. House of Representatives has passed a comprehensive energy bill that includes a carbon cap and trade program in which there is a progressive cap on greenhouse gas emissions and an auctioning and subsequent trading of allowances among those that emit greenhouse gases, a federal renewable portfolio standard, and utility energy efficiency targets.  Current proposed legislation also requires local natural gas distribution companies to hold allowances for the benefit of their customers.  As of the date of this filing, the Senate has not passed a bill, and the House bill is not law.  The U.S. Senate introduced a draft cap and trade proposal that is similar in structure to the House bill.  Numerous competing legislative proposals have also been introduced that involve carbon, energy efficiency, and renewable energy.

In the absence of federal legislation, several regional initiatives throughout the United States are in the process of establishing regional cap and trade programs.  While no climate change legislation is pending in Indiana, the state is an observer to the Midwestern Regional Greenhouse Gas Reduction Accord and the state’s legislature debated, but did not pass, a renewable energy portfolio standard in 2009.

In advance of a federal or state renewable portfolio standard, SIGECO received regulatory approval to purchase a 3 MW landfill gas generation facility from a related entity.  The facility was purchased in 2009 and is directly interconnected to the Company’s distribution system.  In 2009, the Company also executed a long term purchase power commitment for 50 MW of wind energy.  These transactions supplement a 30 MW wind energy purchase power agreement executed in 2008.

In April of 2007, the US Supreme Court determined that greenhouse gases meet the definition of "air pollutant" under the Clean Air Act and ordered the USEPA to determine whether greenhouse gas emissions from motor vehicles cause or contribute to air pollution that may reasonably be anticipated to endanger public health or welfare. In April of 2009, the USEPA published its proposed endangerment finding for public comment.  The proposed endangerment finding concludes that carbon emissions from mobile sources pose an endangerment to public health and the environment.  The endangerment finding was finalized in December of 2009, and is the first step toward USEPA regulating carbon emissions through the existing Clean Air Act in the absence of specific carbon legislation from Congress.  Therefore, any new regulations would likely also impact major stationary sources of greenhouse gases.  The USEPA has recently finalized a mandatory greenhouse gas emissions registry which will require reporting of emissions beginning in 2011 (for the emission year 2010).  The USEPA has also recently proposed a revision to the Prevention of Significant Deterioration (PSD) and Title V permitting rules which would require facilities that emit 25,000 tons or more of greenhouse gases a year to obtain a PSD permit for new construction or a significant modification of an existing facility.  If these proposed rules were adopted, they would apply to SIGECO’s generating facilities.

Impact of Legislative Actions & Other Initiatives is Unknown
If legislation requiring reductions in CO2 and other greenhouse gases or legislation mandating a renewable energy portfolio standard is adopted, such regulation could substantially affect both the costs and operating characteristics of the Company’s fossil fuel generating plants, nonutility coal mining operations, and natural gas distribution businesses.  Further, any legislation would likely impact the Company’s generation resource planning decisions.  At this time and in the absence of final legislation, compliance costs and other effects associated with reductions in greenhouse gas emissions or obtaining renewable energy sources remain uncertain.  The Company has gathered preliminary estimates of the costs to comply with a cap and trade approach to controlling greenhouse gas emissions.  A preliminary investigation demonstrated costs to comply would be significant, first with regard to operating expenses for the purchase of allowances, and later for capital expenditures as technology becomes available to control greenhouse gas emissions.  However, these compliance cost estimates are based on highly uncertain assumptions, including allowance prices and energy efficiency targets.  Costs to purchase allowances that cap greenhouse gas emissions or expenditures made to control emissions should be considered a cost of providing electricity, and as such, the Company believes recovery should be timely reflected in rates charged to customers.  Customer rates may also be impacted should decisions be made to reduce the level of sales to municipal and other wholesale customers in order to meet emission targets.

Ash Ponds & Coal Ash Disposal Regulations
In June 2010, the USEPA issued proposed regulations affecting the management and disposal of coal combustion products, such as ash generated by the Company’s coal-fired power plants.  The proposed rules more stringently regulate these byproducts and would likely increase the cost of operating or expanding existing ash ponds and the development of new ash ponds.   The USEPA did not offer a preferred alternative, but is taking public comment on multiple alternative regulations.  The alternatives include regulating coal combustion by-products as hazardous waste.  At this time, the majority of the Company’s ash is being beneficially reused.  The proposals offered by USEPA allow for the beneficial reuse of ash in certain circumstances. 

Environmental Remediation Efforts
In the past, Indiana Gas, SIGECO, and others operated facilities for the manufacture of gas.  Given the availability of natural gas transported by pipelines, these facilities have not been operated for many years.  Under currently applicable 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 at these sites.

Indiana Gas identified the existence, location, and certain general characteristics of 26 gas manufacturing and storage sites for which it may have some remedial responsibility.  Indiana Gas completed a remedial investigation/feasibility study (RI/FS) at one of the sites under an agreed order between Indiana Gas and the IDEM, and a Record of Decision was issued by the IDEM in January 2000.  Indiana Gas submitted the remainder of the sites to the IDEM's Voluntary Remediation Program  (VRP) and is currently conducting some level of remedial activities, including groundwater monitoring at certain sites, where deemed appropriate, and will continue remedial activities at the sites as appropriate and necessary.

Indiana Gas 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, Indiana Gas has recorded cumulative costs that it reasonably expects to incur totaling approximately $23.3 million.  The estimated accrued costs are limited to Indiana Gas’ share of the remediation efforts.  Indiana Gas has arrangements in place for 19 of the 26 sites with other potentially responsible parties (PRP), which limit Indiana Gas’ costs at these 19 sites to between 20 percent and 50 percent.

With respect to insurance coverage, Indiana Gas has settled with all known insurance carriers under insurance policies in effect when these plants were in operation in an aggregate amount approximating $20.8 million.

In October 2002, SIGECO received a formal information request letter from the IDEM regarding five manufactured gas plants that it owned and/or operated and were not enrolled in the IDEM’s VRP.  In October 2003, SIGECO filed applications to enter four of the manufactured gas plant sites in IDEM's VRP.  The remaining site is currently being addressed in the VRP by another Indiana utility.  SIGECO added those four sites into the renewal of the global Voluntary Remediation Agreement that Indiana Gas has in place with IDEM for its manufactured gas plant sites.  That renewal was approved by the IDEM in February 2004.  SIGECO was also named in a lawsuit filed in federal district court in May 2007, involving another waste disposal site subject to potential environmental remediation efforts.  With respect to that lawsuit, in May 2010, SIGECO settled with the plaintiff mitigating any future claims at this site.  SIGECO has filed a declaratory judgment action against its insurance carriers seeking a judgment finding its carriers liable under the policies for coverage of further investigation and any necessary remediation costs that SIGECO may accrue under the VRP program and/or related to the site subject to the recently settled lawsuit.

SIGECO has recorded cumulative costs that it reasonably expects to incur related to these environmental matters, including the recent settlement, totaling approximately $15.8 million.  However, the total costs that may be incurred in connection with addressing all of these sites cannot be determined at this time.  With respect to insurance coverage, SIGECO has recorded approximately $12.6 million in insurance proceeds from certain of its insurance carriers under insurance policies in effect when these sites were in operation.  While negotiations are ongoing with certain carriers, settlements have been reached with some carriers and $8.1 million in proceeds have been received.  SIGECO has undertaken significant remediation efforts at two MGP sites.

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 some level of additional remedial activities which are not presently foreseen and those costs may not be subject to PRP or insurance recovery.  As of June 30, 2010 and December 31, 2009, approximately $9.5 million and $6.5 million of accrued, but not yet spent, costs are included in Other Liabilities related to both the Indiana Gas and SIGECO sites.

Rate & Regulatory Matters

Vectren South Electric Base Rate Filings
On December 11, 2009, Vectren South filed a request with the IURC to adjust its electric base rates in its south service territory.  The requested increase in base rates addresses capital investments, a modified electric rate design that facilitates a partnership between Vectren South and customers to pursue energy efficiency and conservation, and new energy efficiency programs to complement those currently offered for natural gas customers.  On July 30, 2010, Vectren South revised its increase requested through the filing of its rebuttal position to approximately $34 million. The request addresses the roughly $325 million spent in infrastructure construction since its last base rate increase in August 2007 that was needed to continue to provide reliable service and updates to operating costs and revenues.  The rate design proposed in the filing would break the link between small residential and commercial customers’ consumption and the utility’s margin, thereby aligning the utility’s and customers’ interests in using less energy.  The revised request assumes an overall rate of return of 7.42 percent on rate base of approximately $1.3 billion and an allowed return on equity (ROE) of 10.7 percent.  The OUCC and SIGECO Industrial Group separately filed testimony in this case, proposing an increase of approximately $11 million and $18 million, respectively.  Furthermore, the intervening parties in the case took differing views on, among other matters, the proposed rate design and the level and price of coal inventory.  A hearing on all matters in the case is scheduled for late August 2010.  Based on the current procedural schedule, an order is likely in the first quarter of 2011.

Vectren South Electric Fuel Adjustment Filings
Electric retail rates contain a fuel adjustment clause (FAC) that allows for periodic adjustment in energy to reflect changes in the cost of fuel and purchased power.  These FAC procedures involve periodic filings and IURC hearings to approve the recovery of Vectren South’s fuel and purchased power costs.

In its latest FAC hearing, the OUCC requested the IURC order Vectren South to renegotiate its coal contracts because they are currently above market prices.  This request is consistent with the OUCC’s position taken in Vectren South’s base rate proceeding referred to above.  Vectren South purchases the majority of its coal from Vectren Fuels, Inc. (a nonutility wholly owned subsidiary of the Company) under coal contracts entered into in 2008.  Vectren South states in its filed position that the prices in the coal contracts were at or below the market at the time of contract execution.  Further, the Company has already engaged in some contract renegotiations allowing for contract deferrals, and reducing volumes in 2011 with negotiation to come for market pricing under the terms of the contracts for 2012 or later deliveries.  Moreover, the IURC has already found in a number of FAC proceedings since 2008 that the costs incurred under these coal contracts are reasonable.

The OUCC also raised concerns regarding Vectren South’s generating unit “must run” policy.  Under that policy, for reliability reasons, Vectren South instructs the MISO that certain units must be dispatched regardless of current market conditions.  The OUCC is reviewing data related to Vectren South’s “must run” policy.
 
To allow the FAC to be approved on a timely basis, the parties agreed to the creation of a sub docket proceeding to address the specific issues noted above.  At this point, both the timing and potential impacts of the sub docket proceeding, if any, are not known.  An order establishing the sub docket was issued by the IURC on July 28, 2010 and noted that the parties to the FAC proceeding agreed that the recovery of fuel costs in the current FAC would not be subject to refund.

Straight Fixed Variable Rate Design Fully Implemented in Vectren Ohio’s Service Territory
On January 7, 2009 the PUCO issued a rate Order allowing for a two-phase transition to a straight fixed variable rate design to be fully implemented by February 22, 2010 for all residential and some commercial customers.  This type of rate design places substantially all of the fixed cost recovery in the customer service charge; and, therefore, mitigates most weather risk as well as the effects of declining usage.  Starting in February 2010, nearly 90 percent of the combined residential and commercial base rate margins are recovered through the customer service charge.  The OCC has appealed this rate order to the Ohio Supreme Court.  The appeal is substantially the same as appeals filed by the OCC in two other cases in which the PUCO approved similar rate designs.  The Ohio Supreme Court affirmed the PUCO orders authorizing straight fixed variable rate design in the other two cases. The OCC’s appeal related to the Company’s case has not yet been decided. 

Vectren Ohio Continues the Process to Exit the Merchant Function
The second phase of VEDO’s exiting the merchant function began on April 1, 2010.  During this phase, the Company no longer sells natural gas directly to customers.  Rather, state-certified Competitive Retail Natural Gas Suppliers, that were successful bidders in a regulatory-approved auction, sell the gas commodity to specific customers for a 12 month period at auction-determined standard pricing.  That auction was conducted on January 12, 2010, and the auction results were approved by the PUCO on January 13.  Vectren Source, the Company’s nonutility retail gas marketer, was a successful bidder on one tranche of customers.  The plan approved by the PUCO requires that the Company conduct at least two auctions during this phase.  As such, the Company will conduct another auction in advance of the second 12-month term, which will commence on April 1, 2011.  Consistent with current practice, customers will continue to receive one bill for the delivery of natural gas service. 

The PUCO provided for an Exit Transition Cost rider, which allows the Company to recover costs associated with the transition process.  The impact of exiting the merchant function should not have a material impact on Company earnings or financial condition.  It, however, has and will continue to reduce Gas utility revenues and have an equal and offsetting impact to Cost of gas sold as VEDO no longer purchases gas for resale to these customers.

MISO
The Company is a member of the MISO, a FERC approved regional transmission organization.  When the Company is a net seller of its generation, such net revenues, which totaled $3.8 million and $3.0 million for the three months ended June 30, 2010 and 2009, respectively, are included in Electric utility revenues.  For the six months ended June 30, 2010 and 2009, such net revenues totaled $13.6 million and $13.2 million, respectively.  When the Company is a net purchaser such net purchases, which totaled $12.5 million and $12.2 million for the three months ended June 30, 2010 and 2009, respectively, are included in Cost of fuel & purchased power.  For the six months ended June 30, 2010 and 2009, such purchases totaled $21.5 million and $16.5 million, respectively.  Net positions are determined on an hourly basis.

The Company also receives transmission revenue from the MISO which is included in Electric utility revenues and totaled $5.8 million and $3.6 million for the three months ended June 30, 2010 and 2009, respectively.  For the six months ended June 30, 2010 and 2009, transmission revenue from the MISO totaled $10.6 million and $6.6 million, respectively.  These revenues result from other MISO members’ use of the Company’s transmission system as well as the recovery of the Company’s investment in certain new electric transmission projects meeting MISO’s transmission expansion plan criteria.

One such project currently under construction meeting these expansion plan criteria is an interstate 345 kilovolt transmission line that will connect Vectren’s A.B. Brown Generating Station to a station in Indiana owned by Duke Energy to the north and to a station in Kentucky owned by Big Rivers Electric Corporation to the south.  Throughout the project, SIGECO will recover an approximate 10 percent return, inclusive of the FERC approved equity rate of return of 12.38 percent, on capital investments through a rider mechanism which is updated annually for estimated costs to be incurred.  Of the total investment, which is expected to approximate $87 million, the Company has invested approximately $46.5 million as of June 30, 2010.  The Company expects this project to be fully operational in 2011.  At that time, any operating expenses, including depreciation expense, are also expected to be recovered through a FERC approved rider mechanism.  Further, the approval allows for recovery of expenditures made even in the event of unforeseen difficulties that delay or permanently halt the project.
 
Results of Operations of the Nonutility Group

The Nonutility Group operates in three primary business areas: Energy Marketing and Services, Coal Mining, and Energy Infrastructure Services.  Energy Marketing and Services markets and supplies natural gas and provides energy management services.  Coal Mining mines and sells coal.  Energy Infrastructure Services provides underground construction and repair and provides performance contracting and renewable energy services.  There are also other legacy businesses that have invested in energy-related opportunities and services, real estate, and leveraged leases, among other investments.  The Nonutility Group supports the Company’s regulated utilities pursuant to service contracts by providing natural gas supply services, coal, and infrastructure services.  Results reported by individual company are net of allocated corporate expenses.  Nonutility Group earnings for the three and six months ended June 30, 2010 and 2009 follow:

   
Three Months
   
Six Months
   
Ended June 30,
   
Ended June 30,
(In millions, except per share amounts)
 
2010
   
2009
   
2010
   
2009
 
                         
NET INCOME (LOSS)
  $ (7.5 )   $ (13.0 )   $ 0.3     $ 3.5  
                                 
CONTRIBUTION TO VECTREN BASIC EPS
  $ (0.09 )   $ (0.16 )   $ -     $ 0.04  
                                 
NET INCOME (LOSS) ATTRIBUTED TO:
                               
     Energy Marketing & Services
  $ (8.9 )   $ (16.6 )