10-Q 1 vvc_10q.htm VVC 10Q vvc_10q.htm
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, 2009

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).    Yes oNo o

 
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
 81,091,351
June 30, 2009
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

AFUDC:  allowance for funds used during construction
 
MMBTU:  millions of British thermal units
APB:  Accounting Principles Board
 
MW:  megawatts
EITF:  Emerging Issues Task Force
 
MWh / GWh:  megawatt hours / thousands of megawatt hours (gigawatt hours)
FASB:  Financial Accounting Standards Board
 
OCC:  Ohio Office of the Consumer Counselor
FERC:  Federal Energy Regulatory Commission
 
OUCC:  Indiana Office of the Utility Consumer Counselor
IDEM:  Indiana Department of Environmental Management
 
PUCO:  Public Utilities Commission of Ohio
IURC:  Indiana Utility Regulatory Commission
 
SFAS:  Statement of Financial Accounting Standards
MCF / BCF:  thousands / billions of cubic feet
 
USEPA:  United States Environmental Protection Agency
MDth / MMDth: thousands / millions of dekatherms
 
Throughput:  combined gas sales and gas transportation volumes
MISO: Midwest Independent System Operator
 


Table of Contents


Item
Number
 
Page
Number
 
PART I.  FINANCIAL INFORMATION
 
1
Financial Statements (Unaudited)
 
 
Vectren Corporation and Subsidiary Companies
 
 
 
 
 
2
3
4
     
 
PART II.  OTHER INFORMATION
 
1
1A
2
4
5 Other Information  45 
6
 

 
PART I.  FINANCIAL INFORMATION

ITEM 1.  FINANCIAL STATEMENTS

VECTREN CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED CONDENSED BALANCE SHEETS
(Unaudited – In millions)
 
             
   
June 30,
   
December 31,
 
   
2009
   
2008
 
             
ASSETS
           
             
Current Assets
           
Cash & cash equivalents
  $ 55.1     $ 93.2  
Accounts receivable - less reserves of $8.3 &
               
$5.6, respectively
    129.4       226.7  
Accrued unbilled revenues
    51.8       197.0  
Inventories
    107.8       131.0  
Recoverable fuel & natural gas costs
    -       3.1  
Prepayments & other current assets
    55.6       124.6  
Total current assets
    399.7       775.6  
                 
Utility Plant
               
     Original cost
    4,467.5       4,335.3  
     Less:  accumulated depreciation & amortization
    1,660.7       1,615.0  
Net utility plant
    2,806.8       2,720.3  
                 
Investments in unconsolidated affiliates
    170.0       179.1  
Other utility & corporate investments
    28.4       25.7  
Other nonutility investments
    46.1       45.9  
Nonutility property - net
    429.1       390.2  
Goodwill - net
    240.8       240.2  
Regulatory assets
    210.6       216.7  
Other assets
    33.8       39.2  
TOTAL ASSETS
  $ 4,365.3     $ 4,632.9  




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,
 
   
2009
   
2008
 
             
LIABILITIES & SHAREHOLDERS' EQUITY
           
             
Current Liabilities
           
    Accounts payable
  $ 119.9     $ 266.1  
    Accounts payable to affiliated companies
    27.0       75.2  
    Refundable fuel & natural gas costs
    27.5       4.1  
    Accrued liabilities
    170.9       175.0  
    Short-term borrowings
    88.8       519.5  
    Current maturities of long-term debt
    0.5       0.4  
    Long-term debt subject to tender
    10.0       80.0  
       Total current liabilities
    444.6       1,120.3  
                 
                 
Long-term Debt - Net of Current Maturities &
               
    Debt Subject to Tender
    1,608.0       1,247.9  
                 
Deferred Income Taxes & Other Liabilities
               
    Deferred income taxes
    380.5       353.4  
    Regulatory liabilities
    319.7       315.1  
    Deferred credits & other liabilities
    237.6       244.6  
       Total deferred credits & other liabilities
    937.8       913.1  
                 
Commitments & Contingencies (Notes 8, 10-12)
               
                 
Common Shareholders' Equity
               
    Common stock (no par value) – issued & outstanding
               
       81.1 & 81.0, respectively
    662.6       659.1  
    Retained earnings
    724.8       712.8  
    Accumulated other comprehensive income (loss)
    (12.5 )     (20.3 )
       Total common shareholders' equity
    1,374.9       1,351.6  
                 
TOTAL LIABILITIES & SHAREHOLDERS' EQUITY
  $ 4,365.3     $ 4,632.9  







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,
 
   
2009
   
2008
   
2009
   
2008
 
OPERATING REVENUES
                       
Gas utility
  $ 139.1     $ 224.9     $ 666.5     $ 858.5  
Electric utility
    132.7       127.2       257.7       254.4  
Nonutility revenues
    103.7       111.8       246.5       253.1  
Total operating revenues
    375.5       463.9       1,170.7       1,366.0  
OPERATING EXPENSES
                               
Cost of gas sold
    58.0       143.8       412.6       605.8  
Cost of fuel & purchased power
    50.3       48.5       97.3       94.5  
Cost of nonutility revenues
    43.3       52.1       117.5       147.4  
Other operating
    125.3       124.7       248.0       240.5  
Depreciation & amortization
    53.0       47.4       104.4       94.8  
Taxes other than income taxes
    13.2       14.4       36.7       41.2  
Total operating expenses
    343.1       430.9       1,016.5       1,224.2  
OPERATING INCOME
    32.4       33.0       154.2       141.8  
OTHER INCOME
                               
Equity in earnings (losses) of unconsolidated affiliates
    (23.3 )     (6.5 )     (10.7 )     7.5  
Other income – net
    4.1       3.1       6.5       6.1  
Total other income (loss)
    (19.2 )     (3.4 )     (4.2 )     13.6  
                                 
INTEREST EXPENSE
    25.5       23.2       48.2       48.5  
                                 
INCOME (LOSS) BEFORE INCOME TAXES
    (12.3 )     6.4       101.8       106.9  
                                 
INCOME TAXES
    (5.6 )     1.7       35.7       38.2  
                                 
NET INCOME (LOSS)
  $ (6.7 )   $ 4.7     $ 66.1     $ 68.7  
                                 
AVERAGE COMMON SHARES OUTSTANDING
    80.7       76.2       80.7       76.1  
DILUTED COMMON SHARES OUTSTANDING
    80.7       76.6       80.7       76.3  
                                 
EARNINGS (LOSS) PER SHARE OF COMMON STOCK:
                               
BASIC
  $ (0.08 )   $ 0.06     $ 0.82     $ 0.90  
DILUTED
  $ (0.08 )   $ 0.06     $ 0.82     $ 0.89  
                                 
DIVIDENDS DECLARED PER SHARE OF
                               
COMMON STOCK
  $ 0.34     $ 0.33     $ 0.67     $ 0.65  






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,
 
   
2009
   
2008
 
CASH FLOWS FROM OPERATING ACTIVITIES
           
Net income
  $ 66.1     $ 68.7  
Adjustments to reconcile net income to cash from operating activities:
         
Depreciation & amortization
    104.4       94.8  
Deferred income taxes & investment tax credits
    20.5       18.9  
Equity in (earnings) loss of unconsolidated affiliates
    10.7       (7.5 )
Provision for uncollectible accounts
    9.4       8.9  
Expense portion of pension & postretirement periodic benefit cost
    5.9       3.9  
Other non-cash charges - net
    (0.8 )     7.2  
Changes in working capital accounts:
               
Accounts receivable & accrued unbilled revenues
    232.3       132.0  
Inventories
    23.8       25.7  
Recoverable/refundable fuel & natural gas costs
    26.5       (32.3 )
Prepayments & other current assets
    67.5       41.2  
Accounts payable, including to affiliated companies
    (185.2 )     (48.2 )
Accrued liabilities
    (2.6 )     18.2  
Unconsolidated affiliate dividends
    10.9       9.1  
Changes in noncurrent assets
    5.0       3.9  
Changes in noncurrent liabilities
    (26.5 )     (13.6 )
Net cash flows from operating activities
    367.9       330.9  
CASH FLOWS FROM FINANCING ACTIVITIES
               
Proceeds from:
               
Issuance of common stock
    -       124.9  
Long-term debt, net of issuance costs
    290.8       171.2  
Stock option exercises & other
    3.1       -  
Requirements for:
               
Dividends on common stock
    (54.1 )     (49.4 )
Retirement of long-term debt
    (1.7 )     (103.3 )
Other financing activities
    -       (0.2 )
Net change in short-term borrowings
    (430.7 )     (311.8 )
Net cash flows from financing activities
    (192.6 )     (168.6 )
CASH FLOWS FROM INVESTING ACTIVITIES
               
Proceeds from:
               
Other collections
    1.1       4.3  
Requirements for:
               
Capital expenditures, excluding AFUDC equity
    (213.6 )     (164.4 )
Unconsolidated affiliate investments
    (0.1 )     (0.1 )
Other investments
    (0.8 )     (10.7 )
Net cash flows from investing activities
    (213.4 )     (170.9 )
Net change in cash & cash equivalents
    (38.1 )     (8.6 )
Cash & cash equivalents at beginning of period
    93.2       20.6  
Cash & cash equivalents at end of period
  $ 55.1     $ 12.0  
                 
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 operating 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 (VEDO or Vectren Ohio).  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 560,000 natural gas customers located in central and southern Indiana.  SIGECO provides energy delivery services to over 140,000 electric customers and approximately 110,000 gas customers located near Evansville in southwestern Indiana.  SIGECO also owns and operates electric generation 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 315,000 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, as that term is defined in SFAS 165, through July 31, 2009, 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, 2008, filed with the Securities and Exchange Commission on February 19, 2009, 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)
 
2009
   
2008
   
2009
   
2008
 
Net income (loss)
  $ (6.7 )   $ 4.7     $ 66.1     $ 68.7  
Comprehensive income (loss) of unconsolidated affiliates
    35.2       (14.6 )     13.2       (24.7 )
Cash flow hedges
                               
Unrealized gains/(losses)
    -       -       0.1       -  
Reclassifications to net income (loss)
    -       (0.1 )     (0.1 )     (0.2 )
Income taxes
    (14.3 )     5.8       (5.3 )     9.8  
Total comprehensive income (loss)
  $ 14.2     $ (4.2 )   $ 74.0     $ 53.6  
                                 
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 7 for more information on ProLiance.)

4.    
Earnings Per Share

Earnings per share (EPS) is calculated in accordance with SFAS 128, “Earnings Per Share” and its related interpretations.  Basic earnings per share is computed by dividing net income available to common shareholders by the weighted-average number of common shares outstanding for the period.  Diluted earnings per share 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 earnings per share 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)
 
2009
   
2008
   
2009
   
2008
 
                         
Numerator:
                       
Reported net income (loss)
  $ (6.7 )   $ 4.7     $ 66.1     $ 68.7  
Less: Income allocated to participating share-based securities
    -       -       (0.1 )     (0.1 )
Reported net income (Basic & Diluted EPS)
  $ (6.7 )   $ 4.7     $ 66.0     $ 68.6  
                                 
Denominator:
                               
Weighted average common shares outstanding (Basic EPS)
    80.7       76.2       80.7       76.1  
Equity forward contract
    -       0.3       -       0.1  
Conversion of stock options
    -       0.1       -       0.1  
Adjusted weighted average shares outstanding and
                               
 assumed conversions outstanding (Diluted EPS)
    80.7       76.6       80.7       76.3  
                                 
Basic earnings per share
  $ (0.08 )   $ 0.06     $ 0.82     $ 0.90  
Diluted earnings per share
  $ (0.08 )   $ 0.06     $ 0.82     $ 0.89  
 
For the three and six months ended June  30, 2009, options to purchase 1,329,562 and 906,645, respectively, 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.  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.  For the three and six months ended June 30, 2008, all options were dilutive.

Participating Securities
On January 1, 2009, the Company adopted FSP EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (FSP EITF 03-6-1).  FSP EITF 03-6-1 clarified that unvested share-based payment awards that contain rights to nonforfeitable dividends participate in undistributed earnings with common shareholders.  Awards of this nature that impact the EPS calculation are participating securities.  The presence of a participating security requires EPS to be calculated using the two-class method.

Of the approximate 81 million shares outstanding as of June 30, 2009, unvested share-based payment awards that contain rights to nonforfeitable dividends comprise less than one percent.  The Company prospectively changed share-based payment awards such that dividends on awards granted in 2009 and beyond are subject to forfeiture.

As a result of the insignificant level of participating securities subject to the two-class method of computing earnings per share, the adoption of FSP EITF 03-6-1 had immaterial impacts to both current and prior period earnings per share calculations.

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 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 Cost
A summary of the components of net periodic benefit cost follows:
                         
   
Three Months Ended June 30,
 
   
Pension Benefits
   
Other Benefits
 
(In millions)
 
2009
   
2008
   
2009
   
2008
 
Service cost
  $ 1.6     $ 1.5     $ 0.1     $ 0.1  
Interest cost
    3.9       3.8       1.1       1.0  
Expected return on plan assets
    (4.1 )     (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
    0.6       -       0.1       -  
Net periodic benefit cost
  $ 2.4     $ 1.6     $ 1.3     $ 1.1  
                                 
   
Six Months Ended June 30,
 
   
Pension Benefits
   
Other Benefits
 
(In millions)
    2009       2008       2009       2008  
Service cost
  $ 3.2     $ 3.0     $ 0.2     $ 0.2  
Interest cost
    7.9       7.6       2.2       2.0  
Expected return on plan assets
    (8.2 )     (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
    1.1       -       0.2       -  
Net periodic benefit cost
  $ 4.8     $ 3.2     $ 2.6     $ 2.2  

Employer Contributions to Qualified Pension Plans
Currently, the Company expects to contribute approximately $28 million to its pension plan trusts for 2009.  Through June 30, 2009, contributions of $14.3 million have been made to the pension plan trusts.
 
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 $5.8 million and $7.2 million in the three months ended June 30, 2009 and 2008, respectively.  For the six months ended June 30, 2009 and 2008, these taxes totaled $21.7 million and $26.7 million, respectively.  Expenses associated with excise and utility receipts taxes are recorded as a component of Taxes other than income taxes.

7.    
Accruals for Utility & Nonutility Plant

As of June 30, 2009 and December 31, 2008, the Company has accruals related to utility and nonutility plant purchases totaling approximately $26.8 million and $35.5 million, respectively.

8.    
Transactions with 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
Summarized financial information related to ProLiance is presented below:
                         
   
Three Months
   
Six Months
 
   
Ended June 30,
   
Ended June 30,
 
(In millions)
 
2009
   
2008
   
2009
   
2008
 
Summarized statement of income information:
                       
Revenues
  $ 300.2     $ 621.9     $ 959.0     $ 1,431.4  
Operating income (loss)
    (7.4 )     (11.1 )     13.9       12.1  
Charge related to Investment in Liberty Gas Storage
    (32.7 )     -       (32.7 )     -  
ProLiance's earnings (loss)
    (39.2 )     (10.1 )     (17.5 )     13.5  
                                 
                                 
 
 
 
As of
                 
   
June 30,
   
December 31,
               
(In millions)
    2009       2008                  
Summarized balance sheet information:
                               
Current assets
  $ 368.7     $ 661.5                  
Noncurrent assets
    72.3       104.2                  
Current liabilities
    203.1       514.0                  
Noncurrent liabilities
    3.6       3.6                  
Members' equity
    260.4       295.8                  
Accumulated other comprehensive income (loss)
    (26.1 )     (47.7 )                

Vectren records its 61 percent share of ProLiance’s earnings after income taxes and an interest expense allocation.

Regulatory Matter Resolved
ProLiance self reported to the Federal Energy Regulatory Commission (FERC) in October 2007 possible non-compliance with the FERC’s capacity release policies.  ProLiance has taken corrective actions to assure that current and future transactions are compliant.  During the second quarter of 2009, ProLiance resolved the matter with FERC.  The amount of the penalty was not material to the Company’s consolidated operating results, financial position or cash flows.

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 (previously referred to as the Sulfur site, located near Sulfur, Louisiana), and an additional 17 Bcf of capacity in its south facility (previously referred to as the Hackberry site, near Hackberry, Louisiana). As more fully described below, it is now expected that only the south facility will be completed by the joint venture. This facility is expected to provide at least 17 Bcf of capacity. The Liberty pipeline system is currently connected with several interstate pipelines, including the Cameron Interstate Pipeline operated by Sempra Pipelines & Storage, and will connect area LNG regasification terminals to an interstate natural gas transmission system and storage facilities.  ProLiance's investment in Liberty is $47.3 million at June 30, 2009, after reflecting the charge discussed below.

In late 2008, SE advised ProLiance that the completion of the phase of Liberty’s development at the north site had been delayed by subsurface and well-completion problems.   Based on testing performed in the second quarter of 2009, SE determined that attempts at corrective measures had been unsuccessful.  At June 30, 2009, Liberty recorded a charge of approximately $132 million to write off the caverns and certain related assets, reflecting SE’s view that it is probable that investments made at the north site will provide no future economic benefit.  As an equity investor in Liberty, ProLiance recorded its share of the charge, totaling $33 million at June 30, 2009.  The Company’s share is $11.9 million after tax, or $0.15 per share. In the Consolidated Statement of Income, the charge is an approximate $20 million reduction to Equity in earning of unconsolidated affiliates and an income tax benefit reflected in Income taxes of approximately $8 million. The charge is not material to the Company’s financial condition.  ProLiance does not expect it to impact its future liquidity or access to capital, nor  is it expected that this situation will impact ProLiance’s ability to meet the needs of its customers.

Transactions with ProLiance
Purchases from ProLiance for resale and for injections into storage for the three months ended June 30, 2009 and 2008 totaled $99.3 million and $236.8 million, respectively, and for the six months ended June 30, 2009 and 2008, totaled $302.3 million and $526.2 million.  Amounts owed to ProLiance at June 30, 2009, and December 31, 2008, for those purchases were $27.0 million and $75.1 million, respectively, and are included in Accounts payable to affiliated companies.  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.

9.    
2009 Long-Term Debt Transactions

Put Provisions
Holders of certain debt instruments had the one-time option to put $80 million of debt to the Company during 2009, but that option was not exercised, and the debt has been reclassified as Long-term debt in these consolidated financial statements as of June 30, 2009.  In addition, holders of other debt instruments have the one-time option to put $10 million of debt in 2010, and that debt has been classified as Long-term debt subject to tender in current liabilities.

Utility Holdings 2009 Debt Issuance
On April 7, 2009, Utility Holdings entered into a private placement Note Purchase Agreement pursuant to which institutional investors purchased from Utility Holdings $100 million in 6.28 percent senior unsecured notes due April 7, 2020 (2020 Notes).  The 2020 Notes are guaranteed by Utility Holdings’ three utilities:  SIGECO, Indiana Gas, and VEDO.  These guarantees are full and unconditional and joint and several.  The proceeds from the sale of the 2020 Notes, net of issuance costs, totaled approximately $99.5 million.

The 2020 Notes have no sinking fund requirements, and interest payments are due semi-annually.  The 2020 Notes contain customary representations, warranties and covenants, including a leverage covenant consistent with leverage covenants contained in the Utility Holdings’ $515 million short-term credit facility.

SIGECO 2009 Debt Issuance
On March 26, 2009, SIGECO remarketed the remaining $41.3 million of long-term debt held in treasury at December 31, 2008, receiving proceeds, net of issuance costs of approximately $40.6 million.  The remarketed notes have a variable rate interest rate which is reset weekly and are supported by a standby letter of credit backed by Utility Holdings’ $515 million short-term credit facility.  The notes are collateralized by SIGECO’s utility plant, and $9.8 million are due in 2015 and $31.5 million are due in 2025.  The initial interest rate paid to investors was 0.55 percent.  The equivalent rate of the debt at inception, inclusive of interest, weekly remarketing fees, and letter of credit fees, approximated 1 percent.

Vectren Capital Corp. 2009 Debt Issuance
On March 11, 2009, Vectren and Vectren Capital Corp., its wholly-owned subsidiary (Vectren Capital), entered into a private placement Note Purchase Agreement (the “2009 Note Purchase Agreement”) pursuant to which various institutional investors purchased the following tranches of notes from Vectren Capital: (i) $30 million in 6.37 percent senior notes, Series A due 2014, (ii) $60 million in 6.92 percent senior notes, Series B due 2016 and (iii) $60 million in 7.30 percent senior notes, Series C due 2019. These senior notes are unconditionally guaranteed by Vectren, the parent of Vectren Capital.  These notes have no sinking fund requirements, and interest payments are due semi-annually.  The proceeds from the sale of the notes, net of issuance costs, totaled approximately $149.0 million.

The 2009 Note Purchase Agreement contains customary representations, warranties and covenants, including a leverage covenant consistent with leverage covenants contained in the Vectren Capital $255 million short-term credit facility.

On March 11, 2009, Vectren and Vectren Capital also entered into a first amendment with respect to prior note purchase agreements for the remaining outstanding Vectren Capital debt, other than the $22.5 million series due in 2010, to conform the covenants in certain respects to those contained in the 2009 Note Purchase Agreement.

10.  
Commitments & Contingencies

Guarantees
In the normal course of business, Vectren Corporation issues guarantees supporting the performance of its consolidated subsidiaries as well as its unconsolidated affiliates.  Such guarantees, which contain varying terms, generally allow those subsidiaries and affiliates to execute transactions on more favorable terms than the subsidiaries and affiliates could obtain without such a guarantee.  Guarantees may include posted letters of credit, leasing guarantees, and contract performance guarantees. 

Related specifically to guarantees supporting the performance and activities of unconsolidated affiliates, as of June 30, 2009, such guarantees approximated $3 million.   These guarantees relate primarily to arrangements between ProLiance and various natural gas pipeline operators.  The Company has accrued no liabilities for these unconsolidated affiliate guarantees as they were executed prior to the adoption of FASB Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.” 

Legal and Regulatory Proceedings
The Company is party to various legal proceedings and audits and reviews by taxing authorities and other government agencies arising in the normal course of business.  In the opinion of management, there are no legal proceedings or other regulatory reviews or audits pending against the Company that are likely to have a material adverse effect on its financial position, results of operations or cash flows.

11.  
Environmental Matters

Clean Air Act
The Clean Air Interstate Rule (CAIR) is an allowance cap and trade program requiring further reductions from coal-burning power plants in 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 is positioned to comply with SO2 reductions effective January 1, 2010.  Utilization of the Company’s inventory of NOx and SO2  allowances may also be impacted if CAIR is further revised; however, most of these allowances were granted to the Company at zero cost, so a reduction in carrying value is not expected.

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.  It is possible that the vacatur of the CAMR regulations will lead to increased support for the passage of a multi-pollutant bill in Congress.  It is also possible that the USEPA will promulgate a revised mercury regulation in 2009.

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 $307 million in pollution control equipment, including Selective Catalytic Reduction (SCR) systems and fabric filters.  SCR technology is the most effective method of reducing NOx emissions where high removal efficiencies are required and fabric filters control particulate matter emissions.  These investments were included in rate base for purposes of determining new base rates that went into effect on August 15, 2007.  Prior to being included in base rates, return on investments made and recovery of related operating expenses were recovered through a rider mechanism.

Further, the IURC granted SIGECO authority to invest in an SO2 scrubber at its generating facility that is jointly owned with ALCOA (the Company’s portion is 150 MW).  The order allows SIGECO to recover an approximate 8 percent return on capital investments through a rider mechanism which is periodically updated for actual costs incurred less post in-service depreciation expense.  Through June 30, 2009, the Company has invested approximately $100 million in this project.  The scrubber was placed into service on January 1, 2009.  Recovery through a rider mechanism of associated operating expenses including depreciation expense associated with the scrubber also began on January 1, 2009.  With the SO2 scrubber fully operational, SIGECO is positioned for compliance with the additional SO2 reductions required by Phase I CAIR commencing 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 pollution control legislation, if and when, reductions in mercury and further reductions in NOx and SO2 are promulgated by USEPA.

Climate Change
The U.S. House of Representatives has passed a comprehensive energy bill that includes a carbon cap and trade program where 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.  Under the proposed energy bill, the electric power industry will receive 40 percent of the annual allowance allocation at zero cost.  As of the date of this filing, the Senate has not passed a bill, and the bill is not law.

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 of the Midwestern Regional Greenhouse Gas Reduction Accord, and in the recently completed 2009 session, the state’s legislature debated, but did not pass, a renewable energy portfolio standard.

In advance of a federal or state renewable portfolio standard and with the IURC’s approval, SIGECO recently purchased a  3.2 MW landfill gas generation facility from a related entity that is directly interconnected to the Company’s distribution system and recently 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 new 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.  Upon finalization, the endangerment finding 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 also proposed a significant new mandatory greenhouse gas emissions registry.

Impact of Legislative Actions and 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 possibly 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 to operating expenses for the purchase of allowances, and later to capital expenditures as technology becomes available to control greenhouse gas emissions.  However, these compliance cost estimates are very sensitive to highly uncertain assumptions, including allowance prices and energy efficiency targets.  Costs to purchase allowances that cap greenhouse gas 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.  Approximately 22 percent of electric volumes sold in 2008 were delivered to municipal and other wholesale customers.  As such, the Company has some flexibility to modify the level of these transactions to reduce overall emissions and reduce costs associated with complying with new environmental regulations.

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 $22.2 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 is also named in a lawsuit filed in federal district court in May 2007, involving another site subject to potential environmental remediation efforts.

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 May 2007 lawsuit.  While the total costs that may be incurred in connection with addressing these sites cannot be determined at this time, SIGECO has recorded cumulative costs that it reasonably expects to incur totaling approximately $9.2 million.  With respect to insurance coverage, SIGECO has settled with insurance carriers under insurance policies in effect when these sites were in operation in an aggregate amount of $8.1 million.

Environmental remediation costs related to Indiana Gas’ and SIGECO’s manufactured gas plants and other sites have had a minor impact on results of operations or financial condition since cumulative costs recorded to date approximate PRP and insurance settlement recoveries.  Such cumulative costs 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, 2009 and December 31, 2008, approximately $5.1 million and $6.5 million, respectively, of accrued, but not yet spent, remediation costs are included in Other Liabilities related to both the Indiana Gas and SIGECO sites.

12.  
Rate & Regulatory Matters

Vectren Energy Delivery of Ohio, Inc. (VEDO) Gas Base Rate Order Received
On January 7, 2009, the PUCO issued an order approving the stipulation reached in the VEDO rate case.  The order provides for a rate increase of nearly $14.8 million, an overall rate of return of 8.89 percent on rate base of about $235 million; an opportunity to recover costs of a program to accelerate replacement of cast iron and bare steel pipes, as well as certain service risers; and base rate recovery of an additional $2.9 million in conservation program spending.

The order also adjusted the rate design used to collect the agreed-upon revenue from VEDO's customers.  The order allows 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.  A straight fixed variable design mitigates most weather risk as well as the effects of declining usage, similar to the Company’s lost margin recovery mechanism, which expired when this new rate design went into effect on February 22, 2009.  In 2008, annual results include approximately $4.3 million of revenue from a lost margin recovery mechanism that does not continue once this base rate increase is in effect.  After year one, nearly 90 percent of the combined residential and commercial base rate margins will be recovered through the customer service charge.  The OCC has filed a request for rehearing on the rate design finding by the PUCO.  The rehearing request mirrors similar requests filed by the OCC in each case where the PUCO has approved similar rate designs, and all such requests have been denied.

With this rate order, the Company has in place for its Ohio gas territory rates that allow for the phased implementation of a straight fixed variable rate design that mitigates both weather risk and lost margin; tracking of bad debt and percent of income payment plan (PIPP) expenses; base rate recovery of pipeline integrity management expense; timely recovery of costs associated with the accelerated replacement of bare steel and cast iron pipes, as well as certain service risers; and expanded conservation programs now totaling up to $5 million in annual expenditures.

MISO
Since 2002 and with the IURC’s approval, the Company has been a member of the Midwest Independent System Operator, Inc. (MISO), a FERC approved regional transmission organization.  The MISO serves the electrical transmission needs of much of the Midwest and maintains operational control over the Company’s electric transmission facilities as well as that of other Midwest utilities.  Since April 1, 2005, the Company has been an active participant in the MISO energy markets, bidding its owned generation into the Day Ahead and Real Time markets and procuring power for its retail customers at Locational Marginal Pricing (LMP) as determined by the MISO market.

The Company is typically in a net sales position with MISO as generation capacity is in excess of that needed to serve native load and is from time to time in a net purchase position.  When the Company is a net seller such net revenues are included in Electric Utility revenues and when the Company is a net purchaser such net purchases are included in Cost of fuel and purchased power.  Net positions are determined on an hourly basis.  Since the Company became an active MISO member, its generation optimization strategies primarily involve the sale of excess generation into the MISO day ahead and real-time markets.  Net revenues from wholesale activities included in Electric Utility revenues totaled $3.4 million and $14.9 million in the three months ended June 30, 2009 and 2008 respectively.  For the six months ended June 30, 2009 and 2008, net revenues from wholesale activities included in Electric Utility revenues totaled $16.3 million and $36.3, respectively.

The Company also receives transmission revenue that results from other members’ use of the Company’s transmission system.  These revenues are also included in Electric Utility revenues.  Generally, these transmission revenues along with costs charged by the MISO are considered components of base rates and any variance from that included in base rates is recovered/refunded through tracking mechanisms.

As a result of MISO’s operational control over much of the Midwestern electric transmission grid, including SIGECO’s transmission facilities, SIGECO’s continued ability to import power, when necessary, and export power to the wholesale market has been, and may continue to be, impacted.  Given the nature of MISO’s policies regarding use of transmission facilities, as well as ongoing FERC initiatives, and a Day 3 ancillary services market (ASM), where MISO began providing a bid-based regulation and contingency operating reserve markets on January 6, 2009, it is difficult to predict near term operational impacts.  The IURC has approved the Company’s participation in the ASM and has granted authority to defer costs associated with ASM.  To date impacts from the ASM have been minor.

The need to expend capital for improvements to the regional transmission system, both to SIGECO’s facilities as well as to those facilities of adjacent utilities, over the next several years is expected to be significant.  Beginning in June 2008, the Company began timely recovering its investment in certain new electric transmission projects that benefit the MISO infrastructure at a FERC approved rate of return.  Such revenues recorded in Electric Utility revenues associated with projects meeting the criteria of MISO’s transmission expansion plans totaled $2.2 million and $0.7 million for the three months ended June 30, 2009 and 2008 respectively.  For the six months ended June 30, 2009 and 2008, revenues recorded in Electric Utility revenues associated with projects meeting the criteria of MISO’s transmission expansion plans totaled $4.3 million and $0.7, respectively.

Vectren South Electric Lost Margin Recovery Filing
In 2008, the Company made an initial filing with the IURC requesting a multi-year program to promote energy conservation and expanded demand side management programs within its Vectren South electric utility.  As proposed, costs associated with these programs would be recovered through a tracking mechanism.  The implementation of these programs is designed to work in tandem with a lost margin recovery mechanism.  This mechanism, as proposed, allows recovery of a portion of rates from residential and commercial customers based on the level of customer revenues established in Vectren South’s last electric general rate case.  This program is similar to programs authorized by the IURC in the Company’s Indiana natural gas service territories.  In April of 2009, all filings were completed, and the Company would expect an IURC decision to occur during 2009.

13.  
Derivatives

Adoption of SFAS 161
In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities – an Amendment of FASB Statement No. 133” (SFAS 161).  SFAS 161 describes enhanced disclosures under SFAS 133 and requires that objectives for using derivative instruments be disclosed in terms of underlying risk and accounting designation in order to better convey the purpose of derivative use in terms of the risks that the entity is intending to manage.  The Company adopted the qualitative and quantitative disclosures required in both interim and annual financial statements described in SFAS 161 on January 1, 2009.

Accounting Policy for Derivatives
The Company occasionally executes derivative contracts in the normal course of operations while buying and selling commodities to be used in operations, optimizing its generation assets, and managing risk.  The Company accounts for its derivative contracts in accordance with SFAS 133, “Accounting for Derivatives” and its related amendments and interpretations.  In most cases, SFAS 133 requires a derivative to be recorded on the balance sheet as an asset or liability measured at its market value and that a change in the derivative's market value be recognized currently in earnings unless specific hedge criteria are met.

When an energy contract that is a derivative is designated and documented as a normal purchase or normal sale (NPNS), it is exempted from mark-to-market accounting.  Most energy contracts executed by the Company are subject to the NPNS exclusion.  Such energy contracts include real time and day ahead purchase and sale contracts with the MISO, natural gas purchases from ProLiance and others, and wind farm and other electric generating capacity contracts.

When the Company engages in energy contracts and financial contracts that are derivatives and are not subject to the NPNS or other exclusions identified in SFAS 133, such contracts are recorded at market value as current or noncurrent assets or liabilities depending on their value and on when the contracts are expected to be settled.  Contracts and any associated collateral with counter-parties subject to master netting arrangements are presented net in the Consolidated Balance Sheets.  The offset resulting from carrying the derivative at fair value on the balance sheet is charged to earnings unless it qualifies as a hedge or is subject to SFAS 71.  When hedge accounting is appropriate, the Company assesses and documents hedging relationships between the derivative contract and underlying risks as well as its risk management objectives and anticipated effectiveness.  When the hedging relationship is highly effective, derivatives are designated as hedges.  The market value of the effective portion of the hedge is marked to market in accumulated other comprehensive income for cash flow hedges.  Ineffective portions of hedging arrangements are marked to market through earnings.  For fair value hedges, both the derivative and the underlying hedged item are marked to market through earnings.  The offset to contracts affected by SFAS 71 are marked to market as a regulatory asset or liability.  Market value for derivative contracts is determined using quoted market prices from independent sources.  The Company rarely enters into contracts where internal models are used to calculate fair values that have a significant impact the financial statements.

Derivative Use in Risk Mitigation Strategies
Following is a more detailed discussion of activities where the Company may use derivatives to mitigate risk.

Emission Allowance Risk Management
The Company’s wholesale power marketing operations are exposed to price risk associated with emission allowances.  To mitigate this risk, the Company executed call options to hedge wholesale SO2 emission allowance utilization in future periods.  The Company designated and documented these derivatives as cash flow hedges.  At June 30, 2009, a deferred gain of approximately $0.1 million remains in accumulated comprehensive income related to these call options which will be recognized in earnings as emission allowances are utilized.  As of and for the periods reported in these financial statements, ending values and activity relating to emission allowance derivatives affecting the statements of income and cash flows were not significant.

Natural Gas Procurement Risk Management
The Company’s regulated operations have limited exposure to commodity price risk for purchases and sales of natural gas and electricity for retail customers due to current Indiana and Ohio regulations which, subject to compliance with those regulations, allow for recovery of such purchases through natural gas and fuel cost adjustment and other mechanisms.  Although regulated operations are exposed to limited commodity price risk, volatile natural gas prices can still have negative economic impacts, including higher interest costs.  The Company may mitigate these economic risks by using derivative contracts.  These contracts are subject to regulation which allows for reasonable and prudent hedging costs to be recovered through rates.  When regulation is involved, SFAS 71 controls when the offset to mark-to-market accounting is recognized in earnings.

The Company’s wholly owned gas retail operations also mitigate price risk associated with forecasted natural gas purchases by using derivatives.  These nonregulated gas retail operations may also from time to time execute weather derivatives to mitigate extreme weather affecting unregulated gas retail sales.

As of and for the periods reported in these financial statements, ending values and activity relating to natural gas procurement derivatives affecting the statements of income and cash flows were not significant.

Interest Rate Risk Management
The Company is exposed to interest rate risk associated with its borrowing arrangements.  Its risk management program seeks to reduce the potentially adverse effects that market volatility may have on interest expense.  The Company has used interest rate swaps and treasury locks to hedge forecasted debt issuances and other interest rate swaps to manage interest rate exposure.

As of June 30, 2009 and December 31, 2008, no interest rate swaps were outstanding.  Related to derivative instruments associated with completed debts issuances subject to regulatory oversight, an approximate $7.9 million net regulatory asset remains at June 30, 2009. In the six months ended June 30, 2009 and 2008, $0.1 million and $0.2 million respectively were amortized, decreasing to interest expense.  The Company estimates a $0.3 million reduction to interest expense will occur in 2009 related to the amortization of this net position.

Credit Features
Master agreements in place with certain counterparties contain provisions involving the Company’s credit ratings.  If ratings were to fall below investment grade, counterparties to these arrangements could request immediate payment or demand immediate and ongoing full overnight collateralization on net liability positions.  Currently, contracts to purchase natural gas by the Company’s nonutility retail gas marketer to fulfill its retail sales are the only significant derivative-like instruments impacted by credit contingent features.  Such contracts are subject to the NPNS exclusion.  Generally, the natural gas supply period supported by these arrangements is 60 days, but in some instances, may include forecasted purchases up to 12 months in advance.  If the credit-risk-related contingent features underlying these agreements were triggered, the Company would be required to post approximately $1.6 million of additional collateral at June 30, 2009.

14.  
Fair Value Measurements

Financial assets and liabilities and certain nonfinancial assets and liabilities that are revalued at fair value on a recurring basis are valued and disclosed in accordance with SFAS No. 157, “Fair Value Measurements” (SFAS 157).  SFAS 157 defines a hierarchy for disclosing fair value measurements based primarily on the level of public data used in determining fair value.  Level 1 inputs include quoted market prices in active markets for identical assets or liabilities; Level 2 inputs include inputs other than Level 1 inputs that are directly or indirectly observable; and Level 3 inputs include unobservable inputs using estimates and assumptions developed using internal models, which reflect what a market participant would use to determine fair value.  For the balance sheet dates presented in these financial statements, other than $43 million and $75 million invested in money market funds and included in Cash and cash equivalents as of June 30, 2009 and December 31, 2008 respectively, the Company had no material assets or liabilities recorded at fair value outstanding, and none outstanding valued using Level 3 inputs.  The money market investments were valued using Level 1 inputs.

On January 1, 2009, the Company adopted the provisions of SFAS 157 as they relate to nonfinancial assets and nonfinancial liabilities that are measured at fair value on a nonrecurring basis, such as the initial measurement of an asset retirement obligation or the use of fair value in goodwill, intangible assets and long-lived assets impairment tests.  This adoption had no significant impact on the Company’s operating results or financial condition.

FASB Staff Positions on Fair Value Accounting and Disclosure
On June 30, 2009, the Company adopted FSP No. FAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments” (FSP 107-1).  FSP 107-1 requires disclosure in interim financial statements as well as annual financial statements of fair value of all financial instruments for which it is practicable to estimate that value, whether recognized or not recognized in the statement of financial position, as required by FASB Statement No. 107.  The carrying values and estimated fair values of the Company's other financial instruments follow:
                         
   
June 30, 2009
   
December 31, 2008
 
(In millions)
 
Carrying Amount
 
Est. Fair Value
 
Carrying Amount
 
Est. Fair Value
 
Long-term debt
  $ 1,621.5     $ 1,624.3     $ 1,372.8     $ 1,251.0  
Short-term borrowings & notes payable
    88.8       88.8       519.5       519.5  
Cash & cash equivalents
    55.1       55.1       93.2       93.2  

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 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, 2009 and December 31, 2008, 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 $16.7 million at both June 30, 2009 and December 31, 2008.

On June 30, 2009, the Company also adopted FSP FAS 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly” and FSP FAS 115-2 and FAS 124-2, “Recognition and Presentation of Other-Than-Temporary Impairments.” FSP FAS 157-4 provides additional guidance for estimating fair value in accordance with SFAS 157 when the volume and level of activity for the asset or liability have significantly decreased and also includes guidance on identifying circumstances that indicate a transaction is not orderly.  FSP FAS 115-2 and FAS 124-2, impacts the impairment testing of debt securities held for investment purposes and the presentation and disclosure requirements for debt and equity securities described in FASB Statement 115.   The adoption of these two standards did not have any material impact to the Company’s financial statements.

15.  
Impact of Other Newly Adopted and Newly Issued Accounting Principles

SFAS 141R
On January 1, 2009, the Company adopted SFAS No. 141, “Business Combinations” (SFAS 141R).  SFAS 141R establishes principles and requirements for how the acquirer of an entity (1) recognizes and measures the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree (2) recognizes and measures acquired goodwill or a bargain purchase gain and (3) determines what information to disclose in its financial statements in order to enable users to assess the nature and financial effects of the business combination.  SFAS 141R applies to all transactions or other events in which one entity acquires control of one or more businesses and applies to all business entities.  Because the provisions of this standard are applied prospectively, the impact to the Company cannot be determined until the transactions occur.

SFAS 160
In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements-an Amendment of ARB No. 51” (SFAS 160).  SFAS 160 establishes accounting and reporting standards that require ownership percentages in material subsidiaries held by parties other than the parent be clearly identified, labeled, and presented separately from the parent’s equity in the equity section of the consolidated balance sheet; the amount of consolidated net income attributable to the parent and the noncontrolling interest to be clearly identified and presented on the face of the consolidated income statement; that changes in the parent’s ownership interest while it retains control over its subsidiary be accounted for consistently; that when a subsidiary is deconsolidated, any retained noncontrolling equity investment be initially measured at fair value; and that sufficient disclosure is made to clearly identify and distinguish between the interests of the parent and the noncontrolling owners.  The adoption of SFAS 160 on January 1, 2009 had an immaterial impact to the Company’s presentation of its financial position and operating results.

SFAS 165
The Company adopted Financial Accounting Standards No. 165, “Subsequent Events” (SFAS 165) on June 30, 2009.  In the instance of a public registrant such as the Company, SFAS 165 establishes the accounting for and disclosure of events that occur after the balance sheet date but before financial statements are “issued”, as that term is defined in SFAS 165.   The standard requires the disclosure of the date through which an entity has evaluated subsequent events.  Such disclosure is included in Note 2 to these consolidated financial statements.  The adoption of SFAS 165 did not have a material impact.

EITF 08-05
On January 1, 2009, the Company adopted EITF Issue No. 08-5, “Issuer's Accounting for Liabilities Measured at Fair Value with a Third-Party Credit Enhancement” (EITF 08-5).  EITF 08-5 states that companies should not include the effect of third-party credit enhancements in the fair value measurement of the related liabilities.  EITF 08-5 also requires companies with outstanding liabilities measured or disclosed at fair value to disclose the existence of credit enhancements, to disclose valuation techniques used to measure liabilities and to include a discussion of changes, if any, from the valuation techniques used to measure liabilities in prior periods.

As of June 30, 2009, the Company has approximately $251.1 million of debt instruments that are supported by a third party credit enhancement feature such as insurance from a monoline insurer or a letter of credit posted by third party that supports the Company’s credit facilities.  It is not anticipated the Company’s valuation techniques will change materially as a result of the adoption of EITF 08-5.

FASB Staff Position (FSP) 142-3
In April 2008, the FASB issued FSP No. 142-3, Determination of the Useful Life of Intangible Assets. FSP No. 142-3 amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS No. 142, Goodwill and Other Intangible Assets. The Company adopted FSP No. 142-3 as of January 1, 2009 and such adoption did not have a material impact on the consolidated financial statements.

FSP No. FAS 132(R)-1
In December 2008, the FASB issued FSP No. FAS 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets” (FSP 132(R)-1).  FSP 132(R)-1 amends the plan asset disclosures required under FAS Statement No. 132(R) to provide guidance on an employer’s disclosures about plan assets of a defined benefit pension or other postretirement plan. Guidance provided by this FSP relates to disclosures about investment policies and strategies, categories of plan assets, fair value measurements of plan assets, and significant concentrations of risk. FSP FAS 132(R)-1 is effective for fiscal years ending after December 15, 2009. The Company will include FSP FAS 132(R)-1’s disclosure requirements in its 2009 annual financial statements.

16.  
Segment Reporting

Information related to the Company’s business segments is summarized below:

                             
   
Three Months
   
Six Months
 
   
Ended June 30,
   
Ended June 30,
 
(In millions)
 
2009
     
2008
   
2009
     
2008
 
Revenues
                           
Utility Group
                           
Gas Utility Services
  $ 139.1       $ 224.9     $ 666.5       $ 858.5  
Electric Utility Services
    132.7         127.2       257.7         254.4  
Other Operations
    10.7         11.7       21.4         23.4  
Eliminations
    (10.3 )       (11.1 )     (20.6 )       (22.2 )
Total Utility Group
    272.2         352.7       925.0         1,114.1  
Nonutility Group
    137.2         144.1       328.4         313.8  
Eliminations
    (33.9 )       (32.9 )     (82.7 )       (61.9 )
Consolidated Revenues
  $ 375.5       $ 463.9     $ 1,170.7       $ 1,366.0  
                                     
Profitability Measure - Net Income (Loss)
                                   
Gas Utility Services
  $ (3.3 )     $ (1.9 )   $ 37.9       $ 40.4  
Electric Utility Services
    8.3         6.8       20.2         19.4  
Other Operations
    1.6         3.9       4.7         7.0  
Utility Group Net Income
    6.6         8.8       62.8         66.8  
Nonutility Group Net Income (Loss)
    (13.0 )
1/
    (4.0 )     3.5  
1/
    2.3  
Corporate & Other Group Net (Loss)
    (0.3 )       (0.1 )     (0.2 )       (0.4 )
Consolidated Net Income (Loss)
  $ (6.7 )     $ 4.7     $ 66.1       $ 68.7  

1/ Includes an $11.9 million after tax charge associated with ProLiance’s Liberty Gas Storage investment.  See Note 8.
 
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 operating 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 (VEDO or Vectren Ohio).  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 560,000 natural gas customers located in central and southern Indiana.  SIGECO provides energy delivery services to over 140,000 electric customers and approximately 110,000 gas customers located near Evansville in southwestern Indiana.  SIGECO also owns and operates electric generation 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 315,000 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.

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.

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 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 2008 annual report filed on Form 10-K.

For the three months ended June 30, 2009, there was a consolidated net loss of $6.7 million, or $0.08 per share, compared to earnings of $4.7 million, or $0.06 per share for the three months ended June 30, 2008.  For the six months ended June 30, 2009, consolidated net income was $66.1 million, or $0.82 per share, compared to $68.7 million, or $0.90 per share for the six months ended June 30, 2008.   Excluding the impact of the charge discussed below of $11.9 million after tax, or $0.15 per share, related to ProLiance Holdings, LLC's (ProLiance) investment in Liberty Gas Storage, for the three and six months ended June 30, 2009, there was consolidated net income of $5.2 million, or $0.07 per share, and $78.0 million, or $0.97 per share, respectively.

Charge Related to Liberty Gas Storage

During the three months ended June 30, 2009, the Company recorded its share of a charge related to ProLiance's investment in Liberty Gas Storage, LLC (herein referred to as the Liberty Charge).  In the Consolidated Statement of Income, the impact associated with the Liberty Charge is an approximate $19.9 million reduction to Equity in earning of unconsolidated affiliates and an income tax benefit reflected in Income taxes of approximately $8.0 million. The $11.9  million net after tax, or $0.15 per share, charge is generally consistent with previous disclosures about development issues at the Louisiana site.  More detailed information about ProLiance’s investment in Liberty is included in Note 8 to the consolidated financial statements.

Consolidated Results Excluding the Liberty Charge (See Page 37, Regarding the Use of Non-GAAP Measures)

Net income and earnings per share, excluding the Liberty Charge, in total and by group, for the three and six months ended June 30, 2009 and 2008 follow:

     
Three Months
   
Six Months
 
     
Ended June 30,
   
Ended June 30,
 
(In millions, except per share data)
 
2009
   
2008
   
2009
   
2008
 
Net income, excluding Liberty Charge
  $ 5.2     $ 4.7     $ 78.0     $ 68.7  
Attributed to:
Utility Group
    6.6       8.8       62.8       66.8  
 
Nonutility Group, excluding Liberty Charge
    (1.1 )     (4.0 )     15.4       2.3  
 
Corporate & other
    (0.3 )     (0.1 )     (0.2 )     (0.4 )
                                   
Basic EPS, excluding the Liberty Charge
  $ 0.07     $ 0.06     $ 0.97     $ 0.90  
Attributed to:
Utility Group
    0.08       0.12       0.78       0.88  
                                 Nonutility Group, excluding Liberty Charge
    (0.01 )     (0.05 )     0.19       0.03  
                                          Corporate & other
    -       (0.01 )     -       (0.01 )

For the three months ended June 30, 2009, net income excluding the Liberty Charge was $5.2 million, or $0.07 per share, compared to earnings of $4.7 million, or $0.06 per share for the three months ended June 30, 2008.  For the six months ended June 30, 2009, net income excluding the Liberty Charge was $78.0 million, or $0.97 per share, compared to $68.7 million, or $0.90 per share for the six months ended June 30, 2008.  Year to date, earnings per share are approximately $0.04 per share lower than earnings per share in 2008 due to the increased number of common shares outstanding, resulting from the issuance of common shares in June 2008.

Utility Group

In the second quarter of 2009, the Utility Group’s earnings were $6.6 million compared to $8.8 million in 2008, a decrease of $2.2 million.  Year to date, utility earnings were $62.8 million, or $0.78 per share, compared to $66.8 million, or $0.88 per share, in 2008, a decrease of $4.0 million.  The decreases result primarily from lower large customer usage and lower wholesale power sales, both of which have been impacted by the recession, as well as increased deprecation expense.  Increased revenues associated with regulatory initiatives and warmer weather in June 2009 partially offset these declines.

Nonutility Group

The Nonutility Group’s 2009 second quarter seasonal loss, excluding the Liberty Charge, was $1.1 million compared to a loss of $4.0 million in 2008.  Year to date, nonutility income, excluding the Liberty Charge, was $15.4 million, or $0.19 per share, compared to $2.3 million, or $0.03 per share, in 2008.  An improvement of $3.9 million in the quarter as compared to the prior year is attributable to better results from each of the primarily nonutility business groups.  Primary nonutility business groups are Energy Marketing and Services companies, Coal Mining, and Energy Infrastructure Services companies.

Year to date, nonutility earnings, excluding the Liberty Charge, have increased $13.1 million.  Year to date, Energy Marketing Services’ earnings reflect retail gas marketing earnings $6.1 million higher than the prior year.  Coal mining operations has shown improvement due to new contract pricing effective January 1, 2009, increasing its contribution to earnings approximately $4.5 million.  The remaining year to date increase is primarily due to second quarter 2009 renewable energy project activity at Energy Systems Group, LLC (ESG).

Inclusive of the Liberty Charge, the Nonutility Group incurred a loss of $13.0 million in the three months ended June 30, 2009 and generated net income of $3.5 million for the six months ended June 30, 2009.

Dividends

Dividends declared for the three months ended June 30, 2009, were $0.335 per share compared to $0.325 per share for the same period in 2008.   Dividends declared for the six months ended June 30, 2009, were $0.670 per share compared to $0.650 per share for the same period in 2008.

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, 2009 and 2008 follow:
                         
   
Three Months
   
Six Months
 
   
Ended June 30,
   
Ended June 30,
 
(In millions, except per share data)
 
2009
   
2008
   
2009
   
2008
 
OPERATING REVENUES
                       
Gas utility
  $ 139.1     $ 224.9     $ 666.5     $ 858.5  
Electric utility
    132.7       127.2       257.7       254.4  
 Other      0.4        0.6        0.8        1.2  
Total operating revenues
    272.2       352.7       925.0       1,114.1  
OPERATING EXPENSES
                               
Cost of gas sold
    58.0       143.8       412.6       605.8  
Cost of fuel & purchased power
    50.3       48.5       97.3       94.5  
Other operating
    78.7       74.5       158.0       148.5  
Depreciation & amortization
    45.0       40.9       88.9       81.6  
Taxes other than income taxes
    12.6       13.9       35.4       40.1  
Total operating expenses
    244.6       321.6       792.2       970.5  
                                 
OPERATING INCOME
    27.6       31.1       132.8       143.6  
                                 
OTHER INCOME - NET
    2.5       2.2       4.0       4.2  
                                 
INTEREST EXPENSE
    20.0       19.1       38.7       39.9  
                                 
INCOME BEFORE INCOME TAXES
    10.1       14.2       98.1       107.9  
                                 
INCOME TAXES
    3.5       5.4       35.3       41.1  
                                 
NET INCOME
  $ 6.6     $ 8.8     $ 62.8     $ 66.8  
                                 
CONTRIBUTION TO VECTREN BASIC EPS
  $ 0.08     $ 0.12     $ 0.78     $ 0.88  
 
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.  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 have been volatile.  Normal temperature adjustment (NTA) and lost margin recovery 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.  Indiana Gas’ territory has both an NTA since 2005 and lost margin recovery since 2006.  SIGECO’s natural gas territory has an NTA since 2005 and lost margin recovery since 2007.  The Ohio service territory had lost margin recovery since 2006.  The Ohio lost margin recovery mechanism ended when new base rates went into effect in February 2009.  This mechanism was replaced by a rate design, commonly referred to as a straight fixed variable rate design, which is more dependent on service charge revenues and less dependent on volumetric revenues than previous rate designs. This new rate design, which will be fully phased in February 2010, will eventually mitigate most weather risk in Ohio.  SIGECO’s electric service territory has neither NTA nor lost margin recovery mechanisms. 

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.  Expenses subject to tracking mechanisms include Ohio bad debts and percent of income payment plan expenses, costs associated with exiting the merchant function and to perform riser replacement in Ohio, Indiana gas pipeline integrity management costs, costs to fund Indiana energy efficiency programs, MISO transmission revenues and costs, as well as the gas cost component of bad debt expense based on historical experience and unaccounted for gas.  Unaccounted for gas is also tracked in the Ohio service territory.  Certain operating costs, including depreciation, associated with operating environmental compliance equipment and regional transmission investments are also tracked.

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 recent recession has had and may continue to have some negative impact on both gas and electric large customers.  This impact has included, and may continue to include, tempered growth, significant conservation measures, and perhaps even plant closures or bankruptcies.  While no one industrial customer comprises 10 percent of consolidated margin, the top five industrial electric customers comprise approximately 11 percent of electric utility margin in the six months ended June 30, 2009, and therefore any significant decline in their collective margin could adversely impact operating results.  Deteriorating economic conditions may also lead to continued lower residential and commercial customer counts.  Further, resulting from the lower power prices, decreased demand for electricity, and higher coal prices associated with contracts negotiated last year, 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 the likelihood of growing coal inventories.

Following is a discussion and analysis of margin generated from regulated utility operations.

Gas Utility Margin (Gas utility revenues less Cost of gas)
Gas Utility margin and throughput by customer type follows:
   
Three Months
   
Six Months
 
   
Ended June 30,
   
Ended June 30,
 
(In millions)
 
2009
   
2008
   
2009
   
2008
 
Gas utility revenues
  $ 139.1     $ 224.9     $ 666.5     $ 858.5  
Cost of gas sold
    58.0       143.8       412.6       605.8  
Total gas utility margin
  $ 81.1     $ 81.1     $ 253.9     $ 252.7  
Margin attributed to:
                               
Residential & commercial customers
  $ 68.5     $ 65.4     $ 221.1     $ 216.3  
Industrial customers
    9.3       11.1       24.4       27.8  
Other
    3.3       4.6       8.4       8.6  
Sold & transported volumes in MMDth attributed to:
                 
Residential & commercial customers
    12.6       12.5       65.2       70.3  
Industrial customers
    15.7       20.4       39.8       49.1  
Total sold & transported volumes
    28.3       32.9       105.0       119.4  

For the three and six months ended June 30, 2009 , gas utility margins were $81.1 million and $253.9 million, respectively, and are generally flat compared to the prior year periods.  Among all customer classes, margin increases associated with regulatory initiatives including the full impact of the Vectren North base rate increase effective in February 14, 2008 and the Vectren Ohio base rate increase effective February 22, 2009, were $2.8 million quarter over quarter and $6.3 million year to date.  Increases were offset by impacts of the recession.  During the quarter, management estimates a $1.4 million decrease in industrial customer margin associated with lower volumes sold, and slightly lower residential and commercial customer counts decreased margin approximately $0.5 million.  Year to date, management estimates $3.3 million in industrial customer margin declines and $1.0 million related to lower residential and commercial customer counts.  The impact of operating costs, including revenue and usage taxes, recovered in margin was unfavorable $0.4 million quarter over quarter and unfavorable $0.8 million year over year, reflecting lower revenue taxes offset by higher pass through operating expenses.  The average cost per dekatherm of gas purchased for the six months ended June 30, 2009, was $6.53 compared to $10.07 in 2008.

Electric Utility Margin (Electric Utility revenues less Cost of fuel and purchased power)
Electric Utility margin and volumes sold by customer type follows:
                         
   
Three Months
   
Six Months
 
   
Ended June 30,
   
Ended June 30,
 
(In millions)
 
2009
   
2008
   
2009
   
2008
 
                         
Electric utility revenues
  $ 132.7     $ 127.2     $ 257.7     $ 254.4  
Cost of fuel & purchased power
    50.3       48.5       97.3       94.5  
Total electric utility margin
  $ 82.4     $ 78.7     $ 160.4     $ 159.9  
Margin attributed to:
                               
Residential & commercial customers
  $ 55.6     $ 48.6     $ 107.6     $ 99.9  
Industrial customers
    21.6       19.1       40.3       39.3  
Other customers
    1.2       5.9       2.8       7.5  
Subtotal: retail
  $ 78.4     $ 73.6     $ 150.7     $ 146.7  
Wholesale power marketing & transmission system margin
  $ 4.0     $ 5.1     $ 9.7     $ 13.2  
                                 
Electric volumes sold in GWh attributed to:
                               
Residential & commercial customers
    680.5       646.6       1,352.1       1,361.8  
Industrial customers
    557.4       639.8       1,066.4       1,240.5  
Other customers
    4.5       17.4       9.6       54.0  
Total retail volumes sold
    1,242.4       1,303.8       2,428.1       2,656.3  
                                 

Retail Margin
Electric retail utility margins were $­­­­78.4 million and $150.7 million for the three and six months ended June 30, 2009, increases  over the prior periods of $4.8 million and $4.0 million, respectively.  Increased margin among the customer classes associated with returns on pollution control investments totaled $1.4 million quarter over quarter and $1.9 million year to date, and margin associated with tracked costs such as recovery of MISO and pollution control operating expenses increased $3.1 million quarter over quarter and $5.6 million year to date.  Management estimates the impact of weather 23 percent warmer than the prior year to have increased residential and commercial margin $2.4 million in the second quarter and $1.8 million year to date.  Year to date, management also estimates other usage declines associated with the weak economy to have decreased margin approximately $1.4 million for residential and commercial customers and $3.7 million for industrial customers, with $0.4 million of small customer decline and $1.7 million of the industrial customer decline occurring in the second quarter.

Wholesale Power and Transmission System Operation Margin
Generation capacity is from time to time in excess of native load requirements.  The Company markets and sells this unutilized generation to optimize the return on its owned assets.  Substantially all of the margin generated from off-system sales occurs into the MISO Day Ahead and Real Time markets.  The level of off-system sales is primarily affected by market conditions, the level of excess generating capacity, and electric transmission availability.  MISO-related transmission system operation activity includes margin associated with others using the Company's transmission system and returns on electric transmission projects constructed by the Company in its service territory that benefit reliability throughout the region.  Returns associated with these projects meeting the criteria of MISO’s transmission expansion plans began in June 2008 and returns are increasing due to the level of capital invested in qualifying projects.

Further detail of Wholesale and Transmission activity follows:
                         
   
Three Months
   
Six Months
 
   
Ended June 30,
   
Ended June 30,
 
(In millions)
 
2009
   
2008
   
2009
   
2008
 
Off-system sales
  $ 0.4     $ 3.1     $ 3.1     $ 10.3  
Transmission system sales
    3.6       2.0       6.6       2.9  
Total wholesale and transmission
  $ 4.0     $ 5.1     $ 9.7     $ 13.2  

For the three and six months ended June 30, 2009, total wholesale margins were $4.0 million and $9.7 million, representing decreases of $1.1 million and $3.5 million, respectively, compared to 2008.

During the second quarter of 2009, margin from off-system sales retained by the Company decreased $2.7 million compared to 2008, bringing the year to date decrease in 2009 compared to 2008 to $7.2 million.  During 2009, the Company experienced lower wholesale power marketing margins due to lower demand and wholesale prices due to the recession, coupled with increased coal costs.  Year to date, off-system sales totaled 406.4 GWh in 2009, compared to 740.3 GWh in 2008.  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.

Related to transmission system sales, the contribution to margin has increased as expected based upon increased capital invested in projects meeting the criteria of MISO’s transmission expansion plans.  Margin associated with these projects totaled $2.2 million and $4.3 million for the three and six months ended June 30, 2009, respectively, compared to $0.7 million in both the three and six months ended June 30, 2008.

Utility Group Operating Expenses

Other Operating Expenses
For the three and six months ended June 30, 2009, other operating expenses were $78.7 million and $158.0 million, which reflect increases of $4.2 million and $9.5 million, compared to 2008.  Approximately $2.7 million and $7.2 million of the increases result from increased costs directly recovered through utility margin.  Examples of such tracked costs include Ohio bad debts, Indiana gas pipeline integrity management costs, costs to fund Indiana energy efficiency programs, and MISO transmission revenues and costs, among others.  The remaining increase is primarily related to higher levels of bad debt expense associated with the Indiana service territory. Quarter over quarter and year over year, all other operating expenses were generally flat.

Depreciation & Amortization
For the three and six months ended June 30, 2009, depreciation expense was $45.0 million and $88.9 million, which represents increases of $4.1 million and $7.3 million compared to 2008.  Plant additions include the approximate $100 million SO2 scrubber placed into service January 1, 2009, for which depreciation totaling $1.5 million in the quarter and $2.6 million year to date is directly recovered in electric utility margin.

Taxes Other Than Income Taxes
For the three and six months ended June 30, 2009, taxes other than income taxes were $12.6 million and $35.4 million, which reflect decreases of $1.3 million for the quarter and $4.7 million year over year.  The decrease is attributable to lower utility receipts, excise, and usage taxes caused principally by lower gas prices and is tracked in revenues.

Interest Expense

For the three and six months ended June 30, 2009, interest expense was $20.0 million and $38.7 million, which represents an increase of $0.9 million in the quarter and a decrease of $1.2 million compared to 2008.  The increase in the quarter reflects a long term financing transaction completed in the second quarter of 2009 in which VUHI issued $100 million in unsecured eleven year notes with an interest rate of 6.28 percent to institutional investors.  Both periods reflect lower short-term interest rates and lower average short-term debt balances impacted favorably by lower gas costs.

Income Taxes

For the three and six months ended June 30, 2009, federal and state income taxes were $3.5 million and $35.3 million, which represents decreases of $1.9 million and $5.8 million compared to 2008.  The lower taxes are primarily due to lower pretax income.

Environmental Matters

Clean Air Act

The Clean Air Interstate Rule (CAIR) is an allowance cap and trade program requiring further reductions from coal-burning power plants in 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 is positioned to comply with SO2 reductions effective January 1, 2010.  Utilization of the Company’s inventory of NOx and SO2  allowances may also be impacted if CAIR is further revised; however, most of these allowances were granted to the Company at zero cost, so a reduction in carrying value is not expected.

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.  It is possible that the vacatur of the CAMR regulations will lead to increased support for the passage of a multi-pollutant bill in Congress.  It is also possible that the USEPA will promulgate a revised mercury regulation in 2009.

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 $307 million in pollution control equipment, including Selective Catalytic Reduction (SCR) systems and fabric filters.  SCR technology is the most effective method of reducing NOx emissions where high removal efficiencies are required and fabric filters control particulate matter emissions.  These investments were included in rate base for purposes of determining new base rates that went into effect on August 15, 2007.  Prior to being included in base rates, return on investments made and recovery of related operating expenses were recovered through a rider mechanism.

Further, the IURC granted SIGECO authority to invest in an SO2 scrubber at its generating facility that is jointly owned with ALCOA (the Company’s portion is 150 MW).  The order allows SIGECO to recover an approximate 8 percent return on capital investments through a rider mechanism which is periodically updated for actual costs incurred less post in-service depreciation expense.  Through June 30, 2009, the Company has invested approximately $100 million in this project.  The scrubber was placed into service on January 1, 2009.  Recovery through a rider mechanism of associated operating expenses including depreciation expense associated with the scrubber also began on January 1, 2009.  With the SO2 scrubber fully operational, SIGECO is positioned for compliance with the additional SO2 reductions required by Phase I CAIR commencing 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 pollution control legislation, if and when, reductions in mercury and further reductions in NOx and SO2 are promulgated by USEPA.

Climate Change

Vectren is committed to responsible environmental stewardship and conservation efforts as demonstrated by its proactive approach to balancing environmental and customer needs. While scientific uncertainties exist and the debate surrounding global climate change is ongoing, the growing understanding of the science of climate change would suggest a strong potential for adverse economic and social consequences should world-wide carbon dioxide (CO2) and other greenhouse gas emissions continue at present levels.

The need to reduce CO2 and other greenhouse gas emissions, yet provide affordable energy requires thoughtful balance. For these reasons, Vectren supports a national climate change policy with the following elements:

·  
An inclusive scope that involves all sectors of the economy and sources of greenhouse gases, and recognizes early actions and investments made to mitigate greenhouse gas emissions;
·  
Provisions for enhanced use of renewable energy sources as a supplement to base load coal generation including effective energy conservation, demand side management and generation efficiency measures;
·  
A flexible market-based cap and trade approach with zero cost allowance allocations to coal-fired electric generators.  The approach should have a properly designed economic safety valve in order to reduce or eliminate extreme price spikes and potential price volatility. A long lead time must be included to align nearer-term technology capabilities and expanded generation efficiency and other enhanced renewable strategies, ensuring that generation sources will rely less on natural gas to meet short term carbon reduction requirements.  This new regime should allow for adequate resource and generation planning and remove existing impediments to efficiency enhancements posed by the current New Source Review provisions of the Clean Air Act;
·  
Inclusion of incentives for investment in advanced clean coal technology and support for research and development; and
·  
A strategy supporting alternative energy technologies and biofuels and increasing the domestic supply of natural gas to reduce dependence on foreign oil and imported natural gas.

Current Initiatives to Increase Conservation and Reduce Emissions
The Company is committed to its policy on climate change and conservation. Evidence of this commitment includes:
·  
Focusing the Company’s mission statement and purpose on corporate sustainability and the need to help customers conserve and manage energy costs;
·  
Recently executing long-term contracts to purchase 80MW of wind energy generated by wind farms in Benton County, Indiana;
·  
Evaluating other renewable energy projects to complement base load coal fired generation in advance of  mandated renewable energy portfolio standards;
·  
Implementing conservation initiatives in the Company’s Indiana and Ohio gas utility service territories;
·  
Participation in an electric conservation and demand side management collaborative with the OUCC and other customer advocate groups;
·  
Evaluating potential carbon requirements with regard to new generation, other fuel supply sources, and future environmental compliance plans;
·  
Reducing the Company’s carbon footprint by measures such as purchasing hybrid vehicles, and optimizing generation efficiencies;
·  
Developing renewable energy and energy efficiency performance contracting projects through its wholly owned subsidiary, Energy Systems Group.

Legislative Actions and Other Climate Change Initiatives
The U.S. House of Representatives has passed a comprehensive energy bill that includes a carbon cap and trade program where 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.  Under the proposed energy bill, the electric power industry will receive 40 percent of the annual allowance allocation at zero cost.  As of the date of this filing, the Senate has not passed a bill, and the bill is not law.

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 of the Midwestern Regional Greenhouse Gas Reduction Accord, and in the recently completed 2009 session, the state’s legislature debated, but did not pass, a renewable energy portfolio standard.

In advance of a federal or state renewable portfolio standard, SIGECO recently purchased a  3.2 MW landfill gas generation facility from a related entity that is directly interconnected to the Company’s distribution system and recently 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 new 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.  Upon finalization, the endangerment finding 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 also proposed a significant new mandatory greenhouse gas emissions registry.

Impact of Legislative Actions and 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 possibly 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 to operating expenses for the purchase of allowances, and later to capital expenditures as technology becomes available to control greenhouse gas emissions.  However, these compliance cost estimates are very sensitive to highly uncertain assumptions, including allowance prices and energy efficiency targets.  Costs to purchase allowances that cap greenhouse gas 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.  Approximately 22 percent of electric volumes sold in 2008 were delivered to municipal and other wholesale customers.  As such, the Company has some flexibility to modify the level of these transactions to reduce overall emissions and reduce costs associated with complying with new environmental regulations.

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 $22.2 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 is also named in a lawsuit filed in federal district court in May 2007, involving another site subject to potential environmental remediation efforts.

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 May 2007 lawsuit.  While the total costs that may be incurred in connection with addressing these sites cannot be determined at this time, SIGECO has recorded cumulative costs that it reasonably expects to incur totaling approximately $9.2 million.  With respect to insurance coverage, SIGECO has settled with insurance carriers under insurance policies in effect when these sites were in operation in an aggregate amount of $8.1 million.

Environmental remediation costs related to Indiana Gas’ and SIGECO’s manufactured gas plants and other sites have had a minor impact on results of operations or financial condition since cumulative costs recorded to date approximate PRP and insurance settlement recoveries.  Such cumulative costs 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, 2009 and December 31, 2008, approximately $5.1 million and $6.5 million, respectively, of accrued, but not yet spent, remediation costs are included in Other Liabilities related to both the Indiana Gas and SIGECO sites.

Rate & Regulatory Matters

Vectren Energy Delivery of Ohio, Inc. (VEDO) Gas Base Rate Order Received

On January 7, 2009, the PUCO issued an order approving the stipulation reached in the VEDO rate case.  The order provides for a rate increase of nearly $14.8 million, an overall rate of return of 8.89 percent on rate base of about $235 million; an opportunity to recover costs of a program to accelerate replacement of cast iron and bare steel pipes, as well as certain service risers; and base rate recovery of an additional $2.9 million in conservation program spending.

The order also adjusted the rate design used to collect the agreed-upon revenue from VEDO's customers.  The order allows 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.  A straight fixed variable design mitigates most weather risk as well as the effects of declining usage, similar to the Company’s lost margin recovery mechanism, which expired when this new rate design went into effect on February 22, 2009.  In 2008, annual results include approximately $4.3 million of revenue from a lost margin recovery mechanism that does not continue once this base rate increase is in effect.  After year one, nearly 90 percent of the combined residential and commercial base rate margins will be recovered through the customer service charge.  The OCC has filed a request for rehearing on the rate design finding by the PUCO.  The rehearing request mirrors similar requests filed by the OCC in each case where the PUCO has approved similar rate designs, and all such requests have been denied.

With this rate order the Company has in place for its Ohio gas territory rates that allow for the phased implementation of a straight fixed variable rate design that mitigates both weather risk and lost margin; tracking of bad debt and percent of income payment plan (PIPP) expenses; base rate recovery of pipeline integrity management expense; timely recovery of costs associated with the accelerated replacement of bare steel and cast iron pipes, as well as certain service risers; and expanded conservation programs now totaling up to $5 million in annual expenditures.

MISO

Since 2002 and with the IURC’s approval, the Company has been a member of the Midwest Independent System Operator, Inc. (MISO), a FERC approved regional transmission organization.  The MISO serves the electrical transmission needs of much of the Midwest and maintains operational control over the Company’s electric transmission facilities as well as that of other Midwest utilities.  Since April 1, 2005, the Company has been an active participant in the MISO energy markets, bidding its owned generation into the Day Ahead and Real Time markets and procuring power for its retail customers at Locational Marginal Pricing (LMP) as determined by the MISO market.

The Company is typically in a net sales position with MISO as generation capacity is in excess of that needed to serve native load and is from time to time in a net purchase position.  When the Company is a net seller such net revenues are included in Electric Utility revenues and when the Company is a net purchaser such net purchases are included in Cost of fuel and purchased power.  Net positions are determined on an hourly basis.  Since the Company became an active MISO member, its generation optimization strategies primarily involve the sale of excess generation into the MISO day ahead and real-time markets.  Net revenues from wholesale activities included in Electric Utility revenues totaled $3.4 million and $14.9 million in the three months ended June 30, 2009 and 2008 respectively.  For the six months ended June 30, 2009 and 2008, net revenues from wholesale activities included in Electric Utility revenues totaled $16.3 million and $36.3, respectively.

The Company also receives transmission revenue that results from other members’ use of the Company’s transmission system.  These revenues are also included in Electric Utility revenues.  Generally, these transmission revenues along with costs charged by the MISO are considered components of base rates and any variance from that included in base rates is recovered/ refunded through tracking mechanisms.

As a result of MISO’s operational control over much of the Midwestern electric transmission grid, including SIGECO’s transmission facilities, SIGECO’s continued ability to import power, when necessary, and export power to the wholesale market has been, and may continue to be, impacted.  Given the nature of MISO’s policies regarding use of transmission facilities, as well as ongoing FERC initiatives, and a Day 3 ancillary services market (ASM), where MISO began providing a bid-based regulation and contingency operating reserve markets on January 6, 2009, it is difficult to predict near term operational impacts.  The IURC has approved the Company’s participation in the ASM and has granted authority to defer costs associated with ASM.  To date impacts from the ASM have been minor.

The need to expend capital for improvements to the regional transmission system, both to SIGECO’s facilities as well as to those facilities of adjacent utilities, over the next several years is expected to be significant.  Beginning in June 2008, the Company began timely recovering its investment in certain new electric transmission projects that benefit the MISO infrastructure at a FERC approved rate of return.  Such revenues recorded in Electric Utility revenues associated with projects meeting the criteria of MISO’s transmission expansion plans totaled $2.2 million and $0.7 million for the three months ended June 30, 2009 and 2008 respectively.  For the six months ended June 30, 2009 and 2008, revenues recorded in Electric Utility revenues associated with projects meeting the criteria of MISO’s transmission expansion plans totaled $4.3 million and $0.7, respectively.

One such project currently under construction is an interstate 345 kilovolt transmission line that will connect Vectren’s A B Brown 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 is to 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 $70 million, as of June 30, 2009, the Company has invested approximately $5.8 million.  The Company expects this project to be 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 currently unforeseen difficulties delay or permanently halt the project.

Vectren South Electric Lost Margin Recovery Filing

In 2008, the Company made an initial filing with the IURC requesting a multi-year program to promote energy conservation and expanded demand side management programs within its Vectren South electric utility.  As proposed, costs associated with these programs would be recovered through a tracking mechanism.  The implementation of these programs is designed to work in tandem with a lost margin recovery mechanism.  This mechanism, as proposed, allows recovery of a portion of rates from residential and commercial customers based on the level of customer revenues established in Vectren South’s last electric general rate case.  This program is similar to programs authorized by the IURC in the Company’s Indiana natural gas service territories.  In April of 2009, all filings were completed, and the Company would expect an IURC decision to occur during 2009.

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.  Nonutility Group earnings for the three and six months ended June 30, 2009 and 2008, follow:

   
Three Months
   
Six Months
 
   
Ended June 30,
   
Ended June 30,
 
(In millions, except per share amounts)
 
2009
   
2008
   
2009
   
2008