-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, Qnk/4O3Pzr+h2DYBnzCsraUpXtRLkCcjLyCeXAATiZg3O3H/IvRUeLpjDS5TdhUW K+0cu8EOY8+m13KvHHfN0A== 0001096385-11-000015.txt : 20110217 0001096385-11-000015.hdr.sgml : 20110217 20110217155320 ACCESSION NUMBER: 0001096385-11-000015 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 13 CONFORMED PERIOD OF REPORT: 20101231 FILED AS OF DATE: 20110217 DATE AS OF CHANGE: 20110217 FILER: COMPANY DATA: COMPANY CONFORMED NAME: VECTREN CORP CENTRAL INDEX KEY: 0001096385 STANDARD INDUSTRIAL CLASSIFICATION: GAS & OTHER SERVICES COMBINED [4932] IRS NUMBER: 352086905 STATE OF INCORPORATION: IN FISCAL YEAR END: 0202 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-15467 FILM NUMBER: 11620923 BUSINESS ADDRESS: STREET 1: ONE VECTREN SQUARE CITY: EVANSVILLE STATE: IN ZIP: 47708 BUSINESS PHONE: 8124914000 MAIL ADDRESS: STREET 1: ONE VECTREN SQUARE CITY: EVANSVILLE STATE: IN ZIP: 47708 10-K 1 vvc_10k.htm VVC 10K vvc_10k.htm
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549


FORM 10-K

(Mark One)

ý
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934


For the fiscal year ended December 31, 2010
OR

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

For the transition period from __________________ to ________________________


Commission file number:   1-15467



VECTREN CORPORATION

(Exact name of registrant as specified in its charter)


Vectren Logo

INDIANA
  
35-2086905
(State or other jurisdiction of incorporation or organization)
 
  
(IRS Employer Identification No.)
One Vectren Square
  
47708
(Address of principal executive offices)
  
(Zip Code)

Registrant's telephone number, including area code:  812-491-4000

Securities registered pursuant to Section 12(b) of the Act:

Title of each class
  
Name of each exchange on which registered
 Common – Without Par
  
New York Stock Exchange


Securities registered pursuant to Section 12(g) of the Act:  NONE

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes ý    No□

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  Yes □ No ý

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.  Yes ý 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 ý No □

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. □

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.  (Check one):

Large accelerated filer ý                                                                     Accelerated filer □

Non-accelerated filer □                                                     Smaller reporting company < /font>□
(Do not check if a smaller
reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes □ No ý

The aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of June 30, 2010, was $1,913,186,088.
 
 
 
Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date.
 

Common Stock - Without Par Value
­­­81,667,423
January 31, 2011
Class
Number of Shares
Date


Documents Incorporated by Reference


Certain information in the Company's definitive Proxy Statement for the 2011 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission pursuant to Regulation 14A, not later than 120 days after the end of the fiscal year, is incorporated by reference in Part III of this Form 10-K.


Definitions


AFUDC:  allowance for funds used during construction
 
MCF / BCF:  thousands / billions of cubic feet
ASC:  Accounting Standards Codification
 
MDth / MMDth: thousands / millions of dekatherms
BTU / MMBTU:  British thermal units / millions of BTU
MISO: Midwest Independent System Operator
EPA:  Environmental Protection Agency
 
MW:  megawatts
FASB:  Financial Accounting Standards Board
 
MWh / GWh:  megawatt hours / thousands of megawatt hours (gigawatt hours)
 
FERC:  Federal Energy Regulatory Commission
 
NERC:  North American Electric Reliability Corporation
IDEM:  Indiana Department of Environmental Management
 
OCC:  Ohio Office of the Consumer Counselor
IURC:  Indiana Utility Regulatory Commission
 
OUCC:  Indiana Office of the Utility Consumer Counselor
 
IRC:  Internal Revenue Code
 
PUCO:  Public Utilities Commission of Ohio
Kv:  Kilovolt
Throughput:  combined gas sales and gas transportation volumes
   
   

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:
Robert L. Goocher
Treasurer and Vice President, Investor Relations
 rgoocher@vectren.com
         


Table of Contents

  Item
    
    Page
 Number
  
    Number
Part I
           
 
 1
  
Business
  
5
 
1A
  
Risk Factors
  
13
 
1B
  
Unresolved Staff Comments
  
19
 
 2
  
Properties
  
19
 
 3
  
Legal Proceedings
  
20
           
Part II
           
 
 5
  
Market for the Company’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities
  
21
 
 6
  
Selected Financial Data
  
22
 
 7
  
Management's Discussion and Analysis of Results of Operations and Financial Condition
  
23
 
7A
  
Qualitative and Quantitative Disclosures About Market Risk
  
53
 
 8
  
Financial Statements and Supplementary Data
  
55
 
 9
  
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
  
103
 
9A
  
Controls and Procedures, including Management’s Assessment of Internal Controls over Financial ReportingControls and Procedures
  
103
 
9B
  
Other Information
  
103
     
 
    
Part III
           
 
10
  
Directors, Executive Officers and Corporate Governance
  
103
 
11
  
Executive Compensation
  
104
 
12
  
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
  
104
 
13
  
Certain Relationships, Related Transactions and Director Independence
  
105
 
14
  
Principal Accountant Fees and Services
  
105
     
 
    
Part IV
           
 
15
  
Exhibits and Financial Statement Schedules
  
105
     
Signatures
  
111
           

PART I

ITEM 1.  BUSINESS

Description of the Business

Vectren Corporation (the Company or Vectren), an Indiana corporation, is an energy holding company headquartered in Evansville, Indiana.  The Company’s wholly owned subsidiary, Vectren Utility Holdings, Inc. (Utility Holdings), serves as the intermediate holding company for three public utilities:  Indiana Gas Company, Inc. (Indiana Gas or Vectren North), Southern Indiana Gas and Electric Company (SIGECO or Vectren South), and the Ohio operations.  Utility Holdings also has other assets that provide information technology and other services to the three utilities.  Utility Holdings’ consolidated operations are collectively referred to as the Utility Group.  Both Vectren and Utility Holdings are holding companies as defined by the Energy Policy Act of 2005 (Energy Act).  60;Vectren was incorporated under the laws of Indiana on June 10, 1999.

Indiana Gas provides energy delivery services to over 570,000­ natural gas customers located in central and southern Indiana.  SIGECO provides energy delivery services to approximately 142,000 electric customers and approximately 111,000 gas customers located near Evansville in southwestern Indiana.  SIGECO also owns and operates electric generation assets to serve its electric customers and optimizes those assets in the wholesale power market.  Indiana Gas and SIGECO generally do business as Vectren Energy Delivery of Indiana.  The Ohio operations provide energy delivery services to approximately 314,000 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 four primary business areas:  Infrastructure Services, Energy Services, Coal Mining, and Energy Marketing.  Infrastructure Services provides underground construction and repair services.  Energy Services provides performance contracting and renewable energy services.  Coal Mining mines and sells coal.  Energy Marketing markets and supplies natural gas and provides energy management services.  Enterprises also has other legacy businesses that have invested in energy-related opportunities and services, real estate, and leveraged leases, among other investments.  All of the above are collectively referred to as the Nonutility Group.  Enterprises supports the Comp any’s regulated utilities pursuant to service contracts by providing natural gas supply services, coal, and infrastructure services.

Narrative Description of the Business

The Company segregates its operations into three groups: the Utility Group, the Nonutility Group, and Corporate and Other.  At December 31, 2010, the Company had $4.8 billion in total assets, with $3.9 billion (82 percent) attributed to the Utility Group, $0.9 billion (18 percent) attributed to the Nonutility Group.  Net income for the year ended December 31, 2010, was $133.7 million, or $1.65 per share of common stock, with net income of $123.9 million attributed to the Utility Group and $9.8 million attributed to the Nonutility Group.  Net income for the year ended December 31, 2009, was $133.1 million, or $1.65 per share of common stock.  For further information regarding the activities and assets of operating segments within these Groups, refer to Note 19 in the Company’s Consolidated Fina ncial Statements included under “Item 8 Financial Statements and Supplementary Data.”  Following is a more detailed description of the Utility Group and Nonutility Group.
 
Utility Group

The Utility Group consists of the Company’s regulated operations and other operations that provide information technology and other support services to those regulated operations.  The Company segregates its regulated operations into a Gas Utility Services operating segment and an Electric Utility Services operating segment.  The Gas Utility Services segment includes the operations of Indiana Gas, the Ohio operations, and SIGECO’s natural gas distribution business and provides natural gas distribution and transportation services to nearly two-thirds of Indiana and to west central Ohio.  The Electric Utility Services segment includes the operations of SIGECO’s electric transmission and distribution services, 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.  Following is a more detailed description of the Utility Group’s Gas Utility and Electric Utility operating segments.

Gas Utility Services

At December 31, 2010, the Company supplied natural gas service to approximately 994,800 Indiana and Ohio customers, including 909,300 residential, 83,800 commercial, and 1,700 industrial and other contract customers.  Average gas utility customers served were approximately 982,100 in 2010, 981,300 in 2009, and 986,700 in 2008.

The Company’s service area contains diversified manufacturing and agriculture-related enterprises.  The principal industries served include automotive assembly, parts and accessories, feed, flour and grain processing, metal castings, aluminum products, polycarbonate resin (Lexan®) and plastic products, gypsum products, electrical equipment, metal specialties, glass, steel finishing, pharmaceutical and nutritional products, gasoline and oil products, ethanol, and coal mining.  The largest Indiana communities served are Evansville, Bloomington, Terre Haute, suburban areas surrounding Indianapolis and Indiana counties near Louisville, Kentucky.  The largest community served outside of Indiana is Dayton, Ohio.

Revenues

The Company receives gas revenues by selling gas directly to customers at approved rates or by transporting gas through its pipelines at approved rates to customers that have purchased gas directly from other producers, brokers, or marketers.  Total throughput was 197.0 MMDth for the year ended December 31, 2010.  Gas sold and transported to residential and commercial customers was 106.2 MMDth representing 54 percent of throughput.  Gas transported or sold to industrial and other contract customers was 90.8 MMDth representing 46 percent of throughput.  Rates for transporting gas generally provide for the same margins earned by selling gas under applicable sales tariffs.

For the year ended December 31, 2010, gas utility revenues were approximately $954.1 million, of which residential customers accounted for 68 percent and commercial 25 percent. Industrial and other contract customers account for only 7 percent of revenues due to the high number of transportation customers in that customer class.

Availability of Natural Gas

The volume of gas sold is seasonal and affected by variations in weather conditions.  To mitigate seasonal demand, the Company’s Indiana gas utilities have storage capacity at seven active underground gas storage fields and six liquefied petroleum air-gas manufacturing plants.  Periodically, purchased natural gas is injected into storage.  The injected gas is then available to supplement contracted and manufactured volumes during periods of peak requirements.  The volumes of gas per day that can be delivered during peak demand periods for each utility are located in “Item 2 Properties.”

Natural Gas Purchasing Activity in Indiana
The Indiana utilities also contract with a wholly-owned subsidiary of ProLiance Holdings, LLC (ProLiance), to ensure availability of gas.  ProLiance is an unconsolidated, nonutility, energy marketing affiliate of Vectren and Citizens Energy Group (Citizens).  (See the discussion of Energy Marketing below and Note 5 in the Company’s Consolidated Financial Statements included in “Item 8 Financial Statements and Supplementary Data” regarding transactions with ProLiance).  The Company also prepays ProLiance for natural gas delivery services during the seven months prior to the peak heating season in lieu of maintaining gas storage.  Vectren received regulatory approval on April 25, 2006, from the IURC for ProLiance to continue to provide natural gas supply services to the Company’ ;s Indiana utilities through March 2011.  On November 3, 2010, a settlement agreement was filed with the IURC providing for ProLiance’s continued provision of gas supply services to the Company’s Indiana utilities and Citizens Gas for the period of April 1, 2011 through March 31, 2016.  The settlement has been agreed to by all of the representatives that were parties to the prior settlement.  An order is anticipated during the first quarter of 2011.

Natural Gas Purchasing Activity in Ohio
On April 30, 2008, the PUCO issued an order adopting a stipulation involving the Company, the OCC, and other interveners.  The order approved the first two phases of a three phase plan to exit the merchant function in the Company’s Ohio service territory.  The Company used a third party provider for VEDO’s gas supply and portfolio services through September 30, 2008.

The initial phase of the plan was implemented on October 1, 2008 and continued through March 31, 2010.  During the initial phase, wholesale suppliers that were winning bidders in a PUCO approved auction provided the gas commodity to VEDO for resale to its residential and general service customers at auction-determined standard pricing.  This standard pricing was comprised of the monthly NYMEX settlement price plus a fixed adder.  On October 1, 2008, the Company transferred its natural gas inventory at book value to the winning bidders, receiving proceeds of approximately $107 million, and began purchasing natural gas from those suppliers (one of which was Vectren Source, a wholly owned natural gas retail marketing subsidiary of Vectren).  This method of purchasing gas eliminated the need for monthly gas cost recovery (GCR) filings and prospective PUCO GCR audits. 

The second phase of the exit process began on April 1, 2010.  During this phase, the Company no longer sells natural gas directly to customers.  Rather, state-certified Competitive Retail Natural Gas Suppliers, that were successful bidders in a similar regulatory-approved auction, sell the gas commodity to specific customers for a 12-month period at auction-determined standard pricing.  The first auction was conducted on January 12, 2010, and the auction results were approved by the PUCO on January 13, 2010.  The plan approved by the PUCO required that the Company conduct at least two annual auctions during this phase.  As such, the Company conducted another auction on January 18, 2011 in advance of the second 12-month term which commences on April 1, 2011.  The results of that auction wer e approved by the PUCO on January 19, 2011. Consistent with current practice, customers will continue to receive a single bill for the commodity as well as the delivery component of natural gas service from VEDO.  Vectren Source, the Company’s wholly owned nonutility retail gas marketer, was a successful bidder in both auctions.

In the last phase, which was not approved in the April 2008 order, it is contemplated that all of the Company’s Ohio residential and general service customers will choose their commodity supplier from state-certified Competitive Retail Natural Gas Suppliers in a competitive market. 

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

Total Natural Gas Purchased Volumes
In 2010, Utility Holdings purchased 84,008 MDth volumes of gas at an average cost of $5.99 per Dth, of which approximately 86 percent was purchased from ProLiance, 2 percent was purchased from Vectren Source, and 12 percent was purchased from third party providers.  The average cost of gas per Dth purchased for the previous four years was $5.97 in 2009, $9.61 in 2008, $8.14 in 2007, and $8.64 in 2006.

Electric Utility Services

At December 31, 2010, the Company supplied electric service to approximately 141,600 Indiana customers, including approximately 123,200 residential, 18,300 commercial, and 100 industrial and other customers.  Average electric utility customers served were approximately 141,300 in 2010, 140,900 in 2009, and 141,100 in 2008.

The principal industries served include polycarbonate resin (Lexan®) and plastic products, aluminum smelting and recycling, aluminum sheet products, automotive assembly, steel finishing, pharmaceutical and nutritional products, automotive glass, gasoline and oil products, ethanol, and coal mining.

Revenues

For the year ended December 31, 2010, retail electricity sales totaled 5,616.9 GWh, resulting in revenues of approximately $564.3 million.  Residential customers accounted for 37 percent of 2010 revenues; commercial 27 percent; industrial 35 percent, and other 1 percent.  In addition, in 2010 the Company sold 587.6 GWh through wholesale activities principally to the MISO.  Wholesale revenues, including transmission-related revenue, totaled $43.7 million in 2010.

System Load

Total load for each of the years 2006 through 2010 at the time of the system summer peak, and the related reserve margin, is presented below in MW.
                               
Date of summer peak load
  
8/4/2010
    
6/22/2009
    
7/21/2008
    
8/8/2007
    
8/10/2006
  
Total load at peak (1)
     1,275       1,143       1,167       1,341       1,325  
                                         
Generating capability
     1,298       1,295       1,295       1,295       1,351  
Firm purchase supply
     136       136       135       130       107  
Interruptible contracts & direct load control
     62       62       62       62       62  
Total power supply capacity
     1,496       1,493       1,492       1,487       1,520  
                                         
Reserve margin at peak
     17 %     31 %     28 %     11 %     15 %
 
(1)  
The total load at peak is increased 25 MW in 2007 and 2006 from the total load actually experienced.  The additional 25 MW represents load that would have been incurred if the Summer Cycler program had not been activated.  The 25 MW is also included in the interruptible contract portion of the Company’s total power supply capacity in those years.  On the date of peak in 2008-2010 the Summer Cycler program was not activated.

The winter peak load for the 2009-2010 season of approximately 916 MW occurred on January 8, 2010.  The prior year winter peak load was approximately 883 MW, occurring on January 15, 2009.

Generating Capability
Installed generating capacity as of December 31, 2010, was rated at 1,298 MW.  Coal-fired generating units provide 1,000 MW of capacity, natural gas or oil-fired turbines used for peaking or emergency conditions provide 295 MW, and in 2009 SIGECO purchased a landfill gas electric generation project which provides 3 MW.  Electric generation for 2010 was fueled by coal (98 percent) and natural gas (2 percent).  Oil was used only for testing of gas/oil-fired peaking units.  The Company generated approximately 5,136 GWh in 2010.  Further information about the Company’s owned generation is included in “Item 2 Properties.”

There are substantial coal reserves in the southern Indiana area, and coal for coal-fired generating stations has been supplied from operators of nearby coal mines, including coal mines in Indiana owned by Vectren Fuels, Inc. (Vectren Fuels), a wholly owned subsidiary of the Company.  Approximately 2.2 million tons were purchased for generating electricity during 2010, of which approximately 90 percent was supplied by Vectren Fuels from its mines and third party purchases.  This compares to 2.8 million tons and 3.2 million tons purchased in 2009 and 2008, respectively.  The utility’s coal inventory was approximately 1 million tons at December 31, 2010 and 2009.

The average cost of coal per ton consumed for the last five years was $67.01 in 2010, $61.67 in 2009, $42.50 in 2008, $40.23 in 2007, and $37.51 in 2006.  Effective January 1, 2009, SIGECO began purchasing coal from Vectren Fuels under new coal purchase agreements.  The term of these coal purchase agreements continues to December 31, 2014, with prices specified originally ranging from two to four years.  The prices in these contracts were at or below market prices for Illinois Basin coal at the time of execution and were subject to a bidding process with third parties.  The IURC has found that costs incurred under these contracts are reasonable (See Rate and Regulatory Matters in Item 7.)

Firm Purchase Supply
The Company has a 1.5 percent interest in the Ohio Valley Electric Corporation (OVEC).  OVEC is comprised of several electric utility companies, including SIGECO, and supplies power requirements to the United States Department of Energy’s (DOE) uranium enrichment plant near Portsmouth, Ohio.  The participating companies can receive from OVEC, and are obligated to pay for, any available power in excess of the DOE contract demand.  At the present time, the DOE contract demand is essentially zero.  The Company’s 1.5 percent interest in OVEC makes available approximately 30 MW of capacity.  The Company purchased approximately 193 GWh from OVEC in 2010.

The Company executed a capacity contract with Benton County Wind Farm, LLC in April 2008 to purchase as much as 30 MW from a wind farm located in Benton County, Indiana, with the approval of the IURC.  The contract expires in 2029.  In 2010, the Company purchased approximately 85 GWh under this contract.

In ­­­­December 2009, the Company executed a 20 year power purchase agreement with Fowler Ridge II Wind Farm, LLC to purchase as much as 50 MW of energy from a wind farm located in Benton and Tippecanoe Counties in Indiana, with the approval of the IURC.  The Company purchased 129 GWh under this contract in 2010.

The Company had a capacity contract with Duke Energy Marketing America, LLC to purchase as much as 100 MW at any time from a power plant located in Vermillion County, Indiana.  The contract expired on December 31, 2009 and was not renewed.
 
Other Power Purchases
The Company also purchases power as needed principally from the MISO to supplement its generation and firm purchase supply in periods of peak demand.  Volumes purchased principally from the MISO in 2010 totaled 880 GWh.

MISO Capacity Purchase
In May 2008, the Company executed a MISO capacity purchase from Sempra Energy Trading, LLC to purchase 100 MW of name plate capacity from its generating facility in Dearborn, Michigan.  The term of the contract began January 1, 2010 and continues through December 31, 2012.

Interconnections
The Company has interconnections with Louisville Gas and Electric Company, Duke Energy Shared Services, Inc., Indianapolis Power & Light Company, Hoosier Energy Rural Electric Cooperative, Inc., Big Rivers Electric Corporation, and the City of Jasper, Indiana, providing the ability to simultaneously interchange approximately 675 MW.  This interchange capability has increased in recent years as a result of ongoing initiatives to improve the transmission grid throughout the Midwest.  The Company, as a member of the MISO, has turned over operational control of the interchange facilities and its own transmission assets, like many other Midwestern electric utilities, to MISO.  See “Item 7 Management’s Discussion and Analysis of Results of Operations and Financial Condition” regarding the Comp any’s participation in MISO.

Competition

The utility industry has undergone structural change for several years, resulting in increasing competitive pressures faced by electric and gas utility companies.  Currently, several states have passed legislation allowing electricity customers to choose their electricity supplier in a competitive electricity market and several other states have considered such legislation.  At the present time, Indiana has not adopted such legislation.  Ohio regulation allows gas customers to choose their commodity supplier.  The Company implemented a choice program for its gas customers in Ohio in January 2003.  At December 31, 2010, over 109,000 customers in Vectren’s Ohio service territory have opted to purchase natural gas from a supplier other than VEDO.  In addition, VEDO’s ser vice territory continues transition toward a choice model for all gas customers.  Margin earned for transporting natural gas to those customers, who have purchased natural gas from another supplier, are generally the same as those earned by selling gas under Ohio tariffs.  Indiana has not adopted any regulation requiring gas choice; however, the Company operates under approved tariffs permitting certain industrial and commercial large volume customers to choose their commodity supplier.

Regulatory and Environmental Matters

See “Item 7 Management’s Discussion and Analysis of Results of Operations and Financial Condition” regarding the Company’s regulatory environment and environmental matters.

Nonutility Group

The Company is involved in nonutility activities in four primary business areas: Infrastructure Services, Energy Services, Coal Mining, and Energy Marketing.

Infrastructure Services

Infrastructure Services provides underground construction and repair to utility infrastructure through its wholly owned subsidiary, Miller Pipeline, LLC (Miller).  Effective July 1, 2006, the Company purchased the remaining 50 percent of Miller from a subsidiary of Duke Energy Corporation, making Miller a wholly owned subsidiary.  The results of Miller’s operations, formerly accounted for using the equity method, have been included in consolidated results since July 1, 2006.  Prior to this transaction, Miller was 100 percent owned by Reliant Services, LLC (Reliant).  Reliant provided facilities locating and meter reading services to the Company’s utilities, as well as other utilities.  Reliant exited the meter reading and facilities locating businesses in 2006.  Miller pro vides services to many utilities, including Vectren’s utilities.  Miller generated approximately $236 million in gross revenues for 2010, compared to $202 million in 2009 and $195 million in 2008.  Man hours worked were 2.6 million in 2010, compared to 2.5 million in both 2009 and 2008.

Energy Services

Performance-based energy contracting operations and renewable energy services are performed through Energy Systems Group, LLC (ESG).  ESG assists schools, hospitals, governmental facilities, and other private institutions to reduce energy and maintenance costs by upgrading their facilities with energy-efficient equipment.  ESG is also involved in creating renewable energy projects, including projects to process landfill gas into usable natural gas and electricity.  During 2009, SIGECO purchased one such project with IURC approval.  ESG’s customer base is located throughout the Midwest and Southeast United States.  ESG generated revenues of approximately $147 million in 2010, compared to $121 million in 2009 and $119 million in 2008.  ESG’s back log at December 31, 201 0 was $118 million.

Coal Mining

The Coal Mining group mines and sells coal to the Company’s utility operations and to other third parties through its wholly owned subsidiary, Vectren Fuels.  The Company owns three underground mines (Prosperity, Oaktown 1, and Oaktown 2) and one surface mine (Cypress Creek).  All mines are located in Indiana.  All coal is high-to-mid sulfur bituminous coal from the Illinois Basin.  The Company engages contract mining companies to perform substantially all mining operations.  Coal mining generated approximately $210 million in revenues in 2010, compared to $193 million in 2009 and $164 million in 2008.

Oaktown Mine Expansion
In April 2006, Vectren Fuels announced plans to open two new underground mines.  The first of two underground mines located near Vincennes, Indiana, began full operations in 2010.  The second mine is currently expected to open in 2012.  However, Vectren Fuels may continue to change this time table as it evaluates the impacts of current coal market conditions.  Reserves at the two mines are estimated at about 105 million tons of recoverable number-five coal at 11,200 BTU and less than 6-pound sulfur dioxide.  Once in full production, the two mines are capable of producing about 5 million tons of coal per year.  Management expects to incur approximately $200 million to access the coal reserves.  Of the total $200 million expected investment, the Company has invested $186 million through December 31, 2 010, inclusive of $48 million in land and buildings, $128 million in mine development and equipment, and $10 million in advance royalty payments.

The Oaktown mine infrastructure is located on 1,100 acres near Oaktown in Knox County, Indiana.  Oaktown’s location is within 50 miles of multiple coal-fired power plants including a coal gasification plant currently under construction.  It is estimated approximately 25,000 acres of coal will be mined during the life of both mines.  Through December 31, 2010, approximately 300 acres of coal have been mined with approximately 24,700 acres remaining.  Access to the Oaktown 1 mine was accomplished via a 90 foot deep box cut and a 2,200 foot slope on a 14 percent grade, reaching coal in excess of 375 feet below the surface.  Access to the Oaktown 2 mine is planned via an 80 foot deep box cut and a 2,600 foot slope on a 14 percent grade, reaching coal in excess of 400 feet below the surfa ce.

Both Oaktown mines are room and pillar underground mines meaning that main airways and transportation entries are developed and maintained while remote-controlled continuous miners extract coal from so-called rooms by removing coal from the seam, leaving pillars to support the roof.  Shuttle cars or similar transportation is used to transport coal to a conveyor belt for transport to the surface.  The two mines are separated by a sandstone channel.  The coal seam thickness ranges from 4 feet to over 9 feet.  The mine’s wash plant was originally sized to process 800 tons per hour and has been expanded to 1,600 tons per hour, although the addition to the wash plant will not be utilized until the Oaktown 2 mine is opened.  The two mines are connected to a railway equipped to handle 110 t o 120 car unit trains.  Coal is also transported via truck to its customers, which include Vectren’s power supply operations and other third party utilities.  Reserves, absent expansion, are expected to be completely exhausted over the next 20 years.

Prosperity Mine
Prosperity is an underground mine located on 1,100 surface acres outside of Petersburg in Pike County, Indiana.  Prosperity is also a room and pillar mine where coal removal is accomplished with continuous mining machines.  The mine entrance slopes gradually for 500 ft on a 9 degree grade and is more than 250 feet below ground level.  The coal seam varies in thickness from 4-1/2 to 8 feet.  The mine has a wash plant sized to process 1,000 tons per hour.  The mine is connected to a railway and can handle 110 to 120 car unit trains.  Coal is also transported via truck to its customers, which include Vectren’s power supply operations and other third party utilities.  The mine opened in 2001, and the total plant and development costs to date are $190 million.  60;Through December 31, 2010, approximately 6,000 acres of coal have been mined with approximately 13,000 acres remaining. Reserves at December 31, 2010 approximate 33 million tons, not including possible nearby expansion opportunities.  The remaining unamortized plant balance as of December 31, 2010 approximates $81 million, inclusive of $3 million of land and buildings and $78 million of mine development and equipment.  Reserves, absent expansion, are expected to be exhausted by 2021.

Cypress Creek
Cypress Creek was an above-ground, or surface mine, located on 155 acres about 4 miles north of Boonville in Warrick County, Indiana.  Cypress Creek was a combination truck/shovel, dozer push and high wall mining operation, meaning large shovels or front-end loaders removed earth and rock covering a coal seam and loading equipment placed the coal into trucks for transportation to a blending and loading area.  Cypress Creek’s coal was sold as a raw product after sizing and blending with coal.  Due to the cost of extensive digging, the coal mining limit was 125 to 135 feet deep.  All coal mined from Cypress Creek was transported via truck to Vectren’s power supply operations.  The mine opened in 1998 and the total plant and development costs were $29 million.  As of Dec ember 31, 2010, no significant reserves remain, and the mine is substantially reclaimed.  The remaining unamortized plant balance as of December 31, 2010 approximates $2 million, inclusive of $1 million of land and buildings and $1 million in equipment.

Following is summarized data regarding coal mining operations:

   
 Cypress
      
 Oaktown
  
 Oaktown
    
   
 Creek
  
 Prosperity
  
 Mine 1
  
 Mine 2
  
Totals
                     
Type of Mining
  
 Surface
  
 Underground
  
 Underground
  
 Underground
    
                     
Mining Technology
  
 Truck & Shovel
  
 Room & Pillar
  
 Room & Pillar
  
 Room & Pillar
    
                     
Tons Mined (in thousands)
                    
  2010
  
                        91
  
                  2,685
  
                     995
  
                        -
  
       3,771
  2009
  
                     969
  
                  2,583
  
                         -
  
                        -
  
       3,552
  2008
  
                  1,150
  
                  2,378
  
                         -
  
                        -
  
       3,528
                     
County Located in Indiana
  
 Warrick
  
 Pike
  
 Knox
  
 Knox
    
                     
Coal Reserves (thousands of tons)
                         -
  
               32,900
  
               65,700
  
              38,800
  
  137,400
                     
Average Heat Content (BTU/lb.)
  
                10,500
  
               11,300
  
               11,100
  
              11,300
    
                     
Average Sulfur Content (lbs./ton)
  
                       8.0
  
                      4.0
  
                      5.6
  
                     4.8
    

Energy Marketing

The Energy Marketing group relies heavily on a customer focused, value added strategy in three areas: gas marketing, energy management, and retail gas supply.

ProLiance
ProLiance, a nonutility energy marketing affiliate of Vectren and 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 and 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.  The Company, including its nonutility retail gas marketing operations, contracted for approximately 69 percent of its natural gas purchases through ProLiance in 2010.

For the year ended December 31, 2010, ProLiance’s revenues, including sales to Vectren companies, were $1.5 billion, compared to $1.7 billion in 2009 and $2.9 billion in 2008.  Summarized financial data regarding ProLiance’s operations are included in Note 5 to the Consolidated Financial Statements included in Item 8.  At December 31, 2010, ProLiance customer base was 1,789 customers, compared to 1,578 customers in 2009 and 1,449 customers in 2008.

Vectren Source
As of December 31, 2010, Vectren Source provided natural gas and other related products and services in the Midwest and Northeast United States to over 227,000 equivalent residential and commercial customers.  This customer base reflects approximately 100,000 customers in VEDO’s service territory that have either voluntarily opted to choose their natural gas supplier or are supplied natural gas by Vectren Source but remain customers of the regulated utility as part of VEDO’s exit the merchant function process.  As a result of a supplier choice auction held on January 18, 2011 in VEDO’s service territory, Vectren Source will increase its customer base by approximately 28,000 to over 255,000.  Gas sold by Vectren Source approximated 20,968 MDth in 2010; 18,457 MDth in 2009; and 16,210 MDth in 2008.  Average equivalent customers served by Vectren Source were 203,000 in 2010; 179,000 in 2009; and 157,000 in 2008.  Vectren Source generated approximately $143 million in revenues for 2010 compared to $157 million in 2009 and $183 million in 2008.

Other Businesses

The Other Businesses group includes a variety of legacy, wholly owned operations and investments that have invested in energy-related opportunities and services, real estate, and leveraged leases, among other investments.  Investments at December 31, 2010, include two Haddington Energy Partnerships both approximately 40 percent owned; and wholly owned subsidiaries, Southern Indiana Properties, Inc. and Energy Realty, Inc.

The Company had an approximate 2 percent equity interest and a convertible subordinated debt investment in Utilicom Networks, LLC (Utilicom).  The Company also had an approximate 19 percent equity interest in SIGECOM Holdings, Inc. (Holdings), which was formed by Utilicom to hold interests in SIGECOM, LLC (SIGECOM).  SIGECOM provided broadband services, such as cable television, high-speed internet, and advanced local and long distance phone services, to the greater Evansville, Indiana area.  The Company sold its investment in SIGECOM during 2006.

Synthetic Fuel

The Company had an 8.3 percent ownership interest in Pace Carbon Synfuels, LP (Pace Carbon).  Pace Carbon produced and sold coal-based synthetic fuel using Covol technology, and according to US tax law, its members received a tax credit for every ton of coal-based synthetic fuel sold.  In addition, Vectren Fuels, Inc. received processing fees from synfuel producers unrelated to Pace Carbon for a portion of its coal production. These synfuel related credits and fees ended on December 31, 2007 when tax laws expired.  The partnership was dissolved in 2010.

Personnel

As of December 31, 2010, the Company and its consolidated subsidiaries had 3,800 employees.  Of those employees, 800 are subject to collective bargaining arrangements negotiated by Utility Holdings.  This total also includes 1,700 employees at Miller Pipeline, of which 1,500 are subject to collective bargaining arrangements.

Utility Holdings

In June 2010, the Company reached a three year labor agreement with Local 702 of the International Brotherhood of Electrical Workers, ending June 30, 2013.

In April 2010, the Company reached a three year agreement with Local 175 of the Utility Workers Union of America.  The labor agreement is retroactively effective to November 1, 2009 and ends October 31, 2012.

In September 2009, the Company reached a three year agreement with Local 135 of the Teamsters, Chauffeurs, Warehousemen, and Helpers Union, ending September 2012.

In December 2008, the Company reached a three-year labor agreement, ending December 1, 2011 with Local 1393 of the International Brotherhood of Electrical Workers and United Steelworkers of America Locals 12213 and 7441.

Miller Pipeline

Miller Pipeline negotiates various trade agreements through contractors associations.  The two main associations are the Distribution Contractors Association and the Pipe Line Contractors Association.  These trade agreements are with a variety of construction unions including Laborer’s International Union of North America, International Union of Operating Engineers, United Association of Journeymen and Apprentices of the Plumbing and Pipe Fitting Industry, and Teamsters.  The trade agreements through the DCA have varying expirations ranging from 2012 to 2015.  The trade agreements through the PLCA recently expired.  Miller and the unions continue working under the expired agreements while negotiations continue.  In addition, Miller has various project agreements and small local agreements. The se agreements expire upon completion of a specific project or on various dates throughout the year. 

ITEM 1A.  RISK FACTORS

Investors should consider carefully the following factors that could cause the Company’s operating results and financial condition to be materially adversely affected.  New risks may emerge at any time, and the Company cannot predict those risks or estimate the extent to which they may affect the Company’s businesses or financial performance.

Vectren is a holding company, and its assets consist primarily of investments in its subsidiaries.

Dividends on Vectren’s common stock depend on the earnings, financial condition, capital requirements and cash flow of its subsidiaries, principally Utility Holdings and Enterprises, and the distribution or other payment of earnings from those entities to Vectren.  Should the earnings, financial condition, capital requirements, or cash flow of, or legal requirements applicable to them restrict their ability to pay dividends or make other payments to the Company, its ability to pay dividends on its common stock could be limited and its stock price could be adversely affected.  Vectren’s results of operations, future growth, and earnings and dividend goals also will depend on the performance of its subsidiaries.  Additionally, certain of the Company’s lending arrangements contain restrictive c ovenants, including the maintenance of a total debt to total capitalization ratio, which could limit its ability to pay dividends.

Deterioration in general economic conditions may have adverse impacts.
 
The industries in which the Company operates and serves continue to be impacted by economic uncertainty.  Economic conditions may have some negative impact on both gas and electric large customers and wholesale power sales.  This impact may continue to include volatility and unpredictability in the demand for natural gas and electricity, tempered growth strategies, significant conservation measures, and perhaps even further plant closures or bankruptcies.  Economic conditions may also cause reductions in residential and commercial customer counts and lower Company revenues.  It is also possible that an uncertain economy could continue to affect costs including pension costs, interest costs, and uncollectible accounts expense.  Economic declines may be accompanied by a decrease in demand for products and services offered by nonutility operations and therefore lower revenues for those products and services.  The current economic conditions may continue to have some negative impact on utility industry spending for construction projects, demand for natural gas and coal, and spending on performance contracting and renewable energy expansion.  It is also possible that if the current conditions continue, they could lead to further reductions in the value of certain nonutility real estate and other legacy investments.

Financial market volatility could have adverse impacts.
 
The capital and credit markets may experience volatility and disruption.  If market disruption and volatility occurs, there can be no assurance that the Company, or its unconsolidated affiliates, will not experience adverse effects, which may be material.  These effects may include, but are not limited to, difficulties in accessing the short and long-term debt capital markets and the commercial paper market, increased borrowing costs associated with current short-term debt obligations, higher interest rates in future financings, and a smaller potential pool of investors and funding sources.  Finally, there is no assurance the Company will have access to the equity capital markets to obtain financing when necessary or desirable.

A downgrade (or negative outlook) in or withdrawal of Vectren’s credit ratings could negatively affect its ability to access capital and its cost.

The following table shows the current ratings assigned to certain outstanding debt by Moody’s and Standard & Poor’s:
 
Current Rating
   
Standard
 
Moody’s
& Poor’s
  Utility Holdings and Indiana Gas senior unsecured debt
A3
A-
  Utility Holdings commercial paper program
P-2
A-2
  SIGECO’s senior secured debt
A1
A

The current outlook of both Standard and Poor’s and Moody’s is stable and both categorize the ratings of the above securities as investment grade.  A security rating is not a recommendation to buy, sell, or hold securities.  The rating is subject to revision or withdrawal at any time, and each rating should be evaluated independently of any other rating.  Standard and Poor’s and Moody’s lowest level investment grade rating is BBB- and Baa3, respectively.

If the rating agencies downgrade the Company’s credit ratings, particularly below investment grade, or initiate negative outlooks thereon, or withdraw Vectren’s ratings or, in each case, the ratings of its subsidiaries, it may significantly limit Vectren’s access to the debt capital markets and the commercial paper market, and the Company’s borrowing costs would increase.  In addition, Vectren would likely be required to pay a higher interest rate in future financings, and its potential pool of investors and funding sources would likely decrease.  Finally, there is no assurance that the Company will have access to the equity capital markets to obtain financing when necessary or desirable.

Vectren’s gas and electric utility sales are concentrated in the Midwest.

The operations of the Company’s regulated utilities are concentrated in central and southern Indiana and west central Ohio and are therefore impacted by changes in the Midwest economy in general and changes in particular industries concentrated in the Midwest.  These industries include automotive assembly, parts and accessories, feed, flour and grain processing, metal castings, aluminum products, polycarbonate resin (Lexan®) and plastic products, gypsum products, electrical equipment, metal specialties, glass, steel finishing, pharmaceutical and nutritional products, gasoline and oil products, ethanol and coal mining.

Vectren operates in an increasingly competitive industry, which may affect its future earnings.

The utility industry has been undergoing structural change for several years, resulting in increasing competitive pressure faced by electric and gas utility companies.  Increased competition may create greater risks to the stability of Vectren’s earnings generally and may in the future reduce its earnings from retail electric and gas sales.  Currently, several states, including Ohio, have passed legislation that allows customers to choose their electricity supplier in a competitive market.  Indiana has not enacted such legislation.  Ohio regulation also provides for choice of commodity providers for all gas customers.  In 2003, the Company implemented this choice for its gas customers in Ohio and is currently in the second of the three phase process to exit the merchant function in i ts Ohio service territory.  The state of Indiana has not adopted any regulation requiring gas choice in the Company’s Indiana service territories; however, the Company operates under approved tariffs permitting certain industrial and commercial large volume customers to choose their commodity supplier.  Vectren cannot provide any assurance that increased competition or other changes in legislation, regulation or policies will not have a material adverse effect on its business, financial condition or results of operations.

A significant portion of Vectren’s electric utility sales are space heating and cooling.  Accordingly, its operating results may fluctuate with variability of weather.

Vectren’s electric utility sales are sensitive to variations in weather conditions.  The Company forecasts utility sales on the basis of normal weather.  Since Vectren does not have a weather-normalization mechanism for its electric operations, significant variations from normal weather could have a material impact on its earnings.  However, the impact of weather on the gas operations in the Company’s Indiana territories has been significantly mitigated through the implementation in 2005 of a normal temperature adjustment mechanism.  Additionally, the implementation of a straight fixed variable rate design in a January 2009 PUCO order mitigates most weather risk related to Ohio residential gas sales.

Risks related to the regulation of Vectren’s utility businesses, including environmental regulation, could affect the rates the Company charges its customers, its costs and its profitability.

Vectren’s businesses are subject to regulation by federal, state, and local regulatory authorities and are exposed to public policy decisions that may negatively impact the Company’s earnings.  In particular, Vectren is subject to regulation by the FERC, the NERC, the EPA, the IURC, and the PUCO.  These authorities regulate many aspects of its transmission and distribution operations, including construction and maintenance of facilities, operations, and safety, and its gas marketing operations involving title passage, reliability standards, and future adequacy.  In addition, these regulatory agencies approve its utility-related debt and equity issuances, regulate the rates that Vectren’s utilities can charge customers, the rate of return that Vectren’s utilities are authorized to earn, and its ability to timely recover gas and fuel costs.  Further, there are consumer advocates and other parties which may intervene in regulatory proceedings and affect regulatory outcomes.  The Company’s ability to obtain rate increases to maintain its current authorized rates of return depends upon regulatory discretion, and there can be no assurance that Vectren will be able to obtain rate increases or rate supplements or earn its current authorized rates of return.

Vectren’s operations and properties are subject to extensive environmental regulation pursuant to a variety of federal, state and municipal laws and regulations.  These environmental regulations impose, among other things, restrictions, liabilities, and obligations in connection with storage, transportation, treatment, and disposal of hazardous substances and waste in connection with spills, releases, and emissions of various substances in the environment.  Such airborne emissions from electric generating facilities include particulate matter, sulfur dioxide (SO2), nitrogen oxide (NOx), and mercury, among others.

Environmental legislation/regulation also requires that facilities, sites, and other properties associated with Vectren’s operations be operated, maintained, abandoned, and reclaimed to the satisfaction of applicable regulatory authorities.  The Company’s current costs to comply with these laws and regulations are significant to its results of operations and financial condition.  In addition, claims against the Company under environmental laws and regulations could result in material costs and liabilities.  With the trend toward stricter standards, greater regulation, more extensive permit requirements and an increase in the number and types of assets operated by Vectren subject to environmental regulation, its investment in environmentally compliant equipment, and the costs associated with operat ing that equipment, have increased and are expected to increase in the future.  As examples of the trend toward stricter regulation, the EPA is currently reviewing/revising regulations involving fly ash disposal, cooling tower intake facilities, greenhouse gases, and airborne emissions such as SO2 and NOx.

Climate change regulation could negatively impact operations.

There are proposals to address global climate change that would regulate carbon dioxide (CO2) and other greenhouse gases and other proposals that would mandate an investment in renewable energy sources.  Any future legislative or regulatory actions taken by the EPA or other agencies to address global climate change or mandate renewable energy sources could substantially affect both the costs and operating characteristics of the Company’s fossil fuel generating plants, nonutility coal mining operations, and natural gas distribution businesses.  Further, such legislation or regulatory action would likely impact the Company’s generation resource planning decisions.  At this time and in the absence of final legislation or regulatory mandates, 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 control greenhouse gas emissions.  A preliminary investigation demonstrated costs to comply would be significant, first with regard to operating expenses and later for capital expenditures as technology becomes available to control greenhouse gas emissions.  However, these compliance cost estimates are based on highly uncertain assumptions, including allowance prices if a cap and trade approach were employed, and energy efficiency targets.

Any additional expenses or capital incurred by the Company, as it relates to complying with greenhouse gas emissions regulation or other environmental regulations, are expected to be borne by the customers in its service territories through increased rates.  Increased rates have an impact on the economic health of the communities served.  New regulations could also negatively impact industries in the Company’s service territory, including industries in which the Company operates.

The Company is exposed to physical and financial risks related to the uncertainty of climate change.

A changing climate creates uncertainty and could result in broad changes to the Company’s service territories.  These impacts could include, but are not limited to, population shifts; changes in the level of annual rainfall; changes in the weather; and changes to the frequency and severity of weather events such as thunderstorms, wind, tornadoes, and ice storms that can damage infrastructure.  Such changes could impact the Company in a number of ways including the number and/or type of customers in the Company’s service territories; the demand for energy resulting in the need for additional investment in generation assets or the need to retire current infrastructure that is no longer required; an increase to the cost of providing service; and an increase in the likelihood of capital expenditures to replace damaged infrastructure.

To the extent climate change impacts a region’s economic health, it may also impact the Company’s revenues, costs, and capital structure and thus the need for changes to rates charged to regulated customers.  Rate changes themselves can impact the economic health of the communities served and may in turn adversely affect the Company’s operating results.

The Company may face certain regulatory and financial risks related to pipeline safety legislation.

There are federal proposals currently pending that would increase pipeline operations oversight and would lead to an investment in the inspection, and where necessary, the replacement of pipeline infrastructure.  At this time and in the absence of final legislation, compliance costs and other effects associated with increased pipeline safety regulations remain uncertain.  However, any future legislative or regulatory actions taken to address pipeline safety could substantially affect both operating expenses and capital expenditures associated with the Company’s natural gas distribution businesses.  The Company has been successful in the past recovering costs resulting from government mandates.  However, if the Company is unable to recover from customers through the regulatory process all or some of these costs, including its authorized rate of return on replacement projects, results of operations, financial condition, and cash flows could be adversely impacted.

Vectren regulated distribution operations are subject to various risks.

A variety of hazards and operations risks, such as leaks, accidental explosions, and mechanical problems are inherent in the Company’s gas and electric distribution activities.  If such events occur, they could cause substantial financial losses and result in loss of human life, significant damage to property, environmental pollution, and impairment of operations.  The location of pipelines, storage facilities, and the electric grid near populated areas, including residential areas, commercial business centers, and industrial sites, could increase the level of damages resulting from these risks.  These activities may subject the Company to litigation or administrative proceedings from time to time.  Such litigation or proceedings could result in substantial monetary judgments, fines, or penalt ies or be resolved on unfavorable terms.  In accordance with customary industry practices, the Company maintains insurance against a significant portion, but not all, of these risks and losses. To the extent that the occurrence of any of these events is not fully covered by insurance, it could adversely affect the Company’s financial condition and results of operations.

Vectren’s electric operations are subject to various risks.

The Company’s electric generating facilities are subject to operational risks that could result in unscheduled plant outages, unanticipated operation and maintenance expenses and increased power purchase costs.  Such operational risks can arise from circumstances such as facility shutdowns due to equipment failure or operator error; interruption of fuel supply or increased prices of fuel as contracts expire; disruptions in the delivery of electricity; inability to comply with regulatory or permit requirements; labor disputes; and natural disasters.
 
The impact of MISO participation is uncertain.

Since February 2002 and with the IURC’s approval, the Company has been a member of the MISO.  The MISO serves the electrical transmission needs of much of the Midwest and maintains operational control over SIGECO’s electric transmission facilities as well as that of other Midwest utilities.

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. 

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.  The Company timely recovers its investment in certain new electric transmission projects that benefit the MISO infrastructure at a FERC approved rate of return.

Wholesale power marketing activities may add volatility to earnings.

Vectren’s regulated electric utility engages in wholesale power marketing activities that primarily involve the offering of utility-owned or contracted generation into the MISO hourly and real time markets.  As part of these strategies, the Company may also execute energy contracts that are integrated with portfolio requirements around power supply and delivery.  Presently, margin earned from these activities above or below $10.5 million is shared evenly with customers.  These earnings from wholesale marketing activities may vary based on fluctuating prices for electricity and the amount of electric generating capacity or purchased power available beyond that needed to meet firm service requirements.  In addition, this earnings sharing approach may be modified in future regulatory proceedings.

Increases in the wholesale price of natural gas, coal, and electricity could reduce earnings and working capital.

The Company’s regulated operations have limited exposure to commodity price risk for transactions involving purchases and sales of natural gas, coal, and purchased power for the benefit of retail customers due to current state regulations, which subject to compliance with those regulations, allow for recovery of the cost of such purchases through natural gas and fuel cost adjustment mechanisms.  However, significant increases in the price of natural gas, coal, or purchased power may cause existing customers to conserve or motivate them to switch to alternate sources of energy as well as cause new home developers, builders, and new customers to select alternative sources of energy.  Decreases in volumes sold could reduce earnings.  The decrease would be more significant in the absence of constructive reg ulatory orders, such as those authorizing revenue decoupling, lost margin recovery, and other innovative rate designs.  A decline in new customers could impede growth in future earnings. In addition, during periods when commodity prices are higher than historical levels, working capital costs could increase due to higher carrying costs of inventories and cost recovery mechanisms, and customers may have trouble paying higher bills leading to bad debt expenses.

The performance of Vectren’s nonutility businesses is subject to certain risks.

Execution of the Company’s nonutility business strategies and the success of efforts to invest in and develop new opportunities in the nonutility business area is subject to a number of risks.  These risks include, but are not limited to, the effects of weather; failure of installed performance contracting products to operate as planned; failure to properly estimate the cost to construct projects; failure to develop or obtain gas storage field and mining property; potential legislation that may limit CO2 and other greenhouse gases emissions; creditworthiness of customers and joint venture partners; changes in federal, state or local legal requirements, such as changes in tax laws or rates; and changing market conditions.

Vectren’s nonutility businesses support its regulated utilities pursuant to service contracts by providing natural gas supply services, coal, and infrastructure services.  In most instances, Vectren’s ability to maintain these service contracts depends upon regulatory discretion and negotiation with interveners, and there can be no assurance that it will be able to obtain future service contracts, or that existing arrangements will not be revisited.

Coal mining operations could be adversely affected by a number of factors.

The success of coal mining operations is predicated on the ability to fully access coal at company-owned mines; to operate owned mines in accordance with MSHA guidelines and regulations, recent interpretations of those guidelines and regulations, and any new guidelines or regulations that could result from the recent mining incidents at coal mines of other companies and to respond to more frequent and broader inspections; to negotiate and execute new sales contracts; and to manage production and production costs and other risks in response to changes in demand.  Other risks, which could adversely impact operating results, include but are not limited to:  market demand for coal; geologic, equipment, and operational risks; supplier and contract miner performance; the availability of miners, key equipment and commodities; availability of transportation; and the ability to access/replace coal reserves.

In addition, coal mining operations have exposure to coal commodity prices.  If coal commodity prices change in a direction or manner that is not anticipated, or if the forecasted sales transactions do not occur, losses may result.  Although forecasted sales are hedged with owned coal inventory and known reserves, all exposure to both short and long-term coal price volatility is not hedged.  Therefore, fluctuating coal prices are likely to cause the Company’s net income to be volatile.

The success of Vectren’s natural gas marketing strategies is affected by a number of factors.

ProLiance, and to a lesser extent the Company’s nonutility gas retail supply operations, rely on long-term firm transportation and storage contracts with pipeline companies to deliver natural gas to its customer base.  Those contracts are optimized by balancing physical and financial markets and summer and winter time horizons.  Therefore, recovery of the these contracts’ fixed costs is dependent on a number of factors, including the health of the economy, weather, and changes in the availability and location of natural gas supply and related transmission assets, among others.  A significant decline in optimization opportunities or a deterioration of the customer base may result in the inability to fully recover these fixed price obligations.

Recent market conditions have compressed optimization opportunities, and ProLiance has operated at a loss.  If current market conditions continue, resulting in continued depressed asset optimization opportunities, it is expected that ProLiance will experience a loss in 2011.  Losses could continue in future years should ProLiance be unable to adjust to the current market conditions or be unsuccessful in renegotiating its transportation and storage contracts over time.

In addition to physical and financial contracts executed for optimization opportunities, forward contracts and from time to time option contracts are executed to meet forecasted customer demand that may or may not occur and to hedge commodity price risk and basis risk.  If the value of these contracts changes in a direction or manner that is not anticipated, or if the forecasted sales transactions do not occur, losses may result.  These contracts include fixed-price forward physical purchase and sales contracts, and/or financial forwards, futures, swaps and option contracts traded in the over-the-counter markets or on exchanges.  Therefore, fluctuating natural gas prices are likely to cause the Company’s net income to be volatile.

Vectren’s nonutility group competes with larger energy providers, which may limit its ability to grow its business.

Competitors for Vectren’s nonutility businesses include regional, national and global companies.  Many of Vectren’s competitors are well-established and have larger and more developed networks and systems, greater name recognition, longer operating histories and significantly greater financial, technical and marketing resources.  This competition, and the addition of any new competitors, could negatively impact the financial performance of the nonutility group and the Company’s ability to grow its nonutility businesses.

Increased derivative regulation could impact results.

The Company, as well as ProLiance, uses natural gas derivative instruments in conjunction with energy marketing and procurement activities.  The Company also uses interest rate derivative instruments to minimize the impact of interest rate fluctuations associated with anticipated debt issuances.

In July 2010, legislation regulating the use of derivative instruments was signed into law.  These new regulations include, but are not limited to, a requirement that certain transactions be cleared on exchanges and a requirement to post cash collateral for certain transactions.  Depending on the regulations adopted by the Commodities Futures Trading Commission (CFTC) and other agencies, the Company and ProLiance could be required to post additional collateral with dealer counterparties for commitments and interest rate derivative transactions. Requirements to post collateral could limit cash for investment and for other corporate purposes or could increase debt levels. In addition, a requirement for counterparties to post collateral could result in additional costs associated with executing transactions, thereby decre asing profitability.  An increased collateral requirement could also reduce the Company’s and ProLiance’s ability to execute derivative transactions to reduce commodity price and interest rate uncertainty and to protect cash flows.

The law provides for a potential exception from these clearing and cash collateral requirements for commercial end-users.  Significant rule-making by numerous governmental agencies, particularly the CFTC, must be adopted in the near term so that the restrictions, limitations, and requirements contemplated by the new law can be implemented.  The Company and ProLiance will continue to evaluate the impact as these rules become available and whether any exemption will apply to the Company’s and ProLiance’s use of derivative instruments.

Vectren’s subsidiaries have performance and warranty obligations, some of which are guaranteed by Vectren.

In the normal course of business, subsidiaries of Vectren issue performance bonds and other forms of assurance that commit them to timely install infrastructure, operate facilities, pay vendors or subcontractors, and/or support warranty obligations.  Vectren Corporation, as the parent company, will from time to time guarantee its subsidiaries’ commitments.  These guarantees do not represent incremental consolidated obligations; rather, they represent parental guarantees of subsidiary obligations in order to allow those subsidiaries the flexibility to conduct business without posting other forms of collateral.  The Company has not been called upon to satisfy any obligations pursuant to these parental guarantees.

From time to time, Vectren is subject to material litigation and regulatory proceedings.

From time to time, the Company, as well as its equity investees such as ProLiance, may be subject to material litigation and regulatory proceedings including matters involving compliance with state and federal laws, regulations or other matters.  There can be no assurance that the outcome of these matters will not have a material adverse effect on Vectren’s business, prospects, results of operations, or financial condition.

The investment performance of pension plan holdings and other factors impacting pension plan costs could impact Vectren’s liquidity and results of operations.

The costs associated with the Company’s retirement plans are dependent on a number of factors, such as the rates of return on plan assets; discount rates; the level of interest rates used to measure funding levels; changes in actuarial assumptions; future government regulation; and Company contributions.  In addition, the Company could be required to provide for significant funding of these defined benefit pension plans.  Such cash funding obligations could have a material impact on liquidity by reducing cash flows for other purposes and could negatively affect results of operations.

Catastrophic events could adversely affect Vectren’s facilities and operations.

Catastrophic events such as fires, earthquakes, explosions, floods, ice storms, tornados, terrorist acts or other similar occurrences could adversely affect Vectren’s facilities, operations, financial condition and results of operations.

Workforce risks could affect Vectren’s financial results.

The Company is subject to various workforce risks, including but not limited to, the risk that it will be unable to attract and retain qualified personnel; that it will be unable to effectively transfer the knowledge and expertise of an aging workforce to new personnel as those workers retire; that it will be unable to react to a pandemic illness; and that it will be unable to reach collective bargaining arrangements with the unions that represent certain of its workers, which could result in work stoppages.

ITEM 1B.  UNRESOLVED STAFF COMMENTS

None.

ITEM 2.  PROPERTIES
Gas Utility Services

Indiana Gas owns and operates four active gas storage fields located in Indiana covering 58,100 acres of land with an estimated ready delivery from storage capability of 6.0 BCF of gas with maximum peak day delivery capabilities of 151,000 MCF per day.  Indiana Gas also owns and operates three liquefied petroleum (propane) air-gas manufacturing plants located in Indiana with the ability to store 1.5 million gallons of propane and manufacture for delivery 33,000 MCF of manufactured gas per day.  In addition to its company owned storage and propane capabilities, Indiana Gas has contracted with ProLiance for 16.7 BCF of interstate natural gas pipeline storage service with a maximum peak day delivery capability of 252,600 MMBTU per day.  Indiana Gas’ gas delivery system includes 13,000 miles of distribution and transmission mains, all of which are in Indiana except for pipeline facilities extending from points in northern Kentucky to points in southern Indiana so that gas may be transported to Indiana and sold or transported by Indiana Gas to ultimate customers in Indiana.

SIGECO owns and operates three active underground gas storage fields located in Indiana covering 6,100 acres of land with an estimated ready delivery from storage capability of 6.3 BCF of gas with maximum peak day delivery capabilities of 108,500 MCF per day.  In addition to its company owned storage delivery capabilities, SIGECO has contracted with ProLiance for 0.5 BCF of interstate pipeline storage service with a maximum peak day delivery capability of 19,200 MMBTU per day.  SIGECO's gas delivery system includes 3,200 miles of distribution and transmission mains, all of which are located in Indiana.

The Ohio operations own and operate three liquefied petroleum (propane) air-gas manufacturing plants, all of which are located in Ohio.  The plants can store 0.5 million gallons of propane, and the plants can manufacture for delivery 52,200 MCF of manufactured gas per day.  In addition to its propane delivery capabilities, the Ohio operations have contracted for 11.8 BCF of natural gas delivery service with a maximum peak day delivery capability of 246,100 MMBTU per day.  While the Company still has title to this delivery capability, it has released it to those retail gas marketers now supplying the Ohio operations with natural gas, and those suppliers are responsible for the demand charges.  The Ohio operations’ gas delivery system includes 5,500 miles of distribution and transmission mains, all of which are located in Ohio.

Electric Utility Services

SIGECO's installed generating capacity as of December 31, 2010, was rated at 1,298 MW.  SIGECO's coal-fired generating facilities are the Brown Station with two units of 490 MW of combined capacity, located in Posey County approximately eight miles east of Mt. Vernon, Indiana; the Culley Station with two units of 360 MW of combined capacity, and Warrick Unit 4 with 150 MW of capacity.  Both the Culley and Warrick Stations are located in Warrick County near Yankeetown, Indiana.  SIGECO's gas-fired turbine peaking units are:  two 80 MW gas turbines (Brown Unit 3 and Brown Unit 4) located at the Brown Station; two Broadway Avenue Gas Turbines located in Evansville, Indiana with a combined capacity of 115 MW (Broadway Avenue Unit 1, 50 MW and Broadway Avenue Unit 2, 65 MW); and two Northeast Gas Turbines located northeast of Evansville in Vanderburgh County, Indiana with a combined capacity of 20 MW.  The Brown Unit 3 and Broadway Avenue Unit 2 turbines are also equipped to burn oil.  Total capacity of SIGECO's six gas turbines is 295 MW, and they are generally used only for reserve, peaking, or emergency purposes due to the higher per unit cost of generation.  In 2009, SIGECO, with IURC approval, purchased a landfill gas electric generation project in Pike County, Indiana with a total capability of 3 MW.

SIGECO's transmission system consists of 993 circuit miles of 345Kv, 138Kv and 69Kv lines.  The transmission system also includes 34 substations with an installed capacity of 4,863 megavolt amperes (Mva).  The electric distribution system includes 4,265 pole miles of lower voltage overhead lines and 366 trench miles of conduit containing 1,981 miles of underground distribution cable.  The distribution system also includes 96 distribution substations with an installed capacity of 2,966 Mva and 54,000 distribution transformers with an installed capacity of 2,331 Mva.

SIGECO owns utility property outside of Indiana approximating nine miles of 138,000 volt electric transmission line which is located in Kentucky and which interconnects with Louisville Gas and Electric Company's transmission system at Cloverport, Kentucky.

Nonutility Properties

Subsidiaries other than the utility operations have no significant properties other than the ownership and operation of coal mining property in Indiana which is identified in Item 1.
 
 
Property Serving as Collateral

SIGECO's properties are subject to the lien of the First Mortgage Indenture dated as of April 1, 1932, between SIGECO and Bankers Trust Company, as Trustee, and Deutsche Bank, as successor Trustee, as supplemented by various supplemental indentures.

ITEM 3.  LEGAL PROCEEDINGS

The Company is party to various legal proceedings and audits and reviews by taxing authorities and other government agencies arising in the normal course of business.  In the opinion of management, there are no legal proceedings or other regulatory reviews or audits pending against the Company that are likely to have a material adverse effect on its financial position, results of operations, or cash flows.  See the notes to the consolidated financial statements regarding commitments and contingencies, environmental matters, and rate and regulatory matters.  The consolidated condensed financial statements are included in “Item 8 Financial Statements and Supplementary Data.”

PART II
 
ITEM 5.  MARKET FOR COMPANY'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER
        PURCHASES OF EQUITY SECURITIES
 
Market Data, Dividends Paid, and Holders of Record

The Company’s common stock trades on the New York Stock Exchange under the symbol ‘‘VVC.’’  For each quarter in 2010 and 2009, the high and low sales prices for the Company’s common stock as reported on the New York Stock Exchange and dividends paid are presented below.
               
     
Cash
  
Common Stock Price Range
     
Dividend
  
High
  
Low
2010
            
 
First Quarter
  
 $      0.340
  
 $      25.07
  
 $      22.14
 
Second Quarter
  
         0.340
  
         25.60
  
         21.66
 
Third Quarter
  
         0.340
  
         26.05
  
         22.97
 
Fourth Quarter
  
         0.345
  
         27.85
  
         24.18
2009
            
 
First Quarter
  
 $      0.335
  
 $      26.90
  
 $      18.08
 
Second Quarter
  
         0.335
  
         24.06
  
         19.72
 
Third Quarter
  
         0.335
  
         25.33
  
         22.47
 
Fourth Quarter
  
         0.340
  
         25.50
  
         21.99

On February 2, 2011 the board of directors declared a dividend of $0.345 per share, payable on March 1, 2011, to common shareholders of record on February 15, 2011.

As of January 31, 2011, there were 9,261 shareholders registered of the Company’s common stock.

Quarterly Share Purchases

Periodically, the Company purchases shares from the open market to satisfy share requirements associated with the Company’s share-based compensation plans; however, no such open market purchases were made during the quarter ended December 31, 2010.

Dividend Policy

Common stock dividends are payable at the discretion of the board of directors, out of legally available funds.  The Company’s policy is to distribute approximately 65 percent of earnings over time.  On an annual basis, this percentage has varied and could continue to vary due to short-term earnings volatility.  The Company has increased its dividend for 51 consecutive years.  While the Company is under no contractual obligation to do so, it intends to continue to pay dividends and increase its annual dividend consistent with historical practice.  Nevertheless, should the Company’s financial condition, operating results, capital requirements, or other relevant factors change, future dividend payments, and the amounts of these dividends, will be reassessed.

Certain lending arrangements contain restrictive covenants, including the maintenance of a total debt to total capitalization ratio, which could limit the Company’s ability to pay dividends.  These restrictive covenants are not expected to affect the Company’s ability to pay dividends in the near term.
 
ITEM 6.  SELECTED FINANCIAL DATA

The following selected financial data is derived from the Company’s audited consolidated financial statements and should be read in conjunction with those financial statements and notes thereto contained in this Form 10-K.
                               
   
Year Ended December 31,
(In millions, except per share data)
  
2010
    
2009
    
2008
    
2007
    
2006
  
                               
Operating Data:
                              
Operating revenues
   $ 2,129.5     $ 2,088.9     $ 2,484.7     $ 2,281.9     $ 2,041.6  
Operating income
   $ 316.8     $ 280.1     $ 263.4     $ 260.5     $ 220.5  
Net income
   $ 133.7     $ 133.1     $ 129.0     $ 143.1     $ 108.8  
Average common shares outstanding
     81.2       80.7       78.3       75.9       75.7  
Fully diluted common shares outstanding
     81.3       81.0       78.7       76.4       76.2  
Basic earnings per share
                                        
  on common stock
   $ 1.65     $ 1.65     $ 1.65     $ 1.89     $ 1.44  
Diluted earnings per share
                                        
  on common stock
   $ 1.64     $ 1.64     $ 1.63     $ 1.87     $ 1.43  
Dividends per share on common stock
   $ 1.365     $ 1.345     $ 1.310     $ 1.270     $ 1.230  
                                         
Balance Sheet Data:
                                        
Total assets
   $ 4,764.2     $ 4,671.8     $ 4,632.9     $ 4,296.4     $ 4,091.6  
Long-term debt, net
   $ 1,435.2     $ 1,540.5     $ 1,247.9     $ 1,245.4     $ 1,208.0  
Common shareholders' equity
   $ 1,438.9     $ 1,397.2     $ 1,351.6     $ 1,233.7     $ 1,174.2  
                                         

ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION

Executive Summary of Consolidated Results of Operations

In this discussion and analysis, the Company analyzes contributions to consolidated earnings and earnings per share from its Utility Group and Nonutility Group separately since each operates independently requiring distinct competencies and business strategies, offers different energy and energy related products and services, and experiences different opportunities and risks.  Nonutility Group operations are discussed below as primary operations and other operations.  Primary nonutility operations denote areas of management’s forward looking focus.

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

The Company has in place a disclosure committee that consists of senior management as well as financial management.  The committee is actively involved in the preparation and review of the Company’s SEC filings.

Net income and earnings per share, in total and by group, for the years ended December 31, 2010, 2009, and 2008 follow:
                   
   
Year Ended December 31,
(In millions, except per share data)
  
2010
    
2009
    
2008
  
                   
Net income
   $ 133.7     $ 133.1     $ 129.0  
Attributed to:
                        
Utility Group
   $ 123.9     $ 107.4     $ 111.1  
Nonutility Group
     9.8       25.8       18.9  
Corporate & Other
     -       (0.1 )     (1.0 )
                         
                         
Basic earnings per share
   $ 1.65     $ 1.65     $ 1.65  
Attributed to:
                        
Utility Group
   $ 1.53     $ 1.33     $ 1.42  
Nonutility Group
     0.12       0.32       0.24  
Corporate & Other
     -       -       (0.01 )
 
Results
For the year ended December 31, 2010, consolidated net income was $133.7 million, or $1.65 per share, compared to earnings of $133.1 million, or $1.65 per share in 2009 and $129.0 million, or $1.65 per share in 2008.

Utility Group
In 2010, the Utility Group’s earnings were $123.9 million, compared to earnings of $107.4 million in 2009 and $111.1 million in 2008.  The increase in 2010 compared to 2009 results from the return of large customer usage, summer cooling weather that was significantly warmer than normal and the prior year, and lower operating expenses.  Utility Group results were down only modestly in 2009 compared to 2008, even after considering the impacts of the recession on large customer usage and wholesale power sales and mild cooling weather.  The years presented have also been impacted by increased depreciation expense and interest expense associated with rate base growth, increased revenues associated with regulatory initiatives, volatile market values associated with investments related to benefit plans, and ch anges in the effective tax rate.

Margin in the Company’s electric and the Ohio natural gas service territory, which was not fully protected by straight fixed variable rate design in 2009 and 2008, is impacted by weather.  During 2010, cooling weather was 34 percent warmer than normal and 49 percent warmer than the prior year.  Due primarily to the extreme cooling weather, management estimates the margin impact of weather to be approximately $10.4 million favorable, or $0.08 per share, compared to normal temperatures.  Compared to 2009 which was impacted by mild cooling weather, the margin impact is estimated to be $14.2 million, or $0.10 per share.  In 2008 weather impacts were $0.01 per share unfavorable compared to normal temperatures.  Management estimates the impact of weather based on an assumption of weather s ensitive sales per degree day at current rates.

Nonutility Group
In 2010, Nonutility Group earnings were $9.8 million, compared to earnings of $25.8 million in 2009 and $18.9 million in 2008.  The 2010 period was impacted by charges related to legacy investments totaling $6.9 million after tax.  The 2009 period contains the $11.9 million after tax Liberty Charge (See Note 5 to the consolidated financial statements), and the 2008 period contains a $5.9 million after tax charge associated with legacy commercial real estate investments. 

All other nonutility operating results decreased by approximately $21.0 million in 2010 compared to 2009 driven primarily by reduced optimization opportunities at ProLiance, which resulted in it operating a loss in 2010.  The other operating businesses of Miller Pipeline, Energy Systems Group, Vectren Fuels, and Vectren Source combined for $25.1 million of earnings contribution in 2010.  All other results in 2009 compared to 2008 increased by $12.9 million due primarily to increased earnings from Coal Mining operations.  Results from Coal Mining operations improved due to increased pricing effective January 1, 2009.

Dividends

Dividends declared for the year ended December 31, 2010 were $1.365 per share, compared to $1.345 in 2009 and $1.310 per share in 2008.  In November 2010, the Company’s board of directors increased its quarterly dividend to $0.345 per share from $0.340 per share.  The increase marks the 51st consecutive year Vectren and predecessor companies’ have increased annual dividends paid.

Impacts of Share Issuance in 2008

The increased number of common shares outstanding, resulting from the issuance of common shares in 2008, contributed a $0.04 reduction in earnings per share in 2009 compared to 2008.

Use of Non-GAAP Performance Measures and Per Share Measures

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

Detailed Discussion of Results of Operations

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

Results of Operations of the Utility Group

The Utility Group is comprised of Utility Holdings’ operations and consists 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 ope rating results before certain intersegment eliminations and reclassifications for the years ended December 31, 2010, 2009, and 2008, follow:
 
   
Year Ended December 31,
  
(In millions, except per share data)
  
2010
    
2009
    
2008
  
OPERATING REVENUES
                  
Gas utility
   $ 954.1     $ 1,066.0     $ 1,432.7  
Electric utility
     608.0       528.6       524.2  
Other
     1.6       1.6       1.8  
Total operating revenues
     1,563.7       1,596.2       1,958.7  
OPERATING EXPENSES
                        
Cost of gas sold
     504.7       618.1       983.1  
Cost of fuel & purchased power
     235.0       194.3       182.9  
Other operating
     299.2       304.6       300.3  
Depreciation & amortization
     188.2       180.9       165.5  
Taxes other than income taxes
     59.6       60.3       72.3  
Total operating expenses
     1,286.7       1,358.2       1,704.1  
OPERATING INCOME
     277.0       238.0       254.6  
                         
Other income - net
     5.4       7.8       4.0  
                         
Interest expense
     81.4       79.2       79.9  
                         
INCOME BEFORE INCOME TAXES
     201.0       166.6       178.7  
                         
Income taxes
     77.1       59.2       67.6  
                         
NET INCOME
   $ 123.9     $ 107.4     $ 111.1  
CONTRIBUTION TO VECTREN BASIC EPS
   $ 1.53     $ 1.33     $ 1.42  

Trends in Utility Operations

The Regulatory Environment

Gas and electric operations, with regard to retail rates and charges, terms of service, accounting matters, financing, and certain other operational matters specific to its Indiana customers (the operations of SIGECO and Indiana Gas), are regulated by the IURC.  The retail gas operations of the Ohio operations (VEDO) are subject to regulation by the PUCO.

Over the last four years, the Company has obtained base rate orders at each of its four utilities with SIGECO’s gas and electric territories obtaining base rate increases in August of 2007, Indiana Gas in February 2008, and VEDO in January 2009.  The orders authorize a return on equity ranging from 10.15% to 10.40%.  The authorized returns reflect the impact of innovative rate design strategies having been authorized by these state commissions.  Outside of a full base rate proceeding, these innovative approaches to some extent mitigate the impacts of investments in government-mandated projects, operating costs that are volatile or that increase with government mandates, and changing consumption patterns.  In addition to timely gas and fuel cost recovery, just over $50 million of the Utility Gr oup’s approximate $300 million in other operating expenses incurred during 2010 are subject to a recovery mechanism outside of base rates.
 
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 as more efficient appliances and furnaces are installed, the Company’s utilities have implemented conservation programs, and the price of natural gas has been volatile.  In the Company’s two Indiana natural gas service territories, normal temperature adjustment (NTA) and lost margin recovery mechanisms largely mitigate the effect that would otherwise be caused by variations in volumes sold to these customers due to weather and changing consumption patterns.  The Ohio natural gas service territory has a straight fixed variable rate design.  This rate design, which was fully implemented i n February 2010, mitigates most of the Ohio service territory’s weather risk and risk of decreasing consumption.  Prior to the implementation of this rate design, the Ohio service territory had a lost margin recovery mechanism.  In all natural gas service territories, commissions have authorized bare steel and cast iron replacement programs.  SIGECO’s electric service territory currently recovers certain environmental investments and other transmission investments outside of base rates.  The electric service territory has neither an NTA nor a decoupling mechanism; however, rate designs proposed in the current rate proceeding before the IURC and other related filings would limit weather risk and provide for a decoupling and/or a lost margin recovery mechanism that works in tandem with conservation initiatives.

Tracked Operating Expenses
Gas costs and fuel costs incurred to serve Indiana customers are two of the Company’s most significant operating expenses.  Rates charged to natural gas customers in Indiana contain a gas cost adjustment (GCA) clause. The GCA clause allows the Company to timely charge for changes in the cost of purchased gas, inclusive of unaccounted for gas expense based on historical experience.  Electric rates contain a fuel adjustment clause (FAC) that allows for timely adjustment in charges for electric energy to reflect changes in the cost of fuel.  The net energy cost of purchased power, subject to an approved variable benchmark based on NYMEX natural gas prices, is also timely recovered through the FAC.

GCA and FAC procedures involve periodic filings and IURC hearings to establish the amount of price adjustments for a designated future period.  The procedures also provide for inclusion in later periods of any variances between actual recoveries representing the estimated costs and actual costs incurred.  

The IURC has also applied the statute authorizing GCA and FAC procedures to reduce rates when necessary to limit net operating income to a level authorized in its last general rate order through the application of an earnings test.  These earnings tests have not had any material impact to the Company’s recent operating results and are not expected to have any material impact in the foreseeable future.

Prior to October 1, 2008, gas costs were recovered in Ohio through a gas cost recovery (GCR) mechanism.  The GCR operated similar to the GCA clause in Indiana; however, the GCR was subject to a periodic audit rather than a quarterly hearing process.  The PUCO has completed all audits of periods prior to October 2008, and no issues or findings are outstanding.  After October 1, 2008, the Company is no longer the supplier of natural gas to customers, and therefore no longer recovers natural gas costs via the GCR.

In Indiana, gas pipeline integrity management costs, costs to fund energy efficiency programs, MISO costs, and the gas cost component of uncollectible accounts expense based on historical experience are recovered by mechanisms outside of standard base rate recovery.  Certain operating costs, including depreciation, associated with operating environmental compliance equipment at electric generation facilities and regional electric transmission investments are also recovered outside of base rates.  In Ohio expenses such as uncollectible accounts expense, costs associated with exiting the merchant function, and costs associated with a distribution replacement program are subject to recovery outside of base rates.  Revenues and margins are also impacted by the collection of state mandated taxes, which primarily f luctuate with gas and fuel costs.

See the Rate and Regulatory Matters section of this discussion and analysis for more specific information on significant proceedings involving the Company’s utilities over the last three years.

Utility Group Margin

Throughout this discussion, the terms Gas Utility margin and Electric Utility margin are used.  Gas Utility margin is calculated as Gas utility revenues less the Cost of gas sold.  Electric Utility margin is calculated as Electric utility revenues less Cost of fuel & purchased power.  The Company believes Gas Utility and Electric Utility margins are better indicators of relative contribution than revenues since gas prices and fuel and purchased power costs can be volatile and are generally collected on a dollar-for-dollar basis from customers.  Following is a discussion a nd analysis of margin generated from regulated utility operations.

Gas Utility Margin (Gas utility revenues less Cost of gas sold)
Gas utility margin and throughput by customer type follows:
                   
   
Year Ended December 31,
  
(In millions)
  
2010
    
2009
    
2008
  
                   
Gas utility revenues
   $ 954.1     $ 1,066.0     $ 1,432.7  
Cost of gas sold
     504.7       618.1       983.1  
Total gas utility margin
   $ 449.4     $ 447.9     $ 449.6  
Margin attributed to:
                        
Residential & commercial customers
   $ 385.1     $ 388.8     $ 385.5  
Industrial customers
     52.4       46.8       51.2  
Other
     11.9       12.3       12.9  
                         
Sold & transported volumes in MMDth attributed to:
                  
Residential & commercial customers
     106.2       106.5       114.8  
Industrial customers
     90.8       78.0       91.5  
Total sold & transported volumes
     197.0       184.5       206.3  

Over the three years ended December 31, 2010, there has been a decline in the volumes sold to residential and commercial customers driven by weather and changing consumption patterns.  However, the impact on margin has been generally offset as planned by rate design strategies and the implementation of new base rates in two of the three gas service territories.  Large customer volumes were impacted by the recession, falling approximately 15 percent in 2009 compared to 2008.  With the economy stabilizing in 2010, volumes in 2010 returned to 2008 levels.  The shifting volumes were the principal reason for the change in large customer margin in those years.  The average cost per dekatherm of gas purchased during 2010 was $5.99, compared to $5.97 in 2009 and $9.61 in 2008.

For the year ended December 31, 2010, gas utility margins were $449.4 million and compared to 2009 increased $1.5 million.  Management estimates an increase of $2.4 million due to Ohio rate design changes, as described below.  Large customer margin, net of the impacts of regulatory initiatives and tracked costs, increased by $5.7 million due primarily to increased volumes sold.  Margin decreased $1.9 million due to lower miscellaneous revenues and other revenues associated with lower gas costs.  The remaining decrease is primarily due to a $5.0 million decrease for lower operating expenses and revenue taxes directly recovered in margin.

For the year ended December 31, 2009, gas utility margins decreased $1.7 million compared to 2008.  Management estimates a $4.4 million year over year decrease in industrial customer margin associated with lower volumes sold, and slightly lower residential and commercial customer counts decreased margin approximately $1.7 million.  These recessionary impacts were offset by margin associated with regulatory initiatives.  Among all customer classes, margin increases associated with regulatory initiatives, including the full impact of the Vectren North base rate increase effective in February 2008 and the Vectren Ohio base rate increase effective February 2009, were $8.4 million year over year.  The impact of operating costs, including revenue and usage taxes, recovered in margin was unfavorable $2.9 m illion year over year, reflecting lower revenue taxes offset by higher pass through operating expenses.  The remaining decrease primarily relates to Ohio weather and lower miscellaneous revenues associated with reconnection fees.  The lower fees as well as the lower revenue and usage taxes correlate with lower year over year gas costs.

The rate design approved by the PUCO on January 7, 2009, and initially implemented on February 22, 2009, allowed for the phased movement toward a straight fixed variable rate design, which places substantially all of the fixed cost recovery in the monthly customer service charge.  This rate design mitigates most weather risk as well as the effects of declining usage, similar to the company’s lost margin recovery mechanism in place in the Indiana natural gas service territories and the mechanism in place in Ohio prior to this rate order.  Since the straight fixed variable rate design was fully implemented in February 2010, nearly 90 percent of the combined residential and commercial base rate gas margins were recovered through the customer service charge.  As a result, some margin previously recovered du ring the peak delivery winter months was more ratably recognized throughout the year. In addition in 2010, the Company began recognizing a return on and of investments made to replace distribution risers and bare steel and cast iron infrastructure per a PUCO order.

Electric Utility Margin (Electric utility revenues less Cost of fuel & purchased power)
Electric utility margin and volumes sold by customer type follows:
                   
   
Year Ended December 31,
  
(In millions)
  
2010
    
2009
    
2008
  
                   
Electric utility revenues
   $ 608.0     $ 528.6     $ 524.2  
Cost of fuel & purchased power
     235.0       194.3       182.9  
Total electric utility margin
   $ 373.0     $ 334.3     $ 341.3  
Margin attributed to:
                        
Residential & commercial customers
   $ 241.2     $ 224.7     $ 218.0  
Industrial customers
     97.1       81.7       83.4  
Municipals & other customers
     8.5       7.2       7.4  
Subtotal: Retail
   $ 346.8     $ 313.6     $ 308.8  
Wholesale margin
     26.2       20.7       32.5  
Total electric utility margin
   $ 373.0     $ 334.3     $ 341.3  
                         
Electric volumes sold in GWh attributed to:
                        
Residential & commercial customers
     2,964.0       2,760.8       2,850.5  
Industrial customers
     2,630.3       2,258.9       2,409.1  
Municipals & other
     22.6       20.0       63.8  
Total retail & firm wholesale volumes sold
     5,616.9       5,039.7       5,323.4  

Retail
Electric retail utility margins were $346.8 million for the year ended December 31, 2010, and compared to 2009 increased $33.2 million.  Management estimates the impact of warmer than normal weather to have increased residential and commercial margin $14.2 million year over year.  Management also estimates industrial margins, net of the impacts of regulatory initiatives and recovery of tracked costs, to have increased approximately $12.8 million year to date due primarily to increased volumes.  Margin among the customer classes associated with returns on pollution control investments increased $3.4 million, and margin associated with tracked costs such as recovery of MISO and pollution control operating expenses increased $4.1 million.

Electric retail utility margin was $313.6 million for the year ended December 31, 2009, and compared to 2008 increased $4.8 million.  Increased margin among the customer classes associated with returns on pollution control equipment and other investments totaled $4.5 million year over year, and margin associated with tracked costs such as recovery of MISO and pollution control operating expenses increased $10.3 million.  Management estimates weather, driven primarily by cooling weather 10 percent milder than the prior year, decreased residential and commercial margin $5.2 million compared to 2008.  Industrial margins, net of the impacts of regulatory initiatives and recovery of tracked costs, decreased approximately $4.9 million due primarily to the weak economy.  The industrial decreases were due p rimarily to lower usage.

Margin from Wholesale Electric Activities
Periodically, generation capacity is in excess of native load.  The Company markets and sells this unutilized generating and transmission capacity to optimize the return on its owned assets.  Substantially all off-system sales occur into the MISO Day Ahead and Real Time markets.  Further detail of Wholesale activity follows:
                   
   
Year Ended December 31,
(In millions)
  
2010
    
2009
    
2008
  
Transmission system margin
   $ 18.8     $ 14.6     $ 9.3  
Off-system margin
     7.4       6.1       23.2  
Total wholesale margin
   $ 26.2     $ 20.7     $ 32.5  

Beginning in June 2008, the Company began earning a return on electric transmission projects constructed by the Company in its service territory that meet the criteria of MISO’s regional transmission expansion plans.  Margin associated with these projects, including the reconciliation of recovery mechanisms, and other transmission system operations, totaled $18.8 million during 2010, compared to $14.6 in 2009 and $9.3 million in 2008.  The increase in these transmission system sales is principally due to the increased investment in qualifying projects.

For the year ended December 31, 2010, margin from off-system sales was $7.4 million, compared to $6.1 million in 2009 and $23.2 million in 2008.  In 2009 compared to 2008, margin from off-system sales decreased $17.1 million.  The Company experienced lower wholesale power marketing margins due primarily to lower demand and wholesale prices due to the recession, coupled with increased coal costs.  Off-system sales totaled 587.6 GWh in 2010, compared to 603.6 GWh in 2009, and 1,512.9 GWh in 2008.  The base rate increase 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.  Results for the periods presented reflect the impact of that sharing.

Purchased Power
The Company’s mix of generated and purchased electricity has been more volatile in recent years due to changing commodity prices and the presence of wind farm purchased power agreements.  For the years ended December 31, 2010, 2009, and 2008, respectively, the Company purchased approximately 1,287 GWh, 1,159 GWh, and 372 GWh, of power from the MISO and other sources.  The total cost associated with these volumes of purchased power is approximately $56 million, $43 million, and $26 million in 2010, 2009, and 2008, respectively, and is included in the Cost of fuel & purchased power.

Utility Group Operating Expenses

Other Operating
For the year ended December 31, 2010, other operating expenses were $ 299.2 million, which is a decrease in expenses compared to 2009.  Excluding expenses tracked directly in margin, operating costs decreased $7.9 million.  The primary drivers of the decrease are a $3.0 million reduction in Indiana uncollectible accounts expense and the $4.1 million in costs for environmental matters related to manufactured gas plant site clean-up incurred in 2009.

For the year ended December 31, 2009, other operating expenses were $304.6 million, increasing $4.3 million compared to 2008.  Approximately $10.9 million of the change results from increased costs directly recovered through utility margin.  Increases in other operating expenses in 2009, not directly recovered in margin, include an approximate $6.3 million increase for certain compensation costs and a $4.1 million increase associated with environmental matters related to manufactured gas plant site clean-up.  All other operating expenses were approximately $17.0 million lower than the prior year driven primarily by reductions in electric maintenance costs and lower chemical costs.  Despite significantly lower gas costs due to the recession, In diana uncollectible accounts expense was only slightly favorable compared to 2008.

Depreciation & Amortization
For the year ended December 31, 2010, depreciation expense was $188.2 million, compared to $180.9 in 2009 and $165.5 in 2008.  The increase over the periods presented is due largely to utility capital expenditures placed into service.  Plant placed into service in 2009 included the approximate $100 million SO2 scrubber.

Taxes Other Than Income Taxes
Taxes other than income taxes decreased $0.7 million in 2010 compared to 2009 and decreased $12.0 million in 2009 compared to 2008.  These taxes are primarily revenue-related taxes.  The variations are primarily attributable to volatility in revenues, inclusive of changes in natural gas prices and gas volumes sold.  These tax expenses are recovered through revenue.

Other Income-Net
Other income-net reflects income of $5.4 million in 2010, compared to income of $7.8 million in 2009 and $4.0 million in 2008. The higher earnings in 2009 reflect the partial recovery from the 2008 market declines associated with investments related to benefit plans.

Interest Expense
For the year ended December 31, 2010, interest expense was $81.4 million, compared to $79.2 million in 2009 and $79.9 million in 2008.  The $2.2 million increase in 2010 compared to 2009 reflects the impact of long-term financing transactions completed in 2009, offset by lower interest from less debt outstanding overall.  The slight decrease in interest expense in 2009 compared to 2008 reflects lower short-term interest rates and lower average short-term debt balances.  The lower short-term balances were reflective of lower gas prices and the issuance of new long-term debt.  The long-term financing transactions completed in 2009 include a second quarter issuance by Utility Holdings of $1 00 million in unsecured eleven year notes with an interest rate of 6.28 percent and a third quarter completion by SIGECO of a $22.3 million debt issuance of 31 year tax exempt first mortgage bonds with an interest rate of 5.4 percent.

Income Taxes
Federal and state income taxes were $77.1 million in 2010, compared to $59.2 million in 2009 and $67.6 million in 2008.  The annual change is primarily impacted by greater pre-tax income in 2010 and no manufacturing tax deduction in 2010 as a result of significant bonus depreciation driving down qualifying income.  In addition, the lower effective tax rate in 2009 reflects a greater share of taxable income in states with low, or no, state income taxes.

During the first quarter of 2010, the Company recorded a $2.3 million increase to its deferred tax liabilities associated with a change in the federal tax treatment of the Medicare Part D subsidy as a result of the Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act of 2010 signed by the President as of the end of March 2010.  Like tax law changes in the past, it is expected that the impact of this change will be reflected in customer rates in the future.  As a result, the Company has recorded a $5.1 million regulatory asset related to this matter in its financial statements at December 31, 2010.

Environmental Matters

Clean Air Act
The Clean Air Interstate Rule (CAIR) is an allowance cap and trade program that required reductions from coal-burning power plants for NOx emissions beginning January 1, 2009 and SO2 emissions beginning January 1, 2010, with a second phase of reductions in 2015.  On July 11, 2008, the US Court of Appeals for the District of Columbia vacated the federal CAIR regulations.  Various parties filed motions for reconsideration, and on December 23, 2008, the Court reinstated the CAIR regulations and remanded the regulations back to the EPA 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 EPA revises it per the Court’s guidance.  SIGECO is in compliance with the current CAIR Phase I annual NOx reduction requirements in effect on January 1, 2009, and the Phase I annual SO2 reduction requirements in effect on January 1, 2010.  Utilization of the Company’s inventory of NOx and SO2  allowances may also be impacted if CAIR is further revised.  Most of these allowances were granted to the Company at zero cost; therefore, any reduction in carrying value that could result from future changes in regulations would be immaterial.

Similarly, in March of 2005, EPA promulgated the Clean Air Mercury Rule (CAMR).  CAMR is an allowance cap and trade program requiring further reductions in mercury emissions from coal-burning power plants.  The CAMR regulations were vacated by the US Court of Appeals for the DC Circuit in July 2008.  In response to the court decision, EPA has announced that it intends to publish proposed Maximum Achievable Control Technology standards for mercury in 2011.  It is uncertain what emission limit the EPA is considering, and whether they will address hazardous pollutants in addition to mercury.

To comply with Indiana’s implementation plan of the Clean Air Act of 1990, the CAIR regulations, and to comply with potential future regulations of mercury and further NOx and SO2  reductions, SIGECO has IURC authority to invest in clean coal technology.  Using this authorization, SIGECO has invested approximately $411 million in pollution control equipment, including Selective Catalytic Reduction (SCR) systems, fabric filters, and an SO2 scrubber at its generating facility that is jointly owned with ALCOA (the Company&# 8217;s portion is 150 MW).  SCR technology is the most effective method of reducing NOx emissions where high removal efficiencies are required and fabric filters control particulate matter emissions.  Of the $411 million, $312 million was included in rate base for purposes of determining SIGECO’s new electric base rates that went into effect on August 15, 2007, and $99 million is currently recovered through a rider mechanism which is periodically updated for actual costs incurred including depreciation expense. As part of its recent rate proceeding, the Company has requested to also include these more recent expenditures in rate base as well.

SIGECO’s coal fired generating fleet is 100 percent scrubbed for SO2 and 90 percent controlled for NOx.  SIGECO's investments in scrubber, SCR, and fabric filter technology allows for compliance with existing regulations and should position it to comply with future reasonable mercury pollution control legislation, if and when, reductions are promulgated by EPA.  On July 6, 2010, the EPA issued its proposed revisions to CAIR, renamed the Clean Air Transport Rule, for public comment.  The Transport Rule proposes a 71 percent reduction of SO2 over 2005 national levels and a 52 percent reduction of NOx over 2005 national levels and would further impact the utili zation of currently granted SO2 and NOx allowances.  The Company is currently reviewing the sufficiency of its existing pollution control equipment in relation to the requirements proposed in the Clean Air Transport Rule and currently does not expect significant capital expenditures will be required to comply if the Transport Rule is adopted in its current form.

Climate Change
Vectren is committed to responsible environmental stewardship and conservation efforts.  While scientific uncertainties exist and the debate surrounding global climate change is ongoing, current information suggests a potential for adverse economic and social consequences should world-wide carbon dioxide (CO2) and other greenhouse gas emissions continue at present levels.

The Company emits greenhouse gases (GHG) primarily from its fossil fuel electric generation plants.  The Company uses methodology described in the Acid Rain Program (under Title IV of the Clean Air Act) to calculate its level of direct CO2 emissions from its fossil fuel electric generating plants.  The Company’s direct CO2 emissions from its plants over the past 5 years are represented below:
                                 
(in thousands)
  
2010
    
2009
      
2008
    
2007
    
2006
  
Direct CO2 Emissions (tons)
     6,120       5,500   1/   8,029       7,995       7,827  
 
1/  
The decline in emissions from 2008 to 2009 is primarily due to recessionary impacts that resulted in a 30 percent decrease in generation.  It is not clear to what extent this recent reduction may continue.

Based on 2005 data made available through the Emissions and Generation Resource Integrated Database (eGRID) maintained by the EPA, the Company’s direct CO2 emissions from its fossil fuel electric generation that report under the Acid Rain Program were less than one half of one percent of all emissions in the United States from similar sources.  The EPA has yet to release data subsequent to 2005.

Emissions from other Company operations, including those from its natural gas distribution operations, are monitored internally using the Department of Energy 1605(b) Standard, and the Company will report these other emissions generated in 2010 to the EPA per mandatory reporting requirements later in 2011.

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;
·  
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; and
·  
The allocation of zero cost allowances to natural gas distribution companies if those companies are required to hold allowances for the benefit of the end use customer.

Current Initiatives to Increase Conservation & Reduce Emissions
The Company is committed to a policy that reduces greenhouse gas emissions and conserves energy usage.  Evidence of this commitment includes:
·  
Focusing the Company’s mission statement and purpose on corporate sustainability and the need to help customers conserve and manage energy costs;
·  
Building a renewable energy portfolio 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;
·  
The recent settlement agreement between the Company and the OUCC regarding electric demand side management initiatives;
·  
Evaluating potential carbon requirements with regard to new generation, other fuel supply sources, and future environmental compliance plans;
·  
Reducing the Company’s carbon footprint by measures such as utilizing hybrid vehicles and optimizing generation efficiencies; and
·  
Developing renewable energy and energy efficiency performance contracting projects through its wholly owned subsidiary, Energy Systems Group.

Legislative Actions & Other Climate Change Initiatives
Numerous competing legislative proposals have been introduced in recent years that involve carbon, energy efficiency, and renewable energy.  Comprehensive energy legislation at the federal level continues to be debated, but there has been little progress to date.  The progression of regional initiatives throughout the United States has also slowed.  While no climate change legislation is pending in Indiana, the state is an observer to the Midwestern Regional Greenhouse Gas Reduction Accord and the state’s legislature debated, but did not pass, a renewable energy portfolio standard in 2009.

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

In April of 2007, the US Supreme Court determined that greenhouse gases meet the definition of "air pollutant" under the Clean Air Act and ordered the EPA to determine whether greenhouse gas emissions from motor vehicles cause or contribute to air pollution that may reasonably be anticipated to endanger public health or welfare. In April of 2009, the EPA published its proposed endangerment finding for public comment.  The proposed endangerment finding concludes that carbon emissions from mobile sources pose an endangerment to public health and the environment.  The endangerment finding was finalized in December of 2009, and is the first step toward EPA regulating carbon emissions through the existing Clean Air Act in the absence of specific carbon legislation from Congress.  Therefore, any new regulations wou ld likely also impact major stationary sources of greenhouse gases.  The EPA has promulgated two greenhouse gas regulations that apply to SIGECO’s generating facilities.  In 2009, the EPA finalized a mandatory greenhouse gas emissions registry which will require reporting of emissions beginning in 2011 (for the emission year 2010).  The EPA has also recently finalized a revision to the Prevention of Significant Deterioration (PSD) and Title V permitting rules which would require facilities that emit 75,000 tons or more of greenhouse gases a year to obtain a PSD permit for new construction or a significant modification of an existing facility.

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

Ash Ponds & Coal Ash Disposal Regulations

In June 2010, the EPA issued proposed regulations affecting the management and disposal of coal combustion products, such as ash generated by the Company’s coal-fired power plants.  The proposed rules more stringently regulate these byproducts and would likely increase the cost of operating or expanding existing ash ponds and the development of new ash ponds.  The EPA did not offer a preferred alternative, but is taking public comment on multiple alternative regulations.  The alternatives include regulating coal combustion by-products as hazardous waste.  At this time, the majority of the Company’s ash is being beneficially reused.  The proposals offered by EPA allow for the beneficial reuse of ash in certain circumstances.  The Company estimates capital expenditures to comply could be as much as $30 million, and such expenditures could exceed $100 million if the most stringent of the alternatives is selected.  Annual compliance costs could increase slightly or be impacted by as much as $5 million.

Clean Water Act

Section 316(b) of the Clean Water Act requires that generating facilities use the “best technology available” to minimize adverse environmental impacts.  More specifically, Section 316(b) is concerned with impingement and entrainment of aquatic species in once-through cooling water intake structures.  In April of 2009, the U.S. Supreme Court affirmed that the EPA could, but was not required to, consider costs and benefits in making the evaluation as to the best technology available for existing facilities.  The regulation was remanded back to the EPA for further consideration.  Depending upon the approaches taken by the EPA when it reissues the regulation, capital investments could be in the $40 million range if new infrastructure, such as new cooling water towers, is required.

Jacobsville Superfund Site

On July 22, 2004, the EPA listed the Jacobsville Neighborhood Soil Contamination site in Evansville, Indiana, on the National Priorities List under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA).  The EPA has identified four sources of historic lead contamination.  These four sources shut down manufacturing operations years ago.  When drawing up the boundaries for the listing, the EPA included a 250 acre block of properties surrounding the Jacobsville neighborhood, including Vectren's Wagner Operations Center.  Vectren's property has not been named as a source of the lead contamination.  Vectren's own soil testing, completed during the construction of the Operations Center, did not indicate that the Vectren property contains lead contaminated soils above industrial cleanup levels.  At this time, it is anticipated that the EPA may request only additional soil testing at some future date.

Environmental Remediation Efforts

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

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

Indiana Gas accrued the estimated costs for further investigation, remediation, groundwater monitoring, and related costs for the sites.  While the total costs that may be incurred in connection with addressing these sites cannot be determined at this time, Indiana Gas has recorded cumulative costs that it reasonably expects to incur totaling approximately $23.1 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 received approximately $20.8 million from all known insurance carriers under insu rance policies in effect when these plants were in operation.

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

SIGECO has recorded cumulative costs that it reasonably expects to incur related to these environmental matters, including the recent settlement discussed above, totaling approximately $15.8 million.  However, the total costs that may be incurred in connection with addressing all of these sites cannot be determined at this time.  With respect to insurance coverage, SIGECO has recorded approximately $14.1 million of expected insurance recoveries from certain of its insurance carriers under insurance policies in effect when these sites were in operation.  While negotiations are ongoing with certain carriers, settlements have been reached with some carriers and $8.2 million in proceeds have been received.

The costs the Company expects to incur are estimated by management using assumptions based on actual costs incurred, the timing of expected future payments, and inflation factors, among others.  While the Company’s utilities have recorded all costs which they presently expect to incur in connection with activities at these sites, it is possible that future events may require some level of additional remedial activities which are not presently foreseen and those costs may not be subject to PRP or insurance recovery.  As of December 31, 2010 and 2009, respectively, approximately $5.5 million and $6.5 million of accrued, but not yet spent, costs are included in Other Liabilities related to both the Indiana Gas and SIGECO sites.

Rate & Regulatory Matters

Vectren South Electric Base Rate Filing

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

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

During 2010, as part of its FAC testimony, the OUCC requested the IURC require Vectren South to renegotiate its term coal contracts because they were priced higher than prevailing spot prices.  This request was repeated by the OUCC in Vectren South’s base rate proceeding referred to above.  Vectren South purchases the majority of its coal from Vectren Fuels, Inc. (a nonutility wholly owned subsidiary of the Company) under coal contracts entered into in 2008.  Vectren South states in its rate case testimony that the prices in the coal contracts were at or below the market at the time of contract execution and were subject to a bidding process that included third parties.  Further, the Company has already engaged in contract renegotiations to defer certain deliveries, and to eliminate some volum es in 2011, with further price negotiation to occur in 2011 under the terms of the contracts.  The IURC has already found in a number of FAC proceedings since 2008, including in its most recent FAC order dated November 4, 2010, that the costs incurred under these coal contracts are reasonable.

The OUCC also raised concerns regarding Vectren South’s generating unit “must run” policy.  Under that policy, for reliability reasons, Vectren South instructs the MISO that certain units must be dispatched regardless of current market conditions.  The OUCC is reviewing data related to Vectren South’s “must run” policy.

The parties agreed to the creation of an FAC sub docket proceeding to address the specific issues noted above.  An order establishing the sub docket was issued by the IURC on July 28, 2010.  On November 30, 2010, in response to a joint motion filed by the OUCC and Vectren South, the IURC issued an order dismissing this sub docket as these coal contract issues will be addressed in the pending Vectren South Electric base rate case.

Vectren South Electric Demand Side Management Program Filing

On August 16, 2010, Vectren South filed a petition with the IURC, seeking approval of its proposed Demand Side Management (DSM) Programs, recovery of the costs associated with these programs, recovery of lost margins as a result of implementing these programs for large customers, and recovery of performance incentives linked with specific measurement criteria on all programs.  The DSM Programs proposed are consistent with a December 9, 2009 order issued by the IURC, which, among other actions, defined long-term conservation objectives and goals of DSM programs for all Indiana electric utilities under a consistent statewide approach.  In order to meet these objectives, the IURC order divided the DSM programs into Core and Core Plus programs.  Core programs are joint programs required to be offered by all India na electric utilities to all customers, including large industrial customers.  Core Plus programs are those programs not required specifically by the IURC, but defined by each utility to meet the overall energy savings targets defined by the IURC.

In its August filing, Vectren South proposed a three-year DSM Plan that expands its current portfolio of Core and Core Plus DSM Programs in order to meet the energy savings goals established by the IURC.  Vectren South requested recovery of these program costs under a current tracking mechanism.  In addition, Vectren South proposed a performance incentive mechanism that is contingent upon the success of each of the DSM Programs in reducing energy usage to the levels defined by the IURC.  This performance incentive would also be recovered in the same tracking mechanism.  Finally, the Company proposed lost margin recovery associated with the implementation of DSM programs for large customers, and cited its decoupling proposal applicable to residential and general service customers in the pending elect ric base rate case.  On January 20, 2011, the OUCC and Vectren South filed a settlement with the IURC reflecting agreement on the Company’s programs and lost margin recovery from large customers.  A hearing will be held on March 8, 2011 involving all parties to this proceeding.
 
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 for residential customers which places 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 decoupling 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 the decoupling mechanism that did not continue once this base rate increase went into effect.  Since the straight fixed variable rate design was fully implemented in February 2010, nearly 90 percent of the combined residential and commercial base rate margins were recovered through the customer service charge.  The OCC appealed this rate order to the Ohio Supreme Court, which had affirmed PUCO orders authorizing straight fixed variable rate design in two other cases. On December 23, 2010, the Ohio Supreme Court affirmed the PUCO order authorizing straight fixed variable rate design in VEDO’s case. 

With this rate order, the Company has in place for its Ohio gas territory rates that allow for a straight fixed variable rate design that mitigates both weather risk and lost margin for residential customers; tracking of uncollectible accounts 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.

VEDO Continues the Process to Exit the Merchant Function

On August 20, 2008, the PUCO approved the results of an auction selecting qualified wholesale suppliers to provide the gas commodity to the Company for resale to its customers at auction-determined standard pricing.  This standard pricing was comprised of the monthly NYMEX settlement price plus a fixed adder.  This standard pricing, which was effective from October 1, 2008 through March 31, 2010, was the initial step in exiting the merchant function in the Company’s Ohio service territory.  The approach eliminated the need for monthly gas cost recovery (GCR) filings and prospective PUCO GCR audits.  In October 2008, VEDO’s entire natural gas inventory was transferred to the auction’s winning wholesale supplie rs, resulting in proceeds to VEDO of approximately $107 million.

The second phase of the exit process began on April 1, 2010.  During this phase, the Company no longer sells natural gas directly to customers.  Rather, state-certified Competitive Retail Natural Gas Suppliers, that were successful bidders in a similar regulatory-approved auction, sell the gas commodity to specific customers for a 12 month period at auction-determined standard pricing.  The first auction was conducted on January 12, 2010, and the auction results were approved by the PUCO on January 13, 2010.  The plan approved by the PUCO required that the Company conduct at least two annual auctions during this phase.  As such, the Company conducted another auction on January 18, 2011 in advance of the second 12-month term which commences on April 1, 2011.  The results of that auction wer e approved by the PUCO on January 19, 2011. Consistent with current practice, customers will continue to receive a single bill for the commodity as well as the delivery component of natural gas service from VEDO.  Vectren Source, the Company’s wholly owned nonutility retail gas marketer, was a successful bidder in both auctions.

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

Vectren North Gas Base Rate Order Received

On February 13, 2008, the Company received an order from the IURC which approved the settlement agreement reached in its Vectren North gas rate case.  The order provided for a base rate increase of $16.3 million and a return on equity (ROE) of 10.2 percent, with an overall rate of return of 7.8 percent on rate base of approximately $793 million.  The order also provided for the recovery of $10.6 million of costs through separate cost recovery mechanisms rather than base rates.

Further, additional expenditures for a multi-year bare steel and cast iron capital replacement program will be afforded certain accounting treatment that mitigates earnings attrition from the investment between rate cases.  The accounting treatment allows for the continuation of the accrual for AFUDC and the deferral of depreciation expense after the projects go in service but before they are included in base rates.  To qualify for this treatment, the annual expenditures are limited to $20 million and the treatment cannot extend beyond four years from the in-service date for each specific project.

With this order, the Company has in place for its North gas territory weather normalization, a conservation and decoupling mechanism, recovery of gas cost expense related to uncollectible accounts expense based on historical experience and tracking of unaccounted for gas costs through the existing GCA mechanism, and tracking of pipeline integrity management expense. 

MISO

The Company is a member of the MISO, a FERC approved regional transmission organization.  When the Company is a net seller of its generation, such net revenues, which totaled $24.9 million, $20.8 million, and $57.6 million for the twelve months ended December 31, 2010, 2009, and 2008, respectively, are included in Electric utility revenues.  When the Company is a net purchaser such net purchases, which totaled $46.1 million, $34.4 million, and $16.6 million for the twelve months ended December 31, 2010, 2009, and 2008, respectively, are included in Cost of fuel & purchased power.  Net positions are determined on an hourly basis.

The Company also receives transmission revenue from the MISO which is included in Electric utility revenues and totaled $18.8 million, $14.6 million, and $9.3 million for the twelve months ended December 31, 2010, 2009, and 2008, respectively.  These revenues result from other MISO members’ use of the Company’s transmission system as well as the recovery of the Company’s investment in certain new electric transmission projects meeting MISO’s transmission expansion plan criteria.

One such project currently under construction meeting these expansion plan criteria is an interstate 345 Kv transmission line that will connect Vectren’s A.B. Brown Generating Station to a station in Indiana owned by Duke Energy to the north and to a station in Kentucky owned by Big Rivers Electric Corporation to the south.  During the construction of these transmission assets and while these assets are in service, SIGECO will recover an approximate 10 percent return, inclusive of the FERC approved equity rate of return of 12.38 percent, on capital investments through a rider mechanism which is projected annually and reconciled the following year based on actual results.  Of the total investment, which is expected to approximate $90 million, the Company has invested approximately $59.2 mi llion as of December 31, 2010.  The north leg of this expansion was placed in service in November 2010, and the south leg of this project is expected to be operational in 2012.  Further, the FERC approval allows for recovery of expenditures made in the event of unforeseen difficulties that delay or permanently halt the project.

Results of Operations of the Nonutility Group

The Nonutility Group operates in four primary business areas: Infrastructure Services, Energy Services, Coal Mining, and Energy Marketing.  Infrastructure Services provides underground construction and repair.  Energy Services provides performance contracting and renewable energy services.  Coal Mining mines and sells coal.  Energy Marketing markets and supplies natural gas and provides energy management 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 e arnings for the years ended December 31, 2010, 2009, and 2008, follow:
                   
   
Year Ended December 31,
  
(In millions, except per share amounts)
  
2010
    
2009
    
2008
  
NET INCOME
   $ 9.8     $ 25.8     $ 18.9  
                         
CONTRIBUTION TO VECTREN BASIC EPS
   $ 0.12     $ 0.32     $ 0.24  
                         
NET INCOME (LOSS) ATTRIBUTED TO:
                  
Infrastructure Services
   $ 3.1     $ 2.4     $ 5.2  
Energy Services
     6.4       8.4       6.2  
Coal Mining
     11.9       13.4       (4.6 )
Energy Marketing
     (4.2 )     4.1       18.0  
Other Businesses
     (7.4 )     (2.5 )     (5.9 )

Infrastructure Services

Infrastructure Services provides underground construction and repair to utility infrastructure through Miller Pipeline, LLC (Miller).  Inclusive of holding company costs, Infrastructure’s operations contributed earnings of $3.1 million in 2010, compared to $2.4 million in 2009 and $5.2 million in 2008.

In 2010, Miller’s earnings contribution increased $0.7 million, compared to earnings generated in 2009.  Even with cold weather conditions in the first quarter of 2010 restricting construction levels, results in 2010 compared to 2009 reflect higher revenues and man hours worked.  Man hours increased approximately 4 percent in 2010 compared to both 2009 and 2008.  The lower earnings in 2009 compared to 2008 primarily results from customer cutbacks in spending as a result of the recession.  In addition, startup costs associated with new contracts also negatively impacted year over year results.  Lower interest rates partially offset the lower margins.  The year ended December 31, 2008 was a record year in terms of earnings contribution from Miller.

Utilities continue to replace their aging natural gas and wastewater infrastructure and needs for shale gas infrastructure are becoming more prevalent.  The current low interest rate environment, when coupled with the impacts of bonus depreciation legislation and proposed regulations to accelerate the replacement of aging gas pipeline infrastructure, positions Miller for future growth and resulting earnings.
 
Energy Services

Energy Services provides energy performance contracting and renewable energy services through Energy Systems Group, LLC (ESG).  Inclusive of holding company costs, Energy Services’ operations contributed earnings of $6.4 million in 2010, compared to $8.4 million in 2009 and $6.2 million in 2008.

Over the last three years, performance contracting operations have continued to grow.  At December 31, 2010, ESG’s backlog was $118 million, a new record level, compared to $70 million at December 31, 2009 and $65 million at December 31, 2008, reflecting substantial work for 2011 and beyond.  Both 2009 and 2008 were favorably impacted by discrete renewable energy projects.  As part of ESG’s ongoing renewable energy project development strategy, results in 2009 include the sale of a 3 megawatt landfill gas facility.  With IURC approval, the facility was sold to SIGECO, to further the utility’s strategy of building a renewable energy portfolio.  ESG’s earnings associated with this renewable project match the results of a similar land fill gas project completed for a t hird party customer near Atlanta, Georgia in 2008.

The national focus on a comprehensive energy strategy and a continued focus on renewable energy, energy conservation, and sustainability measures by ESG’s customers are expected to create favorable conditions for ESG’s future growth.  As a recent example, on February 8, 2011, ESG was selected to design, construct, and operate a landfill gas-to-recycled natural gas processing facility for DeKalb County, Georgia’s Seminole Road Landfill.  The recycled natural gas will be used to fuel compressed natural gas (CNG) vehicles at the Seminole Road Landfill, and the project will result in millions of dollars in savings in fuel costs to operate the Dekalb County sanitation fleet.

Coal Mining

Coal Mining owns mines that produce and sell coal to the Company’s utility operations and to third parties through its wholly owned subsidiary Vectren Fuels, Inc. (Vectren Fuels).  Coal Mining, inclusive of holding company costs, earned approximately $11.9 million in 2010, compared to $13.4 million in 2009 and a loss of $4.6 million in 2008.

In 2010, Coal Mining revenues were $210 million, a $17 million increase compared to 2009 and a $46 million increase compared to 2008.  In 2010, expected higher depreciation and other mining costs as well as higher interest costs associated with the ramp up of mining at the Oaktown mine complex more than offset the increase in sales.  In 2009 compared to 2008, Coal Mining earnings increased based on new contract pricing effective January 1, 2009.  The impact of higher revenues in 2009 was somewhat offset by increased costs per ton mined and the recession.  The anticipated cost increase was reflective of efforts of the contract miner to reconfigure the mining operation at Prosperity mine in order to improve future productivity and meet Mine Safety and Health Administration (MSHA) requirements.  During the second half of 2009, these improvements began to favorably impact production and operating costs. 

The recent recession resulted in a decrease in the demand for, and market price of, Illinois Basin coal and has resulted in lower than anticipated earnings from Coal Mining operations.  The lowered demand caused some build up of coal inventory at most customer locations as well as at the mines owned by Vectren Fuels.  As a result of contracts with minimum delivery provisions, certain customers scaled back their deliveries within specified limits.  This resulted in less 2010 and 2009 mine production as production was aligned with customer’s needs.  In the current market conditions, the coal mines sold 3.7 million tons in 2010, 3.5 million tons in 2009, and 4.2 million tons in 2008.  During 2010, there has been some improvement in the demand and supply imbalance for Illinois Basin coal that began in 2009.  Demand is returning as evidenced by successful negotiations with a number of new term supply contracts, as well as continued spot sales.  The anticipated 2011 coal production is approximately 5.1 million tons with total sales in 2011 of 5.4 million tons expected and over 90% of those sales have been contracted and priced.

Oaktown Mines
The first of two new underground mine investments, located near Vincennes, Indiana, began full operations in 2010.  The second mine is currently expected to open in 2012.  However, Vectren Fuels may continue to adjust this timing as it evaluates the impacts of market conditions.  Reserves at the two mines are estimated at about 105 million tons of recoverable coal at 11,200 BTU and less than 6-pound sulfur dioxide.  The reserves at these new mines bring total coal reserves to approximately 137 million tons at December 31, 2010.  Once in production, the two new mines are capable of producing about 5 million tons of coal per year.  Management expects to incur approximately $200 million to access the coal reserves.  At December 31, 2010, Vectren Fuels has invested approximately $186 million in the new mines toward initial construction.

Mine Safety Information
The Company, through its wholly owned subsidiary Vectren Fuels, Inc., owns coal mines and related assets located in Indiana.  The Company has retained independent third party contract mining companies to operate its coal mines.  Five Star Mining LLC ("Five Star") is the contract mining company at the Prosperity underground mine and Black Panther Mining LLC ("Black Panther") is the contract mining company at the Oaktown underground mines.  While in operation, Vigo-Cypress Creek, LLC was the contract mining company at Cypress Creek surface mine. The contract mining companies are the mine “operator”, as that term is used in both the Federal Mine Safety and Health Act of 1977 (the “Mine Act”) and the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010.  All emp loyees at the coal mines are hired, supervised, and paid by the contract mining companies.  As the mine operator, the contract mining companies make all regulatory filings required by the MSHA.  In most circumstances, however, the cost of fines and penalties assessed by MSHA are contractually passed through from the contract mining company to Vectren Fuels.  The process of settling such claims can take years in certain circumstances.  During the year ended December 31, 2010, the Company paid approximately $0.7 million related to assessments issued to the mine operators.

More detailed information about the Company’s mines, including safety-related data, can be found at MSHA’s website, www.MSHA.gov.  Prosperity operates under the MSHA identification number 1202249; the Oaktown mining complex operates under the identification numbers 1202394 and 1202418; and Cypress Creek’s identification number is 1202178.  Mine safety-related data included on the MSHA website is influenced by the size of the mine, the level of activity at the mine, and the mine inspector’s judgment, among other factors. These factors can impact the comparability of information from mine to mine and time period to time period.  Given the recent incidents at coal mines of other companies, a significant increase in the frequency and scope of MSHA inspections continues.  In addit ion, both houses of Congress are considering new mine safety legislation.  The Company is currently assessing the impact new laws and regulations may have on its investments.

Energy Marketing

Energy Marketing is comprised of the Company’s gas marketing operations, energy management services, and retail gas supply operations.  Operating entities contributing to these results include ProLiance and Vectren Source.  Results, inclusive of holding company costs from Energy Marketing for the year ended December 31, 2010, were a loss of $4.2 million, compared to earnings of $4.1 million in 2009 and $18.0 million in 2008.

ProLiance
ProLiance, a nonutility energy marketing affiliate of Vectren and 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 and 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.  Therefore, the Company accounts for its investment in ProLiance using the eq uity method of accounting.  Vectren received regulatory approval on April 25, 2006, from the IURC for ProLiance to continue to provide natural gas supply services to the Company’s Indiana utilities through March 2011.  On November 3, 2010, a settlement agreement was filed with the IURC providing for ProLiance’s continued provision of gas supply services to the Company’s Indiana utilities and Citizens Gas for the period of April 1, 2011 through March 31, 2016.  The settlement has been agreed to by all of the representatives that were parties to the prior settlement.  An order is anticipated during the first quarter of 2011.

Vectren Energy Marketing and Services, Inc (EMS), a wholly owned subsidiary, holds the Company’s investment in ProLiance.  Within the consolidated entity, EMS is responsible for certain financing costs associated with ProLiance and is also responsible for income taxes and allocated corporate expenses related to the Company’s portion of ProLiance’s results.  During the year ended December 31, 2010, ProLiance’s results, inclusive of financing costs and income taxes, were a loss of approximately $7.9 million compared to a loss of $2.3 million in 2009 and earnings of $16.5 million in 2008.  Results in 2009 include an $11.9 million after tax charge associated with ProLiance’s investment in Liberty Gas Storage, as noted below.

In 2010 compared to 2009, results at EMS related to ProLiance decreased $5.6 million.  Before the Liberty Charge, ProLiance’s results decreased approximately $17.5 million year over year.  The decrease reflects the impacts of new natural gas sources from shale and greater transmission capacity as well as the impacts of reduced industrial demand for natural gas in the Midwest.  These conditions have resulted in plentiful natural gas supply and lower and less volatile natural gas prices.  Historical basis differences between physical and financial markets and summer and winter prices have narrowed.  As a result, there have been reduced opportunities to optimize ProLiance’s firm transportation and storage capacity.  ProLiance has structured optimization activities to rem ain flexible to maximize potential opportunities if market conditions improve and has undertaken other actions to improve future results.  However, if current market conditions continue, resulting in continued depressed asset optimization opportunities, it is expected that ProLiance will experience a loss in 2011.  Given the continuing compressed margins experienced during the first few weeks of 2011, the Company currently estimates a first quarter 2011 net loss of approximately $9.0 million to $13.0 million, compared to first quarter 2010 earnings of $3.9 million, and thereafter results are expected to be about breakeven for the remainder of the year based upon the current market for basis and seasonal spreads. 

ProLiance has approximately $80 million of annual fixed costs related to its transportation and storage contracts, with contracts representing nearly a third of these fixed costs expiring over the next three years and half over the next five years.  At December 31, 2010 ProLiance continued to maintain significant sources of liquidity beyond its credit facility, which is up for renewal in June 2011, and its balance sheet has $209 million of members’ equity, no long-term debt, and $49 million of working capital debt outstanding, which has now been repaid.  Various profit improvement initiatives are underway, including lowering the cost of pipeline demand costs through ongoing pipeline renegotiations. Should market conditions improve from the current depressed levels, ProLiance’s return to profitability would be ac celerated.

During 2009, ProLiance’s earnings contribution decreased $18.8 million compared to 2008.  The decrease reflects the 2009 Liberty Charge and also reflects lower cash to NYMEX spreads compared to the prior year, particularly spreads existing in the third quarter of 2008 that had unprecedented price volatility and resulted in record quarterly earnings from ProLiance.  ProLiance’s storage capacity was 46 Bcf at December 31, 2010 and 2009 compared to 42 Bcf at December 31, 2008.

For the years ended December 31, 2010, 2009, and 2008, the amounts recorded to Equity in earnings of unconsolidated affiliates related to ProLiance’s operations totaled a pre-tax loss of $2.5 million, earnings of $3.6 million, and earnings of $39.5 million, respectively.  The earnings in 2009 include the Liberty Charge described below.

Investment in Liberty Gas Storage
Liberty Gas Storage, LLC (Liberty), a joint venture between a subsidiary of ProLiance and a subsidiary of Sempra Energy (SE), is a development project for salt-cavern natural gas storage facilities.  ProLiance is the minority member with a 25 percent interest, which it accounts for using the equity method.  The project was expected to include 17 Bcf of capacity in its north facility, and an additional 17 Bcf of capacity in its south facility.  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 $36.7 million at December 31, 20 10, 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 in development of certain caverns.  At June 30, 2009, Liberty recorded a charge of approximately $132 million to write off the north caverns and certain related assets.  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 for the year ended December 31, 2009, the char ge is an approximate $19.9 million reduction to Equity in earnings of unconsolidated affiliates and an income tax benefit reflected in Income taxes of approximately $8.0 million. ProLiance has not experienced, and does not expect, any impact to its liquidity or access to capital as a result of the impairment charge, nor is it expected that this situation will impact ProLiance’s ability to meet the needs of its customers.

Liberty received a Demand for Arbitration from Williams Midstream Natural Gas Liquids, Inc. (“Williams”) on February 8, 2011 related to a Sublease Agreement (“Sublease”) between Liberty and Williams.  Williams alleges that Liberty was negligent in its attempt to convert certain salt caverns to natural gas storage and thereby damaged the caverns.  Williams alleges damages of $56.7 million.  Liberty believes that the claims are without merit and believes that it has complied with all of its obligations to Williams and has properly terminated the Sublease.  Liberty intends to vigorously defend itself and believes it has counterclaims against Williams which it will assert in the arbitration proceeding.  Liberty has made no accrual for this matter as of December 31, 2010.

Vectren Source
Vectren Source, a wholly owned subsidiary, provides natural gas and other related products and services to customers opting for choice among energy providers.  Vectren Source earned approximately $3.7 million in 2010, compared to $6.4 million in 2009 and $1.5 million in 2008.  Results in 2010 were lower than the prior year, as expected, due to higher margins on variable priced contracts in the first quarter of 2009.  During 2009’s first quarter, revenues on variable priced sales contracts fell more slowly than gas costs. Results in 2008 were impacted by a $0.5 million gain on the sale of its Georgia customer base.  Vectren Source’s customer count at December 31, 2010 was approximately 227,000 equivalent customers, compared to 189,000 at December 31, 2009 and 170,000 at December 31, 2008.   The 2010 customer count reflects nearly 100,000 customers in VEDO’s service territory that have either voluntarily opted to choose their natural gas supplier or are supplied natural gas by Vectren Source but remain customers of the regulated utility as part of VEDO’s exit the merchant function process.  As a result of a supplier choice auction held on January 18, 2011 in VEDO’s service territory, Vectren Source will increase its customer base by 28,000 to over 255,000.

Other Businesses

Within the Nonutility business segment, there are legacy investments involved in energy-related opportunities and services, real estate, leveraged leases, and other ventures.  As of December 31, 2010, remaining legacy investments included in the Other Businesses portfolio total $52.7 million, of which $40.9 million are included in Other nonutility investments and $11.8 million are included in Investments in unconsolidated affiliates.  Further separation of that remaining investment by type of investment follows: commercial real estate $19.8 million; leveraged leases $17.9 million; affordable housing projects $7.2 million; Haddington Energy Partners $3.4 million; and other investments $4.4 million.  0;As of December 31, 2009, investments totaled $64.5 million.

Other Businesses losses were $7.4 million in 2010, compared to a loss of $2.5 million in 2009 and a loss of $5.9 million in 2008. Results in 2010 reflect a $4.0 million after tax charge related to a decline in the fair value of an energy-related investment originally made in 2004 by Haddington Energy Partners.  The lower results in 2010 also reflect a first quarter $2.9 million after tax charge related to the reduction in value of a note receivable recorded in 2002 related to a previously exited business. Results in 2008 reflect a write-down associated with commercial real estate investments.

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

During the second quarter of 2010, the Company recorded its share of the decline in fair value and also impaired a note receivable associated with Haddington’s investment in a liquefied natural gas facility.  In total, the charge was approximately $6.5 million, of which, $6.1 million is reflected in Equity in earnings of unconsolidated affiliates and $0.4 million is reflected in Other-net.  At December 31, 2010, the Company’s remaining $3.4 million investment in the Haddington ventures is related to payments to be received associated with the sale of a compressed air storage facility sold in 2009.  The Company has no further commitments to invest in either Haddington I or II.  < /div>

2008 Commercial Real Estate Charge
The recession impacted the value of commercial real estate investments within this portfolio.  During 2008, the Company assessed its commercial real estate investments for impairment and identified the need to reduce their carrying values.  The 2008 impairment charge totaled $10.0 million, $5.9 million after tax, or $0.08 per basic earnings per share.  Of the $10.0 million charge, $5.2 million is included in Other-net and $4.8 million is included in Other operating expenses.  The charge impacted the carrying values of primarily notes receivable collateralized by commercial real estate and an office building. The Company took possession of the office building when a leveraged lease expire d in 2008; the building is currently for sale.

Impact of Recently Issued Accounting Guidance

Variable Interest Entities

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

Fair Value Measurements & Disclosures

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

Critical Accounting Policies

Management is required to make judgments, assumptions, and estimates that affect the amounts reported in the consolidated financial statements and the related disclosures that conform to accounting principles generally accepted in the United States.  The consolidated financial statement footnotes describe the significant accounting policies and methods used in the preparation of the consolidated financial statements.  Certain estimates used in the financial statements are subjective and use variables that require judgment.  These include the estimates to perform goodwill and other asset impairments tests and to determine pension and postretirement benefit obligations.  The Company makes other estimates in the course of accounting for unbilled revenue and the effects of regulation that are critical t o the Company’s financial results but that are less likely to be impacted by near term changes.  Other estimates that significantly affect the Company’s results, but are not necessarily critical to operations, include depreciating utility and nonutility plant, valuing reclamation liabilities, valuing derivative contracts, and estimating uncollectible accounts and coal reserves, among others.  Actual results could differ from these estimates.

Impairment Review of Investments

The Company has both debt and equity investments in unconsolidated entities.  When events occur that may cause an investment to be impaired, the Company performs both a qualitative and quantitative review of that investment and when necessary performs an impairment analysis.  An impairment analysis of notes receivable usually involves the comparison of the investment’s estimated free cash flows to the stated terms of the note, or in certain cases for notes that are collateral dependent, a comparison of the collateral’s fair value, to the carrying amount of the note.  An impairment analysis of equity investments involves comparison of the investment’s estimated fair value to its carrying amount and an assessment of whether any decline in fair value is “other than temporary.”   Fair value is estimated using market comparisons, appraisals, and/or discounted cash flow analyses.  Calculating free cash flows and fair value using the above methods is subjective and requires judgment concerning growth assumptions, longevity of cash flows, and discount rates (for fair value calculations), among others.

The recent economic recession impacted the value of commercial real estate investments within the Other Businesses nonutility portfolio.  During 2008, the Company assessed its commercial real estate investments for impairment using the methods described above and identified the need to reduce their carrying values.  The impairment charge recorded in 2008 totaled $10.0 million.

Significant assumptions impacting these analyses were holding periods, net operating income and capitalization rates, which increased during 2008.  Related to capitalization rates, the Company used a 9.75 cap rate in its valuation of a suburban Chicago commercial real estate holding owned by the Company that is currently vacant and a 9.25 cap rate in its valuation of leased commercial real estate located in Charlotte, NC and Birmingham, AL that serve as collateral for a note receivable.  A 50 basis point increase in those cap rates would have increased the impairment charge by $2.5 million.  The Company examined these investments for impairment throughout 2010 and 2009, noting that current capitalization rates and other assumptions indicate no further impairment. However, the commercial real estate markets re main soft and uncertain.  Should current market conditions continue or worsen, additional impairments could result and actual realized values could differ from the current carrying values.

Goodwill & Intangible Assets

The Company performs an annual impairment analysis of its goodwill, most of which resides in the Gas Utility Services operating segment, at the beginning of each year, and more frequently if events or circumstances indicate that an impairment loss may have been incurred.  Impairment tests are performed at the reporting unit level.  The Company has determined its Gas Utility Services operating segment as identified in Note 19 to the consolidated financial statements to be the level at which impairment is tested as its reporting units are similar.  Nonutility Group reporting units are generally defined as the operating companies that aggregate segments.  An impairment test requires that a reporting unit’s fair value be estimated.  The Company used a discounted cash flow model and other market based information to estimate the fair value of its Gas Utility Services operating segment, and that estimated fair value was compared to its carrying amount, including goodwill.  The estimated fair value has been in excess of the carrying amount in each of the last three years and therefore resulted in no impairment.  Goodwill related to the Nonutility Group is also tested using market comparable data, if readily available, or a discounted cash flow model.

Estimating fair value using a discounted cash flow model is subjective and requires significant judgment in applying a discount rate, growth assumptions, company expense allocations, and longevity of cash flows.  A 100 basis point increase in the discount rate utilized to calculate the Gas Utility Services segment’s fair value also would have resulted in no impairment charge.

The Company also annually tests non-amortizing intangible assets for impairment and amortizing intangible assets are tested on an event and circumstance basis.  During the last three years, these tests yielded no impairment charges.

Pension & Other Postretirement Obligations

The Company estimates the expected return on plan assets, discount rate, rate of compensation increase, and future health care costs, among other inputs, and obtains actuarial estimates to assess the future potential liability and funding requirements of the Company's pension and postretirement plans.  The Company used the following weighted average assumptions to develop 2010 periodic benefit cost:  a discount rate of 6.0 percent, an expected return on plan assets of 8.0 percent, a rate of compensation increase of 3.5 percent, and an inflation assumption of 3.0 percent.  Due to the impacts of the recession, these assumptions were each lowered 25 basis points from assumptions used in 2009.  To estimate 2011 costs, the discount rate, expected return on plan assets, rate of compensation increase, and inflation assumption were 5.5 percent, 8.0 percent, 3.5 percent, and 3.0 percent respectively, reflecting the lower interest rate environment.  Management currently estimates a pension and postretirement cost of approximately $13 million in 2011, compared to approximately $14 million in 2010, $15 million in 2009, and $11 million in 2008.  Future changes in health care costs, work force demographics, interest rates, asset values or plan changes could significantly affect the estimated cost of these future benefits.

Management estimates that a 50 basis point decrease in the discount rate used to estimate retirement costs generally increases periodic benefit cost by approximately $1.5 million to $2.0 million.

Unbilled Revenues

To more closely match revenues and expenses, the Company records revenues for all gas and electricity delivered to customers but not billed at the end of the accounting period.  The Company uses actual units billed during the month to allocate unbilled units by customer class.  Those allocated units are multiplied by rates in effect during the month to calculate unbilled revenue at balance sheet dates.

Regulation

At each reporting date, the Company reviews current regulatory trends in the markets in which it operates.  This review involves judgment and is critical in assessing the recoverability of regulatory assets as well as the ability to continue to account for its activities based on the criteria set forth in FASB guidance related to accounting for the effects of certain types of regulation.  Based on the Company’s current review, it believes its regulatory assets are probable of recovery.  If all or part of the Company's operations cease to meet the criteria, a write off of related regulatory assets and liabilities could be required.  In addition, the Company would be required to determine any impairment to the carrying value of its utility plant and other regulated assets and liabilities. & #160;In the unlikely event of a change in the current regulatory environment, such write-offs and impairment charges could be significant.

Financial Condition

Within Vectren’s consolidated group, Utility Holdings primarily funds the short-term and long-term financing needs of the Utility Group operations, and Vectren Capital Corp (Vectren Capital) funds short-term and long-term financing needs of the Nonutility Group and corporate operations.  Vectren Corporation guarantees Vectren Capital’s debt, but does not guarantee Utility Holdings’ debt.  Vectren Capital’s long-term and short-term obligations outstanding at December 31, 2010 approximated $410 million and $71 million, respectively.  Utility Holdings’ outstanding long-term and short-term borrowing arrangements are jointly and severally guaranteed by Indiana Gas, SIGECO, and VEDO.  Utility Holdings’ long-term debt, including current maturities, and short-term obligat ions outstanding at December 31, 2010 approximated $919 million and $47 million, respectively.  Additionally, prior to Utility Holdings’ formation, Indiana Gas and SIGECO funded their operations separately, and therefore, have long-term debt outstanding funded solely by their operations.  SIGECO will also occasionally issue tax exempt debt to fund qualifying pollution control capital expenditures.

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

The credit ratings of the senior unsecured debt of Utility Holdings and Indiana Gas, at December 31, 2010, are A-/A3 as rated by Standard and Poor's Ratings Services (Standard and Poor’s) and Moody’s Investors Service (Moody’s), respectively.  The credit ratings on SIGECO's secured debt are A/A1.  Utility Holdings’ commercial paper has a credit rating of A-2/P-2.  In September of 2010, Moody’s increased its rating on Utility Holdings’ and Indiana Gas’ senior unsecured debt from Baa1 to A3 and on SIGECO’s secured debt from A2 to A1.  The current outlook of both Moody’s and Standard and Poor’s is stable.  A security rating is not a recommendation to buy, sell, or hold securities.  The rating is subject to revision or withd rawal at any time, and each rating should be evaluated independently of any other rating.  Standard and Poor’s and Moody’s lowest level investment grade rating is BBB- and Baa3, respectively.

The Company’s consolidated equity capitalization objective is 45-55 percent of long-term capitalization.  This objective may have varied, and will vary, depending on particular business opportunities, capital spending requirements, execution of long-term financing plans, and seasonal factors that affect the Company’s operations.  The Company’s equity component was 46 percent of long-term capitalization at both December 31, 2010 and 2009.  Long-term capitalization includes long-term debt, including current maturities and debt subject to tender, as well as common shareholders’ equity.

As of December 31, 2010, the Company was in compliance with all financial covenants.

Available Liquidity in Current Credit Conditions

The Company’s A-/A3 investment grade credit ratings have allowed it to access the capital markets as needed.  Over the last three years, the Company has significantly enhanced its short-term borrowing capacity with the completion of several long-term financing transactions including issuances of long-term debt and the settlement of an equity forward contract.  The Company anticipates funding future capital expenditures and dividends through internally generated funds.  In addition, available liquidity is expected to be enhanced by cash resulting from the extension of bonus depreciation legislation.  Therefore, management expects that only a portion of the Utility Holdings’ $250 million debt redemption due in December 2011 needs to be refinanced with new long-term debt.  The Com pany currently foresees no issues with accessing the capital markets to execute the refinancing.

Long-term debt transactions completed in 2010 and 2009 include issuances by Vectren Capital totaling $275 million and a $100 million issuance by Vectren Utility Holdings.  SIGECO also remarketed $41.3 million of long-term debt and completed a $22.3 million tax-exempt first mortgage bond issuance.  These transactions, along with financing transactions completed in 2008, are more fully described below.  (See Financing Cash Flow.)

Consolidated Short-Term Borrowing Arrangements

At December 31, 2010, the Company has $600 million of short-term borrowing capacity, including $350 million for the Utility Group and $250 million for the wholly owned Nonutility Group and corporate operations.  As reduced by borrowings currently outstanding, approximately $303 million was available for the Utility Group operations and approximately $179 million was available for the wholly owned Nonutility Group and corporate operations.  These facilities are used to supplement working capital needs and also to fund capital investments and debt redemptions until financed on a long-term basis.

Both Vectren Capital’s and Utility Holdings’ short-term credit facilities were renewed on September 30, 2010 and are available through September 2013.  During the renewal process, the Company lowered the level of capacity due to the reduced requirements for short-term borrowings.  The level of short-term borrowings is significantly lower compared to historical trends due to the recently completed long-term financing transactions, the impacts of additional bonus depreciation and other tax strategies, lower inventory values due to lower natural gas prices, and lower natural gas inventory volumes due to exiting the merchant function in Ohio.  The short-term borrowing facilities were lowered from $515 million to $350 million for the Utility Group and from $255 million to $250 million for the Nonutilit y Group.  In addition, the Nonutility Group had a $120 million one year credit facility that expired in 2009 and was not renewed.  The Company has historically funded the short-term borrowing needs of Utility Holdings’ operations through the commercial paper market and expects to use the Utility Holdings short-term borrowing facility in instances where the commercial paper market is not efficient.  Following is certain information regarding these short-term borrowing arrangements.

                           
     
Utility Group Borrowings
  
Nonutility Group Borrowings
(In millions)
  
2010
  
2009
  
2008
  
2010
  
2009
  
2008
Year End
                        
 
Balance Outstanding
  
 $   47.0
  
 $   16.4
  
 $ 191.9
  
 $   71.3
  
 $ 197.1
  
 $ 327.5
 
Weighted Average Interest Rate
  
0.41%
  
0.25%
  
2.68%
  
2.01%
  
0.60%
  
1.54%
Annual Average
                        
 
Balance Outstanding
  
 $   14.0
  
 $   29.2
  
 $ 178.3
  
 $ 143.2
  
 $ 151.8
  
 $ 208.8
 
Weighted Average Interest Rate
  
0.40%
  
1.28%
  
3.71%
  
0.93%
  
0.78%
  
3.19%
Maximum Month End Balance Outstanding
  
 $   47.0
  
 $ 151.1
  
 $ 338.0
  
 $ 174.6
  
 $ 256.5
  
 $ 327.5
 
In 2008, the Company’s access to longer term commercial paper was significantly reduced as a result of the turmoil and volatility in the financial markets.  As a result, the Company met short-term financing needs through a combination of A-2/P-2 commercial paper issuances and draws on Utility Holdings’ back-up credit facility.  At December 31, 2008, borrowings outstanding were comprised of $100.4 million of bank loans at a weighted average interest rate of 1.56% and $91.5 million of commercial paper at a weighted average interest rate of 3.87%.  The average annual balance outstanding in 2008 was comprised of $28.1 million of bank loans at a weighted average interest rate of 3.42% and $150.2 million of commercial paper at a weighted average interest rate of 3.76%.  Throughout 2010 and most of 2009, the Company has placed commercial paper without any significant issues and only had to borrow from its backup credit facility in early 2009 on a limited basis.

Due to the seasonal nature of the Company’s business peak borrowing typically occurs during the fourth quarter and therefore the year end balance is typically higher than the average throughout the year.  However, the 2010 fourth quarter was impacted by the December issuance of Vectren Capital long-term debt.  Short-term borrowing metrics applicable to the fourth quarter of 2010 and 2009 follows.
                   
     
Utility Group Borrowings
  
Nonutility Group Borrowings
(In millions)
  
2010
  
2009
  
2010
  
2009
Quarterly  Average- December 31
                
 
Balance Outstanding
  
 $       41.4
  
 $          7.4
  
 $      118.0
  
 $      186.9
 
Weighted Average Interest Rate
  
0.40%
  
0.26%
  
2.04%
  
0.61%
Maximum Month End Balance Outstanding
  
 $       47.0
  
 $       16.4
  
 $      135.8
  
 $      205.5
 
-46-
ProLiance Short-Term Borrowing Arrangements

ProLiance, a nonutility energy marketing affiliate of the Company, has separate borrowing capacity available through a syndicated credit facility.  Subject to compliance with certain financial covenants, the facility allows for $325 million of capacity, as adjusted for letters of credit and current inventory and receivable balances.  At December 31, 2010, ProLiance was not in compliance with one financial covenant due to low operating results.  ProLiance received a quarterly waiver related to that covenant through March 31, 2011.  The credit facility expires on June 3, 2011 and will require renegotiation as it is integral to ProLiance’s seasonal liquidity needs.  As of December 31, 2010, borrowings of $49 million were outstanding.  The current facility is not guaranteed by Vectren or Citizens. 
 
New Share Issues

The Company may periodically issue new common shares to satisfy the dividend reinvestment plan, stock option plan and other employee benefit plan requirements.  New issuances added additional liquidity of $14.0 million in 2010, $5.8 million in 2009, and $1.2 million in 2008.

Potential Uses of Liquidity

Pension & Postretirement Funding Obligations

As of December 31, 2010, asset values of the Company’s qualified pension plans were approximately 83 percent of the projected benefit obligation.  Management currently estimates contributing $35 million to qualified pension plans in 2011. Of that amount, approximately $25 million is made available by bonus depreciation opportunities.  Contributions in 2012 and beyond are dependent on a variety of factors, including the Company’s progress toward attaining its long-term goal of being fully funded related to the plans’ accrued benefit obligations and the available sources of cash to fund such additional contributions.

Corporate Guarantees

The Company issues corporate guarantees to certain vendors and customers of its wholly owned subsidiaries and unconsolidated affiliates.  These guarantees do not represent incremental consolidated obligations; rather, they represent parental guarantees of subsidiary and unconsolidated affiliate obligations in order to allow those subsidiaries and affiliates the flexibility to conduct business without posting other forms of collateral.  At December 31, 2010, corporate issued guarantees support a maximum of $25 million of ESG’s performance contracting commitments and warranty obligations and $29 million of other project guarantees described below.  In addition, the Company has approximately $75 million of other guarantees outstanding supporting other consolidated subsidiary operations, of which $51 millio n support the operations of Vectren Source, a wholly owned nonutility retail gas marketer and $17 million represent letters of credit supporting other nonutility operations.  Guarantees issued and outstanding on behalf of unconsolidated affiliates approximated $3 million at December 31, 2010. These guarantees relate primarily to arrangements between ProLiance and various natural gas pipeline operators. The Company has not been called upon to satisfy any obligations pursuant to these parental guarantees and has accrued no significant liabilities related to these guarantees.

Performance Guarantees & Product Warranties

In the normal course of business, ESG, Miller, and other wholly owned subsidiaries issue performance bonds or other forms of assurance that commit them to timely install infrastructure, operate facilities, pay vendors or subcontractors, and/or support warranty obligations.  Based on a history of meeting performance obligations and installed products operating effectively, no significant liability or cost has been recognized during the periods presented.

Specific to ESG, in its role as a general contractor in the performance contracting industry, at December 31, 2010, there are 70 open surety bonds supporting future performance. The average face amount of these bonds is $4.2 million, and the largest obligation has a face amount of $30.4 million.  The maximum exposure of these obligations is less than these amounts for several factors, including the level of work already completed.  At December 31, 2010, over 57 percent of work was completed on projects with open surety bonds.  A significant portion of these commitments will be fulfilled within one year.  In instances where ESG operates facilities, project guarantees extend over a longer period.  In addition to its performance obligations, ESG also warrants the functionality of certain inst alled infrastructure generally for one year and the associated energy savings over a specified number of years.
 
Other Letters of Credit

As of December 31, 2010, Utility Holdings has letters of credit outstanding in support of two SIGECO tax exempt adjustable rate first mortgage bonds totaling $41.7 million.  In the unlikely event the letters of credit were called, the Company could settle with the financial institutions supporting these letters of credit with general assets or by drawing from the renewed credit line that expires in September of 2013.  Due to the long-term nature of the credit agreement, such debt is classified as long-term at December 31, 2010.

Planned Capital Expenditures & Investments

During 2010 capital expenditures and other investments approximated $280 million, of which $230 million related to Utility Group expenditures.  This compares to 2009 and 2008 where in each year consolidated investments exceeded $400 million with over $300 million attributed to the Utility Group.  Planned Utility Group capital expenditures, including contractual purchase commitments, for the five-year period 2011 – 2015 are expected to be more consistent with expenditures made in 2010 and total (in millions):  $244, $231, $243, $245, and $243, respectively.

Planned Nonutility Group capital expenditures for mine development and recurring infrastructure investments, including contractual purchase commitments, for the five-year period 2011 – 2015 are expected to total (in millions):  $68, $74, $47, $48, and $47, respectively.  In addition, the Company may expand its Infrastructure Services business through acquisitions and/or make investments in renewable energy projects, among other growth strategies.  The timing and amount of such investments depends on a variety of factors, including the availability of acquisition targets, energy demand, and forecasted liquidity.   
 
Contractual Obligations

The following is a summary of contractual obligations at December 31, 2010:
                         
(In millions)
Total
  
2011
  
2012
  
2013
  
2014
  
2015
Thereafter
                         
Long-term debt (1)(2)
 $  1,715.9
  
 $ 250.7
  
 $    60.0
  
 $  105.0
  
 $    30.0
  
 $  179.8
 $  1,090.4
Short-term debt
         118.3
  
     118.3
  
            -
  
            -
  
            -
  
            -
                -
Long-term debt interest commitments
     1,134.0
  
       99.2
  
       82.3
  
       77.8
  
        73.1
  
       71.9
         729.7
Nonutility transportation/storage commitments
           17.9
  
         4.2
  
         4.1
  
          3.8
  
          1.8
  
          0.8
             3.2
Nonutility commodity purchase commitments
           16.1
  
       11.8
  
         2.9
  
          1.4
  
            -
  
            -
                -
Plant purchase commitments
           15.8
  
       15.8
  
            -
  
            -
  
            -
  
            -
                -
Operating leases
           10.4
  
         4.1
  
         2.7
  
          1.8
  
          1.2
  
          0.5
             0.1
  Total (3)
 $  3,028.4
  
 $ 504.1
  
 $ 152.0
  
 $  189.8
  
 $  106.1
  
 $  253.0
 $  1,823.4
 
(1)  
Certain long-term debt issues contain put and call provisions that can be exercised on various dates before maturity.  These provisions allow holders the one-time option to put debt back to the Company at face value or the Company to call debt at face value or at a premium.  Long-term debt subject to tender during the years following 2010 (in millions) is $30.0 in 2011, zero in 2012 and thereafter.
(2)  
The Company currently anticipates that only a portion of the Utility Holdings $250 million maturity due in December 2011 will require refinancing.  The $60 million of debt due in 2012 was issued by Vectren Capital.
(3)  
The Company has other long-term liabilities that total approximately $220 million.  This amount is comprised of the following:  pension obligations $60 million, postretirement obligations $73 million, deferred compensation and share-based compensation obligations $28 million, asset retirement obligations $38 million, investment tax credits $5 million, environmental remediation obligations $6 million, and other obligations including unrecognized tax benefits totaling $11 million.  Based on the nature of these items their expected settlement dates cannot be estimated.

The Company’s regulated utilities have both firm and non-firm commitments to purchase natural gas, electricity, and coal as well as certain transportation and storage rights.  Costs arising from these commitments, while significant, are pass-through costs, generally collected dollar-for-dollar from retail customers through regulator-approved cost recovery mechanisms.  Because of the pass through nature of these costs, they have not been included in the listing of contractual obligations.

Comparison of Historical Sources & Uses of Liquidity

Operating Cash Flow

The Company's primary source of liquidity to fund working capital requirements has been cash generated from operations, which totaled $384.8 million in 2010, compared to $449.6 million in 2009 and $423.2 million in 2008.

The $64.8 million decrease in operating cash flow in 2010 compared to 2009 is primarily due to much a greater level of cash generated from working capital in 2009 offset by a special dividend from ProLiance totaling approximately $30 million and higher net income and non-cash charges in 2010.

In 2009, operating cash flows increased $26.4 million compared to 2008 due to increased cash generated from consolidated companies.  This is evident from a $51.7 million year over year increase in net income before the impacts of depreciation, deferred taxes, equity in earnings of unconsolidated affiliates and other non-cash charges.  Due principally to lower gas costs, changes in working capital generated $34.2 million of additional cash flow year over year.  These increases were offset by additional cash uses associated with noncurrent assets and liabilities.  This increased usage is primarily related to a $23.4 million increase in pension and other retirement plan contributions.

Tax payments in the periods presented were favorably impacted by federal legislation extending bonus depreciation and a change in the tax method for recognizing repair and maintenance activities.  Federal legislation extending bonus depreciation continues at 100 percent of qualifying capital expenditures in 2011 and 50 percent in 2012.  The Company estimates a significant portion of planned capital expenditures in 2011 and 2012 will qualify for this bonus treatment.

Financing Cash Flow

During 2010, 2009 and 2008, net cash flow associated with financing activities is reflective of management’s ongoing effort to rely less on short-term borrowing arrangements.  Over the last three years, the Company’s operating cash flow funded over 80 percent of capital expenditures and dividends in those years, including 100 percent funded in 2010.  Recently completed long-term financing transactions have allowed for the repayment of over $400 million in short term borrowings over the past two years, including over $300 million repaid in 2009.  In addition, these long-term financing transactions have financed other capital expenditures on a long-term basis.  During the first quarter of 2008, the Company mitigated its exposure to auction rate debt markets.  These transactions a re more fully described below.

Vectren Capital Corp. 2010 Debt Issuance
On December 15, 2010, the Company and Vectren Capital executed a private placement Note Purchase Agreement pursuant to which various institutional investors agreed to purchase the following tranches of notes from Vectren Capital:  (i) $75 million 3.48% Senior Notes, Series A due 2017, and (ii) $50 million 4.53% Senior Notes, Series B due 2025.  These Senior Notes are unconditionally guaranteed by Vectren.  The proceeds from the issuance replaced $48 million debt maturities due in December 2010 and permanently financed some nonutility investments originally financed with short-term borrowings.  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 $124.2 million.   These notes contain customary representations, warranties and covenants, including a leverage covenant consistent with leverage covenants contained in other Vectren Capital borrowing arrangements.

Vectren Capital Corp. 2009 Debt Issuance
On March 11, 2009, Vectren and Vectren Capital executed 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 other Vectren Capital borrowing arrangements.  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.
 
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 other Ut ility Holdings’ borrowing arrangements.

SIGECO 2009 Debt Issuance
On August 19, 2009 SIGECO also completed a $22.3 million tax-exempt first mortgage bond issuance at an interest rate of 5.4 percent that is fixed through maturity.  The bonds mature in 2040.  The proceeds from the sale of the bonds, net of issuance costs, totaled approximately $21.3 million.

Vectren Common Stock Issuance
In February 2007, the Company sold 4.6 million authorized but previously unissued shares of its common stock to a group of underwriters in an SEC-registered primary offering at a price of $28.33 per share.  The transaction generated proceeds, net of underwriting discounts and commissions, of approximately $125.7 million.  The Company executed an equity forward sale agreement (equity forward) in connection with the offering, and therefore, did not receive proceeds at the time of the equity offering.  The equity forward allowed the Company to price an offering under market conditions existing at that time, and to better match the receipt of the offering proceeds and the associated share dilution with the implementation of regulatory initiatives.

On June 27, 2008, the Company physically settled the equity forward by delivering the 4.6 million shares, receiving proceeds of approximately $124.9 million.  The slight difference between the proceeds generated by the public offering and those received by the Company were due to adjustments defined in the equity forward agreement including:  1) daily increases in the forward sale price based on a floating interest factor equal to the federal funds rate, less a 35 basis point fixed spread, and 2) structured quarterly decreases to the forward sale price that align with expected Company dividend payments. 

Vectren transferred the proceeds to Utility Holdings, and Utility Holdings used the proceeds to repay short-term debt obligations incurred primarily to fund its capital expenditure program.  The proceeds received were recorded as an increase to Common Stock in Common Shareholders’ Equity and are presented in the Statement of Cash Flows as a financing activity.

Utility Holdings 2008 Debt Issuance
In March 2008, Utility Holdings issued $125 million in 6.25 percent senior unsecured notes due April 1, 2039 (2039 Notes) at par.  The 2039 Notes are guaranteed by Utility Holdings’ three public utilities:  SIGECO, Indiana Gas, and VEDO.  These guarantees are full and unconditional and joint and several.  The 2039 Notes have no sinking fund requirements and interest payments are due monthly.  The notes may be called by Utility Holdings, in whole or in part, at any time on or after April 1, 2013, at 100 percent of principal amount plus accrued interest.  During 2007, Utility Holdings entered into several interest rate hedges with an $80 million notional amount.  Upon issuance of the notes, these instruments were settled resulting in the payment of approximately $9. 6 million, which was recorded as a Regulatory asset pursuant to existing regulatory orders.  The value paid is being amortized as an increase to interest expense over the life of the issue.  The proceeds from the sale of the 2039 Notes less settlement of the hedging arrangements and payments of issuance costs amounted to approximately $111.1 million.

Auction Rate Securities
In February 2008, SIGECO provided notice to the current holders of approximately $103 million of tax-exempt auction rate mode long-term debt of its plans to convert that debt from its current auction rate mode into a daily interest rate mode.  In March 2008, the debt was tendered at 100 percent of the principal amount plus accrued interest.  During March 2008, SIGECO remarketed approximately $61.8 million of these instruments at interest rates that are fixed to maturity, receiving proceeds, net of issuance costs, of approximately $60.0 million.  The terms are $22.6 million at 5.15 percent due in 2023, $22.2 million at 5.35 percent due in 2030 and $17.0 million at 5.45 percent due in 2041.

On March 26, 2009, SIGECO remarketed the remaining $41.3 million of these obligations, 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.  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.
 
Long-Term Debt Puts
Certain long-term debt issues contain put and call provisions that can be exercised on various dates before maturity.  Other than certain instruments that can be put to the company upon the death of the holder (death puts), these put or call provisions are not triggered by specific events, but are based upon dates stated in the note agreements.  During 2010, 2009 and 2008, the Company repaid approximately $1.8 million, $3.0 million, and $1.6 million, respectively, related to death puts.  Debt which may be put to the Company for reasons other than a death during the years following 2010 (in millions) is $30.0 in 2011, zero in 2012 and thereafter.  Investors had the one-time option to put $10 million in May 2010; however, no notice was received during the notification period and such debt is classifie d as long-term at December 31, 2010. Debt that can be put to the Company within one year or that is supported by a credit facility that expires within one year is classified in current liabilities in Long-term debt subject to tender. 

Investing Cash Flow

Cash flow required for investing activities was $269.0 million in 2010, $431.1 million in 2009, and $402.4 million in 2008.  Capital expenditures are the primary component of investing activities and totaled $277.2 million in 2010, $432.0 million in 2009 compared to $391.0 million in 2008.  The decrease in capital expenditures in 2010 compared to 2009 reflects the roughly $20 million spent in 2009 associated with the January 2009 ice storm restoration projects and approximately $55 million in lower other utility capital spending as well as approximately $90 million in lower expenditures relating to Coal Mining, primarily Oaktown mine development costs. The increase in capital expenditures in 2009 compared to 2008 reflects increased expenditures for coal mine development and the ice storm.  Other investments i n 2009 and 2008 include minor acquisitions by Miller, among other items.

Forward-Looking Information

A “safe harbor” for forward-looking statements is provided by the Private Securities Litigation Reform Act of 1995 (Reform Act of 1995).  The Reform Act of 1995 was adopted to encourage such forward-looking statements without the threat of litigation, provided those statements are identified as forward-looking and are accompanied by meaningful cautionary statements identifying important factors that could cause the actual results to differ materially from those projected in the statement.  Certain matters described in Management’s Discussion and Analysis of Results of Operations and Financial Condition are forward-looking statements.  Such statements are based on management’s beliefs, as well as assumptions made by and information currently available to management.& #160; When used in this filing, the words “believe”, “anticipate”, “endeavor”, “estimate”, “expect”, “objective”, “projection”, “forecast”, “goal”, “likely”, and similar expressions are intended to identify forward-looking statements.  In addition to any assumptions and other factors referred to specifically in connection with such forward-looking statements, factors that could cause the Company’s actual results to differ materially from those contemplated in any forward-looking statements include, among others, the following:

·   
Factors affecting utility operations such as unusual weather conditions; catastrophic weather-related damage; unusual maintenance or repairs; unanticipated changes to fossil fuel costs; unanticipated changes to gas transportation and storage costs, or availability due to higher demand, shortages, transportation problems or other developments; environmental or pipeline incidents; transmission or distribution incidents; unanticipated changes to electric energy supply costs, or availability due to demand, shortages, transmission problems or other developments; or electric transmission or gas pipeline system constraints.
·  
Catastrophic events such as fires, earthquakes, explosions, floods, ice storms, tornados, terrorist acts or other similar occurrences could adversely affect Vectren’s facilities, operations, financial condition and results of operations.
·  
Increased competition in the energy industry, including the effects of industry restructuring and unbundling.
·  
Regulatory factors such as unanticipated changes in rate-setting policies or procedures, recovery of investments and costs made under traditional regulation, and the frequency and timing of rate increases.
·  
Financial, regulatory or accounting principles or policies imposed by the Financial Accounting Standards Board; the Securities and Exchange Commission; the Federal Energy Regulatory Commission; state public utility commissions; state entities which regulate electric and natural gas transmission and distribution, natural gas gathering and processing, electric power supply; and similar entities with regulatory oversight.
·  
Economic conditions including the effects of an economic downturn, inflation rates, commodity prices, and monetary fluctuations.
·  
Economic conditions surrounding the current economic uncertainty,  including significantly lower levels of economic activity; uncertainty regarding energy prices and the capital and commodity markets; volatile changes in the demand for natural gas, electricity, coal, and other nonutility products and services; impacts on both gas and electric large customers; lower residential and commercial customer counts; higher operating expenses; and further reductions in the value of certain nonutility real estate and other legacy investments.
 
·  
Volatile natural gas and coal commodity prices and the potential impact on customer consumption, uncollectible accounts expense, unaccounted for gas and interest expense.
·  
Changing market conditions and a variety of other factors associated with physical energy and financial trading activities including, but not limited to, price, basis, credit, liquidity, volatility, capacity, interest rate, and warranty risks.
·  
Direct or indirect effects on the Company’s business, financial condition, liquidity and results of operations resulting from changes in credit ratings, changes in interest rates, and/or changes in market perceptions of the utility industry and other energy-related industries.
·  
The performance of projects undertaken by the Company’s nonutility businesses and the success of efforts to invest in and develop new opportunities, including but not limited to, the Company’s infrastructure, energy services, coal mining, and energy marketing strategies.
·  
Factors affecting coal mining operations including  MSHA guidelines and interpretations of those guidelines, as well as additional mine regulations and more frequent and broader inspections that could result from the recent  mining incidents at coal mines of other companies; geologic, equipment, and operational risks; the ability to execute and negotiate new sales contracts and resolve contract interpretations; volatile coal market prices and demand;  supplier and contract miner performance; the availability of key equipment, contract miners and commodities; availability of transportation; and the ability to access/replace coal reserves .
·  
Employee or contractor workforce factors including changes in key executives, collective bargaining agreements with union employees, aging workforce issues, work stoppages, or pandemic illness.
·  
Legal and regulatory delays and other obstacles associated with mergers, acquisitions and investments in joint ventures.
·  
Costs, fines, penalties and other effects of legal and administrative proceedings, settlements, investigations, claims, including, but not limited to, such matters involving compliance with state and federal laws and interpretations of these laws.
·  
Changes in or additions to  federal, state or local legislative requirements, such as changes in or additions to tax laws or rates, environmental laws, including laws governing greenhouse gases, mandates of sources of renewable energy, and other regulations.

The Company undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of changes in actual results, changes in assumptions, or other factors affecting such statements.

ITEM 7A.  QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK

The Company is exposed to various business risks associated with commodity prices, interest rates, and counter-party credit.  These financial exposures are monitored and managed by the Company as an integral part of its overall risk management program.  The Company’s risk management program includes, among other things, the use of derivatives.  The Company may also execute derivative contracts in the normal course of operations while buying and selling commodities to be used in operations and optimizing its generation assets.

The Company has in place a risk management committee that consists of senior management as well as financial and operational management.  The committee is actively involved in identifying risks as well as reviewing and authorizing risk mitigation strategies.

Commodity Price Risk

Regulated Operations

The Company’s regulated operations have limited exposure to commodity price risk for transactions involving purchases and sales of natural gas, coal and purchased power for the benefit of retail customers due to current state regulations, which subject to compliance with those regulations, allow for recovery of the cost of such purchases through natural gas and fuel cost adjustment mechanisms.  Constructive regulatory orders, such as those authorizing lost margin recovery, other innovative rate designs, and recovery of unaccounted for gas and other gas related expenses, also mitigate the effect volatile gas costs may have on the Company’s financial condition.  Although Vectren’s regulated operations are exposed to limited commodity price risk, volatile natural gas prices have other effects on working capital requirements, interest costs, and some level of price-sensitivity in volumes sold or delivered.

Wholesale Power Marketing

The Company’s wholesale power marketing activities undertake strategies to optimize electric generating capacity beyond that needed for native load.  In recent years, the primary strategy involves the sale of excess generation into the MISO Day Ahead and Real-time markets.  As part of these strategies, the Company may also from time to time execute energy contracts that commit the Company to purchase and sell electricity in future periods.  Commodity price risk results from forward positions that commit the Company to deliver electricity.  The Company mitigates price risk exposure with planned unutilized generation capability.  The Company accounts for any energy contracts that are derivatives at fair value with the offset marked to market through earnings.  No market sensi tive derivative positions were outstanding on December 31, 2010 and 2009.

For retail sales of electricity, the Company receives the majority of its NOx and SO2 allowances at zero cost through an allocation process.  Based on arrangements with regulators, wholesale operations can purchase allowances from retail operations at current market values, the value of which is distributed back to retail customers through a MISO cost recovery tracking mechanism.  Wholesale operations are therefore at risk for the cost of allowances, which for the recent past have been volatile.  The Company manages this risk by purchasing allowances from retail operations as needed and occasionally from other third parties in advance of usage.  In the past, the Company also used derivative financial instruments to hedge this risk, but no such derivative instruments were outstanding at December 31, 2010 or 2009.

Other Operations

Other commodity-related operations are exposed to commodity price risk associated with natural gas and coal.  Other commodity-related operations include Vectren Source, a nonutility retail gas marketer, coal mining operations, and the operations at ProLiance.  Open positions in terms of price, volume, and specified delivery points may occur and are managed using methods described below with frequent management reporting.

These subsidiaries, as well as ProLiance, purchase and sell natural gas and coal to meet customer demands.  Forward contracts, and occasionally option contracts, commit them to purchase and sell commodities in the future.  Price risk from forward positions is mitigated using stored inventory and offsetting forward purchase contracts.  Price risk also results from forward contracts to purchase commodities to fulfill forecasted non-regulated sales of natural gas and coal that may or may not occur.  Related to Vectren Source and coal mining operations, most contracts are expected to be settled by physical receipt or delivery of the commodity.  A small portion of contracts that are derivatives are hedges of forecasted transactions.  ProLiance more frequently uses financial instrument s that are derivatives to hedge its market exposures that arise from gas in storage, imbalances, and fixed-price forward purchase and sale contracts.

Interest Rate Risk

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 limits this risk by allowing only an annual average of 15 percent to 25 percent of its total debt to be exposed to variable rate volatility.  However, this targeted range may not always be attained during the seasonal increases in short-term borrowings.  To manage this exposure, the Company may use derivative financial instruments.

Market risk is estimated as the potential impact resulting from fluctuations in interest rates on adjustable rate borrowing arrangements exposed to short-term interest rate volatility.  During 2010 and 2009, the weighted average combined borrowings under these arrangements approximated $198 million and $211 million, respectively.  At December 31, 2010 and 2009, combined borrowings under these arrangements were $160 million and $255 million, respectively.  Based upon average borrowing rates under these facilities during the years ended December 31, 2010 and 2009, an increase of 100 basis points (one percentage point) in the rates would have increased interest expense by approximately $2 million in each year.

Other Risks

By using financial instruments to manage risk, the Company, as well as ProLiance, creates exposure to counter-party credit risk and market risk.  The Company manages exposure to counter-party credit risk by entering into contracts with companies that can be reasonably expected to fully perform under the terms of the contract.  Counter-party credit risk is monitored regularly and positions are adjusted appropriately to manage risk.  Further, tools such as netting arrangements and requests for collateral are also used to manage credit risk.  Market risk is the adverse effect on the value of a financial instrument that results from a change in commodity prices or interest rates.  The Company attempts to manage exposure to market risk associated with commodity contracts and interest rates by e stablishing parameters and monitoring those parameters that limit the types and degree of market risk that may be undertaken.

The Company’s customer receivables from gas and electric sales and gas transportation services are primarily derived from residential, commercial, and industrial customers located in Indiana and west central Ohio.  The Company manages credit risk associated with its receivables by continually reviewing creditworthiness and requests cash deposits or refunds cash deposits based on that review.  Credit risk associated with certain investments is also managed by a review of creditworthiness and receipt of collateral.  In addition, credit risk is mitigated by regulatory orders that allow recovery of all uncollectible accounts expense in Ohio and the gas cost portion of uncollectible accounts expense in Indiana based on historical experience.

ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

MANAGEMENT’S RESPONSIBILITY FOR THE FINANCIAL STATEMENTS

Vectren Corporation’s management is responsible for establishing and maintaining adequate internal control over financial reporting.  Those control procedures underlie the preparation of the consolidated balance sheets, statements of income, cash flows, and common shareholders’ equity, and related footnotes contained herein.

These consolidated financial statements were prepared in conformity with accounting principles generally accepted in the United States and follow accounting policies and principles applicable to regulated public utilities.  The integrity and objectivity of these consolidated financial statements, including required estimates and judgments, is the responsibility of management.

These consolidated financial statements are also subject to an evaluation of internal control over financial reporting conducted under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer.  Based on that evaluation, conducted under the framework in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, the Company concluded that its internal control over financial reporting was effective as of December 31, 2010.  Management certified this in its Sarbanes Oxley Section 302 certifications, which are attached as exhibits to this 2010 Form 10-K.
 
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of Vectren Corporation:

We have audited the accompanying consolidated balance sheets of Vectren Corporation and subsidiaries (the “Company”) as of December 31, 2010 and 2009, and the related consolidated statements of income, common shareholders’ equity and cash flows for each of the three years in the period ended December 31, 2010. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Vectren Corporation and subsidiaries as of December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2010, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 17, 2011 expressed an unqualified opinion on the Company’s internal control over financial reporting.


/s/ DELOITTE & TOUCHE LLP
Indianapolis, Indiana
February 17, 2011

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of Vectren Corporation:


We have audited the internal control over financial reporting of Vectren Corporation and subsidiaries (the “Company”) as of December 31, 2010, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are r ecorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedule as of and for the year ended December 31, 2010 of the Company and our report dated February 17, 2011 expressed an unqualified opinion on those financial statements and financial statement schedule.


/s/ DELOITTE & TOUCHE LLP
Indianapolis, Indiana
February 17, 2011
 
VECTREN CORPORATION AND SUBSIDIARY COMPANIES
 
CONSOLIDATED BALANCE SHEETS
(In millions)

             
   
At December 31,
  
   
2010
    
2009
  
ASSETS
            
             
Current Assets
            
  Cash & cash equivalents
   $ 10.4     $ 11.9  
  Accounts receivable - less reserves of $5.3 &
          $5.2, respectively
     176.6       162.4  
  Accrued unbilled revenues
     162.0       144.7  
  Inventories
     187.1       167.8  
  Recoverable fuel & natural gas costs
     7.9       -  
  Prepayments & other current assets
     101.2       95.1  
    Total current assets
     645.2       581.9  
                 
Utility Plant
                
  Original cost
     4,791.7       4,601.4  
  Less:  accumulated depreciation & amortization
     1,836.3       1,722.6  
    Net utility plant
     2,955.4       2,878.8  
                 
Investments in unconsolidated affiliates
     135.2       186.2  
Other utility & corporate investments
     34.1       33.2  
Other nonutility investments
     40.9       46.2  
Nonutility plant - net
     488.3       482.6  
Goodwill - net
     242.0       242.0  
Regulatory assets
     189.4       187.9  
Other assets
     33.7       33.0  
TOTAL ASSETS
   $ 4,764.2     $ 4,671.8  
















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


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

             
   
At December 31,
  
   
2010
    
2009
  
LIABILITIES & SHAREHOLDERS' EQUITY
            
             
Current Liabilities
            
  Accounts payable
   $ 183.7     $ 183.8  
  Accounts payable to affiliated companies
     59.6       54.1  
  Refundable fuel & natural gas costs
     -       22.3  
  Accrued liabilities
     178.4       174.7  
  Short-term borrowings
     118.3       213.5  
  Current maturities of long-term debt
     250.7       48.0  
  Long-term debt subject to tender
     30.0       51.3  
    Total current liabilities
     820.7       747.7  
                 
Long-term Debt - Net of Current Maturities &
          Debt Subject to Tender
     1,435.2       1,540.5  
                 
Deferred Income Taxes & Other Liabilities
                
  Deferred income taxes
     515.3       458.7  
  Regulatory liabilities
     333.5       322.1  
  Deferred credits & other liabilities
     220.6       205.6  
    Total deferred credits & other liabilities
     1,069.4       986.4  
                 
                 
Commitments & Contingencies (Notes 5, 15-17)
                
                 
Common Shareholders' Equity
                
  Common stock (no par value) – issued & outstanding
          81.7 and 81.1, respectively
     683.4       666.8  
  Retained earnings
     759.9       737.2  
  Accumulated other comprehensive income/(loss)
     (4.4 )     (6.8 )
    Total common shareholders' equity
     1,438.9       1,397.2  
                 
TOTAL LIABILITIES & SHAREHOLDERS' EQUITY
   $ 4,764.2     $ 4,671.8  










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



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

   
Year Ended December 31,
  
   
2010
    
2009
    
2008
  
OPERATING REVENUES
                  
  Gas utility
   $ 954.1     $ 1,066.0     $ 1,432.7  
  Electric utility
     608.0       528.6       524.2  
  Nonutility
     567.4       494.3       527.8  
    Total operating revenues
     2,129.5       2,088.9       2,484.7  
OPERATING EXPENSES
                        
  Cost of gas sold
     504.7       618.1       983.1  
  Cost of fuel & purchased power
     235.0       194.3       182.9  
  Cost of nonutility revenues
     243.3       207.5       282.2  
  Other operating
     538.4       514.0       506.3  
  Depreciation & amortization
     229.1       211.9       192.3  
  Taxes other than income taxes
     62.2       63.0       74.5  
    Total operating expenses
     1,812.7       1,808.8       2,221.3  
OPERATING INCOME
     316.8       280.1       263.4  
OTHER INCOME (EXPENSE)
                        
  Equity in earnings (losses) of unconsolidated affiliates
     (8.6 )     3.4       37.4  
  Other  income – net
     4.8       13.7       2.1  
    Total other income (expense)
     (3.8 )     17.1       39.5  
Interest expense
     104.6       100.0       97.8  
INCOME BEFORE INCOME TAXES
     208.4       197.2       205.1  
Income taxes
     74.7       64.1       76.1  
NET INCOME
   $ 133.7     $ 133.1     $ 129.0  
                         
AVERAGE COMMON SHARES OUTSTANDING
     81.2       80.7       78.3  
DILUTED COMMON SHARES OUTSTANDING
     81.3       81.0       78.7  
                         
EARNINGS PER SHARE OF COMMON STOCK:
                        
   BASIC
   $ 1.65     $ 1.65     $ 1.65  
   DILUTED
   $ 1.64     $ 1.64     $ 1.63  









The accompanying notes are an integral part of these consolidated financial statements.
 
VECTREN CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
                   
                   
   
Year Ended December 31,
  
   
2010
    
2009
    
2008
  
CASH FLOWS FROM OPERATING ACTIVITIES
              
  Net income
   $ 133.7     $ 133.1     $ 129.0  
  Adjustments to reconcile net income to cash from operating activities:
  
    Depreciation & amortization
     229.1       211.9       192.3  
    Deferred income taxes & investment tax credits
     69.3       84.9       79.6  
    Equity in (earnings) losses of unconsolidated affiliates
     8.6       (3.4 )     (37.4 )
    Provision for uncollectible accounts
     16.8       15.1       16.9  
    Expense portion of pension & postretirement benefit cost
     10.0       10.4       7.8  
    Other non-cash charges - net
     15.9       13.3       25.4  
    Changes in working capital accounts:
                        
     Accounts receivable & accrued unbilled revenue
     (48.3 )     96.9       (83.0 )
     Inventories
     (19.3 )     (36.1 )     26.4  
     Recoverable/refundable fuel & natural gas costs
     (30.2 )     21.3       (26.2 )
     Prepayments & other current assets
     (23.5 )     43.1       9.8  
     Accounts payable, including to affiliated companies
     5.5       (85.8 )     65.7  
     Accrued liabilities
     10.2       4.0       16.5  
    Unconsolidated affiliate dividends
     42.7       12.6       15.5  
    Employer contributions to pension & postretirement plans
     (22.0 )     (38.5 )     (15.1 )
    Changes in noncurrent assets
     (7.6 )     0.2       19.6  
    Changes in noncurrent liabilities
     (6.1 )     (33.4 )     (19.6 )
     Net cash flows from operating activities
     384.8       449.6       423.2  
CASH FLOWS FROM FINANCING ACTIVITIES
                  
  Proceeds from:
                        
    Long-term debt, net of issuance costs
     124.2       312.5       171.4  
    Issuance of common stock
     -       -       124.9  
    Dividend reinvestment plan & other common stock issuances
     14.0       5.8       0.9  
  Requirements for:
                        
    Dividends on common stock
     (110.8 )     (108.6 )     (102.6 )
    Retirement of long-term debt
     (49.3 )     (3.5 )     (104.9 )
    Other financing activities
     (0.2 )     -       (0.1 )
  Net change in short-term borrowings
     (95.2 )     (306.0 )     (37.8 )
       Net cash flows from financing activities
     (117.3 )     (99.8 )     51.8  
CASH FLOWS FROM INVESTING ACTIVITIES
                  
  Proceeds from:
                        
    Unconsolidated affiliate distributions
     0.5       4.6       0.2  
    Other collections
     10.8       1.5       6.4  
  Requirements for:
                        
    Capital expenditures, excluding AFUDC equity
     (277.2 )     (432.0 )     (391.0 )
    Unconsolidated affiliate investments
     (0.2 )     (0.2 )     (0.6 )
    Other investments
     (2.9 )     (5.0 )     (17.4 )
       Net cash flows from investing activities
     (269.0 )     (431.1 )     (402.4 )
Net change in cash & cash equivalents
     (1.5 )     (81.3 )     72.6  
Cash & cash equivalents at beginning of period
     11.9       93.2       20.6  
Cash & cash equivalents at end of period
   $ 10.4     $ 11.9     $ 93.2  
 
The accompanying notes are an integral part of these consolidated financial statements.
 
VECTREN CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY
(In millions, except per share amounts)

                     
Accumulated
        
   
Common Stock
          
Other
        
               
Retained
    
Comprehensive
        
   
Shares
    
Amount
    
Earnings
    
Income (Loss)
    
Total
  
Balance at January 1, 2008
     76.3     $ 532.7     $ 688.5     $ 12.5     $ 1,233.7  
                                         
Comprehensive income:
                                        
Net income
                     129.0               129.0  
Pension/OPEB funded status adjustment - net of $1.7 million in tax
                             (2.4 )     (2.4 )
Cash flow hedges:
                                        
     reclassifications to net income- net of $0.2 million in tax
                             (0.2 )     (0.2 )
Comprehensive income of unconsolidated
  affiliates - net of $20.0 million in tax
                       (30.2 )     (30.2 )
Total comprehensive income
                                     96.2  
Pension/OPEB measurement date adjustment
  - net of $1.1 million in tax (see note 9)
       (1.6 )             (1.6 )
Common stock:
                                        
     Issuance:  settlement of equity forward
     4.6       124.9                       124.9  
     Issuance:  option exercises & dividend reinvestment plan
     0.1       1.2                       1.2  
     Dividends ($1.310 per share)
                     (102.6 )             (102.6 )
Other
             0.3       (0.5 )             (0.2 )
Balance at December 31, 2008
     81.0       659.1       712.8       (20.3 )     1,351.6  
                                         
Comprehensive income:
                                        
Net income
                     133.1               133.1  
Pension/OPEB funded status adjustment - net of $0.4 million in tax
                             0.5       0.5  
Comprehensive income of unconsolidated
  affiliates - net of $8.9 million in tax
                       13.0       13.0  
Total comprehensive income
                                     146.6  
Common stock:
                                        
     Issuance:  option exercises & dividend reinvestment plan
     0.3       5.8                       5.8  
     Dividends ($1.345 per share)
                     (108.6 )             (108.6 )
Other
     (0.2 )     1.9       (0.1 )             1.8  
Balance at December 31, 2009
     81.1       666.8       737.2       (6.8 )     1,397.2  
                                         
Comprehensive income:
                                        
Net income
                     133.7               133.7  
Pension/OPEB funded status adjustment - net of $0.2 million in tax
                             (0.3 )     (0.3 )
Cash flow hedges:
                                        
     unrealized gains (losses) - net of $1.5 million in tax
                             2.5       2.5  
     reclassifications to net income- net of tax
                             (0.1 )     (0.1 )
Comprehensive income of unconsolidated
   affiliates - net of $0.2 million in tax
                       0.3       0.3  
Total comprehensive income
                                     136.1  
Common stock:
                                        
     Issuance:  option exercises & dividend reinvestment plan
     0.6       14.0                       14.0  
     Dividends ($1.365 per share)
                     (110.8 )             (110.8 )
Other
             2.6       (0.2 )             2.4  
Balance at December 31, 2010
     81.7     $ 683.4     $ 759.9     $ (4.4 )   $ 1,438.9  


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

VECTREN CORPORATION AND SUBSIDIARY COMPANIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

1.    
Organization and Nature of Operations

Vectren Corporation (the Company or Vectren), an Indiana corporation, is an energy holding company headquartered in Evansville, Indiana.  The Company’s wholly owned subsidiary, Vectren Utility Holdings, Inc. (Utility Holdings), serves as the intermediate holding company for three public utilities:  Indiana Gas Company, Inc. (Indiana Gas or Vectren North), Southern Indiana Gas and Electric Company (SIGECO or Vectren South), and the Ohio operations.  Utility Holdings also has other assets that provide information technology and other services to the three utilities.  Utility Holdings’ consolidated operations are collectively referred to as the Utility Group.  Both Vectren and Utility Holdings are holding companies as defined by the Energy Policy Act of 2005 (Energy Act).  60;Vectren was incorporated under the laws of Indiana on June 10, 1999.

Indiana Gas provides energy delivery services to over 570,000 natural gas customers located in central and southern Indiana.  SIGECO provides energy delivery services to approximately 142,000 electric customers and approximately 111,000 gas customers located near Evansville in southwestern Indiana.  SIGECO also owns and operates electric generation assets to serve its electric customers and optimizes those assets in the wholesale power market.  Indiana Gas and SIGECO generally do business as Vectren Energy Delivery of Indiana.  The Ohio operations provide energy delivery services to approximately 314,000 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 subsid iary 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 four primary business areas:  Infrastructure Services, Energy Services, Coal Mining, and Energy Marketing.  Infrastructure Services provides underground construction and repair services.  Energy Services provides performance contracting and renewable energy services.  Coal Mining mines and sells coal.  Energy Marketing markets and supplies natural gas and provides energy management services.  Enterprises also has other legacy businesses that have invested in energy-related opportunities and services, real estate, and leveraged leases, among other investments.  All of the above are collectively referred to as the Nonutility Group.  Enterprises supports the Comp any’s regulated utilities pursuant to service contracts by providing natural gas supply services, coal, and infrastructure services.

2.    
Summary of Significant Accounting Policies

In applying its accounting policies, the Company makes judgments, assumptions, and estimates that affect the amounts reported in these consolidated financial statements and related footnotes.  Examples of transactions for which estimation techniques are used include valuing pension and postretirement benefit obligations, deferred tax obligations, unbilled revenue, uncollectible accounts, regulatory assets and liabilities, reclamation liabilities, and derivatives and other financial instruments.  Estimates also impact the depreciation of utility and nonutility plant and the testing goodwill and other assets for impairment.  Recorded estimates are revised when better information becomes available or when actual amounts can be determined.  Actual results could differ from current estimates.

Principles of Consolidation
The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries, after elimination of significant intercompany transactions.

Subsequent Events Review
Management performs a review of subsequent events for any events occurring after the balance sheet date but prior to the date the financial statements are issued.

Cash & Cash Equivalents
All highly liquid investments with an original maturity of three months or less at the date of purchase are considered cash equivalents.  Cash and cash equivalents are stated at cost plus accrued interest to approximate fair value.

Allowance for Uncollectible Accounts
The Company maintains allowances for uncollectible accounts for estimated losses resulting from the inability of its customers to make required payments. The Company estimates the allowance for uncollectible accounts based on a variety of factors including the length of time receivables are past due, the financial health of its customers, unusual macroeconomic conditions, and historical experience.  If the financial condition of its customers deteriorates or other circumstances occur that result in an impairment of customers’ ability to make payments, the Company records additional allowances as needed.

Inventories
In most circumstances, the Company’s inventory components are recorded using an average cost method; however, natural gas in storage at the Company’s Indiana utilities and coal inventory at the Company’s nonutility coal mines are recorded using the Last In – First Out (LIFO) method.  Inventory related to the Company’s regulated operations is valued at historical cost consistent with ratemaking treatment.  Materials and supplies are recorded as inventory when purchased and subsequently charged to expense or capitalized to plant when installed.  Nonutility inventory is valued at the lower of cost or market.

Property, Plant & Equipment
Both the Company’s Utility Plant and Nonutility Plant is stated at historical cost, inclusive of financing costs and direct and indirect construction costs, less accumulated depreciation and when necessary, impairment charges.  The cost of renewals and betterments that extend the useful life are capitalized.  Maintenance and repairs, including the cost of removal of minor items of property and planned major maintenance projects, are charged to expense as incurred.

Utility Plant & Related Depreciation
Both the IURC and PUCO allow the Company’s utilities to capitalize financing costs associated with Utility Plant based on a computed interest cost and a designated cost of equity funds.  These financing costs are commonly referred to as AFUDC and are capitalized for ratemaking purposes and for financial reporting purposes instead of amounts that would otherwise be capitalized when acquiring nonutility plant.  The Company reports both the debt and equity components of AFUDC in Other – net in the Consolidated Statements of Income.

When property that represents a retirement unit is replaced or removed, the remaining historical value of such property is charged to Utility plant, with an offsetting charge to Accumulated depreciation, resulting in no gain or loss.  Costs to dismantle and remove retired property are recovered through the depreciation rates as determined by the IURC and PUCO.

The Company’s portion of jointly owned Utility Plant, along with that plant’s related operating expenses, is presented in these financial statements in proportion to the ownership percentage.

Nonutility Plant & Related Depreciation
The depreciation of Nonutility Plant is charged against income over its estimated useful life, using the straight-line method of depreciation or units-of-production method of amortization for certain coal mining assets.  When nonutility property is retired, or otherwise disposed of, the asset and accumulated depreciation are removed, and the resulting gain or loss is reflected in income, typically impacting operating expenses.

Impairment Reviews
Property, plant and equipment along with other long-lived assets are reviewed as facts and circumstances indicate that the carrying amount may be impaired.  This impairment review involves the comparison of an asset’s (or group of assets’) carrying value to the estimated future cash flows the asset (or asset group) is expected to generate over a remaining life.  If this evaluation were to conclude that the carrying value is impaired, an impairment charge would be recorded based on the difference between the carrying amount and its fair value (less costs to sell for assets to be disposed of by sale) as a charge to operations or discontinued operations.

Investments in Unconsolidated Affiliates
Investments in unconsolidated affiliates where the Company has significant influence are accounted for using the equity method of accounting.  The Company’s share of net income or loss from these investments is recorded in Equity in earnings of unconsolidated affiliates.  Dividends are recorded as a reduction of the carrying value of the investment when received.  Investments in unconsolidated affiliates where the Company does not have significant influence are accounted for using the cost method of accounting.  Dividends associated with cost method investments are recorded as Other – net when received.  Investments, when necessary, include adjustments for declines in value judged to be other than temporary.

Goodwill
Goodwill recorded on the Consolidated Balance Sheets results from business acquisitions and is based on a fair value allocation of the businesses’ purchase price at the time of acquisition.  Goodwill is charged to expense only when it is impaired.  The Company tests its goodwill for impairment at a reporting unit level at least annually and that test is performed at the beginning of each year.  Impairment reviews consist of a comparison of the fair value of a reporting unit to its carrying amount.  If the fair value of a reporting unit is less than its carrying amount, an impairment loss is recognized in operations.  No goodwill impairments have been recorded during the p eriods presented.

Regulation
Retail public utility operations affecting Indiana customers are subject to regulation by the IURC, and retail public utility operations affecting Ohio customers are subject to regulation by the PUCO.  The Company’s accounting policies give recognition to the ratemaking and accounting practices authorized by these agencies.

Refundable or Recoverable Gas Costs & Cost of Fuel & Purchased Power
All metered gas rates contain a gas cost adjustment clause that allows the Company to charge for changes in the cost of purchased gas.  Metered electric rates contain a fuel adjustment clause that allows for adjustment in charges for electric energy to reflect changes in the cost of fuel.  The net energy cost of purchased power, subject to a variable benchmark based on NYMEX natural gas prices, is also recovered through regulatory proceedings.  The Company records any under-or-over-recovery resulting from gas and fuel adjustment clauses each month in revenues.  A corresponding asset or liability is recorded until the under or over-recovery is billed or refunded to utility customers.  The cost of gas sold is charged to operating expense as delivered to customers, and the cost of fuel and pu rchased power for electric generation is charged to operating expense when consumed.

Regulatory Assets & Liabilities
Regulatory assets represent probable future revenues associated with certain incurred costs, which will be recovered from customers through the ratemaking process.  Regulatory liabilities represent probable expenditures by the Company for removal costs or future reductions in revenues associated with amounts that are to be credited to customers through the ratemaking process.  The Company continually assesses the recoverability of costs recognized as regulatory assets and liabilities and the ability to recognize new regulatory assets and liabilities associated with its regulated utility operations.  Given the current regulatory environment in its jurisdictions, the Company believes such accounting is appropriate.

The Company collects an estimated cost of removal of its utility plant through depreciation rates established in regulatory proceedings.  The Company records amounts expensed in advance of payments as a Regulatory liability because the liability does not meet the threshold of an asset retirement obligation.

Postretirement Obligations & Costs
The Company recognizes the funded status of its pension plans and postretirement plans on its balance sheet date.  The funded status of a defined benefit plan is its assets (if any) less its projected benefit obligation (PBO), which reflects service accrued to date and includes the impact of projected salary increases (for pay-related benefits).  The funded status of a postretirement plan is its assets (in any) less its accumulated postretirement benefit obligation (APBO), which reflects accrued service to date.  To the extent this obligation exceeds amounts previously recognized in the statement of income, the Company records a Regulatory asset for that portion related to its cost-based and rate regulated utilities.  To the extent that excess liability does not relate to a cost-based rate-regulated utility, the offset is recorded as a reduction to equity in Accumulated other comprehensive income.

The annual cost of all post retirement plans is recognized in operating expenses or capitalized to plant following the direct labor of current employees.  Specific to pension plans, the Company uses the projected unit credit actuarial cost method to calculate service cost and the PBO.  This method projects the present value of benefits at retirement and allocates that cost over the projected years of service.  Annual service cost represents one year’s benefit accrual while the PBO represents benefits allocated to previously accrued service.  For other postretirement plans, service cost is calculated by dividing the present value of a participant’s projected postretirement benefits into equal parts based upon the number of years between a participant’s hire date and first eligible r etirement date.  Annual service cost represents one year’s benefit accrual while the APBO represents benefit allocated to previously accrued service.  To calculate the expected return on pension plan assets, the Company uses the plan assets’ market-related value and an expected long-term rate of return.  For the majority of the Company’s pension plans, the fair market value of the assets at the measurement date is adjusted to a market-related value by recognizing the change in fair value experienced in a given year ratably over a five-year period.  Interest cost represents the annual accretion of the PBO and APBO at the discount rate.  Actuarial gains and losses outside of a corridor (equal to 10% of the greater of the benefit obligation and the market-related value of assets) are amortized over the expected future working lifetime of active participants (except for plans where almost all participants are inactive).  Prior service costs related to plan changes are amortized over the expected future working lifetime (or to full eligibility date for postretirement plan other than pensions) of the active participants at the time of the amendment.

Asset Retirement Obligations
A portion of removal costs related to interim retirements of gas utility pipeline and utility poles, certain asbestos-related issues, and reclamation activities meet the definition of an asset retirement obligation (ARO).  The Company records the fair value of a liability for a legal ARO in the period in which it is incurred.  When the liability is initially recorded, the Company capitalizes a cost by increasing the carrying amount of the related long-lived asset.  The liability is accreted, and the capitalized cost is depreciated over the useful life of the related asset.  Upon settlement of the liability, the Company settles the obligation for its recorded amount or incurs a gain or loss.  To the extent regulation is involved, regulatory assets and liabilities result when accretion and a mortization is adjusted to match rates established by regulators and any gain or loss is subject to deferral.

Product Warranties, Performance Guarantees & Other Guarantees
Liabilities and expenses associated with product warranties and performance guarantees are recognized based on historical experience at the time the associated revenue is recognized.  Adjustments are made as changes become reasonably estimable.  The Company does not recognize the fair value of an obligation at inception for these guarantees because they are guarantees of the Company’s own performance and/or product installations.

While not significant at December 31, 2010 or 2009, the Company does recognize the fair value of an obligation at the inception of a guarantee in certain circumstances.  These circumstances would include executing certain indemnification agreements and guaranteeing operating lease residual values, the performance of a third party, or the indebtedness of a third party.

Energy Contracts & Derivatives
The Company will periodically execute 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.  A derivative is recognized on the balance sheet as an asset or liability measured at its fair market value and the change in the derivative's fair market value is 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 or are not considered derivatives.  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, 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 regulatory accounting treatment.  When hedge accounting is appropriate, the Company assesses and documents hedging relationships between t he 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 regulatory accounting treatment 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 that have a significant impact to the financial statements where internal mo dels are used to calculate fair value.  As of and for the periods presented, related derivative activity is not material to these financial statements.

Income Taxes
Deferred income taxes are provided for temporary differences between the tax basis (adjusted for related unrecognized tax benefits, if any) of an asset or liability and its reported amount in the financial statements.  Deferred tax assets and liabilities are computed based on the currently-enacted statutory income tax rates that are expected to be applicable when the temporary differences are scheduled to reverse.  The Company’s rate-regulated utilities recognize regulatory liabilities for deferred taxes provided in excess of the current statutory tax rate and regulatory assets for deferred taxes provided at rates less than the current statutory tax rate.  Such tax-related regulatory assets and liabilities are reported at the revenue requirement level and amortized to income as the related temporary differences revers e, generally over the lives of the related properties.  A valuation allowance is recorded to reduce the carrying amounts of deferred tax assets unless it is more likely than not that the deferred tax assets will be realized.  

Tax benefits associated with income tax positions taken, or expected to be taken, in a tax return are recorded only when the more-likely-than-not recognition threshold is satisfied and measured at the largest amount of benefit that is greater than 50 percent likely of being realized upon settlement.  The Company reports interest and penalties associated with unrecognized tax benefits within Income taxes in the Consolidated Statements of Income and reports tax liabilities related to unrecognized tax benefits as part of Deferred credits & other liabilities.

Investment tax credits (ITCs) are deferred and amortized to income over the approximate lives of the related property in accordance with the regulatory treatment.  Production tax credits (PTCs) are recognized as energy is generated and sold based on a per kilowatt hour rate prescribed in applicable federal and state statutes.  

Revenues
Most revenues are recorded as products and services are delivered to customers.  Some nonutility revenues are recognized using the percentage of completion method with such percentage based on project cost.  The Company records revenues for all gas and electricity delivered to customers but not billed at the end of the accounting period in Accrued unbilled revenues.

MISO Transactions
With the IURC’s approval, the Company is a member of the 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.
 
MISO-related purchase and sale transactions are recorded using settlement information provided by MISO. These purchase and sale transactions are accounted for on a net hourly position. Net purchases in a single hour are recorded in Cost of fuel & purchased power and net sales in a single hour are recorded in Electric utility revenues. On occasion, prior period transactions are resettled outside the routine process due to a change in MISO’s tariff or a material interpretation thereof.  Expenses associated with resettlements are recorded once the resettlement is probable and the resettlement amount can be estimated. Revenues associated with resettlements are recognized when the amount is determinable and collectability is reasonably assured.

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 from / refunded to retail customers through tracking mechanisms.

Share-Based Compensation
 
The Company grants share-based compensation to certain employees and board members.  Liability classified share-based compensation awards are re-measured at the end of each period based on their expected settlement date fair value.  Equity classified stock-based compensation awards are measured at the grant date, based on the fair value of the award.  Expense associated with share-based awards is recognized over the requisite service period, which generally begins on the date the award is granted through the earlier of the date the award vests or the date the employee becomes retirement eligible.

Excise & 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 $33.8 million in 2010, $36.3 million in 2009, and $45.0 million in 2008.  Expense associated with excise and utility receipts taxes are recorded as a component of Taxes other than income taxes.

Operating Segments
The Company’s chief operating decision maker is comprised of a group of executive management led by the Chief Executive Officer.  The Company uses net income calculated in accordance with generally accepted accounting principles as its most relevant performance measure.  The Company has three operating segments within its Utility Group, five operating segments in its Nonutility Group, and a Corporate and Other segment.

Fair Value Measurements
Certain assets and liabilities are valued and/or disclosed at fair value.  Financial assets include securities held in trust by the Company’s pension plans.  Nonfinancial assets and liabilities include the initial measurement of an asset retirement obligation or the use of fair value in goodwill, intangible assets and long-lived assets impairment tests, FASB guidance provides the framework for measuring fair value.  That framework provides a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value.  The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements).  The three levels of the fair value hierarchy are described as follows:

Level 1
Inputs to the valuation methodology are unadjusted quoted prices for identical assets or liabilities in active markets that the Plan has the ability to access.
Level 2
Inputs to the valuation methodology include
· quoted prices for similar assets or liabilities in active markets;
· quoted prices for identical or similar assets or liabilities in inactive markets;
· inputs other than quoted prices that are observable for the asset or liability;
· inputs that are derived principally from or corroborated by observable market data by correlation or other means
If the asset or liability has a specified (contractual) term, the Level 2 input must be observable for substantially the full term of the asset or liability.
Level 3
Inputs to the valuation methodology are unobservable and significant to the fair value measurement.

The asset or liability’s fair value measurement level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement.  Valuation techniques used need to maximize the use of observable inputs and minimize the use of unobservable inputs.

3.    
Utility & Nonutility Plant

The original cost of Utility Plant, together with depreciation rates expressed as a percentage of original cost, follows:
   
At December 31,
  
(In millions)
  
2010
    
2009
  
   
 
 
 
Original Cost
    
Depreciation
Rates as a
Percent of 
Original Cost
  
 
 
 
Original Cost
    
Depreciation
Rates as a
Percent of 
Original Cost
Gas utility plant
   $ 2,410.2       3.6 %   $ 2,299.1       3.5 %
Electric utility plant
     2,258.6       3.4 %     2,113.3       3.4 %
Common utility plant
     49.7       3.1 %     48.7       2.9 %
Construction work in progress
     73.2       -       140.3       -  
Total original cost
   $ 4,791.7             $ 4,601.4          
                                 
SIGECO and Alcoa Generating Corporation (AGC), a subsidiary of ALCOA, own the 300 MW Unit 4 at the Warrick Power Plant as tenants in common.  SIGECO's share of the cost of this unit at December 31, 2010, is $176.2 million with accumulated depreciation totaling $59.2 million.  The construction work-in-progress balance associated with SIGECO’s ownership interest totaled $3.1 million at December 31, 2010.  AGC and SIGECO also share equally in the cost of operation and output of the unit.  SIGECO's share of operating costs is included in Other operating expenses in the Consolidated Statements of Income.

Nonutility plant, net of accumulated depreciation and amortization follows:
   
At December 31,
  
(In millions)
  
2010
    
2009
  
Coal mine development costs & equipment
   $ 196.9     $ 188.6  
Computer hardware & software
     114.5       119.9  
Land & buildings
     112.8       115.1  
Vehicles & equipment
     46.9       43.7  
All other
     17.2       15.3  
Nonutility plant - net
   $ 488.3     $ 482.6  
                 
Nonutility plant is presented net of accumulated depreciation and amortization totaling $385.5 million and $334.3 million as of December 31, 2010 and 2009, respectively.  For the years ended December 31, 2010, 2009, and 2008, the Company capitalized interest totaling $2.1 million, $6.0 million, and $3.7 million, respectively, on nonutility plant construction projects.

4.    
Regulatory Assets & Liabilities

Regulatory Assets
Regulatory assets consist of the following:
   
At December 31,
  
(In millions)
  
2010
    
2009
  
Future amounts recoverable from ratepayers related to:
  
Benefit obligations
   $ 92.5     $ 83.9  
Deferred Income taxes
     19.2       14.7  
Asset retirement obligations & other
     2.1       4.2  
      113.8       102.8  
Amounts deferred for future recovery related to:
          
Cost recovery riders & other
     2.8       1.0  
      2.8       1.0  
Amounts currently recovered in customer rates related to:
  
Unamortized debt issue costs & hedging proceeds
     35.7       38.1  
Demand side management programs
     9.5       15.3  
Indiana authorized trackers
     17.3       15.6  
Ohio authorized trackers
     2.0       8.2  
Premiums paid to reacquire debt
     3.8       4.3  
Other base rate recoveries
     4.5       2.6  
      72.8       84.1  
Total regulatory assets
   $ 189.4     $ 187.9  

Of the $72.8 million currently being recovered in customer rates, $9.5 million that is associated with demand side management programs is earning a return.  The weighted average recovery period of regulatory assets currently being recovered is 16 years.  The Company has rate orders for all deferred costs not yet in rates and therefore believes that future recovery is probable.

Regulatory Liabilities
At December 31, 2010 and 2009, the Company has approximately $333.5 million and $322.1 million, respectively, in Regulatory liabilities.  Of these amounts, $307.5 million and $294.4 million relate to cost of removal obligations.  The remaining amounts primarily relate to timing differences associated with asset retirement obligations and deferred financing costs.

5.    
Investment in 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 acc ounts for its investment in ProLiance using the equity method of accounting.  The Company, including its retail gas supply operations, contracted for a substantial portion of its natural gas purchases through ProLiance in 2010, 2009, and 2008.
 
Summarized Financial Information
   
Year Ended December 31,
  
(In millions)
  
2010
    
2009
    
2008
  
Summarized Statement of Income information:
                  
Revenues
   $ 1,497.0     $ 1,654.9     $ 2,883.6  
Operating income (loss)
     (3.1 )     35.2       63.7  
Charge related to Investment in Liberty Gas Storage
     -       (32.7 )     -  
ProLiance's earnings (losses)
     (3.7 )     4.5       64.7  

   
As of December 31,
  
(In millions)
  
2010
    
2009
  
Summarized balance sheet information:
            
  Current assets
   $ 441.4     $ 477.6  
  Noncurrent assets
     59.1       61.7  
  Current liabilities
     298.1       264.5  
  Noncurrent liabilities
     0.4       0.5  
  Members' equity
     208.9       282.4  
  Accumulated other comprehensive income (loss)
     (10.8 )     (11.6 )
  Noncontrolling interest
     3.9       3.5  
 
Vectren records its 61 percent share of ProLiance’s earnings after income taxes and an interest expense allocation.

Investment in Liberty Gas Storage
Liberty Gas Storage, LLC (Liberty), a joint venture between a subsidiary of ProLiance and a subsidiary of Sempra Energy (SE), is a development project for salt-cavern natural gas storage facilities.  ProLiance is the minority member with a 25 percent interest, which it accounts for using the equity method.  The project was expected to include 17 Bcf of capacity in its north facility, and an additional 17 Bcf of capacity in its south facility.  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 $36.7 million at December 31, 20 10, 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 in development of certain caverns.  At June 30, 2009, Liberty recorded a charge of approximately $132 million to write off the north caverns and certain related assets.  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. In the Consolidated Statement of Income for the year ended December 31, 2009, the charge is an approximate $19.9 million reduction to Equity in earnings of unconsolidated affiliates and an income tax benefit reflected in Income taxes of approximately $8.0 million. ProLiance has not experienced, and does not expect, any impact to its liquidity or access to capital as a result of the impairment charge, nor is it expected that this situation will impact ProLiance’s ability to meet the needs of its customers.

Liberty received a Demand for Arbitration from Williams Midstream Natural Gas Liquids, Inc. (“Williams”) on February 8, 2011 related to a Sublease Agreement (“Sublease”) between Liberty and Williams.  Williams alleges that Liberty was negligent in its attempt to convert certain salt caverns to natural gas storage and thereby damaged the caverns.  Williams alleges damages of $56.7 million.  Liberty believes that the claims are without merit and believes that it has complied with all of its obligations to Williams and has properly terminated the Sublease.  Liberty intends to vigorously defend itself and believes it has counterclaims against Williams which it will assert in the arbitration proceeding.  Liberty has made no accrual for this matter as of December 31, 2010.

Firm Transportation and Storage Commitments
ProLiance has various firm transportation and storage agreements with only minimal support from Vectren or Citizens. (See Note 15 regarding corporate guarantees.)  Under these agreements, ProLiance must make specified minimum payments which extend through 2029.  At December 31, 2010, the estimated aggregated amounts of such required future payments were $75.8 million, $66.6 million, $50.9 million, $45.7 million, $36.5 million, and $259.5 million for 2011, 2012, 2013, 2014, 2015, and thereafter, respectively.  During 2010, 2009, and 2008, fixed payments under these agreements were $76.8 million, $63.0 million, and $68.9 million, respectively.  ProLiance also made variable payments under these agreements in 2010, 2009, and 2008. Variable payments include st orage injection and withdrawal charges, and commodity transportation charges.

Transactions with ProLiance
Purchases from ProLiance for resale and for injections into storage for the years ended December 31, 2010, 2009, and 2008, totaled $437.7 million, $533.4 million, and $940.1 million, respectively.  Amounts owed to ProLiance at December 31, 2010, and 2009, for those purchases were $59.6 million and $54.1 million, respectively, and are included in Accounts payable to affiliated companies in the Consolidated Balance Sheets.  Vectren received regulatory approval on April 25, 2006, from the IURC for ProLiance to provide natural gas supply services to the Company’s Indiana utilities through March 2011.  On November 3, 2010, a settlement agreement was filed with the IURC providing for ProLianceR 17;s continued provision of gas supply services to the Company’s Indiana utilities and Citizens Gas for the period of April 1, 2011 through March 31, 2016.  The settlement has been agreed to by all of the representatives that were parties to the prior settlement.  An order is anticipated during the first quarter of 2011.  Amounts charged by ProLiance for gas supply services are established by supply agreements with each utility.

Undistributed Earnings
As of December 31, 2010, Vectren’s share of ProLiance’s undistributed earnings approximated $110 million and represents substantially all of the undistributed earnings of unconsolidated affiliates.

6.    
Nonutility Real Estate & Other Legacy Holdings
Within the Nonutility business segment, there are legacy investments involved in energy-related infrastructure and services, real estate, leveraged leases, and other ventures.  As of December 31, 2010 and 2009, total remaining legacy investments included in the Other Businesses portfolio total $52.7 million and $64.5 million, respectively.  Further separation of that 2010 investment by type of investment follows:
                   
   
December 31, 2010
  
         
Value Included In
  
(In millions)
  
Carrying
Value
    
Other
Nonutility
Investments
  
Investments in Unconsolidated Affiliates
  
Commercial real estate investments
   $ 19.8     $ 19.8     $ -  
Leveraged leases
     17.9       17.9       -  
Affordable housing projects
     7.2       0.2       7.0  
Haddington energy partnerships
     3.4       -       3.4  
Other investments
     4.4       3.0       1.4  
    $ 52.7     $ 40.9     $ 11.8  
                         
Haddington Energy Partnerships
The Company has an approximate 40 percent ownership interest in Haddington Energy Partners, LP (Haddington I) and Haddington Energy Partners II, LP (Haddington II).  As of December 31, 2010, these Haddington ventures have interests in two remaining mid-stream energy related investments.  Both Haddington ventures are investment companies accounted for using the equity method of accounting.  During the second quarter of 2010, the Company recorded its share of the decline in fair value and also impaired a note receivable associated with Haddington’s investment in a liquefied natural gas facility.  In total, the charge was approximately $6.5 million, of which, $6.1 million is reflected in Equity in earnings (losses) of unconsolidated affiliates and $0 .4 million is reflected in Other income-net, for the twelve months ended December 31, 2010.  At December 31, 2010, the Company’s remaining $3.4 million investment in the Haddington ventures is related to payments to be received associated with the sale of a compressed air storage facility sold in 2009.  The Company has no further commitments to invest in either Haddington I or II.  

The following is summarized financial information as to the assets, liabilities, and results of operations of Haddington.  For the year ended December 31, 2010, revenues, operating loss, and net income were (in millions) zero, $(0.3), and $(18.1), respectively.  For the year ended December 31, 2009, revenues, operating loss, and net income were (in millions) zero, $(0.4), and $7.9, respectively.  For the year ended December 31, 2008, revenues, operating loss, and net loss were (in millions) zero, $(0.4), and $(0.3), respectively.  As of December 31, 2010, investments, other assets, and liabilities were (in millions) $8.6, zero, and zero, respectively.  As of December 31, 2009, investments, other assets, and liabilities were (in millions) $26.4, zero, and zero, respectively.

Leveraged Leases
The Company is a lessor in leveraged lease agreements under which real estate or equipment is leased to third parties.  The total equipment and facilities cost was approximately $45.2 million at December 31, 2010.  The cost of the equipment and facilities was partially financed by non-recourse debt provided by lenders who have been granted an assignment of rentals due under the leases and a security interest in the leased property, which they accepted as their sole remedy in the event of default by the lessee.  Such debt amounted to approximately $44.5 million at December 31, 2010.  At December 31, 2010, the Company’s $17.9 million leveraged lease investment when netted against related deferred tax liabilities was $3.7 million.

Notes Receivable
At December 31, 2010 and 2009, notes receivable totaled $10.9 million and $16.7 million, respectively.  These amounts are inclusive of accrued interest and net of reserves totaling $6.1 million and 9.2 million, respectively.  Of the $40.9 million in Other nonutility investments identified above, notes receivable comprise approximately $8.8 million of the commercial real estate investments, $0.2 million of the affordable housing projects, and $1.9 million of the other investments.  As of December 31, 2010, the Company is recognizing interest on the cash basis for substantially the entire note portfolio.  Such interest income has been insignificant during the past three years.  Second mortgages serve as collateral for notes associated with the commercial real estate investments.

Commercial Real Estate Charge
The recent recession impacted the value of commercial real estate investments within this portfolio.  During 2008, the Company assessed its commercial real estate investments for impairment and identified the need to reduce their carrying values.  The impairment charge totaled $10.0 million.  Of the $10.0 million charge, $5.2 million is included in Other-net and $4.8 million is included in Other operating expenses.  The impairment impacted the carrying values of primarily notes receivable collateralized by commercial real estate and an office building. The Company took possession of the office building when a leveraged lease expired in 2008; the building is currently for sale.

Variable Interest Entities
Some of these legacy nonutility investments are partnership-like structures involved in activities surrounding multifamily housing and office properties and are variable interest entities.  The Company is either a limited partner or a subordinated lender and does not consolidate any of these entities.  The Company’s exposure to loss is limited to its investment which as of December 31, 2010, and 2009, totaled $7.0 million and $7.7 million, respectively, recorded in Investments in unconsolidated affiliates, and $9.0 million and $10.1 million, respectively, recorded in Other nonutility investments.

7.    
Intangible Assets
Intangible assets, which are included in Other assets, consist of the following:
                         
(In millions)
  
At December 31,
  
   
2010
    
2009
  
   
Amortizing
    
Non-amortizing
    
Amortizing
    
Non-amortizing
  
Customer-related assets
   $ 7.4     $ -     $ 8.0     $ -  
Market-related assets
     -       7.0       -       7.0  
Intangible assets, net
   $ 7.4     $ 7.0     $ 8.0     $ 7.0  
 
As of December 31, 2010, the weighted average remaining life for amortizing customer-related assets and all amortizing intangibles is 23 years.  These amortizing intangible assets have no significant residual values.  Intangible assets are presented net of accumulated amortization totaling $3.4 million for customer-related assets and $0.3 million for market-related assets at December 31, 2010 and $2.8 million for customer-related assets and $0.2 million for market-related assets at December 31, 2009.  Annual amortization associated with intangible assets totaled $0.6 million in 2010, 2009, and 2008.  Amortization should approximate that incurred in 2010 in each of the next five years.  Intangible assets are primarily in the Nonutility Group.
 
8.    
Income Taxes

A reconciliation of the federal statutory rate to the effective income tax rate follows:
   
Year Ended December 31,
  
   
2010
    
2009
    
2008
  
Statutory rate:
     35.0 %     35.0 %     35.0 %
    State & local taxes-net of federal benefit
     3.8       2.3       3.9  
    Amortization of investment tax credit
     (0.4 )     (0.5 )     (0.6 )
    Depletion
     (2.0 )     (2.0 )     (0.4 )
    Other tax credits
     (0.2 )     (0.2 )     (0.9 )
    Adjustment of income tax accruals
     (0.2 )     (2.1 )     -  
    All other-net
     (0.2 )     -       0.1  
   Effective tax rate
     35.8 %     32.5 %     37.1 %
 
Significant components of the net deferred tax liability follow:
   
At December 31,
  
(In millions)
  
2010
    
2009
  
Noncurrent deferred tax liabilities (assets):
            
  Depreciation & cost recovery timing differences
   $ 565.7     $ 483.3  
  Leveraged leases
     14.2       14.7  
  Regulatory assets recoverable through future rates
     20.1       25.6  
  Other comprehensive income
     (4.2 )     (5.7 )
  Alternative minimum tax carryforward
     (48.6 )     (21.6 )
  Employee benefit obligations
     (18.9 )     (24.0 )
  Net operating loss & other carryforwards
     (3.8 )     (0.5 )
  Regulatory liabilities to be settled through future rates
     (4.8 )     (11.7 )
  Other – net
     (4.4 )     (1.4 )
    Net noncurrent deferred tax liability
     515.3       458.7  
Current deferred tax (assets)/liabilities:
                
  Deferred fuel costs-net
     2.4       1.2  
  Demand side management programs
     2.5       5.2  
  Alternative minimum tax carryforward
     (0.8 )     (15.8 )
  Other – net
     (7.9 )     (12.3 )
    Net current deferred tax asset
     (3.8 )     (21.7 )
    Net deferred tax liability
   $ 511.5     $ 437.0  

At December 31, 2010 and 2009, investment tax credits totaling $5.0 million and $5.8 million, respectively, are included in Deferred credits & other liabilities.  At December 31, 2010, the Company has alternative minimum tax carryforwards which do not expire.  In addition, the Company has $3.8 million in net operating loss and general business credit carryforwards, which will expire in 5 to 20 years.

The components of income tax expense and utilization of investment tax credits follow:
                 
 
Year Ended December 31,
  
(In millions)
  
2010
    
2009
    
2008
  
Current:
                  
Federal
   $ (0.8 )   $ (21.4 )   $ (14.8 )
State
     6.2       0.6       11.3  
Total current taxes
     5.4       (20.8 )     (3.5 )
Deferred:
                        
Federal
     65.6       78.7       78.2  
State
     4.5       7.3       2.7  
Total deferred taxes
     70.1       86.0       80.9  
Amortization of investment tax credits
     (0.8 )     (1.1 )     (1.3 )
Total income tax expense
   $ 74.7     $ 64.1     $ 76.1  

Uncertain Tax Positions

Following is a roll forward of unrecognized tax benefits for the three years ended December 31, 2010:
                   
(In millions)
  
2010
    
2009
    
2008
  
Unrecognized tax benefits at January 1
   $ 11.5     $ 2.2     $ 6.2  
  Gross increases - tax positions in prior periods
     1.6       1.1       1.7  
  Gross decreases - tax positions in prior periods
     (0.3 )     (1.8 )     (6.0 )
  Gross increases - current period tax positions
     1.0       9.0       0.3  
  Settlements
     -       (0.1 )     -  
  Lapse of statute of limitations
     (0.5 )     1.1       -  
    Unrecognized tax benefits at December 31
   $ 13.3     $ 11.5     $ 2.2  

Of the change in unrecognized tax benefits during 2010, 2009, and 2008, almost none impacted the effective rate.  The amount of unrecognized tax benefits, which if recognized, that would impact the effective tax rate was $0.7 million at December 31, 2010 and $0.5 million at both December 31, 2009 and 2008.  As of December 31, 2010, the unrecognized tax benefit relates to tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility.  Because of the impact of deferred tax accounting, other than interest and penalties, the disallowance of the shorter deductibility period would not affect the annual effective tax rate but would accelerate the payment of cash to the taxing authority. Thus, it is not expected that any changes to these tax positions would have a significant impact on earnings.

The Company recognized expense related to interest and penalties totaling approximately $0.3 million in 2010, $0.2 million in 2009, and less than $0.1 million in 2008.  The Company had approximately $0.9 million and $0.6 million for the payment of interest and penalties accrued as of December 31, 2010 and 2009, respectively.

The net liability on the Consolidated Balance Sheet for unrecognized tax benefits inclusive of interest, penalties and net of secondary impacts which are a component of the Deferred income taxes and are benefits, totaled $9.8 million and $7.9 million, respectively, at December 31, 2010 and 2009.

The Company and/or certain of its subsidiaries file income tax returns in the U.S. federal jurisdiction and various states.  The Internal Revenue Service (IRS) has conducted examinations of the Company’s U.S. federal income tax returns for tax years through December 31, 2005.  Tax years 2006 and 2008 are currently under IRS exam.  The State of Indiana, the Company’s primary state tax jurisdiction, has conducted examinations of state income tax returns for tax years through December 31, 2007.  The statutes of limitations for assessment of federal income tax have expired with respect to tax years through 2005 and through 2006 for Indiana income tax.

Impact of Healthcare Legislation
In March 2010, the President signed into law comprehensive health care reform legislation under the Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act of 2010.  Included among the major provisions of the law is a change in the federal income tax treatment of a subsidy received by the Company to offset the cost of providing Medicare equivalent retiree prescription drug benefits, commonly referred to as the Medicare Part D subsidy.  Prior to the change in law, the deduction for retiree drug benefits excluded the government subsidy, effectively making the subsidy tax free.  Due to the change in tax treatment, the Company recorded a $2.3 million increase in its deferred tax liabilities, during the first quarter of 2010, related to the estimated $6.1 million accrued sub sidy receivable at that date.  Like tax law changes in the past, it is expected that the impact of this change will be reflected in customer rates in the future.  As a result, the Company has recorded a $5.1 million regulatory asset related to this matter in its financial statements at December 31, 2010.

9.    
Retirement Plans & Other Postretirement Benefits

At December 31, 2010, the Company maintains three qualified defined benefit pension plans, a nonqualified supplemental executive retirement plan (SERP), and three other postretirement benefit plans.  The defined benefit pension and other postretirement benefit plans, which cover eligible full-time regular employees, are primarily noncontributory.  The postretirement health care and life insurance plans are a combination of self-insured and fully insured plans.  The Company has a Voluntary Employee Beneficiary Association (VEBA) Trust Agreement for the partial funding of postretirement health benefits for retirees and their eligible dependents and beneficiaries in one of the three plans.  Annual VEBA funding is discretionary; however, no further funding is anticipated.  The qualified pensio n plans and the SERP are aggregated under the heading “Pension Benefits.”  Other postretirement benefit plans are aggregated under the heading “Other Benefits.”

Measurement Date Change
Prior to 2008, the Company measured obligations as of September 30.  The Company changed its measurement date due to a required change in the accounting rules.  The effects of moving the measurement date were calculated using a measurement of plan assets and benefit obligations as of September 30, 2007 and a 15-month projection of periodic cost to December 31, 2008.  The Company recorded three months of that cost totaling $2.7 million, or $1.6 million after tax, directly to Retained earnings on January 1, 2008.

Net Periodic Benefit Costs
A summary of the components of net periodic benefit cost for the three years ended December 31, 2010 follows:

                                     
   
Pension Benefits
    
Other Benefits
  
(In millions)
  
2010
    
2009
    
2008
    
2010
    
2009
    
2008
  
Service cost
   $ 6.3     $ 6.3     $ 6.1     $ 0.5     $ 0.5     $ 0.5  
Interest cost
     15.9       15.8       15.1       4.6       4.4       4.2  
Expected return on plan assets
     (18.4 )     (16.4 )     (16.6 )     (0.4 )     (0.3 )     (0.5 )
Amortization of prior service cost (benefit)
     1.6       1.7       1.7       (0.8 )     (0.8 )     (0.8 )
Amortization of actuarial loss (gain)
     3.2       2.2       0.1       0.5       0.4       -  
Amortization of transitional obligation
      -       -       -       1.2       1.1       1.1  
  Net periodic benefit cost
   $ 8.6     $ 9.6     $ 6.4     $ 5.6     $ 5.3     $ 4.5  
 
A portion of benefit costs are capitalized as Utility plant.  Costs capitalized in 2010, 2009, and 2008 are estimated at $4.3 million, $4.5 million, and $3.0 million, respectively.

The Company lowered the discount rate used to measure periodic cost from 6.25 percent in 2009 to 6.00 percent in 2010 due to lower benchmark interest rates that approximate the expected duration of the Company’s benefit obligations.  For fiscal year 2011, the discount rate will be 5.50 percent.  Over the periods presented other assumptions have also declined reflecting the lower interest rate environment.

The weighted averages of significant assumptions used to determine net periodic benefit costs follow:

                           
     
Pension Benefits
  
Other Benefits
     
2010
  
2009
  
2008
  
2010
  
2009
  
2008
Discount rate
  
6.00%
  
6.25%
  
6.25%
  
6.00%
  
6.25%
  
6.25%
Rate of compensation increase
  
3.50%
  
3.75%
  
3.75%
  
N/A
  
N/A
  
N/A
Expected return on plan assets
  
8.00%
  
8.25%
  
8.25%
  
8.00%
  
8.25%
  
8.25%
Expected increase in Consumer Price Index
  
N/A
  
N/A
  
N/A
  
3.00%
  
3.50%
  
3.50%
 
Health care cost trend rate assumptions do not have a material effect on the service and interest cost components of benefit costs.  The Company’s plans limit its exposure to increases in health care costs to annual changes in the Consumer Price Index (CPI).  Any increase in health care costs in excess of the CPI increase is the responsibility of the plan participants.

Benefit Obligations
A reconciliation of the Company’s benefit obligations at December 31, 2010 and 2009 follows:

                         
   
Pension Benefits
    
Other Benefits
  
(In millions)
  
2010
    
2009
    
2010
    
2009
  
Benefit obligation, beginning of period
   $ 271.5     $ 260.6     $ 79.6     $ 72.3  
Service cost – benefits earned during the period
     6.3       6.3       0.5       0.5  
Interest cost on projected benefit obligation
     15.9       15.8       4.6       4.4  
Plan participants' contributions
     -       -       1.7       2.8  
Plan amendments
     0.8       0.1       -       -  
Actuarial loss (gain)
     21.3       2.0       1.2       7.2  
Medicare subsidy receipts
     -       -       0.5       0.8  
Benefit payments
     (18.5 )     (13.3 )     (7.4 )     (8.4 )
Benefit obligation, end of period
   $ 297.3     $ 271.5     $ 80.7     $ 79.6  
                                 
The accumulated benefit obligation for all defined benefit pension plans was $280.5 and $257.0 million at December 31, 2010 and 2009, respectively.

The benefit obligation as of December 31, 2010 and 2009 was calculated using the following assumptions:
                   
     
Pension Benefits
  
Other Benefits
     
2010
  
2009
  
2010
  
2009
Discount rate
  
5.50%
  
6.00%
  
5.50%
  
6.00%
Rate of compensation increase
  
3.50%
  
3.50%
  
N/A
  
N/A
Expected increase in Consumer Price Index
  
N/A
  
N/A
  
3.00%
  
3.00%
 
To calculate the 2010 ending postretirement benefit obligation, medical claims costs in 2011 were assumed to be 8 percent higher than those incurred in 2010.  That trend was assumed to reach its ultimate trending increase of 5 percent by 2014 and remain level thereafter.  A one-percentage point change in assumed health care cost trend rates would have changed the benefit obligation by approximately $2.4 million.

Plan Assets
A reconciliation of the Company’s plan assets at December 31, 2010 and 2009 follows:
                         
   
Pension Benefits
    
Other Benefits
  
(In millions)
  
2010
    
2009
    
2010
    
2009
  
Plan assets at fair value, beginning of period
   $ 211.1     $ 150.9     $ 4.0     $ 4.3  
Actual return on plan assets
     26.8       38.6       0.3       0.9  
Employer contributions
     17.8       34.9       4.5       4.4  
Plan participants' contributions
     -       -       1.7       2.8  
Benefit payments
     (18.5 )     (13.3 )     (7.4 )     (8.4 )
Fair value of plan assets, end of period
   $ 237.2     $ 211.1     $ 3.1     $ 4.0  
                                 
The Company’s overall investment strategy for its retirement plan trusts is to maintain investments in a diversified portfolio, comprised of primarily equity and fixed income investments, which are further diversified among various asset classes.  The diversification is designed to minimize the risk of large losses while maximizing total return within reasonable and prudent levels of risk.  The investment objectives specify a targeted investment allocation for the pension plans of 60 percent equities, 35 percent debt, and 5 percent for other investments, including real estate.  Both the equity and debt securities have a blend of domestic and international exposures.  For other benefit plans the targeted allocation is 75 percent equities and 25 percent debt.  Objectives do not target a specific return by asset class.  The portfolios’ return is monitored in total.   Following is a description of the valuation methodologies used for trust assets measured at fair value.

Mutual Funds
The fair values of mutual funds are derived from quoted market prices or net asset values as these instruments have active markets (Level 1 inputs). 

Common Collective Trust Funds (CTF’s)
The Company’s plans have investments in trust funds similar to mutual funds in that they are created by pooling of funds from investors into a common trust and such funds are managed by a third party investment manager.  These trust funds typically give investors a wider range of investment options through this pooling of funds than that generally available to investors on an individual basis.  However, unlike mutual funds, these trusts are not publicly traded in an active market.  The fair values of these trusts are derived from Level 2 market inputs based on a daily calculated unit value as determined by the issuer.  This daily calculated value is based on the fair market value of the underlying investments.  These funds are primarily comprised of investments in equity and fix ed income securities which represent approximately 55 percent and 37 percent, respectively, of their fair value as of December 31, 2010.  Equity securities within these funds are primarily valued using quoted market prices as these instruments have active markets.  From time to time, less liquid equity securities are valued using Level 2 inputs, such as bid prices or a closing price, as determined in good faith by the investment manager.  Fixed income securities are valued at the last available bid prices quoted by an independent pricing service.  When valuations are not readily available, fixed income securities are valued using primarily other Level 2 inputs as determined in good faith by the investment manager.

The fair value of these funds totals $110.4 million at December 31, 2010 and $105.5 million at December 31, 2009.  In relation to these investments, there are no unfunded commitments.  Also, the Plan can exchange shares with minimal restrictions.  However, in certain events, a restriction of up to 31 days may exist.

Guaranteed Annuity Contract
One of the Company’s pension plans is party to a group annuity contract with John Hancock Life Insurance Company.  At December 31, 2010, the estimate of undiscounted funds necessary to satisfy John Hancock’s remaining obligation was $3.1 million.  If funds retained by John Hancock are not sufficient to satisfy retirement payments due these retirees, the shortfall must be funded by the Company. The composite investment return, net of manger fees and other charges for the year ended December 31, 2010 was 5.37 percent.  The Company values this illiquid investment using long-term interest rate and mortality assumptions, among others, and is therefore considered a Level 3 investment.  There is no unfunded commitment related to this investment.

The fair values of the Company’s pension and other retirement plan assets at December 31, 2010 by asset category and by fair value hierarchy are as follows:
                       
 
As of December 31, 2010
  
(In millions)
  
Level 1
    
Level 2
    
Level 3
    
Total
  
                         
Domestic equities & equity funds
   $ 54.6     $ 60.8     $ -     $ 115.4  
International equities & equity funds
     29.7       -       -       29.7  
Domestic bonds & bond funds
     35.3       31.3       -       66.6  
Inflation protected security fund
     -       9.2       -       9.2  
Real estate, commodities & other
     6.6       9.1       3.7       19.4  
Total Plan Investments
   $ 126.2     $ 110.4     $ 3.7     $ 240.3  
 
                         
   
As of December 31, 2009
  
(In millions)
  
Level 1
    
Level 2
    
Level 3
    
Total
  
                         
Domestic equities & equity funds
   $ 46.5     $ 48.3     $ -     $ 94.8  
International equities & equity funds
     23.1       -       -       23.1  
Domestic bonds & bond funds
     31.1       42.4       -       73.5  
Inflation protected security fund
     -       8.0       -       8.0  
Real estate, commodities & other
     5.3       6.8       3.6       15.7  
Total Plan Investments
   $ 106.0     $ 105.5     $ 3.6     $ 215.1  

A roll forward of the fair value of the guaranteed annuity contract calculated using Level 3 valuation assumptions follows:
             
(In millions)
  
2010
    
2009
  
Fair value, beginning of year
   $ 3.6     $ 3.5  
Unrealized gains related to
   investments still held at reporting date
     0.2       0.2  
Purchases, sales and settlements, net
     (0.1 )     (0.1 )
Fair value, end of year
   $ 3.7     $ 3.6  
 
Funded Status
The funded status of the plans as of December 31, 2010 and 2009 follows:
                         
   
Pension Benefits
    
Other Benefits
  
(In millions)
  
2010
    
2009
    
2010
    
2009
  
Qualified Plans
                        
  Benefit obligation, end of period
   $ (285.5 )   $ (256.8 )   $ (80.7 )   $ (79.6 )
  Fair value of plan assets, end of period
     237.2       211.1       3.1       4.0  
  Funded Status of Qualified Plans, end of period
     (48.3 )     (45.7 )     (77.6 )     (75.6 )
  Benefit obligation of SERP Plan, end of period
     (11.8 )     (14.7 )     -       -  
  Total funded status, end of period
   $ (60.1 )   $ (60.4 )   $ (77.6 )   $ (75.6 )
  Accrued liabilities
   $ 0.7     $ 6.0     $ 4.6     $ 4.5  
  Deferred credits & other liabilities
   $ 59.4     $ 54.4     $ 73.0     $ 71.1  
 
Expected Cash Flows
In 2011, the Company expects to make contributions of approximately $35 million to its pension plan trusts.  In addition, the Company expects to make payments totaling approximately $0.7 million directly to SERP participants and approximately $4.6 million directly to those participating in other postretirement plans.

Estimated retiree pension benefit payments, including the SERP, projected to be required during the years following 2010 (in millions) are approximately $15.4 in 2011, $16.1 in 2012 $16.9 in 2013, $17.6 in 2014, $18.5 in 2015 and $111.7 in years 2016-2020.  Expected benefit payments projected to be required for postretirement benefits during the years following 2010 (in millions) are approximately $7.6 in 2011, $8.1 in 2012, $8.6 in 2013, $9.1 in 2014, and $9.5 in 2015 and $55.2 in years 2016-2020.

Prior Service Cost, Actuarial Gains and Losses, and Transition Obligation Effects

Following is a roll forward of prior service cost, actuarial gains and losses, and transition obligations.
                               
(In millions)
  
Pensions
    
Other Benefits
  
   
Prior Service Cost
    
Net Gain or Loss
    
Prior Service Cost
    
Net Gain or Loss
    
Transition Obligation
  
Balance January 1, 2008
   $ 11.2     $ 11.9     $ (4.7 )   $ (1.1 )   $ 7.6  
Amounts arising during the period
     0.4       79.1       -       4.6       -  
Reclassification to benefit costs
     (2.1 )     (0.1 )     1.0       -       (1.4 )
Balance December 31, 2008
     9.5       90.9       (3.7 )     3.5       6.2  
Amounts arising during the period
     0.1       (20.2 )     0.1       6.6       (0.1 )
Reclassification to benefit costs
     (1.7 )     (2.2 )     0.8       (0.4 )     (1.1 )
Balance December 31, 2009
   $ 7.9     $ 68.5     $ (2.8 )   $ 9.7     $ 5.0  
Amounts arising during the period
     0.8       12.9       -       1.1       -  
Reclassification to benefit costs
     (1.6 )     (3.2 )     0.8       (0.5 )     (1.2 )
Balance December 31, 2010
   $ 7.1     $ 78.2     $ (2.0 )   $ 10.3     $ 3.8  

The 2008 roll forwards of prior service cost, actuarial gains and losses, and transition obligations include 15 months of activity due to moving the measurement date from September 30 to December 31.

Following is a reconciliation of the amounts in Accumulated other comprehensive income (AOCI) and Regulatory assets related to retirement plan obligations at December 31, 2010 and 2009:
                         
(In millions)
  
2010
    
2009
  
   
Pensions
    
Other Benefits
    
Pensions
    
Other Benefits
  
Prior service cost
   $ 7.1     $ (2.0 )   $ 7.9     $ (2.8 )
Unamortized actuarial gain/(loss)
     78.2       10.3       68.5       9.7  
Transition obligation
     -       3.8       -       5.0  
      85.3       12.1       76.4       11.9  
Less: Regulatory asset deferral
     (81.0 )     (11.5 )     (72.6 )     (11.3 )
AOCI before taxes
   $ 4.3     $ 0.6     $ 3.8     $ 0.6  
 
Related to pension plans, $1.7 million of prior service cost and $3.8 million of actuarial gain/loss is expected to be amortized to cost in 2011.  Related to other benefits, $1.1 million of the transition obligation and $0.6 million of actuarial gain/loss is expected to be amortized to periodic cost in 2011, and $0.8 million of prior service cost is expected to reduce cost in 2011.

Multiemployer Benefit Plan
One of the company’s subsidiaries, Miller Pipeline LLC (Miller), participates in several industry-wide, multi-employer pension plans for its union employees which provide for monthly benefits based on length of service. The expense for these plans amounted to $10.0 million, $8.8 million, and $7.6 million for the years ended December 31, 2010, 2009, and 2008, respectively. The relative position of each employer participating in these plans with respect to the actuarial present value of accumulated plan benefits and net assets available for benefits is not readily available.

Defined Contribution Plan
The Company also has defined contribution retirement savings plans that are qualified under sections 401(a) and 401(k) of the Internal Revenue Code and include an option to invest in Vectren common stock, among other alternatives.  During 2010, 2009 and 2008, the Company made contributions to these plans of $6.6 million, $4.6 million, and $4.1 million, respectively.

10.  
Borrowing Arrangements

Short-Term Borrowings
At December 31, 2010, the Company has $600 million of short-term borrowing capacity, including $350 million for the Utility Group and $250 million for the wholly owned Nonutility Group and corporate operations.  As reduced by borrowings currently outstanding, approximately $303 million was available for the Utility Group operations and approximately $179 million was available for the wholly owned Nonutility Group and corporate operations. 
 
Both Vectren Capital’s and Utility Holdings’ short-term credit facilities were renewed on September 30, 2010 and are available through September 2013.  During the renewal process, the Company lowered the level of capacity.  The short-term borrowing facilities were lowered from $515 million to $350 million for the Utility Group and from $255 million to $250 million for the Nonutility Group.  In addition, the Nonutility Group had a $120 million one year credit facility that expired in 2009 and was not renewed.  The Company has historically funded the short-term borrowing needs of Utility Holdings’ operations through the commercial paper market and expects to use the Utility Holdings short-term borrowing facility in instances where the commercial paper market is not efficient. 

Following is certain information regarding these short-term borrowing arrangements.
                                     
   
Utility Group Borrowings
    
Nonutility Group Borrowings
  
(In millions)
  
2010
    
2009
    
2008
    
2010
    
2009
    
2008
  
Year End
                                    
Balance Outstanding
   $ 47.0     $ 16.4     $ 191.9     $ 71.3     $ 197.1     $ 327.5  
Weighted Average Interest Rate
     0.41 %     0.25 %     2.68 %     2.01 %     0.60 %     1.54 %
Annual Average
                                                
Balance Outstanding
   $ 14.0     $ 29.2     $ 178.3     $ 143.2     $ 151.8     $ 208.8  
Weighted Average Interest Rate
     0.40 %     1.28 %     3.71 %     0.93 %     0.78 %     3.19 %
Maximum Month End Balance Outstanding
   $ 47.0     $ 151.1     $ 338.0     $ 174.6     $ 256.5     $ 327.5  
 
In 2008, the Company’s access to longer term commercial paper was significantly reduced as a result of the turmoil and volatility in the financial markets.  As a result, the Company met short-term financing needs through a combination of A-2/P-2 commercial paper issuances and draws on Utility Holdings’ back-up credit facility.  At December 31, 2008, borrowings outstanding were comprised of $100.4 million of bank loans at a weighted average interest rate of 1.56% and $91.5 million of commercial paper at a weighted average interest rate of 3.87%.  The average annual balance outstanding in 2008 was comprised of $28.1 million of bank loans at a weighted average interest rate of 3.42% and $150.2 million of commercial paper at a weighted average interest rate of 3.76%.  Throughout 2010 and most of 2009, the Company has placed commercial paper without any significant issues and only had to borrow from its backup credit facility in 2009 in early 2009 on a limited basis.
 
Long-Term Debt
Long-term senior unsecured obligations and first mortgage bonds outstanding by subsidiary follow:
     
At December 31,
(In millions)
2010
  
2009
Utility Holdings
      
 
Fixed Rate Senior Unsecured Notes
      
   
2011, 6.625%
 $          250.0
  
 $        250.0
   
2013, 5.25%
              100.0
  
           100.0
   
2015, 5.45%
                75.0
  
             75.0
   
2018, 5.75%
              100.0
  
           100.0
   
2020, 6.28%
              100.0
  
           100.0
   
2035, 6.10%
                75.0
  
             75.0
   
2036, 5.95%
                96.7
  
             97.8
   
2039, 6.25%
              121.9
  
           122.5
   
Total Utility Holdings
              918.6
  
           920.3
Indiana Gas
      
 
Fixed Rate Senior Unsecured Notes
      
   
2013, Series E, 6.69%
                  5.0
  
                5.0
   
2015, Series E, 7.15%
                  5.0
  
                5.0
   
2015, Series E, 6.69%
                  5.0
  
                5.0
   
2015, Series E, 6.69%
                10.0
  
             10.0
   
2025, Series E, 6.53%
                10.0
  
             10.0
   
2027, Series E, 6.42%
                  5.0
  
                5.0
   
2027, Series E, 6.68%
                  1.0
  
                1.0
 
 
2027, Series F, 6.34%
                20.0
  
             20.0
   
2028, Series F, 6.36%
                10.0
  
             10.0
   
2028, Series F, 6.55%
                20.0
  
             20.0
   
2029, Series G, 7.08%
                30.0
  
             30.0
   
Total Indiana Gas
              121.0
  
           121.0
SIGECO
      
 
First Mortgage Bonds
      
   
2015, 1985 Pollution Control Series A, current adjustable rate 0.33%, tax exempt,
   
    2010 weighted average: 0.27%
                  9.8
  
                9.8
   
2016, 1986 Series, 8.875%
                13.0
  
             13.0
   
2020, 1998 Pollution Control Series B, 4.50%, tax exempt
                  4.6
  
                4.6
   
2023, 1993 Environmental Improvement Series B, 5.15%, tax exempt
                22.6
  
             22.6
   
2024, 2000 Environmental Improvement Series A, 4.65%, tax exempt
                22.5
  
             22.5
   
2025, 1998 Pollution Control Series A, current adjustable rate 0.33%, tax exempt,
   
    2010 weighted average: 0.27%
                31.5
  
             31.5
   
2029, 1999 Senior Notes, 6.72%
                80.0
  
             80.0
   
2030, 1998 Pollution Control Series B, 5.00%, tax exempt
                22.0
  
             22.0
   
2030, 1998 Pollution Control Series C, 5.35%, tax exempt
                22.2
  
             22.2
   
2040, 2009 Environmental Improvement Series, 5.40%, tax exempt
                22.3
  
             22.3
   
2041, 2007 Pollution Control Series, 5.45%, tax exempt
                17.0
  
             17.0
   
Total SIGECO
              267.5
  
           267.5
 
 
-82-

     
At December 31,
(In millions)
2010
  
2009
Vectren Capital Corp.
      
 
Fixed Rate Senior Unsecured Notes
      
   
2010, 4.99%
                     -
  
             25.0
   
2010, 7.98%
                     -
  
             22.5
   
2012, 5.13%
                25.0
  
             25.0
   
2012, 7.43%
                35.0
  
             35.0
   
2014, 6.37%
                30.0
  
             30.0
   
2015, 5.31%
                75.0
  
             75.0
   
2016, 6.92%
                60.0
  
             60.0
   
2017, 3.48%
                75.0
  
                  -
   
2019, 7.30%
                60.0
  
             60.0
   
2025, 4.53%
                50.0
  
                  -
   
Total Vectren Capital Corp.
              410.0
  
           332.5
Other Long-Term Notes Payable
                  1.1
  
                1.2
Total long-term debt outstanding
          1,718.2
  
        1,642.5
 
Current maturities of long-term debt
            (250.7)
  
            (48.0)
 
Debt subject to tender
              (30.0)
  
            (51.3)
 
Unamortized debt premium & discount - net
                 (2.3)
  
              (2.7)
   
Total long-term debt-net
 $       1,435.2
  
 $    1,540.5
 
Vectren Capital Corp. 2010 Debt Issuance
On December 15, 2010, the Company and Vectren Capital Corp. (Vectren Capital), its wholly-owned subsidiary, executed a private placement Note Purchase Agreement pursuant to which various institutional investors purchased the following tranches of notes from Vectren Capital:  (i) $75 million 3.48% Senior Notes, Series A due 2017, and (ii) $50 million 4.53% Senior Notes, Series B due 2025.  These Senior Notes are unconditionally guaranteed by Vectren.  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 $124.2 million.  The notes contain customary representations, warranties and covenants, including a leverage covenant consistent with leverage covenants contained in o ther Vectren Capital borrowing arrangements.

Vectren Capital Corp. 2009 Debt Issuance
On March 11, 2009, Vectren and Vectren Capital, executed 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 representation s, warranties and covenants, including a leverage covenant consistent with that contained in other Vectren Capital borrowing arrangements.  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.

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 other Ut ility Holdings’ borrowing arrangements.

SIGECO 2009 Debt Issuance
On August 19, 2009 SIGECO also completed a $22.3 million tax-exempt first mortgage bond issuance at an interest rate of 5.4 percent that is fixed through maturity.  The bonds mature in 2040.  The proceeds from the sale of the bonds, net of issuance costs, totaled approximately $21.3 million.

Long-Term Debt Put and Call Provisions
Certain long-term debt issues contain put and call provisions that can be exercised on various dates before maturity.  Other than certain instruments that can be put to the Company upon the death of the holder (death puts), these put or call provisions are not triggered by specific events, but are based upon dates stated in the note agreements.  During 2010, 2009, and 2008, the Company repaid approximately $1.8 million, $3.0 million, and $1.6 million, respectively, related to death puts.  Debt which may be put to the Company for reasons other than a death during the years following 2010 (in millions) is $30.0 in 2011, zero in 2012 and thereafter.  Investors had the one-time option to put $10 million in May 2010; however, no notice was received during the notification period and such debt is classifi ed as long-term at December 31, 2010.  Debt that may be put to the Company within one year or debt that is supported by lines of credit that expire within one year are classified as Long-term debt subject to tender in current liabilities.

Utility Holdings 2008 Debt Issuance
In March 2008, Utility Holdings issued $125 million in 6.25 percent senior unsecured notes due April 1, 2039 (2039 Notes) at par.  The 2039 Notes are guaranteed by Utility Holdings’ three public utilities:  SIGECO, Indiana Gas, and VEDO.  These guarantees are full and unconditional and joint and several.  The 2039 Notes have no sinking fund requirements and interest payments are due monthly.  The notes may be called by Utility Holdings, in whole or in part, at any time on or after April 1, 2013, at 100 percent of principal amount plus accrued interest.  During 2007, Utility Holdings entered into several interest rate hedges with an $80 million notional amount.  Upon issuance of the notes, these instruments were settled resulting in the payment of approximately $9. 6 million, which was recorded as a Regulatory asset pursuant to existing regulatory orders.  The value paid is being amortized as an increase to interest expense over the life of the issue.  The proceeds from the sale of the 2039 Notes less settlement of the hedging arrangements and payments of issuance costs amounted to approximately $111.1 million.

Auction Rate Securities
In February 2008, SIGECO provided notice to the current holders of approximately $103 million of tax-exempt auction rate mode long-term debt of its plans to convert that debt from its current auction rate mode into a daily interest rate mode.  In March 2008, the debt was tendered at 100 percent of the principal amount plus accrued interest.  During March 2008, SIGECO remarketed approximately $61.8 million of these instruments at interest rates that are fixed to maturity, receiving proceeds, net of issuance costs, of approximately $60.0 million.  The terms are $22.6 million at 5.15 percent due in 2023, $22.2 million at 5.35 percent due in 2030 and $17.0 million at 5.45 percent due in 2041.

On March 26, 2009, SIGECO remarketed the remaining $41.3 million of these obligations, 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.  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.

Future Long-Term Debt Sinking Fund Requirements and Maturities
The annual sinking fund requirement of SIGECO's first mortgage bonds is 1 percent of the greatest amount of bonds outstanding under the Mortgage Indenture.  This requirement may be satisfied by certification to the Trustee of unfunded property additions in the prescribed amount as provided in the Mortgage Indenture.  SIGECO intends to meet the 2010 sinking fund requirement by this means and, accordingly, the sinking fund requirement for 2010 is excluded from Current liabilities in the Consolidated Balance Sheets.  At December 31, 2010, $1.2 billion of SIGECO's utility plant remained unfunded under SIGECO's Mortgage Indenture.  SIGECO’s gross utility plant balance subject to the Mor tgage Indenture approximated $2.6 billion at December 31, 2010.

Consolidated maturities of long-term debt during the five years following 2010 (in millions) are $250.7 in 2011, $60.0 in 2012, $105.0 in 2013, $30.0 in 2014, and $179.8 in 2015.

Debt Guarantees
Vectren Corporation guarantees Vectren Capital’s long-term and short-term debt, which totaled $410 million and $71 million, respectively, at December 31, 2010.  Utility Holdings’ currently outstanding long-term and short-term debt is jointly and severally guaranteed by Indiana Gas, SIGECO, and VEDO.  Utility Holdings’ long-term debt, including current maturities, and short-term debt outstanding at December 31, 2010, totaled $919 million and $47 million, respectively.

Covenants
Both long-term and short-term borrowing arrangements contain customary default provisions; restrictions on liens, sale-leaseback transactions, mergers or consolidations, and sales of assets; and restrictions on leverage and interest coverage, among other restrictions.  As an example, the Vectren Capital’s short-term debt agreement expiring in 2013 contains a covenant that the ratio of consolidated total debt to consolidated total capitalization will not exceed 65 percent.  As of December 31, 2010, the Company was in compliance with all financial covenants.

11.  
Common Shareholders’ Equity

Common Stock Offering
In February 2007, the Company sold 4.6 million authorized but previously unissued shares of its common stock to a group of underwriters in an SEC-registered primary offering at a price of $28.33 per share.  The transaction generated proceeds, net of underwriting discounts and commissions, of approximately $125.7 million.  The Company executed an equity forward sale agreement (equity forward) in connection with the offering, and therefore, did not receive proceeds at the time of the equity offering.  The equity forward allowed the Company to price an offering under market conditions existing at that time, and to better match the receipt of the offering proceeds and the associated share dilution with the implementation of regulatory initiatives.

On June 27, 2008, the Company physically settled the equity forward by delivering the 4.6 million shares, receiving proceeds of approximately $124.9 million.  The slight difference between the proceeds generated by the public offering and those received by the Company were due to adjustments defined in the equity forward agreement including:  1) daily increases in the forward sale price based on a floating interest factor equal to the federal funds rate, less a 35 basis point fixed spread, and 2) structured quarterly decreases to the forward sale price that align with expected Company dividend payments. 

Vectren transferred the proceeds to Utility Holdings, and Utility Holdings used the proceeds to repay short-term debt obligations incurred primarily to fund its capital expenditure program.  The proceeds received were recorded as an increase to Common Stock in Common Shareholders’ Equity and are presented in the Statement of Cash Flows as a financing activity.

Authorized, Reserved Common and Preferred Shares
At December 31, 2010 and 2009, the Company was authorized to issue 480.0 million shares of common stock and 20.0 million shares of preferred stock.  Of the authorized common shares, approximately 5.5 million shares at December 31, 2010 and 6.6 million shares at December 31, 2009, were reserved by the board of directors for issuance through the Company’s share-based compensation plans, benefit plans, and dividend reinvestment plan.  At December 31, 2010 and 2009, there were 392.8 million and 392.3 million, respectively, of authorized shares of common stock and all authorized shares of preferred stock, available for a variety of general corporate purposes, including future public offerings to raise additional capital and for facilitating acquisitions.

12.  
Earnings Per Share

The Company uses the two class method to calculate earnings per share (EPS).  The two class method is an earnings allocation formula that treats a participating security as having rights to earnings that otherwise would have been available to common shareholders.  Under the two-class method, earnings for a period are allocated between common shareholders and participating security holders based on their respective rights to receive dividends as if all undistributed book earnings for the period were distributed.  Basic EPS is computed by dividing net income attributable to only the common shareholders by the weighted-average number of common shares outstanding for the period.  Diluted EPS includes the impact of stock options and other equity based instruments to the extent the effect is dilutive.
 
The following table illustrates the basic and dilutive EPS calculations for the three years ended December 31, 2010:
                   
   
Year Ended December 31,
  
(In millions, except per share data)
  
2010
    
2009
    
2008
  
Numerator:
                  
Numerator for basic EPS
   $ 133.6     $ 132.9     $ 128.8  
Add back earnings attributable to participating securities
     0.1       0.2       0.2  
Reported net income (Numerator for Diluted EPS)
   $ 133.7     $ 133.1     $ 129.0  
                         
Denominator:
                        
Weighted average common shares outstanding (Basic EPS)
     81.2       80.7       78.3  
Equity forward contract
     -       -       0.1  
Conversion of share based compensation arrangements
     0.1       0.3       0.3  
Adjusted weighted average shares outstanding and
                        
assumed conversions outstanding (Diluted EPS)
     81.3       81.0       78.7  
                         
Basic earnings per share
   $ 1.65     $ 1.65     $ 1.65  
Diluted earnings per share
   $ 1.64     $ 1.64     $ 1.63  

For the year ended December 31, 2010 and 2009, options to purchase 308,800 and 837,100, 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 $24.90 to $27.15 and $23.19 to $27.15 for the years ended December 31, 2010 and 2009, respectively.  For the year ended December 31, 2008, all options were dilutive.

13.  
Accumulated Other Comprehensive Income

A summary of the components of and changes in Accumulated other comprehensive income for the past three years follows:
                                           
   
2008
    
2009
    
2010
  
   
Beginning
  
Changes
    
End
    
Changes
    
End
    
Changes
    
End
  
   
of Year
  
During
    
of Year
  
During
    
of Year
  
During
    
of Year
  
(In millions)
  
Balance
  
Year
    
Balance
  
Year
    
Balance
  
Year
    
Balance
  
                                           
Unconsolidated affiliates
   $ 21.2     $ (50.2 )   $ (29.0 )   $ 21.9     $ (7.1 )   $ 0.5     $ (6.6 )
Pension & other benefit costs
     (1.3 )     (4.0 )     (5.3 )     0.9       (4.4 )     (0.5 )     (4.9 )
Cash flow hedges
     0.6       (0.5 )     0.1       -       0.1       3.9       4.0  
Deferred income taxes
     (8.0 )     21.9       13.9       (9.3 )     4.6       (1.5 )     3.1  
Accumulated other comprehensive income (loss)
   $ 12.5     $ (32.8 )   $ (20.3 )   $ 13.5     $ (6.8 )   $ 2.4     $ (4.4 )
 
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 5 for more information on ProLiance.)

14.  
Share-Based Compensation & Deferred Compensation Arrangements

The Company has various share-based compensation programs to encourage executives, key non-officer employees, and non-employee directors to remain with the Company and to more closely align their interests with those of the Company’s shareholders.  Under these programs, the Company issues stock options, non-vested shares (herein referred to as restricted stock), and restricted stock units.  All share-based compensation programs are shareholder approved.  In addition, the Company maintains a deferred compensation plan for executives and non-employee directors where participants have the option to invest earned compensation and vested restricted stock and restricted units in phantom Company stock units.  Certain option and share awards provide for accelerated vesting if there is a change in cont rol or upon the participant’s retirement.

Following is a reconciliation of the total cost associated with share-based awards recognized in the Company’s financial statements to its after tax effect on net income:
                   
   
Year ended December 31,
  
(In millions)
  
2010
    
2009
    
2008
  
Total cost of share-based compensation
   $ 4.9     $ 4.6     $ 3.7  
Less capitalized cost
     1.7       1.6       0.9  
Total in other operating expense
     3.2       3.0       2.8  
Less income tax benefit in earnings
     1.3       1.2       1.1  
After tax effect of share-based compensation
   $ 1.9     $ 1.8     $ 1.7  

Restricted Stock & Restricted Stock Unit Plans
The Company periodically grants restricted stock and/or restricted stock units to executives and other key non-officer employees.  The vesting of those grants is contingent upon meeting a total return and/or return on equity performance objectives.  In addition non-employee directors receive a portion of their fees in restricted stock.  Grants to executives and key non-officer employees generally vest at the end of a four-year period, with performance measured at the end of the third year.  Based on that performance, awards could double or could be entirely forfeited.  However, a limited number of awards are time-vested awards that vest ratably over a three year period.  Awards to non-employee directors are not performance based and generally vest over one year.  Because exe cutives and non-employee directors have the choice of settling awards in shares, cash, or deferring their receipt into a deferred compensation plan (where the value is eventually withdrawn in cash), these awards are accounted for as liability awards at their settlement date fair value.  Certain share awards to key non-officer employees must be settled in shares and are therefore accounted for in equity at their grant date fair value.

A summary of the status of the Company’s restricted stock and restricted unit awards separated between those accounted for as liabilities and equity as of December 31, 2010, and changes during the year ended December 31, 2010, follows:


                     
   
Equity Awards
          
         
Wtd. Avg.
          
         
Grant Date
    
Liability Awards
   
Shares
    
Fair value
    
Shares/Units
  
Fair value
Restricted awards at January 1, 2010
     38,913     $ 27.55       606,353    
Granted
     15,608       24.87       317,003    
Vested
     (9,825 )     29.17       (201,971 )  
Forfeited
     (3,238 )     27.07       (52,493 )  
Restricted awards at December 31, 2010
     41,458     $ 26.19       668,892  
 $           25.38

As of December 31, 2010, there was $6.9 million of total unrecognized compensation cost related to restricted stock awards.  That cost is expected to be recognized over a weighted-average period of 2.2 years.  The total fair value of shares vested for liability awards during the years ended December 31, 2010, 2009, and 2008, was $5.0 million, $2.8 million, and $0.4 million, respectively.  The total fair value of equity awards vesting during the year ended December 31, 2010 and 2009 was $0.2 million and $0.1 million, respectively.  No equity awards vested in 2008.

Stock Option Plans
In the past, option awards were granted to executives and other key employees with an exercise price equal to the market price of the Company’s stock at the date of grant; those option awards generally required 3 years of continuous service and have 10-year contractual terms.  These awards generally vested on a pro-rata basis over 3 years.  The last option grant occurred in 2005, and the Company does not intend to issue options in the future.  All compensation cost has been recognized.  
 
A summary of the status of the Company’s stock option awards as of December 31, 2010, and changes during the year ended December 31, 2010, follows:

         
Weighted average
    
Aggregate
  
               
Remaining
    
Intrinsic
  
   
Shares
    
Exercise
    
Contractual
    
Value
  
         
Price
    
Term (years)
    
(In millions)
  
                         
Outstanding at January 1, 2010
     1,329,562     $ 23.97              
Exercised
     (398,182 )   $ 22.62              
Forfeited or expired
     (1,574 )   $ 25.39              
Outstanding at December 31, 2010
     929,806     $ 24.55       2.7     $ 1.1  
                                 
Exercisable at December 31, 2010
     929,806     $ 24.55       2.7     $ 1.1  

The total intrinsic value of options exercised during the year ended December 31, 2010 and 2008 was $1.3 million and $0.5 million, respectively.  The actual tax benefit realized for tax deductions from option exercises was approximately $0.5 million in 2010 and $0.1 million in 2008.

The Company periodically issues new shares and also from time to time repurchases shares to satisfy share option exercises.  During the year ended December 31, 2010, the Company received cash upon exercise of stock options totaling approximately $9.5 million.  During this period, the Company repurchased shares totaling approximately $1.2 million.  During 2008, the Company received cash upon exercise of stock options totaling approximately $1.9 million and repurchased shares totaling approximately $2.2 million.  During the year ended December 31, 2009, stock option activity was insignificant.

The fair value of option awards granted in prior years was estimated on the date of grant using a Black-Scholes option valuation model.  Expected volatilities were based on historical volatility of the Company’s stock and other factors.  The Company used historical data to estimate the expected term and forfeiture patterns of the options.  The risk-free rate for periods within the contractual life of the option was based on the U.S. Treasury yield curve in effect at the time of grant.

Deferred Compensation Plans
The Company has nonqualified deferred compensation plans, which permit eligible executives and non-employee directors to defer portions of their compensation and vested restricted stock or units.  A record keeping account is established for each participant, and the participant chooses from a variety of measurement funds for the deemed investment of their accounts.  The measurement funds are similar to the funds in the Company's defined contribution plan and include an investment in phantom stock units of the Company.  The account balance fluctuates with the investment returns on those funds.  At December 31, 2010 and 2009, the liability associated with these plans totaled $19.1 million and $22.8 million, respectively.  Other than $0.5 million and $6.6 million which are classified in Accrued liabilities at December 31, 2010 and 2009, respectively, the liability is included in Deferred credits & other liabilities.  The impact of these plans on Other operating expenses was expense of $2.3 million in 2010, $0.8 million in 2009 and income of $2.6 million in 2008.  The amount recorded in earnings related to the investment activities in Vectren phantom stock associated with these plans during the years ended December 31, 2010, 2009, and 2008, was a cost of $1.6 million, a benefit of $1.5 million and a cost of $0.6 million, respectively.

The Company has certain investments currently funded primarily through corporate-owned life insurance policies.  These investments, which are consolidated, are available to pay deferred compensation benefits.  These investments are also subject to the claims of the Company's creditors.  The cash surrender value of these policies included in Other corporate & utility investments on the Consolidated Balance Sheets were $27.5 million and $24.7 million at December 31, 2010 and 2009, respectively.  Earnings from those investments, which are recorded in Other-net, were earnings $1.9 million in 2010, earnings of $4.1 million in 2008, and a loss of $2.8 million in 2008. 

15.  
Commitments & Contingencies

Commitments
Future minimum lease payments required under operating leases that have initial or remaining noncancelable lease terms in excess of one year during the five years following 2010 and thereafter (in millions) are $4.1 in 2011, $2.7 in 2012, $1.8 in 2013, $1.2 in 2014, $0.5 in 2015, and $0.1 thereafter.  Total lease expense (in millions) was $7.3 in 2010, $8.0 in 2009, and $8.8 in 2008.

Firm nonutility purchase commitments for commodities total (in millions) $11.8 in 2011, $2.9 in 2012, $1.4 in 2013, zero in 2014 and 2015.  Firm nonutility commitments for transportation and storage capacity total (in millions) $4.2 in 2011, $4.1 in 2012, $3.8 in 2013, $1.8 in 2014, $0.8 in 2015, and $3.2 thereafter.

The Company’s regulated utilities have both firm and non-firm commitments to purchase natural gas, electricity, and coal as well as certain transportation and storage rights.  Costs arising from these commitments, while significant, are pass-through costs, generally collected dollar-for-dollar from retail customers through regulator-approved cost recovery mechanisms.

Corporate Guarantees
The Company issues corporate guarantees to certain vendors and customers of its wholly owned subsidiaries and unconsolidated affiliates.  These guarantees do not represent incremental consolidated obligations; rather, they represent parental guarantees of subsidiary and unconsolidated affiliate obligations in order to allow those subsidiaries and affiliates the flexibility to conduct business without posting other forms of collateral.  At December 31, 2010, corporate issued guarantees support a maximum of $25 million of ESG’s performance contracting commitments and warranty obligations and $29 million of other project guarantees described below.  In addition, the Company has approximately $75 million of other guarantees outstanding supporting other consolidated subsidiary operations, of which $51 millio n support the operations of Vectren Source, a wholly owned non-regulated retail gas marketer and $17 million represent letters of credit supporting other nonutility operations.  Guarantees issued and outstanding on behalf of unconsolidated affiliates approximated $3 million at December 31, 2010.  These guarantees relate primarily to arrangements between ProLiance and various natural gas pipeline operators.  The Company has not been called upon to satisfy any obligations pursuant to these parental guarantees and has accrued no significant liabilities related to these guarantees.

Performance Guarantees & Product Warranties
In the normal course of business, ESG, Miller, and other wholly owned subsidiaries issue performance bonds or other forms of assurance that commit them to timely install infrastructure, operate facilities, pay vendors or subcontractors, and/or support warranty obligations.  Based on a history of meeting performance obligations and installed products operating effectively, no significant liability or cost has been recognized for the periods presented.

Specific to ESG, in its role as a general contractor in the performance contracting industry, at December 31, 2010, there are 70 open surety bonds supporting future performance.  The average face amount of these obligations is $4.2 million, and the largest obligation has a face amount of $30.4 million. The maximum exposure of these obligations is less than these amounts for several factors, including the level of work already completed.  At December 31, 2010, over 57 percent of work was completed on projects with open surety bonds.  A significant portion of these commitments will be fulfilled within one year.  In instances where ESG operates facilities, project guarantees extend over a longer period.  In addition to its performance obligations, ESG also warrants the functionality of certai n installed infrastructure generally for one year and the associated energy savings over a specified number of years.  The Company has no significant accruals for these warranty obligations as of December 31, 2010.

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

16.  
Environmental Matters

Clean Air Act
The Clean Air Interstate Rule (CAIR) is an allowance cap and trade program that required reductions from coal-burning power plants for NOx emissions beginning January 1, 2009 and SO2 emissions beginning January 1, 2010, with a second phase of reductions in 2015.  On July 11, 2008, the US Court of Appeals for the District of Columbia vacated the federal CAIR regulations.  Various parties filed motions for reconsideration, and on December 23, 2008, the Court reinstated the CAIR regulations and remanded the regulations back to the EPA 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 EPA revises it per the Court’s guidance.  SIGECO is in compliance with the current CAIR Phase I annual NOx reduction requirements in effect on January 1, 2009, and the Phase I annual SO2 reduction requirements in effect on January 1, 2010.  Utilization of the Company’s inventory of NOx and SO2  allowances may also be impacted if CAIR is further revised.  Most of these allowances were granted to the Company at zero cost; therefore, any reduction in carrying value that could result from future changes in regulations would be immaterial.

Similarly, in March of 2005, EPA promulgated the Clean Air Mercury Rule (CAMR).  CAMR is an allowance cap and trade program requiring further reductions in mercury emissions from coal-burning power plants.  The CAMR regulations were vacated by the US Court of Appeals for the DC Circuit in July 2008.  In response to the court decision, EPA has announced that it intends to publish proposed Maximum Achievable Control Technology standards for mercury in 2011.  It is uncertain what emission limit the EPA is considering, and whether they will address hazardous pollutants in addition to mercury.

To comply with Indiana’s implementation plan of the Clean Air Act of 1990, the CAIR regulations, and to comply with potential future regulations of mercury and further NOx and SO2  reductions, SIGECO has IURC authority to invest in clean coal technology.  Using this authorization, SIGECO has invested approximately $411 million in pollution control equipment, including Selective Catalytic Reduction (SCR) systems, fabric filters, and an SO2 scrubber at its generating facility that is jointly owned with ALCOA (the Company&# 8217;s portion is 150 MW).  SCR technology is the most effective method of reducing NOx emissions where high removal efficiencies are required and fabric filters control particulate matter emissions.  Of the $411 million, $312 million was included in rate base for purposes of determining SIGECO’s new electric base rates that went into effect on August 15, 2007, and $99 million is currently recovered through a rider mechanism which is periodically updated for actual costs incurred including depreciation expense. As part of its recent rate proceeding, the Company has requested to also include these more recent expenditures in rate base as well.

SIGECO’s coal fired generating fleet is 100 percent scrubbed for SO2 and 90 percent controlled for NOx.  SIGECO's investments in scrubber, SCR, and fabric filter technology allows for compliance with existing regulations and should position it to comply with future reasonable mercury pollution control legislation, if and when, reductions are promulgated by EPA.  On July 6, 2010, the EPA issued its proposed revisions to CAIR, renamed the Clean Air Transport Rule, for public comment.  The Transport Rule proposes a 71 percent reduction of SO2 over 2005 national levels and a 52 percent reduction of NOx over 2005 national levels and would further impact the utili zation of currently granted SO2 and NOx allowances.  The Company is currently reviewing the sufficiency of its existing pollution control equipment in relation to the requirements proposed in the Clean Air Transport Rule and currently does not expect significant capital expenditures will be required to comply if the Transport Rule is adopted in its current form.

Climate Change
Numerous competing legislative proposals have also been introduced in recent years that involve carbon, energy efficiency, and renewable energy.  Comprehensive energy legislation at the federal level continues to be debated, but there has been little progress to date.  The progression of regional initiatives throughout the United States has slowed.  While no climate change legislation is pending in Indiana, the state is an observer to the Midwestern Regional Greenhouse Gas Reduction Accord and the state’s legislature debated, but did not pass, a renewable energy portfolio standard in 2009.

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

In April of 2007, the US Supreme Court determined that greenhouse gases meet the definition of "air pollutant" under the Clean Air Act and ordered the EPA to determine whether greenhouse gas emissions from motor vehicles cause or contribute to air pollution that may reasonably be anticipated to endanger public health or welfare. In April of 2009, the EPA published its proposed endangerment finding for public comment.  The proposed endangerment finding concludes that carbon emissions from mobile sources pose an endangerment to public health and the environment.  The endangerment finding was finalized in December of 2009, and is the first step toward EPA regulating carbon emissions through the existing Clean Air Act in the absence of specific carbon legislation from Congress.  Therefore, any new regulations wou ld likely also impact major stationary sources of greenhouse gases.  The EPA has promulgated two greenhouse gas regulations that apply to SIGECO’s generating facilities.  In 2009, the EPA finalized a mandatory greenhouse gas emissions registry which will require reporting of emissions beginning in 2011 (for the emission year 2010).  The EPA has also recently finalized a revision to the Prevention of Significant Deterioration (PSD) and Title V permitting rules which would require facilities that emit 75,000 tons or more of greenhouse gases a year to obtain a PSD permit for new construction or a significant modification of an existing facility.

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

Ash Ponds & Coal Ash Disposal Regulations
In June 2010, the EPA issued proposed regulations affecting the management and disposal of coal combustion products, such as ash generated by the Company’s coal-fired power plants.  The proposed rules more stringently regulate these byproducts and would likely increase the cost of operating or expanding existing ash ponds and the development of new ash ponds.  The EPA did not offer a preferred alternative, but is taking public comment on multiple alternative regulations.  The alternatives include regulating coal combustion by-products as hazardous waste.  At this time, the majority of the Company’s ash is being beneficially reused.  The proposals offered by EPA allow for the beneficial reuse of ash in certain circumstances.  The Company estimates capital expenditures to comply could be as much as $30 million, and such expenditures could exceed $100 million if the most stringent of the alternatives is selected.  Annual compliance costs could increase slightly or be impacted by as much as $5 million.

Clean Water Act
Section 316(b) of the Clean Water Act requires that generating facilities use the “best technology available” to minimize adverse environmental impacts.  More specifically, Section 316(b) is concerned with impingement and entrainment of aquatic species in once-through cooling water intake structures.  In April of 2009, the U.S. Supreme Court affirmed that the EPA could, but was not required to, consider costs and benefits in making the evaluation as to the best technology available for existing facilities.  The regulation was remanded back to the EPA for further consideration.  Depending upon the approaches taken by the EPA when it reissues the regulation, capital investments could be in the $40 million range if new infrastructure, such as new cooling water towers, is required.

Jacobsville Superfund Site
On July 22, 2004, the EPA listed the Jacobsville Neighborhood Soil Contamination site in Evansville, Indiana, on the National Priorities List under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA).  The EPA has identified four sources of historic lead contamination.  These four sources shut down manufacturing operations years ago.  When drawing up the boundaries for the listing, the EPA included a 250 acre block of properties surrounding the Jacobsville neighborhood, including Vectren's Wagner Operations Center.  Vectren's property has not been named as a source of the lead contamination.  Vectren's own soil testing, completed during the construction of the Operations Center, did not indicate that the Vectren property contains lead contaminated soils above industrial cleanup levels.  At this time, it is anticipated that the EPA may request only additional soil testing at some future date.

Environmental Remediation Efforts
In the past, Indiana Gas, SIGECO, and others operated facilities for the manufacture of gas.  Given the availability of natural gas transported by pipelines, these facilities have not been operated for many years.  Under currently applicable environmental laws and regulations, those that owned or operated these facilities may now be required to take remedial action if certain contaminants are found above the regulatory thresholds at these sites.

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

Indiana Gas accrued the estimated costs for further investigation, remediation, groundwater monitoring, and related costs for the sites.  While the total costs that may be incurred in connection with addressing these sites cannot be determined at this time, Indiana Gas has recorded cumulative costs that it reasonably expects to incur totaling approximately $23.1 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 received approximately $20.8 million from all known insurance carriers under insu rance policies in effect when these plants were in operation.

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

SIGECO has recorded cumulative costs that it reasonably expects to incur related to these environmental matters, including the recent settlement discussed above, totaling approximately $15.8 million.  However, the total costs that may be incurred in connection with addressing all of these sites cannot be determined at this time.  With respect to insurance coverage, SIGECO has recorded approximately $14.1 million of expected insurance recoveries from certain of its insurance carriers under insurance policies in effect when these sites were in operation.  While negotiations are ongoing with certain carriers, settlements have been reached with some carriers and $8.2 million in proceeds have been received.

The costs the Company expects to incur are estimated by management using assumptions based on actual costs incurred, the timing of expected future payments, and inflation factors, among others.  While the Company’s utilities have recorded all costs which they presently expect to incur in connection with activities at these sites, it is possible that future events may require some level of additional remedial activities which are not presently foreseen and those costs may not be subject to PRP or insurance recovery.  As of December 31, 2010 and 2009, respectively, approximately $5.5 million and $6.5 million of accrued, but not yet spent, costs are included in Other Liabilities related to both the Indiana Gas and SIGECO sites.

17.  
Rate & Regulatory Matters

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

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

During 2010, as part of its FAC testimony, the OUCC requested the IURC require Vectren South to renegotiate its term coal contracts because they were priced higher than prevailing spot prices.  This request was repeated by the OUCC in Vectren South’s base rate proceeding referred to above.  Vectren South purchases the majority of its coal from Vectren Fuels, Inc. (a nonutility wholly owned subsidiary of the Company) under coal contracts entered into in 2008.  Vectren South states in its rate case testimony that the prices in the coal contracts were at or below the market at the time of contract execution and were subject to a bidding process that included third parties.  Further, the Company has already engaged in contract renegotiations to defer certain deliveries, and to eliminate some volum es in 2011, with further price negotiation to occur in 2011 under the terms of the contracts.  The IURC has already found in a number of FAC proceedings since 2008, including in its most recent FAC order dated November 4, 2010, that the costs incurred under these coal contracts are reasonable.

The OUCC also raised concerns regarding Vectren South’s generating unit “must run” policy.  Under that policy, for reliability reasons, Vectren South instructs the MISO that certain units must be dispatched regardless of current market conditions.  The OUCC is reviewing data related to Vectren South’s “must run” policy.

The parties agreed to the creation of an FAC sub docket proceeding to address the specific issues noted above.  An order establishing the sub docket was issued by the IURC on July 28, 2010.  On November 30, 2010, in response to a joint motion filed by the OUCC and Vectren South, the IURC issued an order dismissing this sub docket as these coal contract issues will be addressed in the pending Vectren South Electric base rate case.

Vectren South Electric Demand Side Management Program Filing
On August 16, 2010, Vectren South filed a petition with the IURC, seeking approval of its proposed Demand Side Management (DSM) Programs, recovery of the costs associated with these programs, recovery of lost margins as a result of implementing these programs for large customers, and recovery of performance incentives linked with specific measurement criteria on all programs.  The DSM Programs proposed are consistent with a December 9, 2009 order issued by the IURC, which, among other actions, defined long-term conservation objectives and goals of DSM programs for all Indiana electric utilities under a consistent statewide approach.  In order to meet these objectives, the IURC order divided the DSM programs into Core and Core Plus programs.  Core programs are joint programs required to be offered by all India na electric utilities to all customers, including large industrial customers.  Core Plus programs are those programs not required specifically by the IURC, but defined by each utility to meet the overall energy savings targets defined by the IURC.

In its August filing, Vectren South proposed a three-year DSM Plan that expands its current portfolio of Core and Core Plus DSM Programs in order to meet the energy savings goals established by the IURC.  Vectren South requested recovery of these program costs under a current tracking mechanism.  In addition, Vectren South proposed a performance incentive mechanism that is contingent upon the success of each of the DSM Programs in reducing energy usage to the levels defined by the IURC.  This performance incentive would also be recovered in the same tracking mechanism.  Finally, the Company proposed lost margin recovery associated with the implementation of DSM programs for large customers, and cited its decoupling proposal applicable to residential and general service customers in the pending elect ric base rate case.  On January 20, 2011, the OUCC and Vectren South filed a settlement with the IURC reflecting agreement on the Company’s programs and lost margin recovery from large customers.  A hearing will be held on March 8, 2011 involving all parties to this proceeding.

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 for residential customers which places 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 decoupling 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 the decoupling mechanism that did not continue once this base rate increase went into effect.  Since the straight fixed variable rate design was fully implemented in February 2010, nearly 90 percent of the combined residential and commercial base rate margins were recovered through the customer service charge.  The OCC appealed this rate order to the Ohio Supreme Court, which had affirmed PUCO orders authorizing straight fixed variable rate design in two other cases. On December 23, 2010, the Ohio Supreme Court affirmed the PUCO order authorizing straight fixed variable rate design in VEDO’s case. 

With this rate order, the Company has in place for its Ohio gas territory rates that allow for a straight fixed variable rate design that mitigates both weather risk and lost margin for residential customers; tracking of uncollectible accounts 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.

VEDO Continues the Process to Exit the Merchant Function
On August 20, 2008, the PUCO approved the results of an auction selecting qualified wholesale suppliers to provide the gas commodity to the Company for resale to its customers at auction-determined standard pricing.  This standard pricing was comprised of the monthly NYMEX settlement price plus a fixed adder.  This standard pricing, which was effective from October 1, 2008 through March 31, 2010, was the initial step in exiting the merchant function in the Company’s Ohio service territory.  The approach eliminated the need for monthly gas cost recovery (GCR) filings and prospective PUCO GCR audits.  In October 2008, VEDO’s entire natural gas inventory was transferred to the auction’s winning wholesale supplie rs, resulting in proceeds to VEDO of approximately $107 million.

The second phase of the exit process began on April 1, 2010.  During this phase, the Company no longer sells natural gas directly to customers.  Rather, state-certified Competitive Retail Natural Gas Suppliers, that were successful bidders in a similar regulatory-approved auction, sell the gas commodity to specific customers for a 12 month period at auction-determined standard pricing.  The first auction was conducted on January 12, 2010, and the auction results were approved by the PUCO on January 13, 2010.  The plan approved by the PUCO required that the Company conduct at least two annual auctions during this phase.  As such, the Company conducted another auction on January 18, 2011 in advance of the second 12-month term which commences on April 1, 2011.  The results of that auction wer e approved by the PUCO on January 19, 2011. Consistent with current practice, customers will continue to receive a single bill for the commodity as well as the delivery component of natural gas service from VEDO.  Vectren Source, the Company’s wholly owned nonutility retail gas marketer, was a successful bidder in both auctions.

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

Vectren North Gas Base Rate Order Received
On February 13, 2008, the Company received an order from the IURC which approved the settlement agreement reached in its Vectren North gas rate case.  The order provided for a base rate increase of $16.3 million and a return on equity (ROE) of 10.2 percent, with an overall rate of return of 7.8 percent on rate base of approximately $793 million.  The order also provided for the recovery of $10.6 million of costs through separate cost recovery mechanisms rather than base rates.

Further, additional expenditures for a multi-year bare steel and cast iron capital replacement program will be afforded certain accounting treatment that mitigates earnings attrition from the investment between rate cases.  The accounting treatment allows for the continuation of the accrual for AFUDC and the deferral of depreciation expense after the projects go in service but before they are included in base rates.  To qualify for this treatment, the annual expenditures are limited to $20 million and the treatment cannot extend beyond four years from the in-service date for each specific project.

With this order, the Company has in place for its North gas territory weather normalization, a conservation and decoupling mechanism, recovery of gas cost expense related to uncollectible accounts expense based on historical experience and tracking of unaccounted for gas costs through the existing GCA mechanism, and tracking of pipeline integrity management expense. 

MISO Transactions
The Company is a member of the MISO, a FERC approved regional transmission organization.  When the Company is a net seller of its generation, such net revenues, which totaled $24.9 million, $20.8 million, and $57.6 million for the twelve months ended December 31, 2010, 2009, and 2008, respectively, are included in Electric utility revenues.  When the Company is a net purchaser such net purchases, which totaled $46.1 million, $34.4 million, and $16.6 million for the twelve months ended December 31, 2010, 2009, and 2008, respectively, are included in Cost of fuel & purchased power.  Net positions are determined on an hourly basis.

The Company also receives transmission revenue from the MISO which is included in Electric utility revenues and totaled $18.8 million, $14.6 million, and $9.3 million for the twelve months ended December 31, 2010, 2009, and 2008, respectively.  These revenues result from other MISO members’ use of the Company’s transmission system as well as the recovery of the Company’s investment in certain new electric transmission projects meeting MISO’s transmission expansion plan criteria.

18.  
Fair Value Measurements

The carrying values and estimated fair values of the Company's other financial instruments follow:
                         
   
At December 31,
  
   
2010
    
2009
  
(In millions)
  
Carrying Amount
  
Est. Fair Value
    
Carrying Amount
  
Est. Fair Value
  
Long-term debt
   $ 1,715.9     $ 1,767.3     $ 1,639.8     $ 1,720.1  
Short-term borrowings & notes payable
     118.3       118.3       213.5       213.5  
Cash & cash equivalents
     10.4       10.4       11.9       11.9  

For the balance sheet dates presented in these financial statements, the Company had no material assets or liabilities recorded at fair value outstanding, and no material assets or liabilities valued using Level 3 inputs.

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

Under current regulatory treatment, call premiums on reacquisition of 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 December 31, 2010 and 2009, the fair value for these financial instruments was not estimated.  The carrying value of notes receivable, inclusive of any accrued interest and net of impairment reserves, was approximately $10.9 million and $16.7 million December 31, 2010 and 2009.

19.  
Segment Reporting

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

The Utility Group is comprised of Vectren Utility Holdings, Inc.’s operations, which consist of the Company’s regulated operations and other operations that provide information technology and other support services to those regulated operations.  The Company segregates its regulated operations between a Gas Utility Services operating segment and an Electric Utility Services operating segment.  The Gas Utility Services segment provides natural gas distribution and transportation services to nearly two-thirds of Indiana and to west central Ohio.  The Electric Utility Services segment provides electric distribution services primarily to southwestern Indiana, and includes the Company’s power generating and wholesale power operations.  Regulated operations supply natural gas and /or ele ctricity to over one million customers.  In total, the Utility Group is comprised of three operating segments:  Gas Utility Services, Electric Utility Services, and Other Shared Service operations.

Consistent with a reporting structure implemented during 2010, the Nonutility Group is comprised of five operating segments.  Prior segment disclosures reported the Nonutility Group as a single operating segment, and for comparison purposes those prior periods are conformed to the current year presentation.  The operating segments of the Nonutility Group are Infrastructure Services, Energy Services, Coal Mining, Energy Marketing, and Other Businesses.

Corporate and Other includes unallocated corporate expenses such as advertising and charitable contributions, among other activities, that benefit the Company’s other operating segments.

Net income is the measure of profitability used by management for all operations.

Information related to the Company’s business segments is summarized below:
   
Year Ended December 31,
  
(In millions)
  
2010
    
2009
    
2008
  
Revenues
                  
  Utility Group
                  
    Gas Utility Services
   $ 954.1     $ 1,066.0     $ 1,432.7  
    Electric Utility Services
     608.0       528.6       524.2  
    Other Operations
     44.5       42.8       36.8  
    Eliminations
     (42.9 )     (41.2 )     (35.0 )
     Total Utility Group
     1,563.7       1,596.2       1,958.7  
  Nonutility Group
                        
    Infrastructure Services
     235.6       202.0       195.4  
    Energy Services
     146.9       121.3       118.6  
    Coal Mining
     209.9       193.4       164.4  
    Energy Marketing
     142.8       157.2       182.6  
    Other Businesses
     -       -       3.7  
     Total Nonutility Group
     735.2       673.9       664.7  
  Eliminations
     (169.4 )     (181.2 )     (138.7 )
  Consolidated Revenues
   $ 2,129.5     $ 2,088.9     $ 2,484.7  

   
Year Ended December 31,
  
(In millions)
  
2010
    
2009
    
2008
  
Profitability Measures - Net Income
                  
  Utility Group Net Income
                  
    Gas Utility Services
   $ 53.7     $ 50.2     $ 53.3  
    Electric Utility Services
     60.9       48.3       50.7  
    Other Operations
     9.3       8.9       7.1  
     Total Utility Group Net Income
     123.9       107.4       111.1  
  Nonutility Group Net Income
                        
    Infrastructure Services
     3.1       2.4       5.2  
    Energy Services
     6.4       8.4       6.2  
    Coal Mining
     11.9       13.4       (4.6 )
    Energy Marketing
     (4.2 )     4.1       18.0  
    Other Businesses
     (7.4 )     (2.5 )     (5.9 )
     Total Nonutility Group Net Income
     9.8       25.8       18.9  
  Corporate & Other Net Loss
     -       (0.1 )     (1.0 )
  Consolidated Net Income
   $ 133.7     $ 133.1     $ 129.0  
                         
Amounts Included in Profitability Measures
                        
   Depreciation & Amortization
                        
  Utility Group
                        
    Gas Utility Services
   $ 80.7     $ 76.9     $ 74.1  
    Electric Utility Services
     80.8       77.5       68.5  
    Other Operations
     26.7       26.5       22.9  
     Total Utility Group
     188.2       180.9       165.5  
  Nonutility Group
                        
    Infrastructure Services
     8.8       8.3       7.6  
    Energy Services
     1.2       1.2       1.1  
    Coal Mining
     30.4       21.0       17.4  
    Energy Marketing
     0.5       0.5       0.6  
    Other Businesses
     -       -       0.1  
     Total Nonutility Group
     40.9       31.0       26.8  
  Consolidated Depreciation & Amortization
   $ 229.1     $ 211.9     $ 192.3  
Interest Expense
                        
  Utility Group
                        
    Gas Utility Services
   $ 38.8     $ 38.8     $ 42.0  
    Electric Utility Services
     36.4       34.8       32.0  
    Other Operations
     6.2       5.6       5.9  
     Total Utility Group
     81.4       79.2       79.9  
  Nonutility Group
                        
    Infrastructure Services
     3.3       2.6       4.1  
    Energy Services
     0.2       0.6       0.5  
    Coal Mining
     10.1       8.1       4.0  
    Energy Marketing
     8.5       8.3       7.7  
    Other Businesses
     1.5       1.3       1.0  
     Total Nonutility Group
     23.6       20.9       17.3  
  Corporate & Other
     (0.4 )     (0.1 )     0.6  
  Consolidated Interest Expense
   $ 104.6     $ 100.0     $ 97.8  




   
Year Ended December 31,
  
(In millions)
  
2010
    
2009
    
2008
  
Income Taxes
                  
  Utility Group
                  
    Gas Utility Services
   $ 35.1     $ 31.3     $ 35.5  
    Electric Utility Services
     40.8       27.4       32.0  
    Other Operations
     1.2       0.5       0.1  
     Total Utility Group
     77.1       59.2       67.6  
  Nonutility Group
                        
    Infrastructure Services
     2.7       2.1       4.3  
    Energy Services
     2.5       1.6       1.6  
    Coal Mining
     1.9       4.1       (3.5 )
    Energy Marketing
     (2.7 )     0.3       14.6  
    Other Businesses
     (5.9 )     (2.2 )     (7.5 )
     Total Nonutility Group
     (1.5 )     5.9       9.5  
  Corporate & Other
     (0.9 )     (1.0 )     (1.0 )
  Consolidated Income Taxes
   $ 74.7     $ 64.1     $ 76.1  
                         
Capital Expenditures
                        
  Utility Group
                        
    Gas Utility Services
   $ 88.7     $ 121.1     $ 110.4  
    Electric Utility Services
     120.1       154.1       172.0  
    Other Operations
     22.5       16.7       29.6  
    Non-cash costs & changes in accruals
     (6.2 )     10.8       (8.3 )
     Total Utility Group
     225.1       302.7       303.7  
  Nonutility Group
                        
    Infrastructure Services
     12.0       11.0       11.8  
    Energy Services
     1.2       1.9       6.0  
    Coal Mining
     38.7       126.8       69.1  
    Energy Marketing
     0.2       0.6       0.3  
    Other Businesses, net of eliminations
     -       (11.0 )     0.1  
     Total Nonutility Group
     52.1       129.3       87.3  
  Consolidated Capital Expenditures
   $ 277.2     $ 432.0     $ 391.0  

   
At December 31,
  
(In millions)
  
2010
    
2009
  
Assets
            
  Utility Group
            
    Gas Utility Services
   $ 2,161.7     $ 2,102.4  
    Electric Utility Services
     1,666.5       1,592.4  
    Other Operations, net of eliminations
     96.3       128.3  
     Total Utility Group
     3,924.5       3,823.1  
  Nonutility Group
                
    Infrastructure Services
     174.6       141.4  
    Energy Services
     67.4       54.5  
    Coal Mining
     362.5       342.8  
    Energy Marketing
     209.1       229.6  
    Other Businesses
     57.1       65.7  
    Eliminations
     (2.2 )     2.0  
     Total Nonutility Group
     868.5       836.0  
  Corporate & Other
     706.2       715.9  
  Eliminations
     (735.0 )     (703.2 )
  Consolidated Assets
   $ 4,764.2     $ 4,671.8  


20.  
Additional Balance Sheet & Operational Information

Inventories consist of the following:
   
At December 31,
  
(In millions)
  
2010
    
2009
  
Gas in storage – at average cost
   $ 23.6     $ 22.2  
Gas in storage – at LIFO cost
     26.2       24.4  
Total Gas in storage
     49.8       46.6  
Materials & supplies
     48.8       42.6  
Coal & Oil for electric generation - at average cost
     70.1       66.8  
Nonutility Coal - at LIFO cost
     16.2       8.5  
Other
     2.2       3.3  
Total inventories
   $ 187.1     $ 167.8  
 
Based on the average cost of gas purchased and coal produced during December, the cost of replacing inventories carried at LIFO cost exceeded that carrying value at December 31, 2010, and 2009, by approximately $16 million and $21 million, respectively.

Prepayments & other current assets in the Consolidated Balance Sheets consist of the following:
   
At December 31,
  
(In millions)
  
2010
    
2009
  
Prepaid gas delivery service
   $ 40.7     $ 38.7  
Deferred income taxes
     3.8       21.7  
Prepaid taxes
     31.5       20.6  
Other prepayments & current assets
     25.2       14.1  
Total prepayments & other current assets
   $ 101.2     $ 95.1  
 
Investments in unconsolidated affiliates consist of the following:
 
At December 31,
  
(In millions)
  
2010
    
2009
  
ProLiance Holdings, LLC
   $ 123.2     $ 167.9  
Haddington Energy Partnerships
     3.4       9.3  
Other non-utility partnerships & corporations
     8.4       8.8  
Other utility investments
     0.2       0.2  
Total investments in unconsolidated affiliates
   $ 135.2     $ 186.2  

Other utility & corporate Investments in the Consolidated Balance Sheets consist of the following:
   
At December 31,
  
(In millions)
  
2010
    
2009
  
Cash surrender value of life insurance policies
   $ 27.5     $ 24.7  
Municipal bond
     4.1       4.3  
Restricted cash
     1.2       2.8  
Other investments
     1.3       1.4  
Other utility & corporate investments
   $ 34.1     $ 33.2  

Goodwill by operating segment follows:
   
At December 31,
  
(In millions)
  
2010
    
2009
  
Utility Group
            
Gas Utility Services
   $ 205.0     $ 205.0  
Nonutility Group
                
Infrastructure Services
     34.9       34.9  
Energy Services
     2.1       2.1  
Consolidated goodwill
   $ 242.0     $ 242.0  

Accrued liabilities in the Consolidated Balance Sheets consist of the following:
   
At December 31,
  
(In millions)
  
2010
    
2009
  
Refunds to customers & customer deposits
   $ 54.8     $ 51.0  
Accrued taxes
     40.9       32.7  
Accrued interest
     23.8       23.7  
Accrued retirement & deferred compensation benefits
     5.8       19.6  
Accrued salaries & other
     53.1       47.7  
Total accrued liabilities
   $ 178.4     $ 174.7  

Asset retirement obligations included in the Consolidated Balance Sheets roll forward as follows:

             
(In millions)
  
2010
    
2009
  
Asset retirement obligation, January 1
   $ 36.1     $ 34.7  
    Accretion
     2.1       1.5  
    Increases (decreases) in estimates, net of cash payments
     0.5       (0.1 )
Asset retirement obligation, December 31
     38.7       36.1  
  Accrued liabilities
   $ 0.3     $ 3.0  
  Deffered credits & other liabilities
   $ 38.4     $ 33.1  

Equity in earnings (losses) of unconsolidated affiliates consists of the following:

   
Year Ended December 31,
  
(In millions)
  
2010
    
2009
    
2008
  
ProLiance Holdings, LLC
   $ (2.5 )   $ 3.6     $ 39.5  
Haddington Energy Partners, LP
     (6.1 )     0.9       (0.2 )
Other
     -       (1.1 )     (1.9 )
Total equity in earnings (losses) of unconsolidated affiliates
   $ (8.6 )   $ 3.4     $ 37.4  

Other – net in the Consolidated Statements of Income consists of the following:
   
Year Ended December 31,
  
(In millions)
  
2010
    
2009
    
2008
  
AFUDC – borrowed funds
   $ 1.4     $ 1.3     $ 2.2  
AFUDC – equity funds
     0.3       0.7       0.3  
Nonutility plant capitalized interest
     2.1       6.0       3.7  
Interest income, net
     1.7       1.4       2.3  
Other nonutility investment impairment charges
     (4.7 )     -       (5.2 )
Cash surrender value of life insurance policies
     1.9       4.1       (2.8 )
All other income
     2.1       0.2       1.6  
Total other – net
   $ 4.8     $ 13.7     $ 2.1  
 
Supplemental Cash Flow Information:

   
Year Ended December 31,
  
(In millions)
  
2010
    
2009
    
2008
  
Cash paid for:
                  
    Interest
   $ 104.5     $ 95.5     $ 92.6  
    Income taxes
     8.1       (12.2 )     (3.5 )
 
As of December 31, 2010 and 2009, the Company has accruals related to utility and nonutility plant purchases totaling approximately $13.9 million and $12.4 million, respectively.

21.  
Impact of Recently Issued Accounting Guidance

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

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

22.  
Quarterly Financial Data (Unaudited)

Information in any one quarterly period is not indicative of annual results due to the seasonal variations common to the Company’s utility operations.  Summarized quarterly financial data for 2010 and 2009 follows:

                         
(In millions, except per share amounts)
     Q1       Q2       Q3       Q4  
2010
                                
Operating revenues
   $ 740.3     $ 402.4     $ 422.7     $ 564.1  
Operating income
     116.2       52.1       58.6       89.9  
Net income
     63.2       8.7       16.4       45.4  
Earnings per share:
                                
Basic
   $ 0.78     $ 0.11     $ 0.20     $ 0.56  
Diluted
     0.78       0.11       0.20       0.55  
2009
                                
Operating revenues
   $ 795.2     $ 375.5     $ 349.6     $ 568.6  
Operating income
     121.8       32.4       40.5       85.4  
Net income
     72.8       (6.7 )     12.4       54.6  
Earnings per share:
                                
Basic
   $ 0.90     $ (0.08 )   $ 0.15     $ 0.68  
Diluted
     0.90       (0.08 )     0.15       0.67  

ITEM 9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.
 
ITEM 9A.  CONTROLS AND PROCEDURES
 
Changes in Internal Controls over Financial Reporting

During the quarter ended December 31, 2010, there have been no changes to the Company’s internal controls over financial reporting that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

As of December 31, 2010, the Company conducted an evaluation under the supervision and with the participation of the Chief Executive Officer and Chief Financial Officer of the effectiveness and the design and operation of the Company's disclosure controls and procedures.  Based on that evaluation, the Chief Executive Officer and the Chief Financial Officer have concluded that the Company's disclosure controls and procedures are effective as of December 31, 2010, to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is:
1) 
recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and
 
    2)
accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

Management’s Report on Internal Control over Financial Reporting

Vectren Corporation’s management is responsible for establishing and maintaining adequate internal control over financial reporting.  Under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, the Company conducted an evaluation of the effectiveness of its internal control over financial reporting based on the framework in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.  Based on that evaluation under the framework in Internal Control — Integrated Framework, the Company concluded that its internal control over financial reporting was effective as of Dece mber 31, 2010.

The effectiveness of internal control over financial reporting as of December 31, 2010, has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report which is included in Item 8 of this annual report.

ITEM 9B.  OTHER INFORMATION

None.
PART III

ITEM 10.  DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The information required by Part III, Item 10 of this Form 10-K is incorporated by reference herein, and made part of this Form 10-K, from the Company's Proxy Statement for its 2011 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission pursuant to Regulation 14A, within 120 days after the end of the fiscal year.  The Company’s executive officers are the same as those named executive officers detailed in the Proxy Statement.

Management Succession

Niel C. Ellerbrook, chairman and CEO of the Company, retired May 31, 2010, as the Company’s CEO. Ellerbrook will continue to serve in the role of non-executive chairman for the Company through May of 2011.  As part of the Company’s succession planning process, the board of directors chose Carl L. Chapman, Vectren’s president and chief operating officer, to replace Ellerbrook as the next CEO. Chapman was elected to the board of directors in May 2009 and has served as an officer of the Company for more than 20 years.

Corporate Code of Conduct

The Company’s Corporate Governance Guidelines, its charters for each of its Audit, Compensation and Benefits and Nominating and Corporate Governance Committees, and its Corporate Code of Conduct that covers the Company’s directors, officers and employees are available in the Corporate Governance section of the Company’s website, www.vectren.com.  The Corporate Code of Conduct (titled “Corp Code of Conduct”) contains specific codes of ethics pertaining to the CEO and senior financial officers and the Board of Directors in Exhibits D and E, respectively.  A copy will be mailed upon request to Investor Relations, Attention: Steve Schein, One Vectren Square, Evansville, Indiana 47708.  The Company intends to disclose any amendm ents to the Corporate Code of Conduct or waivers of the Corporate Code of Conduct on behalf of the Company’s directors or officers including, but not limited to, the principal executive officer, principal financial officer, principal accounting officer and persons performing similar functions on the Company’s website at the internet address set forth above promptly following the date of such amendment or waiver and such information will also be available by mail upon request to the address listed above.

ITEM 11.  EXECUTIVE COMPENSATION

Information required by Part III, Item 11 of this Form 10-K is incorporated by reference herein, and made part of this Form 10-K, from the Company's Proxy Statement for its 2011 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission pursuant to Regulation 14A, within 120 days after the end of the fiscal year.
 
ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Except with respect to equity compensation plan information of the Registrant, which is included herein, the information required by Part III, Item 12 of this Form 10-K is incorporated by reference herein, and made part of this Form 10-K, from the Company's Proxy Statement for its 2011 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission pursuant to Regulation 14A, within 120 days after the end of the fiscal year.

Shares Issuable under Share-Based Compensation Plans

As of December 31, 2010, the following shares were authorized to be issued under share-based compensation plans:
                     
     
A
    
B
    
C
  
 
 
 
 
Plan category
  
 
Number of securities to
be issued upon exercise
of outstanding options,
warrants and rights
 
Weighted average
exercise price of
outstanding options,
warrants and rights
Number of securities remaining
available for future issuance
under equity compensation
plans (excluding securities
reflected in column (a))
                     
Equity compensation plans approved by
              
  security holders
  
                  929,806
(1)
 $                24.55
(1)
                            2,302,674
(2)
Equity compensation plans not approved
                  
  by security holders
  
                            -
    
                         -
    
                                        -
  
Total
    
929,806
    
 $                24.55
    
2,302,674
  
 
(1)  
Under the Vectren At-Risk Compensation Plan, the Company may buy shares on the open market during periods when there are no restrictions on insider transactions to fulfill these obligations.
(2)  
On February 14, 2011, 219,700 restricted units were approved to be issued to management by the Compensation and Benefits Committee of the Board of Directors.  In addition, on February 14, 2011, participants forfeited 95,182 shares related to awards measured during the three year performance period ending December 31, 2010.  The issuance and forfeiture of the shares on February 14, 2011 are not included in the above table.

The At-Risk Compensation plan was approved by Vectren Corporation common shareholders after the merger forming Vectren and was reapproved at the 2006 annual meeting of shareholders.

ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

Information required by Part III, Item 13 of this Form 10-K is incorporated by reference herein, and made part of this Form 10-K, from the Company's Proxy Statement for its 2011 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission pursuant to Regulation 14A, within 120 days after the end of the fiscal year.

ITEM 14.  PRINCIPAL ACCOUNTANT FEES AND SERVICES

Information required by Part III, Item 14 of this Form 10-K is incorporated by reference herein, and made part of this Form 10-K, from the Company's Proxy Statement for its 2011 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission pursuant to Regulation 14A, within 120 days after the end of the fiscal year.

PART IV

ITEM 15.  EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

List of Documents Filed as Part of This Report

Consolidated Financial Statements
The consolidated financial statements and related notes, together with the report of Deloitte & Touche LLP, appear in Part II “Item 8 Financial Statements and Supplementary Data” of this Form 10-K.

Supplemental Schedules
For the years ended December 31, 2010, 2009, and 2008, the Company’s Schedule II -- Valuation and Qualifying Accounts Consolidated Financial Statement Schedules is presented herein.  The report of Deloitte & Touche LLP on the schedule may be found in Item 8.  All other schedules are omitted as the required information is inapplicable or the information is presented in the Consolidated Financial Statements or related notes in Item 8.

SCHEDULE II
Vectren Corporation and Subsidiaries
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

                               
Column A
  
Column B
    
Column C
    
Column D
    
Column E
  
         
Additions
              
   
Balance at
    
Charged
    
Charged
    
Deductions
    
Balance at
  
   
Beginning
    
to
    
to Other
    
from
    
End of
  
Description
  
of Year
    
Expenses
    
Accounts
    
Reserves, Net
    
Year
  
(In millions)
                              
VALUATION AND QUALIFYING ACCOUNTS:
                          
Year 2010 – Accumulated provision for
                          
                    uncollectible accounts
   $ 5.2     $ 16.8     $ -     $ 16.7     $ 5.3  
Year 2009 – Accumulated provision for
                                  
                    uncollectible accounts
   $ 5.6     $ 15.1     $ -     $ 15.5     $ 5.2  
Year 2008 – Accumulated provision for
                                  
                    uncollectible accounts
   $ 3.7     $ 16.9     $ 0.3     $ 15.3     $ 5.6  
                                         
Year 2010 – Reserve for impaired
                                        
                    notes receivable
   $ 9.2     $ 1.2     $ -     $ 4.3     $ 6.1  
Year 2009 – Reserve for impaired
                                        
                    notes receivable
   $ 6.3     $ 2.9     $ -     $ -     $ 9.2  
Year 2008 – Reserve for impaired
                                        
                    notes receivable
   $ 1.7     $ 4.6     $ -     $ -     $ 6.3  
OTHER RESERVES:
                                        
Year 2010 – Restructuring costs
   $ 0.5     $ -     $ -     $ 0.1     $ 0.4  
Year 2009 – Restructuring costs
   $ 0.6     $ -     $ -     $ 0.1     $ 0.5  
Year 2008 – Restructuring costs
   $ 0.6     $ -     $ -     $ -     $ 0.6  

List of Exhibits
The Company has incorporated by reference herein certain exhibits as specified below pursuant to Rule 12b-32 under the Exchange Act.  Exhibits for the Company attached to this filing filed electronically with the SEC are listed below.  Exhibits for the Company are listed in the Index to Exhibits.

Vectren Corporation
Form 10-K
Attached Exhibits

The following Exhibits are included in this Annual Report on Form 10-K.

Exhibit
Number
 
Document
   
31.1
Chief Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
31.2
Chief Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
   
32
Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

The following Exhibits, as well as the Exhibits listed above, were filed electronically with the SEC with this filing.

Exhibit
Number
 
Document
   
21.1
List of Company’s Significant Subsidiaries
 
23.1
Consent of Independent Registered Public Accounting Firm
 
INDEX TO EXHIBITS

3.  Articles of Incorporation and By-Laws
3.1  
Amended and Restated Articles of Incorporation of Vectren Corporation effective March 31, 2000.  (Filed and designated in Current Report on Form 8-K filed April 14, 2000, File No. 1-15467, as Exhibit 4.1.)
3.2  
Code of By-Laws of Vectren Corporation as Most Recently Amended and Restated as of February 2, 2011.  (Filed and designated in Current Report on Form 8-K filed February 4, 2011, File No. 1-15467, as Exhibit 3.1.)

4.   Instruments Defining the Rights of Security Holders, Including Indentures
4.1  
Mortgage and Deed of Trust dated as of April 1, 1932 between Southern Indiana Gas and Electric Company and Bankers Trust Company, as Trustee, and Supplemental Indentures thereto dated August 31, 1936, October 1, 1937, March 22, 1939, July 1, 1948, June 1, 1949, October 1, 1949, January 1, 1951, April 1, 1954, March 1, 1957, October 1, 1965, September 1, 1966, August 1, 1968, May 1, 1970, August 1, 1971, April 1, 1972, October 1, 1973, April 1, 1975, January 15, 1977, April 1, 1978, June 4, 1981, January 20, 1983, November 1, 1983, March 1, 1984, June 1, 1984, November 1, 1984, July 1, 1985, November 1, 1985, June 1, 1986.  (Filed and designated in Registration No. 2-2536 as Exhibits B-1 and B-2; in Post-effective Amendment No. 1 to Registration No. 2-62032 as Exhibit (b)(4)(ii), in Registration No. 2-88923 as Exhibit 4(b)(2), in Form 8-K, Fi le No. 1-3553, dated June 1, 1984 as Exhibit (4), File No. 1-3553, dated March 24, 1986 as Exhibit 4-A, in Form 8-K, File No. 1-3553, dated June 3, 1986 as Exhibit (4).)  July 1, 1985 and November 1, 1985 (Filed and designated in Form 10-K, for the fiscal year 1985, File No. 1-3553, as Exhibit 4-A.)  November 15, 1986 and January 15, 1987.  (Filed and designated in Form 10-K, for the fiscal year 1986, File No. 1-3553, as Exhibit 4-A.)  December 15, 1987.  (Filed and designated in Form 10-K, for the fiscal year 1987, File No. 1-3553, as Exhibit 4-A.)  December 13, 1990.  (Filed and designated in Form 10-K, for the fiscal year 1990, File No. 1-3553, as Exhibit 4-A.)  April 1, 1993.  (Filed and designated in Form 8-K, dated April 13, 1993, File No. 1-3553, as Exhibit 4.)  June 1, 1993 (Filed and designated in Form 8-K, dated June 14, 1993, File No. 1-3553, as Exhibit 4.)  May 1, 1993.  (F iled and designated in Form 10-K, for the fiscal year 1993, File No. 1-3553, as Exhibit 4(a).)  July 1, 1999.  (Filed and designated in Form 10-Q, dated August 16, 1999, File No. 1-3553, as Exhibit 4(a).)  March 1, 2000.  (Filed and designated in Form 10-K for the year ended December 31, 2001, File No. 1-15467, as Exhibit 4.1.) August 1, 2004.  (Filed and designated in Form 10-K for the year ended December 31, 2004, File No. 1-15467, as Exhibit 4.1.)  October 1, 2004.  (Filed and designated in Form 10-K for the year ended December 31, 2004, File No. 1-15467, as Exhibit 4.2.)  April 1, 2005 (Filed and designated in Form 10-K for the year ended December 31, 2007, File No 1-15467, as Exhibit 4.1)  March 1, 2006 (Filed and designated in Form 10-K for the year ended December 31, 2007, File No 1-15467, as Exhibit 4.2)  December 1, 2007 (Filed and designated in Form 10-K for the year ended December 31, 2007, File No 1-15467, as Exhibit 4.3) August 1, 2009 (Filed herewith, as Exhibit 4.1)

4.2  
Indenture dated February 1, 1991, between Indiana Gas and U.S. Bank Trust National Association (formerly know as First Trust National Association, which was formerly know as Bank of America Illinois, which was formerly know as Continental Bank, National Association.  Inc.'s. (Filed and designated in Current Report on Form 8-K filed February 15, 1991, File No. 1-6494.); First Supplemental Indenture thereto dated as of February 15, 1991.  (Filed and designated in Current Report on Form 8-K filed February 15, 1991, File No. 1-6494, as Exhibit 4(b).); Second Supplemental Indenture thereto dated as of September 15, 1991, (Filed and designated in Current Report on Form 8-K filed September 25, 1991, File No. 1-6494, as Exhibit 4(b).); Third supplemental Indenture thereto dated as of September 15, 1991 (Filed and designated in Current Repo rt on Form 8-K filed September 25, 1991, File No. 1-6494, as Exhibit 4(c).); Fourth Supplemental Indenture thereto dated as of December 2, 1992, (Filed and designated in Current Report on Form 8-K filed December 8, 1992, File No. 1-6494, as Exhibit 4(b).); Fifth Supplemental Indenture thereto dated as of December 28, 2000, (Filed and designated in Current Report on Form 8-K filed December 27, 2000, File No. 1-6494, as Exhibit 4.)

4.3  
Indenture dated October 19, 2001, among Vectren Utility Holdings, Inc., Indiana Gas Company, Inc., Southern Indiana Gas and Electric Company, Vectren Energy Delivery of Ohio, Inc., and U.S. Bank Trust National Association.  (Filed and designated in Form 8-K, dated October 19, 2001, File No. 1-16739, as Exhibit 4.1); First Supplemental Indenture, dated October 19, 2001, between Vectren Utility Holdings, Inc., Indiana Gas Company, Inc., Southern Indiana Gas and Electric Company, Vectren Energy Delivery of Ohio, Inc., and U.S. Bank Trust National Association.  (Filed and designated in Form 8-K, dated October 19, 2001, File No. 1-16739, as Exhibit 4.2); Second Supplemental Indenture, among Vectren Utility Holdings, Inc., Indiana Gas Company, Inc., Southern Indiana Gas and Electric Company, Vectren Energy Delivery of Ohio, Inc., and U.S. Bank Tru st National Association.  (Filed and designated in Form 8-K, dated November 29, 2001, File No. 1-16739, as Exhibit 4.1); Third Supplemental Indenture, among Vectren Utility Holdings, Inc., Indiana Gas Company, Inc., Southern Indiana Gas and Electric Company, Vectren Energy Delivery of Ohio, Inc., and U.S. Bank Trust National Association.  (Filed and designated in Form 8-K, dated July 24, 2003, File No. 1-16739, as Exhibit 4.1); Fourth Supplemental Indenture, among Vectren Utility Holdings, Inc., Indiana Gas Company, Inc., Southern Indiana Gas and Electric Company, Vectren Energy Delivery of Ohio, Inc., and U.S. Bank Trust National Association.  (Filed and designated in Form 8-K, dated November 18, 2005, File No. 1-16739, as Exhibit 4.1).  Form of Fifth Supplemental Indenture, among Vectren Utility Holdings, Inc., Indiana Gas Company, Inc., Southern Indiana Gas & Electric Company, Vectren Energy Delivery of Ohio, Inc., and U.S. Bank Trust National Association. (Filed and designated in Form 8-K, dated October 16, 2006, File No. 1-16739, as Exhibit 4.1).  Sixth Supplemental Indenture, dated March 10, 2008, among Vectren Utility Holdings, Inc., Indiana Gas Company, Inc., Southern Indiana Gas and Electric Company, Vectren Energy Delivery of Ohio, Inc., and U.S. Bank National Association (Filed and designated in Form 8-K, dated March 10, 2008, File No. 1-16739, as Exhibit 4.1)

4.4  
Note purchase agreement, dated October 11, 2005, between Vectren Capital Corp. and each of the purchasers named therein.  (Filed designated in Form 10-K for the year ended December 31, 2005, File No. 1-15467, as Exhibit 4.4.) First Amendment, dated March 11, 2009, to Note Purchase Agreement dated October 11, 2005, among Vectren Corporation, Vectren Capital, Corp. and each of the holders named herein. (Filed and designated in Form 8-K dated March 16, 2009 File No. 1-15467, as Exhibit 4.6)

4.5  
Note Purchase Agreement, dated March 11, 2009, among Vectren Corporation, Vectren Capital, Corp. and each of the purchasers named therein. (Filed and designated in Form 8-K dated March 16, 2009 File No. 1-15467, as Exhibit 4.5)

4.6  
Note Purchase Agreement, dated April 7, 2009, among Vectren Utility Holdings, Inc., Indiana Gas Company, Inc., Southern Indiana Gas and Electric Company and Vectren Energy Delivery of Ohio, Inc. and the purchasers named therein. (Filed and designated in Form 8-K dated April 7, 2009 File No. 1-15467, as Exhibit 4.5)

4.7  
Note Purchase Agreement, dated September 9, 2010, among Vectren Capital, Corp. and the purchasers named therein.  (Filed and designated in Form 8-K dated September 10, 2010 File No. 1-15467, as Exhibit 4.1)

10. Material Contracts
10.1  
Summary description of Southern Indiana Gas and Electric Company's nonqualified Supplemental Retirement Plan (Filed and designated in Form 10-K for the fiscal year 1992, File No. 1-3553, as Exhibit 10-A-17.)  First Amendment, effective April 16, 1997 (Filed and designated in Form 10-K for the fiscal year 1997, File No. 1-3553, as Exhibit 10.29.).
10.2  
Southern Indiana Gas and Electric Company 1994 Stock Option Plan (Filed and designated in Southern Indiana Gas and Electric Company's Proxy Statement dated February 22, 1994, File No. 1-3553, as Exhibit A.)
10.3  
Vectren Corporation At Risk Compensation Plan effective May 1, 2001, (as amended and restated as of May 1, 2006).  (Filed and designated in Vectren Corporation’s Proxy Statement dated March 15, 2006, File No. 1-15467, as Appendix H.)
10.4  
Vectren Corporation Non-Qualified Deferred Compensation Plan, as amended and restated effective January 1, 2001.  (Filed and designated in Form 10-K, for the year ended December 31, 2001, File No. 1-15467, as Exhibit 10.32.)
 
 
10.5  
Vectren Corporation Nonqualified Deferred Compensation Plan, effective January 1, 2005.  (Filed and designated in Form 8-K dated September 29, 2008, File No. 1-15467, as Exhibit 10.3.)
10.6  
Vectren Corporation Unfunded Supplemental Retirement Plan for a Select Group of Management Employees (As Amended and Restated Effective January 1, 2005).(Filed and designated in Form 8-K dated December 17, 2008, File No. 1-15467, as Exhibit 10.1.)
10.7  
Vectren Corporation Nonqualified Defined Benefit Restoration Plan (As Amended and Restated Effective January 1, 2005). (Filed and designated in Form 8-K dated December 17, 2008, File No. 1-15467, as Exhibit 10.2.)
10.8  
Vectren Corporation Change in Control Agreement between Vectren Corporation and Niel C. Ellerbrook dated as of March 1, 2005.  (Filed and designated in Form 8-K dated March 1, 2005, File No. 1-15467, as Exhibit 99.1.).  Amendment Number One to the Vectren Corporation Change in Control Agreement, effective as of March 1, 2005 between Vectren Corporation and Niel C. Ellerbrook (Filed and designated in Form 8-K dated September 29, 2008, File No. 1-15467, as Exhibit 10.1.)
10.9  
Vectren Corporation At Risk Compensation Plan specimen restricted stock grant agreement for officers, effective January 1, 2006.  (Filed and designated in Form 8-K, dated February 27, 2006, File No. 1-15467, as Exhibit 99.1.)
10.10  
Vectren Corporation At Risk Compensation Plan specimen unit award agreement for officers, effective January 1, 2010.  (Filed and designated in Form 8-K, dated January 7, 2010, File No. 1-15467, as Exhibit 10.1.)
10.11  
Vectren Corporation At Risk Compensation Plan specimen unit award agreement for officers, effective January 1, 2009.  (Filed and designated in Form 8-K, dated February 17, 2009, File No. 1-15467, as Exhibit 10.1.)
10.12  
Vectren Corporation At Risk Compensation Plan specimen restricted stock grant agreement for officers, effective January 1, 2008.  (Filed and designated in Form 8-K, dated December 28, 2007, File No. 1-15467, as Exhibit 99.1.)
10.13  
Vectren Corporation At Risk Compensation Plan specimen restricted stock units agreement for officers, effective January 1, 2008.  (Filed and designated in Form 8-K, dated December 28, 2007, File No. 1-15467, as Exhibit 99.2.)
10.14  
Vectren Corporation At Risk Compensation Plan specimen Stock Option Grant Agreement for officers, effective January 1, 2005.  (Filed and designated in Form 8-K, dated January 1, 2005, File No. 1-15467, as Exhibit 99.2.)
10.15  
Vectren Corporation At Risk Compensation Plan stock unit award agreement for non-employee directors, effective May 1, 2009. (Filed and designation in Form 8-K, dated February 20, 2009, File No. 1-15467, as Exhibit 10.1)
10.16  
Vectren Corporation specimen employment agreement dated February 1, 2005.  (Filed and designated in Form 8-K, dated February 1, 2005, File No. 1-15467, as Exhibit 99.1.)  Amendment Number One to the Specimen Vectren Corporation Employment Agreement between Vectren Corporation and Executive Officers (Filed and designated in Form 8-K dated September 29, 2008, File No. 1-15467, as Exhibit 10.2.) The specimen agreements and related amendments differ among named executive officers only to the extent severance and change in control benefits are provided in the amount of three times base salary and bonus for Messrs. Benkert, Chapman, and Christian and two times for Mr. Doty.
10.17  
Coal Supply Agreement for Warrick 4 Generating Station between Southern Indiana Gas and Electric Company and Vectren Fuels, Inc., effective January 1, 2009.  (Filed and designated in Form 8-K dated January 5, 2009, File No. 1-15467, as Exhibit 10.1.)
10.18  
Coal Supply Agreement for F.B. Culley Generating Station between Southern Indiana Gas and Electric Company and Vectren Fuels, Inc., effective January 1, 2009.  (Filed and designated in Form 8-K dated January 5, 2009, File No. 1-15467, as Exhibit 10.2.)
10.19  
Coal Supply Agreement for A.B. Brown Generating Station for 410,000 tons between Southern Indiana Gas and Electric Company and Vectren Fuels, Inc., effective January 1, 2009.  (Filed and designated in Form 8-K dated January 5, 2009, File No. 1-15467, as Exhibit 10.3.)
10.20  
Coal Supply Agreement for A.B. Brown Generating Station for 1 million tons between Southern Indiana Gas and Electric Company and Vectren Fuels, Inc., effective January 1, 2009.  (Filed and designated in Form 8-K dated January 5, 2009, File No. 1-15467, as Exhibit 10.4.)
10.21  
Amendment to F.B. Culley and A.B. Brown Coal Supply Agreements dated December 21, 2009. (Filed herewith as exhibit 10.1)
10.22  
Gas Sales and Portfolio Administration Agreement between Indiana Gas Company, Inc. and ProLiance Energy, LLC, effective August 30, 2003.  (Filed and designated in Form 10-K, for the year ended December 31, 2003, File No. 1-15467, as Exhibit 10.15.)
10.23  
Gas Sales and Portfolio Administration Agreement between Southern Indiana Gas and Electric Company and ProLiance Energy, LLC, effective September 1, 2002.  (Filed and designated in Form 10-K, for the year ended December 31, 2003, File No. 1-15467, as Exhibit 10.16.)
10.24  
Formation Agreement among Indiana Energy, Inc., Indiana Gas Company, Inc., IGC Energy, Inc., Indiana Energy Services, Inc., Citizens Energy Group, Citizens Energy Services Corporation and ProLiance Energy, LLC, effective March 15, 1996.  (Filed and designated in Form 10-Q for the quarterly period ended March 31, 1996, File No. 1-9091, as Exhibit 10-C.)
10.25  
Revolving Credit Agreement (5 year facility), dated November 10, 2005, among Vectren Utility Holdings, Inc., and each of the financial institutions named therein.  (Filed and designated in Form 10-Q, for the period ended September 30, 2009, File No. 1-15467, as Exhibit 10.24.)
10.26  
Revolving Credit Agreement (5 year facility), dated November 10, 2005, among Vectren Capital Corp., and each of the financial institutions named therein.  (Filed and designated in Form 10-Q, for the period ended September 30, 2009, File No. 1-15467, as Exhibit 10.25.)
10.27  
Revolving Credit Agreement (3 year facility), dated September 30, 2010, among Vectren Utility Holdings, Inc., and each of the financial institutions named therein.  (Filed and designated in Form 8-K dated October 5, 2010, File No. 1-15467, as Exhibit 10.1)
10.28  
Revolving Credit Agreement (3 year facility), dated September 30, 2010, among Vectren Capital Corp., and each of the financial institutions named therein.  (Filed and designated in Form 8-K dated October 5, 2010, File No. 1-15467, as Exhibit 10.2)
 
 
10.29  Niel C. Ellerbrook Retirement Agreement, dated February 3, 2010.  (Filed and designated in Form 8-K dated February 4, 2010 File No. 1-15467, as Exhibit 99.2)
 
21. Subsidiaries of the Company
the list of the Company's significant subsidiaries is attached hereto as Exhibit 21.1.  (Filed herewith.)
 
23. Consents of Experts and Counsel
The consents of Deloitte & Touche LLP are attached hereto as Exhibit 23.1. (Filed herewith.)
 
31. Certification Pursuant To Section 302 of the Sarbanes-Oxley Act of 2002
Chief Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act Of 2002 is attached hereto as Exhibit 31.1 (Filed herewith.)
Chief Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act Of 2002 is attached hereto as Exhibit 31.2 (Filed herewith.)
 
32. Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
Certification Pursuant To Section 906 of the Sarbanes-Oxley Act Of 2002 is attached hereto as Exhibit 32 (Filed herewith.)

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

VECTREN CORPORATION


Dated February 17, 2011                                                                           /s/ Carl L. Chapman                                            &# 160;    
Carl L. Chapman,
President, Chief Executive Officer, and Director

Pursuant to the requirements of the Securities and Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in capacities and on the dates indicated.

Signature
  
Title
  
Date
         
 
/s/ Carl L. Chapman
  
 
President, Chief Executive Officer, and Director
  
 
February 17, 2011
   Carl L. Chapman
 
  
(Principal Executive Officer)
    
 
/s/ Jerome A. Benkert, Jr. 
  
 
Executive Vice President and Chief Financial
  
 
February 17, 2011
   Jerome A. Benkert, Jr.
 
 
  
Officer
(Principal Financial Officer)
 
    
 
/s/ M. Susan Hardwick
  
 
Vice President, Controller and Assistant Treasurer
  
 
February 17, 2011
   M. Susan Hardwick
 
  
(Principal Accounting Officer)
    
/s/ Niel C. Ellerbrook  
Chairman and Director
  
February 17, 2011
   Niel C. Ellerbrook
 
 
        
/s/ James H. DeGraffenreidt   
Director
  
February 17, 2011
   James H. DeGraffenreidt
 
 
        
/s/ John D. Engelbrecht   
Director
  
February 17, 2011
   John D. Engelbrecht
 
 
        
/s/ Anton H. George   
Director
  
February 17, 2011
   Anton H. George
 
 
        
/s/ Martin C. Jischke   
Director
  
February 17, 2011
   Martin C. Jischke
 
 
        

/s/ Robert G. Jones   
Director
  
February 17, 2011
   Robert G. Jones
 
        
/s/ Robert L. Koch II   
Director
  
February 17, 2011
   Robert L. Koch II
 
 
        
/s/ William G. Mays   
Director
  
February 17, 2011
   William G. Mays
 
 
        
/s/ J. Timothy McGinley   
Director
  
February 17, 2011
   J. Timothy McGinley
 
 
        
/s/ R. Daniel Sadlier   
Director
  
February 17, 2011
   R. Daniel Sadlier
 
 
        
/s/ Michael L. Smith   
Director
  
February 17, 2011
   Michael L. Smith
 
 
        
/s/ Jean L. Wojtowicz
 
Director
  
February 17, 2011
   Jean L. Wojtowicz
 
        
EX-21.1 2 ex21_1.htm EXHIBIT 21.1 ex21_1.htm
 
Exhibit  21.1
VECTREN CORPORATION

Subsidiaries

Wholly Owned Subsidiaries:
 
 
Name of Entity
  
State of
Incorporation/
Jurisdiction
  
 
 
Doing Business As
Vectren Utility Holdings, Inc.
  
Indiana
    
Southern Indiana Gas and Electric Company
  
Indiana
  
Vectren Energy Delivery of Indiana, Inc.
Indiana Gas Company, Inc.
  
Indiana, Ohio
  
Vectren Energy Delivery of Indiana, Inc.
Vectren Energy Delivery of Ohio, Inc.
  
Ohio
    
Vectren Capital, Corp.
  
Indiana
    
Vectren Enterprises, Inc.
  
Indiana
    
Vectren Energy Services Holding, Inc.
  
Indiana
    
Vectren Energy Marketing and Services, Inc.
  
Indiana
    
Vectren Energy Services Corporation
  
Indiana
    
Energy Systems Group, LLC
  
Indiana
    
Vectren Energy Retail, Inc.
  
Indiana
    
Vectren Retail, LLC
  
Indiana, Ohio
  
Vectren Source
Vectren Utility Services, Inc.
  
Indiana
    
Vectren Fuels, Inc.
  
Indiana
    
Vectren Infrastructure Services Corporation
  
Indiana
    
Miller Pipeline, LLC
  
Indiana
    
Vectren Communications, Inc.
  
Indiana
    
Vectren Communications Services, Inc.
  
Indiana
    
Vectren Financial Group, Inc.
  
Indiana
    
Southern Indiana Properties, Inc.
  
Indiana
    
Energy Realty, Inc.
  
Indiana
    
Vectren Ventures, Inc.
  
Indiana
    
Vectren Aero, LLC
  
Indiana
    

Less than Wholly Owned Subsidiaries:
 
 
Name of Entity
  
State of
Incorporation/
Jurisdiction
  
 
 
Doing Business As
ProLiance Holdings, LLC
  
Indiana
    
Reliant Services, LLC
  
Indiana
    
Haddington Energy Partners, LP
  
Delaware
    
Haddington Energy Partners II, LP
  
Delaware
    
EX-23.1 3 ex23_1.htm EXHIBIT 23.1 ex23_1.htm
Exhibit 23.1
 
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement Nos. 333-163828, 333-135429, 333-118399, 333-61252, 333-33684, and 333-33608 on Forms S-8 and in Registration Statement Nos. 333-155383 and 333-140777 on Forms S-3ASR of our reports dated February 17, 2011, relating to the consolidated financial statements and consolidated financial statement schedule of Vectren Corporation and subsidiaries, and the effectiveness of Vectren Corporation and subsidiaries’ internal control over financial reporting, appearing in this Annual Report on Form 10-K of Vectren Corporation for the year ended December 31, 2010.


 
/s/ Deloitte & Touche LLP
Indianapolis, Indiana
February 17, 2011

 EX-31.1 4 ex31_1.htm EXHIBIT 31.1 ex31_1.htm
Exhibit 31.1

CERTIFICATION PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

CHIEF EXECUTIVE OFFICER CERTIFICATION

I, Carl L. Chapman, certify that:

1.  
I have reviewed this Annual Report on Form 10-K of Vectren Corporation;

2.  
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.  
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.  
The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)  
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
 
 
(b)  
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)  
Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)  
Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.  
The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a)  
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b)  
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: February 17, 2011

/s/ Carl L. Chapman
Carl L. Chapman
President and Chief Executive Officer
EX-31.2 5 ex31_2.htm EXHIBIT 31.2 ex31_2.htm
Exhibit 31.2

CERTIFICATION PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

CHIEF FINANCIAL OFFICER CERTIFICATION

I, Jerome A. Benkert, Jr., certify that:

1.  
I have reviewed this Annual Report on Form 10-K of Vectren Corporation;

2.  
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.  
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.  
The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)  
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)  
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)  
Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)  
Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.  
The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a)  
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b)  
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: February 17, 2011

/s/ Jerome A. Benkert, Jr.
Jerome A. Benkert, Jr.
Executive Vice President and Chief Financial Officer
EX-32 6 ex32.htm EXHIBIT 32 ex32.htm
Exhibit 32

CERTIFICATION PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

CERTIFICATION
By signing below, each of the undersigned officers hereby certifies pursuant to 18 U.S.C. § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge, (i) this Annual Report on Form 10-K fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in this report fairly presents, in all material respects, the financial condition and results of operations of Vectren Corporation.
 
Signed this 17th day of February, 2011.
 

 
/s/ Jerome A. Benkert, Jr.
  
/s/ Carl L. Chapman
(Signature of Authorized Officer)
  
(Signature of Authorized Officer)
 
Jerome A. Benkert, Jr.
  
Carl L. Chapman
(Typed Name)
  
(Typed Name)
 
Executive Vice President and Chief Financial Officer
  
President and Chief Executive Officer
(Title)
  
(Title)
 
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TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman"><font style="DISPLAY: inline; TEXT-DECORATION: underline">Allowance for Uncollectible Accounts</font></font></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt"><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">The Company maintains allowances for uncollectible accounts for estimated losses resulting from the inability of its customers to make req uired payments. The Company estimates the allowance for uncollectible accounts based on a variety of factors including the length of time receivables are past due, the financial health of its customers, unusual macroeconomic conditions, and historical experience.&#160;&#160;If the financial condition of its customers deteriorates or other circumstances occur that result in an impairment of customers&#8217; ability to make payments, the Company records additional allowances as needed.</font></div></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman"><font style="DISPLAY: inline; TEXT-DECORATION: underline">Inventories</font></font></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font s tyle="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">In most circumstances, the Company&#8217;s inventory components are recorded using an average cost method; however, natural gas in storage at the Company&#8217;s Indiana utilities and coal inventory at the Company&#8217;s nonutility coal mines are recorded using the Last In &#8211; First Out (LIFO) method.&#160;&#160;Inventory related to the Company&#8217;s regulated operations is valued at historical cost consistent with ratemaking treatment.&#160;&#160;Materials and supplies are recorded as inventory when purchased and subsequently charged to expense or capitalized to plant when installed.&#160;&#160;Nonutility inventory is valued at the lower of cost or market.</font></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt"><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div></div><div style="DISPLAY: block; M ARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman"><font style="DISPLAY: inline; TEXT-DECORATION: underline">Property, Plant &amp; Equipment</font></font></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">Both the Company&#8217;s <font style="DISPLAY: inline; FONT-STYLE: italic">Utility Plant</font> and <font style="DISPLAY: inline; FONT-STYLE: italic">Nonutility Plant</font> is stated at historical cost, inclusive of financing costs and direct and indirect construction costs, less accumulated depreciation and when necessary, impairment charges.&#160;&#160;The cost of renewals and betterments that extend the useful life are capitalized.&#160;&#160;Maintenance and repairs, including the cost of remova l of minor items of property and planned major maintenance projects, are charged to expense as incurred.</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-STYLE: italic; FONT-FAMILY: Times New Roman">Utility Plant &amp; Related Depreciation</font></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">Both the IURC and PUCO allow the Company&#8217;s utilities to capitalize financing costs associated with <font style="DISPLAY: inline; FONT-STYLE: italic">Utility Plant</font> based on a computed interest cost and a designated cost of equity funds.&#160;&#160;These financing costs are commonly referred to as AFUDC and are capitalized for ratemaking purposes and for financial reporting purposes instead of amounts that would otherwise be capitalized when acquiring nonutility plant.&#160;&#160;The Company reports both the debt and equity components of AFUDC in <font style="DISPLAY: inline; FONT-STYLE: italic">Other &#8211; net</font> in the <font style="DISPLAY: inline; FONT-STYLE: italic">Consolidated Statements of Income</font>.</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">When property that represents a retirement unit is replaced or removed, the remaining historical value of such property is charged to <font style="DISPLAY: inline; FONT-STYLE: italic">Utility plant</font>, with an offsetting charge to <font style="DISPLAY: inline; FONT-STYLE: italic" >Accumulated depreciation</font>, resulting in no gain or loss.&#160;&#160;Costs to dismantle and remove retired property are recovered through the depreciation rates as determined by the IURC and PUCO.</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">The Company&#8217;s portion of jointly owned <font style="DISPLAY: inline; FONT-STYLE: italic">Utility Plant</font>, along with that plant&#8217;s related operating expenses, is presented in these financial statements in proportion to the ownership percentage.</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FO NT-SIZE: 10pt; FONT-STYLE: italic; FONT-FAMILY: Times New Roman">Nonutility Plant &amp; Related Depreciation</font></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">The depreciation of <font style="DISPLAY: inline; FONT-STYLE: italic">Nonutility Plant</font> is charged against income over its estimated useful life, using the straight-line method of depreciation or units-of-production method of amortization for certain coal mining assets.&#160;&#160;When nonutility property is retired, or otherwise disposed of, the asset and accumulated depreciation are removed, and the resulting gain or loss is reflected in income, typically impacting operating expenses.</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-STYLE: italic; FONT-FAMILY: Times New Roman">Impairment Reviews</font></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">Property, plant and equipment along with other long-lived assets are reviewed as facts and circumstances indicate that the carrying amount may be impaired.&#160;&#160;This impairment review involves the comparison of an asset&#8217;s (or group of assets&#8217;) carrying value to the estimated future cash flows the asset (or asset group) is expected to generate over a remaining life.&#160;&#160;If this evaluation were to conclude that the carrying value is impaired, an impairment charge would be recorded based on the difference between the carrying amount and its fair value (less costs to sell for assets to be disposed of by sale) as a cha rge to operations or discontinued operations.</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman"><font style="DISPLAY: inline; TEXT-DECORATION: underline">Investments in Unconsolidated Affiliates</font></font></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman"><font style="DISPLAY: inline; FONT-STYLE: italic">Investments in unconsolidated affiliates</font> where the Company has significant influence are accounted for using the equity method of accounting.&#160;&#160;The Company&#8217;s share of net income or loss from these investments is recorded in <font style="DISPLAY: inline; FONT-STYLE: italic">Equity in earnings of unconsolidated affiliates</font>.&#160;&#160;Dividends are recorded as a reduction of the carrying value of the investment when received.&#160;&#160;<font style="DISPLAY: inline; FONT-STYLE: italic">Investments in unconsolidated affiliates</font> where the Company does not have significant influence are accounted for using the cost method of accounting.&#160;&#160;Dividends associated with cost method investments are recorded as <font style="DISPLAY: inline; FONT-STYLE: italic">Other &#8211; net </font>when received.&#160;&#160;Investments, when necessary, include adjustments for declines in value judged to be other than temporary.</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman"> ;<font style="DISPLAY: inline; TEXT-DECORATION: underline">Goodwill</font></font></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman"><font style="DISPLAY: inline; FONT-STYLE: italic">Goodwill </font>recorded on the <font style="DISPLAY: inline; 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TEXT-DECORATION: underline">Regulation</font></font></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">Retail public utility operations affecting Indiana customers are subject to regulation by the IURC, and retail public utility operations affecting Ohio customers are subject to regulation by the PUCO.&#160;&#160;The Company& amp;#8217;s accounting policies give recognition to the ratemaking and accounting practices authorized by these agencies.</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-STYLE: italic; FONT-FAMILY: Times New Roman">Refundable or Recoverable Gas Costs &amp; Cost of Fuel &amp; Purchased Power</font></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">All metered gas rates contain a gas cost adjustment clause that allows the Company to charge for changes in the cost of purchased gas.&#160;&#160;Metered electric rates contain a fuel adjustment clause that allows for adjustment in charges for electric energy to reflect changes in the cost of fuel.&#160;&#160;The net energy cost of purchased power, subject to a variable benchmark based on NYMEX natural gas prices, is also recovered through regulatory proceedings.&#160;&#160;The Company records any under-or-over-recovery resulting from gas and fuel adjustment clauses each month in revenues.&#160;&#160;A corresponding asset or liability is recorded until the under or over-recovery is billed or refunded to utility customers.&#160;&#160;The cost of gas sold is charged to operating expense as delivered to customers, and the cost of fuel and purchased power for electric generation is charged to operating expense when consumed.</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-STYLE: italic; FONT-FAMILY: Times New Roman">Regulatory Assets &amp; Liabilities</f ont></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">Regulatory assets represent probable future revenues associated with certain incurred costs, which will be recovered from customers through the ratemaking process.&#160;&#160;Regulatory liabilities represent probable expenditures by the Company for removal costs or future reductions in revenues associated with amounts that are to be credited to customers through the ratemaking process.&#160;&#160;The Company continually assesses the recoverability of costs recognized as regulatory assets and liabilities and the ability to recognize new regulatory assets and liabilities associated with its regulated utility operations.&#160;&#160;Given the current regulatory environment in its jurisdictions, the Company believes such accounting is appropriate.</font></div><div style="DIS PLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">The Company collects an estimated cost of removal of its utility plant through depreciation rates established in regulatory proceedings.&#160;&#160;The Company records amounts expensed in advance of payments as a <font style="DISPLAY: inline; FONT-STYLE: italic">Regulatory liability</font> because the liability does not meet the threshold of an asset retirement obligation.</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman"><font style="DISPLAY: inline; TEXT-DECORATION: underline">Postretirement Obligations &amp ; Costs</font></font></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">The Company recognizes the funded status of its pension plans and postretirement plans on its balance sheet date.&#160;&#160;The funded status of a defined benefit plan is its assets (if any) less its projected benefit obligation (PBO), which reflects service accrued to date and includes the impact of projected salary increases (for pay-related benefits).&#160;&#160;The funded status of a postretirement plan is its assets (in any) less its accumulated postretirement benefit obligation (APBO), which reflects accrued service to date.&#160;&#160;To the extent this obligation exceeds amounts previously recognized in the statement of income, the Company records a <font style="DISPLAY: inline; FONT-STYLE: italic">Regulatory asset</font> for that portion related to its cost-based and rate regulated utilities.&#160;&#160;To the extent that excess liability does not relate to a cost-based rate-regulated utility, the offset is recorded as a reduction to equity in <font style="DISPLAY: inline; FONT-STYLE: italic">Accumulated other comprehensive income</font>.</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">The annual cost of all post retirement plans is recognized in operating expenses or capitalized to plant following the direct labor of current employees.&#160;&#160;Specific to pension plans, the Company uses the projected unit credit actuarial cost method to calculate service cost and the PBO.&#160;&#160;This method projects the present value of benefits at retirement and allocates that cos t over the projected years of service.&#160;&#160;Annual service cost represents one year&#8217;s benefit accrual while the PBO represents benefits allocated to previously accrued service.&#160;&#160;For other postretirement plans, service cost is calculated by dividing the present value of a participant&#8217;s projected postretirement benefits into equal parts based upon the number of years between a participant&#8217;s hire date and first eligible retirement date.&#160;&#160;Annual service cost represents one year&#8217;s benefit accrual while the APBO represents benefit allocated to previously accrued service.&#160;&#160;To calculate the expected return on pension plan assets, the Company uses the plan assets&#8217; market-related value and an expected long-term rate of return.&#160;&#160;For the majority of the Company&#8217;s pension plans, the fair market value of the assets at the measurement date is adjusted to a market-related value by recognizing the change in fair value experienced in a given year ratably over a five-year period.&#160;&#160;Interest cost represents the annual accretion of the PBO and APBO at the discount rate.&#160;&#160;Actuarial gains and losses outside of a corridor (equal to 10% of the greater of the benefit obligation and the market-related value of assets) are amortized over the expected future working lifetime of active participants (except for plans where almost all participants are inactive).&#160;&#160;Prior service costs related to plan changes are amortized over the expected future working lifetime (or to full eligibility date for postretirement plan other than pensions) of the active participants at the time of the amendment.</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMIL Y: Times New Roman"><font style="DISPLAY: inline; TEXT-DECORATION: underline">Asset Retirement Obligations</font></font></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">A portion of removal costs related to interim retirements of gas utility pipeline and utility poles, certain asbestos-related issues, and reclamation activities meet the definition of an asset retirement obligation (ARO).&#160;&#160;The Company records the fair value of a liability for a legal ARO in the period in which it is incurred.&#160;&#160;When the liability is initially recorded, the Company capitalizes a cost by increasing the carrying amount of the related long-lived asset.&#160;&#160;The liability is accreted, and the capitalized cost is depreciated over the useful life of the related asset.&#160;&#160;Upon settlement of the liability , the Company settles the obligation for its recorded amount or incurs a gain or loss.&#160;&#160;To the extent regulation is involved, regulatory assets and liabilities result when accretion and amortization is adjusted to match rates established by regulators and any gain or loss is subject to deferral.</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman"><font style="DISPLAY: inline; TEXT-DECORATION: underline">Product Warranties, Performance Guarantees &amp; Other Guarantees</font></font></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">Liabilities and expenses associated with product warranties and per formance guarantees are recognized based on historical experience at the time the associated revenue is recognized.&#160;&#160;Adjustments are made as changes become reasonably estimable.&#160;&#160;The Company does not recognize the fair value of an obligation at inception for these guarantees because they are guarantees of the Company&#8217;s own performance and/or product installations.</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">While not significant at December 31, 2010 or 2009, the Company does recognize the fair value of an obligation at the inception of a guarantee in certain circumstances.&#160;&#160;These circumstances would include executing certain indemnification agreements and guaranteeing operating lease residual values, the perf ormance of a third party, or the indebtedness of a third party.</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman"><font style="DISPLAY: inline; TEXT-DECORATION: underline">Energy Contracts &amp; Derivatives</font></font></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">The Company will periodically execute 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.&#160;&#160;A derivative is recognized on the balance sheet as an asset or liability measured at its fair market value and the chang e in the derivative's fair market value is recognized currently in earnings unless specific hedge criteria are met.</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">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.&#160;&#160;Most energy contracts executed by the Company are subject to the NPNS exclusion or are not considered derivatives.&#160;&#160;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.</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></d iv><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">When the Company engages in energy contracts and financial contracts that are derivatives and are not subject to the NPNS or other exclusions, 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.&#160;&#160;Contracts and any associated collateral with counter-parties subject to master netting arrangements are presented net in the <font style="DISPLAY: inline; FONT-STYLE: italic">Consolidated Balance Sheets</font>.&#160;&#160;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 regulatory accounting treatment.&#160;&#160;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.&#160;&#160;When the hedging relationship is highly effective, derivatives are designated as hedges.&#160;&#160;The market value of the effective portion of the hedge is marked to market in<font style="DISPLAY: inline; 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(a nonutility wholly owned subsidiary of the Company) under coal contracts entered into in 2008.&#160;&#160;Vectren South states in its rate case testimony that the prices in the coal contracts were at or below the market at the time of contract execution and were subject to a bidd ing process that included third parties.&#160;&#160;Further, the Company has already engaged in contract renegotiations to defer certain deliveries, and to eliminate some volumes in 2011, with further price negotiation to occur in 2011 under the terms of the contracts.&#160;&#160;The IURC has already found in a number of FAC proceedings since 2008, including in its most recent FAC order dated November 4, 2010, that the costs incurred under these coal contracts are reasonable.</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">The OUCC also raised concerns regarding Vectren South&#8217;s generating unit &#8220;must run&#8221; policy.&#160;&#160;Under that policy, for reliability reasons, Vectren South instructs the MISO that certain units must be dispatched regardless of current market conditions. &#160;The OUCC is reviewing data related to Vectren South&#8217;s &#8220;must run&#8221; policy.</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">The parties agreed to the creation of an FAC sub docket proceeding to address the specific issues noted above.&#160;&#160;An order establishing the sub docket was issued by the IURC on July 28, 2010.&#160;&#160;On November 30, 2010, in response to a joint motion filed by the OUCC and Vectren South, the IURC issued an order dismissing this sub docket as these coal contract issues will be addressed in the pending Vectren South Electric base rate case.</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div> <div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman"><font style="DISPLAY: inline; TEXT-DECORATION: underline">Vectren South Electric Demand Side Management Program Filing</font></font></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">On August 16, 2010, Vectren South filed a petition with the IURC, seeking approval of its proposed Demand Side Management (DSM) Programs, recovery of the costs associated with these programs, recovery of lost margins as a result of implementing these programs for large customers, and recovery of performance incentives linked with specific measurement criteria on all programs.&#160;&#160;The DSM Programs proposed are consistent with a December 9, 2009 order issued by the IURC, wh ich, among other actions, defined long-term conservation objectives and goals of DSM programs for all Indiana electric utilities under a consistent statewide approach.&#160;&#160;In order to meet these objectives, the IURC order divided the DSM programs into Core and Core Plus programs.&#160;&#160;Core programs are joint programs required to be offered by all Indiana electric utilities to all customers, including large industrial customers.&#160;&#160;Core Plus programs are those programs not required specifically by the IURC, but defined by each utility to meet the overall energy savings targets defined by the IURC.</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">In its August filing, Vectren South proposed a three-year DSM Plan that expands its curre nt portfolio of Core and Core Plus DSM Programs in order to meet the energy savings goals established by the IURC.&#160;&#160;Vectren South requested recovery of these program costs under a current tracking mechanism.&#160;&#160;In addition, Vectren South proposed a performance incentive mechanism that is contingent upon the success of each of the DSM Programs in reducing energy usage to the levels defined by the IURC.&#160;&#160;This performance incentive would also be recovered in the same tracking mechanism.&#160;&#160;Finally, the Company proposed lost margin recovery associated with the implementation of DSM programs for large customers, and cited its decoupling proposal applicable to residential and general service customers in the pending electric base rate case.&#160;&#160;On January 20, 2011, the OUCC and Vectren South filed a settlement with the IURC reflecting agreement on the Company&#8217;s programs and lost margin recovery from large customers.&#1 60;&#160;A hearing will be held on March 8, 2011 involving all parties to this proceeding.</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman"><font style="DISPLAY: inline; TEXT-DECORATION: underline">VEDO Gas Base Rate Order Received</font></font></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">On January 7, 2009, the PUCO issued an order approving the stipulation reached in the VEDO rate case.&#160;&#160;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 r eplacement 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.</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">The order also adjusted the rate design used to collect the agreed-upon revenue from VEDO's customers.&#160;&#160;The order allows for the phased movement toward a straight fixed variable rate design for residential customers which places all of the fixed cost recovery in the customer service charge.&#160;&#160;A straight fixed variable design mitigates most weather risk as well as the effects of declining usage, similar to the Company&#8217;s decoupling mechanism, which expired when this new rate design went into effect on February 22, 2009.&a mp;#160;&#160;In 2008, annual results include approximately $4.3 million of revenue from the decoupling mechanism that did not continue once this base rate increase went into effect.&#160;&#160;Since the straight fixed variable rate design was fully implemented in February 2010, nearly 90 percent of the combined residential and commercial base rate margins were recovered through the customer service charge.&#160;&#160;The OCC appealed this rate order to the Ohio Supreme Court, which had affirmed PUCO orders authorizing straight fixed variable rate design in two other cases. On December 23, 2010, the Ohio Supreme Court affirmed the PUCO order authorizing straight fixed variable rate design in VEDO&#8217;s case.&#160;</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Time s New Roman">With this rate order, the Company has in place for its Ohio gas territory rates that allow for a straight fixed variable rate design that mitigates both weather risk and lost margin for residential customers; tracking of uncollectible accounts 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.</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman"><font style="DISPLAY: inline; TEXT-DECORATION: underline">VEDO Continues the Process to Exit the Merchant Function</font>< /font></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">On August 20, 2008, the PUCO approved the results of an auction selecting qualified wholesale suppliers to provide the gas commodity to the Company for resale to its customers at auction-determined standard pricing.&#160;&#160;This standard pricing was comprised of the monthly NYMEX settlement price plus a fixed adder.&#160;&#160;This standard pricing, which was effective from October 1, 2008 through March 31, 2010, was the initial step in exiting the merchant function in the Company&#8217;s Ohio service territory.&#160;&#160;The approach eliminated the need for monthly gas cost recovery (GCR) filings and prospective PUCO GCR audits.<font style="DISPLAY: inline; FONT-SIZE: 70%; VERTICAL-ALIGN: text-top">&#160;</font> In October 2008, VEDO&#8217;s entire natur al gas inventory was transferred to the auction&#8217;s winning wholesale suppliers, resulting in proceeds to VEDO of approximately $107 million.</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">The second phase of the exit process began on April 1, 2010.&#160;&#160;During this phase, the Company no longer sells natural gas directly to customers.&#160;&#160;Rather, state-certified Competitive Retail Natural Gas Suppliers, that were successful bidders in a similar regulatory-approved auction, sell the gas commodity to specific customers for a 12 month period at auction-determined standard pricing.&#160;&#160;The first auction was conducted on January 12, 2010, and the auction results were approved by the PUCO on January 13, 2010.&#160; The plan a pproved by the PUCO required that the Company conduct at least two annual auctions during this phase.&#160; As such, the Company conducted another auction on January 18, 2011 in advance of the second 12-month term which commences on April 1, 2011.&#160;&#160;The results of that auction were approved by the PUCO on January 19, 2011.<font style="DISPLAY: inline; FONT-FAMILY: Times New Roman">&#160;</font>Consistent with current practice, customers will continue to receive a single bill for the commodity as well as the delivery component of natural gas service from VEDO.&#160;&#160;Vectren Source, the Company&#8217;s wholly owned nonutility retail gas marketer, was a successful bidder in both auctions.</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">The PUCO provided for an Exit Transition Cost rider, which allows the Company to recover costs associated with the transition process.&#160;&#160;Exiting the merchant function should not have a material impact on earnings or financial condition.&#160;&#160;It, however, has and will continue to reduce <font style="DISPLAY: inline; FONT-STYLE: italic">Gas utility revenues</font> and have an equal and offsetting impact to <font style="DISPLAY: inline; FONT-STYLE: italic">Cost of gas sold </font>as VEDO no longer purchases gas for resale to these customers.</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman"><font style="DISPLAY: inline; TEXT-DECORATION: underline">Vectren North Gas Base Rate Order Received</font></fon t></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">On February 13, 2008, the Company received an order from the IURC which approved the settlement agreement reached in its Vectren North gas rate case.&#160; The order provided for a base rate increase of $16.3 million and a return on equity (ROE) of 10.2 percent, with an overall rate of return of 7.8 percent on rate base of approximately $793 million.&#160;&#160;The order also provided for the recovery of $10.6 million of costs through separate cost recovery mechanisms rather than base rates.</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">Further, additional expendi tures for a multi-year bare steel and cast iron capital replacement program will be afforded certain accounting treatment that mitigates earnings attrition from the investment between rate cases.&#160; The accounting treatment allows for the continuation of the accrual for AFUDC and the deferral of depreciation expense after the projects go in service but before they are included in base rates. &#160;To qualify for this treatment, the annual expenditures are limited to $20 million and the treatment cannot extend beyond four years from the in-service date for each specific project.</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">With this order, the Company has in place for its North gas territory weather normalization, a conservation and decoupling mechanism, recovery of gas cost expense related to uncollectible accounts expense based on historical experience and tracking of unaccounted for gas costs through the existing GCA mechanism, and tracking of pipeline integrity management expense.&#160;</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman"><font style="DISPLAY: inline; TEXT-DECORATION: underline">MISO Transactions</font></font></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">The Company is a member of the MISO, a FERC approved regional transmission organization.&#160;&#160;When the Company is a net seller of its generation, such net revenues, which totaled $24. 9 million, $20.8 million, and $57.6 million for the twelve months ended December 31, 2010, 2009, and 2008, respectively, are included in <font style="DISPLAY: inline; FONT-STYLE: italic">Electric utility revenues</font>.&#160;&#160;When the Company is a net purchaser such net purchases, which totaled $46.1 million, $34.4 million, and $16.6 million for the twelve months ended December 31, 2010, 2009, and 2008, respectively, are included in <font style="DISPLAY: inline; FONT-STYLE: italic">Cost of fuel &amp; purchased power.&#160;&#160;</font>Net positions are determined on an hourly basis.</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">The Company also receives transmission revenue from the MISO which is included in <font style=" DISPLAY: inline; FONT-STYLE: italic">Electric utility revenues</font> and totaled $18.8 million, $14.6 million, and $9.3 million for the twelve months ended December 31, 2010, 2009, and 2008, respectively.&#160;&#160;These revenues result from other MISO members&#8217; use of the Company&#8217;s transmission system as well as the recovery of the Company&#8217;s investment in certain new electric transmission projects meeting MISO&#8217;s transmission expansion plan criteria.</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div> <div><table style="FONT-SIZE: 10pt; FONT-FAMILY: times new roman" cellspacing="0" cellpadding="0" width="100%"><tr valign="top"><td style="WIDTH: 18pt" align="right"><div><font style="DISPLAY: inline; FONT-WEIGHT: bold; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">16.&#160;&#160;</font></div></td><td><div style="MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="justify"><font style="DISPLAY: inline; FONT-WEIGHT: bold; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">Environmental Matters</font></div></td></tr></table></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman"><font style="DISPLAY: i nline; TEXT-DECORATION: underline">Clean Air Act</font></font></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">The Clean Air Interstate Rule (CAIR) is an allowance cap and trade program that required reductions from coal-burning power plants for NOx emissions beginning January 1, 2009 and SO<font style="DISPLAY: inline; FONT-SIZE: 70%; VERTICAL-ALIGN: sub">2</font> emissions beginning January 1, 2010, with a second phase of reductions in 2015.&#160; On July 11, 2008, the US Court of Appeals for the District of Columbia vacated the federal CAIR regulations.&#160;&#160;Various parties filed motions for reconsideration, and on December 23, 2008, the Court reinstated the CAIR regulations and remanded the regulations back to the EPA for promulgation of revisions in accordance with the Court&#8217;s July 11, 2008 order.&#1 60;&#160;Thus, the original version of CAIR promulgated in March of 2005 remains effective while EPA revises it per the Court&#8217;s guidance.&#160;&#160;SIGECO is in compliance with the current CAIR Phase I annual NOx reduction requirements in effect on January 1, 2009, and the Phase I annual SO<font style="DISPLAY: inline; 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TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" a lign="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman"><font style="DISPLAY: inline; FONT-SIZE: 10pt">To comply with Indiana&#8217;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 SO</font><font style="DISPLAY: inline; FONT-SIZE: 70%; VERTICAL-ALIGN: sub">2&#160;&#160;</font><font style="DISPLAY: inline; FONT-SIZE: 10pt">reductions, SIGECO has IURC authority to invest in clean coal technology.&#160; Using this authorization, SIGECO has invested approximately $411 million in pollution control equipment, including Selective Catalytic Reduction (SCR) systems, fabric filters, and an SO</font><font style="DISPLAY: inline; FONT-SIZE: 70%; VERTICAL-ALIGN: sub">2 </font><font style="DISPLAY: inline; FONT-SIZE: 10pt">scrubber at its generating facility that is jointly owned with ALCOA (the Company&#8 217;s portion is 150 MW).&#160;&#160;SCR technology is the most effective method of reducing NOx emissions where high removal efficiencies are required and fabric filters control particulate matter emissions.</font>&#160;&#160;<font style="DISPLAY: inline; FONT-SIZE: 10pt">Of the $411 million, $312 million was included in rate base for purposes of determining SIGECO&#8217;s new electric base rates that went into effect on August 15, 2007, and $99 million is currently recovered through a rider mechanism which is periodically updated for actual costs incurred including depreciation expense. As part of its recent rate proceeding, the Company has requested to also include these more recent expenditures in rate base as well.</font></font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10 pt; FONT-FAMILY: Times New Roman">SIGECO&#8217;s coal fired generating fleet is 100 percent scrubbed for SO<font style="DISPLAY: inline; FONT-SIZE: 70%; VERTICAL-ALIGN: sub">2 </font>and 90 percent controlled for NOx.&#160;&#160;SIGECO's investments in scrubber, SCR, and fabric filter technology allows for compliance with existing regulations and should position it to comply with future reasonable mercury pollution control legislation, if and when, reductions are promulgated by EPA.&#160;&#160;On July 6, 2010, the EPA issued its proposed revisions to CAIR, renamed the Clean Air Transport Rule, for public comment.&#160;&#160;The Transport Rule proposes a 71 percent reduction of SO<font style="DISPLAY: inline; FONT-SIZE: 70%; VERTICAL-ALIGN: sub">2</font> over 2005 national levels and a 52 percent reduction of NOx over 2005 national levels and would further impact the utilization of currently granted SO<font style="DISPLAY: inline; FONT-SIZE: 70%; VERTI CAL-ALIGN: sub">2</font> and NOx allowances.&#160;&#160;The Company is currently reviewing the sufficiency of its existing pollution control equipment in relation to the requirements proposed in the Clean Air Transport Rule and currently does not expect significant capital expenditures will be required to comply if the Transport Rule is adopted in its current form.</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman"><font style="DISPLAY: inline; TEXT-DECORATION: underline">Climate Change</font></font></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">Numerous competing legislative proposals have also b een introduced in recent years that involve carbon, energy efficiency, and renewable energy.&#160;&#160;Comprehensive energy legislation at the federal level continues to be debated, but there has been little progress to date.&#160;&#160;The progression of regional initiatives throughout the United States has slowed.&#160;&#160;While no climate change legislation is pending in Indiana, the state is an observer to the Midwestern Regional Greenhouse Gas Reduction Accord and the state&#8217;s legislature debated, but did not pass, a renewable energy portfolio standard in 2009.</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">In advance of a federal or state renewable portfolio standard, SIGECO received regulatory approval to purchase a 3 MW landfill ga s generation facility from a related entity.&#160;&#160;The facility was purchased in 2009 and is directly interconnected to the Company&#8217;s distribution system.&#160;&#160;In 2009, the Company also executed a long term purchase power commitment for 50 MW of wind energy.&#160;&#160;These transactions supplement a 30 MW wind energy purchase power agreement executed in 2008.</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">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 EPA to determine whether greenhouse gas emissions from motor vehicles cause or contribute to air pollution that may reasonably be anticipated to endanger public health or welfare. In April of 2009, the EPA published its proposed endangerment finding for public comment.&#160;&#160;The proposed endangerment finding concludes that carbon emissions from mobile sources pose an endangerment to public health and the environment.&#160;&#160;The endangerment finding was finalized in December of 2009, and is the first step toward EPA regulating carbon emissions through the existing Clean Air Act in the absence of specific carbon legislation from Congress.&#160;&#160;Therefore, any new regulations would likely also impact major stationary sources of greenhouse gases.&#160;&#160;The EPA has promulgated two greenhouse gas regulations that apply to SIGECO&#8217;s generating facilities.&#160;&#160;In 2009, the EPA finalized a mandatory greenhouse gas emissions registry which will require reporting of emissions beginning in 2011 (for the emission year 2010).&#160;&#160;The EPA has also recently finalized a revision to the Prevention of Significant Deterioration (PSD) and Title V permitting rules which would require facilities that emit 75,000 tons or more of greenhouse gases a year to obtain a PSD permit for new construction or a significant modification of an existing facility.</font></div><div style="DISPLAY: block; 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to minimize adverse environmental impacts.&#160;&#160;More specifically, Section 316(b) is concerned with impingement and entrainment of aquatic species in once-through cooling water intake structures.&#160;&#160;In April of 2009, the U.S. Supreme Court affirmed that the EPA could, but was not required to, consider costs and benefits in making the evaluation as to the best technology available for existing facilities.&#160;&#160;The regulation was remanded back to the EPA for further consideration.&#160;&#160;Depending upon the approaches taken by the EPA when it reissues the regulation, capital investments could be in the $40 million range if new infrastructure, such as new cooling water towers, is required.</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><f ont style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman"><font style="DISPLAY: inline; TEXT-DECORATION: underline">Jacobsville Superfund Site</font></font></div><div style="DISPLAY: block; 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Based on testing performed in the second quarter of 2009, SE determined that attempts at corrective measures had been unsuccessful in development of certain caverns.&#160;&#160;At June 30, 2009, Liberty recorded a charge of approximately $132 mill ion to write off the north caverns and certain related assets.&#160;&#160;As an equity investor in Liberty, ProLiance recorded its share of the charge, totaling $33 million at June 30, 2009.&#160;&#160;The Company&#8217;s share is $11.9 million after tax. 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Related Depreciation</font></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">Both the IURC and PUCO allow the Company&#8217;s utilities to capitalize financing costs associated with <font style="DISPLAY: inline; FONT-STYLE: italic">Utility Plant</font> based on a computed interest cost and a designated cost of equity funds.&#160;&#160;These financing costs are commonly referred to as AFUDC and are capitalized for ratemaking purposes and for financial reporting purposes instead of amounts that would otherwise be capitalized when acquiring nonutility plant.&#160;&#160;The Company reports both the debt and equity components of AFUDC in <font style="DISPLAY: inline; FONT-STYLE: italic">Other &#8211; net</font> in the <font style="DISPLAY: inline; FONT-STYLE: italic">Consolidated Statements of Income</font>.</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">When property that represents a retirement unit is replaced or removed, the remaining historical value of such property is charged to <font style="DISPLAY: inline; FONT-STYLE: ital ic">Utility plant</font>, with an offsetting charge to <font style="DISPLAY: inline; FONT-STYLE: italic">Accumulated depreciation</font>, resulting in no gain or loss.&#160;&#160;Costs to dismantle and remove retired property are recovered through the depreciation rates as determined by the IURC and PUCO.</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">The Company&#8217;s portion of jointly owned <font style="DISPLAY: inline; FONT-STYLE: italic">Utility Plant</font>, along with that plant&#8217;s related operating expenses, is presented in these financial statements in proportion to the ownership percentage.</font></div><div style="DISPLAY: block; 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TEXT-DECORATION: underline">Regulation</font></font></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">Retail public utility operations affecting Indiana customers are subject to regulation by the IURC, and retail publi c utility operations affecting Ohio customers are subject to regulation by the PUCO.&#160;&#160;The Company&#8217;s accounting policies give recognition to the ratemaking and accounting practices authorized by these agencies.</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-STYLE: italic; FONT-FAMILY: Times New Roman">Refundable or Recoverable Gas Costs &amp; Cost of Fuel &amp; Purchased Power</font></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">All metered gas rates contain a gas cost adjustment clause that allows the Company to charge for changes in the cost of purchased gas.&#160;&#160;Metered electric rates contain a fuel adjustment clause that allows for adjustment in charges for electric energy to reflect changes in the cost of fuel.&#160;&#160;The net energy cost of purchased power, subject to a variable benchmark based on NYMEX natural gas prices, is also recovered through regulatory proceedings.&#160;&#160;The Company records any under-or-over-recovery resulting from gas and fuel adjustment clauses each month in revenues.&#160;&#160;A corresponding asset or liability is recorded until the under or over-recovery is billed or refunded to utility customers.&#160;&#160;The cost of gas sold is charged to operating expense as delivered to customers, and the cost of fuel and purchased power for electric generation is charged to operating expense when consumed.</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-STYLE: italic; FONT-FAMILY: Times New Roman">Regulatory Assets &amp; Liabilities</font></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">Regulatory assets represent probable future revenues associated with certain incurred costs, which will be recovered from customers through the ratemaking process.&#160;&#160;Regulatory liabilities represent probable expenditures by the Company for removal costs or future reductions in revenues associated with amounts that are to be credited to customers through the ratemaking process.&#160;&#160;The Company continually assesses the recoverability of costs recognized as regulatory assets and liabilities and the ability to recognize new regulatory assets and liabilities associated with its regulated utility operations.&#160;&#160;Given the current regulatory environment i n its jurisdictions, the Company believes such accounting is appropriate.</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">The Company collects an estimated cost of removal of its utility plant through depreciation rates established in regulatory proceedings.&#160;&#160;The Company records amounts expensed in advance of payments as a <font style="DISPLAY: inline; FONT-STYLE: italic">Regulatory liability</font> because the liability does not meet the threshold of an asset retirement obligation.</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Tim es New Roman"><font style="DISPLAY: inline; TEXT-DECORATION: underline">Postretirement Obligations &amp; Costs</font></font></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; 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market-related value and an expected long-term rate of return.&#160;&#160;For the majority of the Company&#8217;s pension plans, the fair market value of the assets at the measurement date is adjusted to a market-related value by recognizing the change in fair value experienced in a given year ratably over a five-year period.&#160;&#160;Interest cost represents the annual accretion of the PBO and APBO at the discount rate.&#160;&#160;Actuarial gains and losses outside of a corridor (equal to 10% of the greater of the benefit obligation and the market-related value of assets) are amortized over the expected future working lifetime of active participants (except for plans where almost all participants are inactive).&#160;&#160;Prior service costs related to plan changes are amortized over the expected future working lifetime (or to full eligibility date for postretirement plan other than pensions) of the active participants at the time of the amendment.</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0p t; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman"><font style="DISPLAY: inline; TEXT-DECORATION: underline">Asset Retirement Obligations</font></font></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">A portion of removal costs related to interim retirements of gas utility pipeline and utility poles, certain asbestos-related issues, and reclamation activities meet the definition of an asset retirement obligation (ARO).&#160;&#160;The Company records the fair value of a liability for a legal ARO in the period in which it is incurred.&#160;&#160;When the liability is initially recorded, the Company capitalizes a cost by increasing the carrying amount of the related long-lived asset.&#160;&#160;The liability is accreted, and the capitalize d cost is depreciated over the useful life of the related asset.&#160;&#160;Upon settlement of the liability, the Company settles the obligation for its recorded amount or incurs a gain or loss.&#160;&#160;To the extent regulation is involved, regulatory assets and liabilities result when accretion and amortization is adjusted to match rates established by regulators and any gain or loss is subject to deferral.</font></div><div style="DISPLAY: block; 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MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">The Company will periodically execute 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.&#160;&#160;A de rivative is recognized on the balance sheet as an asset or liability measured at its fair market value and the change in the derivative's fair market value is recognized currently in earnings unless specific hedge criteria are met.</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">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.&#160;&#160;Most energy contracts executed by the Company are subject to the NPNS exclusion or are not considered derivatives.&#160;&#160;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 generatin g capacity contracts.</font></div><div style="DISPLAY: block; 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borrowing arrangements.</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div&g t;<div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-STYLE: italic; FONT-FAMILY: Times New Roman">SIGECO 2009 Debt Issuance</font></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">On August 19, 2009 SIGECO also completed a $22.3 million tax-exempt first mortgage bond issuance at an interest rate of 5.4 percent that is fixed through maturity.&#160;&#160;The bonds mature in 2040.&#160;&#160;The proceeds from the sale of the bonds, net of issuance costs, totaled approximately $21.3 million.</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; 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The amount of the economic entity's stockholders' equity attributable to the parent excludes the amount of stockholders' equity which is allocable to that ownership interest in subsidiary equity which is not attributable to the parent (noncontrolling interest, mino rity interest). 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A dividend reinvestment plan allows the holder of the stock to reinvest dividends paid to them by the entity on new issues of stock by the entity.No authoritative reference available.falsefalse28false0vvc_StockIssuedDuringPeriodSharesStockOptionsExercisedAndDividendReinvestmentPlan vvcfalsenadurationNumber of shares issued during the period as a result of the exercise of stock options and from a dividend reinvestment plan...falsefalsefalsefalsefalsefalsefalsefalsefalsefalseterselabel1truefalsefalse3000000.3falsefalsefalsetruefalse2falsefalsefalse00falsefalsefalsetruefalse3falsefalsefalse00falsefalsefalsetruefalse4falsefalsefalse00falsefalsefalsefalsefalseSharesxbrli:sharesItemTypesharesNumber of shares issued during the period as a resul t of the exercise of stock options and from a dividend reinvestment plan (DRIP). 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Does not include common shares that have been repurchased.Reference 1: http://www.xbrl.org/2003/role/presentationRef -Publisher AICPA -Name Accounting Principles Board Opinion (APB) -Number 12 -Paragraph 10 Reference 2: http://www.xbrl.org/2003/role/presentationRef -Publisher SEC -Name Regulation S-X (SX) -Number 210 -Section 04 -Article 3 Reference 3: http://www.xbrl.org/2003/role/presentationRef -Publisher SEC -Name Regulation S-X (SX) -Number 210 -Section 02 -Paragraph 30 -Article 5 falsefalse448CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY (USD $)HundredThousandsHundredThousandsUnKnownUnKnownfalsetrue XML 37 R23.xml IDEA: Rate and Regulatory Matters 2.2.0.25falsefalse006180 - Disclosure - Rate and Regulatory Matterstruefalsefalse1falsefalseUSDfalsefalse1/1/2010 - 12/31/2010 USD ($) USD ($) / shares $c00025http://www.sec.gov/CIK0001096385duration2010-01-01T00:00:002010-12-31T00:00:00u000Standardhttp://www.xbrl.org/2003/iso4217USDiso42170u002Dividehttp://www.xbrl.org/2003/iso4217USDiso4217http://www.xbrl.org/2003/instancesharesxbrli 0u001Standardhttp://www.xbrl.org/2003/instancesharesxbrli0USDUSD$2true0vvc_NotesToFinancialStatementsAbstractvvcfalsenadurationNo definition available.falsefalsefalsefalsefalsefalsefalsefalsefalsefalse1falsefalsefalse00falsefalsefalsefalsefalseOtherxbrli:stringItemTypestringNo definition available.falsefalse3false0us-gaap_PublicUtilitiesDisclosureTextBlockus-gaaptruenadurationNo definition available.falsefalsefalsefalsefalsefalsefalsefalsefalsefalselabel< Cell>1falsefalsefalse00<div><table style="FONT-SIZE: 10pt; FONT-FAMILY: times new roman" cellspacing="0" cellpadding="0" width="100%"><tr valign="top"><td style="WIDTH: 18pt" align="right"><div><font style="DISPLAY: inline; FONT-WEIGHT: bold; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">17.&#160;&#160;</font></div></td><td><div style="MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="justify"><font style="DISPLAY: inline; FONT-WEIGHT: bold; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">Rate &amp; Regulatory Matters</font></div></td></tr></table></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGI N-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman"><font style="DISPLAY: inline; TEXT-DECORATION: underline">Vectren South Electric Base Rate Filing</font></font></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">On December 11, 2009, Vectren South filed a request with the IURC to adjust its base electric rates.&#160;&#160;The requested increase in base rates addresses capital investments, a modified electric rate design that facilitates a partnership between Vectren South and customers to pursue energy efficiency and conservation, and new energy efficiency programs to complement those currently offered for natural gas customers.&#160;&#160;On July 30, 2010, Vectren South revised downward its increase requested through the filing of its rebuttal position to approximately $34 million. The request addresses the roughly $325 million spent in infrastructure construction since its last base rate increase in August 2007 that was needed to continue to provide reliable service and updates to operating costs and revenues.&#160;&#160;The rate design proposed in the filing would break the link between small residential and commercial customers&#8217; consumption and the utility&#8217;s margin, thereby aligning the utility&#8217;s and customers&#8217; interests in using less energy.&#160;&#160;The revised request assumes an overall rate of return of 7.42 percent on rate base of approximately $1.3 billion and an allowed return on equity (ROE) of 10.7 percent.&#160;&#160;The OUCC and SIGECO Industrial Group separately filed testimony in this case, proposing an increase of approximately $11 million and $18 million, respectively.&#160; Furthermore, the intervening parties in the case took differing views on, among other matters, the proposed rate design and the level and price of coal inventory.&#160;&#160;Hearings on all matters in the case were held in early March and late August 2010.&#160;&#160;An order is anticipated in the first half of 2011.</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman"><font style="DISPLAY: inline; TEXT-DECORATION: underline">Vectren South Electric Fuel Adjustment Filings</font></font></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">As stated above, electric retail rates contain a fuel adjustment clause (FAC) that allows for periodic adjustment in energy charges to reflect changes in the cost of fuel and purchas ed power.&#160;&#160;The FAC procedures involve periodic filings and IURC hearings to approve the recovery of Vectren South&#8217;s fuel and purchased power costs.</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">During 2010, as part of its FAC testimony, the OUCC requested the IURC require Vectren South to renegotiate its term coal contracts because they were priced higher than prevailing spot prices.&#160;&#160;This request was repeated by the OUCC in Vectren South&#8217;s base rate proceeding referred to above.&#160;&#160;Vectren South purchases the majority of its coal from Vectren Fuels, Inc. (a nonutility wholly owned subsidiary of the Company) under coal contracts entered into in 2008.&#160;&#160;Vectren South states in its rate c ase testimony that the prices in the coal contracts were at or below the market at the time of contract execution and were subject to a bidding process that included third parties.&#160;&#160;Further, the Company has already engaged in contract renegotiations to defer certain deliveries, and to eliminate some volumes in 2011, with further price negotiation to occur in 2011 under the terms of the contracts.&#160;&#160;The IURC has already found in a number of FAC proceedings since 2008, including in its most recent FAC order dated November 4, 2010, that the costs incurred under these coal contracts are reasonable.</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">The OUCC also raised concerns regarding Vectren South&#8217;s generating unit &#8220;must run &#8221; policy.&#160;&#160;Under that policy, for reliability reasons, Vectren South instructs the MISO that certain units must be dispatched regardless of current market conditions. &#160;The OUCC is reviewing data related to Vectren South&#8217;s &#8220;must run&#8221; policy.</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">The parties agreed to the creation of an FAC sub docket proceeding to address the specific issues noted above.&#160;&#160;An order establishing the sub docket was issued by the IURC on July 28, 2010.&#160;&#160;On November 30, 2010, in response to a joint motion filed by the OUCC and Vectren South, the IURC issued an order dismissing this sub docket as these coal contract issues will be addressed in the pending Vectren South Electric base rate case.</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman"><font style="DISPLAY: inline; TEXT-DECORATION: underline">Vectren South Electric Demand Side Management Program Filing</font></font></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">On August 16, 2010, Vectren South filed a petition with the IURC, seeking approval of its proposed Demand Side Management (DSM) Programs, recovery of the costs associated with these programs, recovery of lost margins as a result of implementing these programs for large customers, and recovery of performance incentives linked with specific measuremen t criteria on all programs.&#160;&#160;The DSM Programs proposed are consistent with a December 9, 2009 order issued by the IURC, which, among other actions, defined long-term conservation objectives and goals of DSM programs for all Indiana electric utilities under a consistent statewide approach.&#160;&#160;In order to meet these objectives, the IURC order divided the DSM programs into Core and Core Plus programs.&#160;&#160;Core programs are joint programs required to be offered by all Indiana electric utilities to all customers, including large industrial customers.&#160;&#160;Core Plus programs are those programs not required specifically by the IURC, but defined by each utility to meet the overall energy savings targets defined by the IURC.</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">In its August filing, Vectren South proposed a three-year DSM Plan that expands its current portfolio of Core and Core Plus DSM Programs in order to meet the energy savings goals established by the IURC.&#160;&#160;Vectren South requested recovery of these program costs under a current tracking mechanism.&#160;&#160;In addition, Vectren South proposed a performance incentive mechanism that is contingent upon the success of each of the DSM Programs in reducing energy usage to the levels defined by the IURC.&#160;&#160;This performance incentive would also be recovered in the same tracking mechanism.&#160;&#160;Finally, the Company proposed lost margin recovery associated with the implementation of DSM programs for large customers, and cited its decoupling proposal applicable to residential and general service customers in the pending electric base rate case.&#160;&#160;On January 20, 2011, the OUCC and Vectren South fil ed a settlement with the IURC reflecting agreement on the Company&#8217;s programs and lost margin recovery from large customers.&#160;&#160;A hearing will be held on March 8, 2011 involving all parties to this proceeding.</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman"><font style="DISPLAY: inline; TEXT-DECORATION: underline">VEDO Gas Base Rate Order Received</font></font></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">On January 7, 2009, the PUCO issued an order approving the stipulation reached in the VEDO rate case.&#160;&#160;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.</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">The order also adjusted the rate design used to collect the agreed-upon revenue from VEDO's customers.&#160;&#160;The order allows for the phased movement toward a straight fixed variable rate design for residential customers which places all of the fixed cost recovery in the customer service charge.&#160;&#160;A straight fixed variable design mitigates most weather risk as well as the effects of declining usag e, similar to the Company&#8217;s decoupling mechanism, which expired when this new rate design went into effect on February 22, 2009.&#160;&#160;In 2008, annual results include approximately $4.3 million of revenue from the decoupling mechanism that did not continue once this base rate increase went into effect.&#160;&#160;Since the straight fixed variable rate design was fully implemented in February 2010, nearly 90 percent of the combined residential and commercial base rate margins were recovered through the customer service charge.&#160;&#160;The OCC appealed this rate order to the Ohio Supreme Court, which had affirmed PUCO orders authorizing straight fixed variable rate design in two other cases. On December 23, 2010, the Ohio Supreme Court affirmed the PUCO order authorizing straight fixed variable rate design in VEDO&#8217;s case.&#160;</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block ; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">With this rate order, the Company has in place for its Ohio gas territory rates that allow for a straight fixed variable rate design that mitigates both weather risk and lost margin for residential customers; tracking of uncollectible accounts 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.</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman"& gt;<font style="DISPLAY: inline; TEXT-DECORATION: underline">VEDO Continues the Process to Exit the Merchant Function</font></font></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">On August 20, 2008, the PUCO approved the results of an auction selecting qualified wholesale suppliers to provide the gas commodity to the Company for resale to its customers at auction-determined standard pricing.&#160;&#160;This standard pricing was comprised of the monthly NYMEX settlement price plus a fixed adder.&#160;&#160;This standard pricing, which was effective from October 1, 2008 through March 31, 2010, was the initial step in exiting the merchant function in the Company&#8217;s Ohio service territory.&#160;&#160;The approach eliminated the need for monthly gas cost recovery (GCR) filings and prospective PUCO GCR audits.<font style="DISPLAY: inline; FONT-SIZE: 70%; VERTICAL-ALIGN: text-top">&#160;</font> In October 2008, VEDO&#8217;s entire natural gas inventory was transferred to the auction&#8217;s winning wholesale suppliers, resulting in proceeds to VEDO of approximately $107 million.</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">The second phase of the exit process began on April 1, 2010.&#160;&#160;During this phase, the Company no longer sells natural gas directly to customers.&#160;&#160;Rather, state-certified Competitive Retail Natural Gas Suppliers, that were successful bidders in a similar regulatory-approved auction, sell the gas commodity to specific customers for a 12 month period at auction-determined standard pricing.&#160;&#160;The first auction was conducted on January 12, 2010, and the auction results were approved by the PUCO on January 13, 2010.&#160; The plan approved by the PUCO required that the Company conduct at least two annual auctions during this phase.&#160; As such, the Company conducted another auction on January 18, 2011 in advance of the second 12-month term which commences on April 1, 2011.&#160;&#160;The results of that auction were approved by the PUCO on January 19, 2011.<font style="DISPLAY: inline; FONT-FAMILY: Times New Roman">&#160;</font>Consistent with current practice, customers will continue to receive a single bill for the commodity as well as the delivery component of natural gas service from VEDO.&#160;&#160;Vectren Source, the Company&#8217;s wholly owned nonutility retail gas marketer, was a successful bidder in both auctions.</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MAR GIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">The PUCO provided for an Exit Transition Cost rider, which allows the Company to recover costs associated with the transition process.&#160;&#160;Exiting the merchant function should not have a material impact on earnings or financial condition.&#160;&#160;It, however, has and will continue to reduce <font style="DISPLAY: inline; FONT-STYLE: italic">Gas utility revenues</font> and have an equal and offsetting impact to <font style="DISPLAY: inline; FONT-STYLE: italic">Cost of gas sold </font>as VEDO no longer purchases gas for resale to these customers.</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times N ew Roman"><font style="DISPLAY: inline; TEXT-DECORATION: underline">Vectren North Gas Base Rate Order Received</font></font></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">On February 13, 2008, the Company received an order from the IURC which approved the settlement agreement reached in its Vectren North gas rate case.&#160; The order provided for a base rate increase of $16.3 million and a return on equity (ROE) of 10.2 percent, with an overall rate of return of 7.8 percent on rate base of approximately $793 million.&#160;&#160;The order also provided for the recovery of $10.6 million of costs through separate cost recovery mechanisms rather than base rates.</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGI N-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">Further, additional expenditures for a multi-year bare steel and cast iron capital replacement program will be afforded certain accounting treatment that mitigates earnings attrition from the investment between rate cases.&#160; The accounting treatment allows for the continuation of the accrual for AFUDC and the deferral of depreciation expense after the projects go in service but before they are included in base rates. &#160;To qualify for this treatment, the annual expenditures are limited to $20 million and the treatment cannot extend beyond four years from the in-service date for each specific project.</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">Wi th this order, the Company has in place for its North gas territory weather normalization, a conservation and decoupling mechanism, recovery of gas cost expense related to uncollectible accounts expense based on historical experience and tracking of unaccounted for gas costs through the existing GCA mechanism, and tracking of pipeline integrity management expense.&#160;</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman"><font style="DISPLAY: inline; TEXT-DECORATION: underline">MISO Transactions</font></font></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">The Company is a member of the MISO, a FERC approved regi onal transmission organization.&#160;&#160;When the Company is a net seller of its generation, such net revenues, which totaled $24.9 million, $20.8 million, and $57.6 million for the twelve months ended December 31, 2010, 2009, and 2008, respectively, are included in <font style="DISPLAY: inline; 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No authoritative reference available. No authoritative reference available. No authoritative reference available. Other long-term nonutility investments not classified elsewhere in the taxonomy. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. Total of the portions of the carrying amounts as of the balance sheet date of long-term debt, which may include notes payable, bonds payable, debentures, mortgage loans, and commercial paper or such debt that is collateralized by a line of credit that has a remaining term less than one year, that contain an option, executable in one year or less, for the holder to put the debt back to the company. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. Value stock issued during the period as a result of the exercise of stock options and from a dividend reinvestment plan (DRIP). A dividend reinvestment plan allows the holder of the stock to reinvest dividends paid to them by the entity on new issues of stock by the entity. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. Other comprehensive income of equity method investees No authoritative reference available. Sum of the amounts paid in advance for capitalized costs that will be expensed with the passage of time or the occurrence of a triggering event, and will be charged against earnings within one year or the normal operating cycle, if longer and aggregate carrying amount, as of the balance sheet date, of current assets not separately presented elsewhere in the balance sheet . No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. Unbilled amounts due for services rendered or products shipped. This element is distinct from unbilled contracts receivables because this is based on noncontract transactions. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. The net change during the reporting period in amount due within one year (or one business cycle) from customers for the credit sale of goods and services. Also includes, the net change during the reporting period the amount of revenue for work performed for which the billing milestone has not occurred, net of uncollectible accounts. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. Sum of the carrying values as of the balance sheet date of all long-term debt, which is debt initially having maturities due after one year from the balance sheet date or beyond the operating cycle, if longer, but excluding the portions thereof scheduled to be repaid within one year (current maturities) or the normal operating cycle, if longer, and after deducting unamortized discount or premiums, if any. Also excludes the portion of debt that could be repaid in one year at the option of the holder. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. Other comprehensive income of equity method investees No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. Disclosure related to accounts comprising common shareholders' equity. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. Cost of natural gas sold during the reporting period, operations of which is regulated by a federal or state agency. No authoritative reference available. Sum of operating profit and nonoperating income (expense) before income taxes. No authoritative reference available. No authoritative reference available. No authoritative reference available. Other long-term utility and corporate investments not classified elsewhere in the taxonomy. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. Disclosure related to additional balance sheet and operational information, including prepayments and other current assets, other utility and corporate investments, accrued liabilities, other income - net, and supplemental cash flow information, and other information. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. Number of shares issued during the period as a result of the exercise of stock options and from a dividend reinvestment plan (DRIP). A dividend reinvestment plan allows the holder of the stock to reinvest dividends paid to them by the entity on new issues of stock by the entity. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. Tax effect of the adjustment decreasing (increasing) retained earnings due to a change in the measurement date for a defined benefit pension and other postretirement plan in the initial application of the measurement provision of FAS 158. No authoritative reference available. This item represents disclosure of the amount of other distributions received from unconsolidated subsidiaries, certain corporate joint ventures, and certain noncontrolled corporations; these distribuions constitute a return of investment. No authoritative reference available. No authoritative reference available. No authoritative reference available. Disclosure related to legacy investments involved in energy-related infrastructure and services, real estate, leveraged leases, and other ventures within the Nonutility business segment. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. No authoritative reference available. 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MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMI LY: times new roman">Consolidated goodwill</font></div></td><td style="BORDER-BOTTOM: black 4px double" valign="bottom" align="right" width="1%"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: times new roman">&#160;</font></td><td style="BORDER-BOTTOM: black 4px double; TEXT-ALIGN: left" valign="bottom" width="1%"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: times new roman">$</font></td><td style="BORDER-BOTTOM: black 4px double; TEXT-ALIGN: right" valign="bottom" width="9%"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: times new roman">242.0</font></td><td style="BORDER-BOTTOM: black 4px double; TEXT-ALIGN: left" valign="bottom" nowrap="nowrap" width="1%"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: times new roman">&#160;</font></td><td style="BORDER-BOTTOM: black 4px double" valign="bottom" align="right" width="1%">< font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: times new roman">&#160;</font></td><td style="BORDER-BOTTOM: black 4px double; TEXT-ALIGN: left" valign="bottom" width="1%"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: times new roman">$</font></td><td style="BORDER-BOTTOM: black 4px double; TEXT-ALIGN: right" valign="bottom" width="9%"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: times new roman">242.0</font></td><td style="BORDER-BOTTOM: black 4px double; TEXT-ALIGN: left" valign="bottom" nowrap="nowrap" width="1%"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: times new roman">&#160;</font></td></tr></table></div><br /><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman"><font style="DISPLAY: inline; FONT-STYLE: italic">Accrued liabilities</font> in the <font style="DISPLAY: inline; FONT-STYLE : italic">Consolidated Balance Sheets</font> consist of the following:</font></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; 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MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-STYLE: italic; FONT-FAMILY: times new roman">(In millions)</font></div></td><td style="BORDER-BOTTOM: black 2px solid" valign="bottom"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: times new roman">&#160;</font></td><td style="BORDER-BOTTOM: black 2px solid" valign="bottom" colspan="2"><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="center"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: times new roman"> ;2010</font></div></td><td style="BORDER-BOTTOM: black 2px solid; TEXT-ALIGN: left" valign="bottom" nowrap="nowrap"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: times new roman">&#160;</font></td><td style="BORDER-BOTTOM: black 2px solid" valign="bottom"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: times new roman">&#160;</font></td><td style="BORDER-BOTTOM: black 2px solid" valign="bottom" colspan="2"><div style="DISPLAY: block; 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(Utility Holdings), serves as the intermediate holding company for three public utilities:&#160;&#160;Indiana Gas Company, Inc. (Indiana Gas or Vectren North), Southern Indiana Gas and Electric Company (SIGECO or Vectren South), and the Ohio operations.&#160;&#160;Utility Holdings also has other assets that provide information technology and other services to the three utilities.&#160;&#160;Utility Holdings&#8217; consolidated operations are collectively referred to as the Utility Group.&#160;&#160;Both Vectren and Utility Holdings are holding companies as defined by the Energy Policy Act of 200 5 (Energy Act).&#160;&#160;Vectren was incorporated under the laws of Indiana on June 10, 1999.</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">Indiana Gas provides energy delivery services to over 570,000 natural gas customers located in central and southern Indiana.&#160;&#160;SIGECO provides energy delivery services to approximately 142,000 electric customers and approximately 111,000 gas customers located near Evansville in southwestern Indiana.&#160;&#160;SIGECO also owns and operates electric generation assets to serve its electric customers and optimizes those assets in the wholesale power market.&#160;&#160;Indiana Gas and SIGECO generally do business as Vectren Energy Delivery of Indiana.&#160;&#160;The Ohio operations provide energy delivery services to approximately 314,000 natural gas customers located near Dayton in west central Ohio.&#160;&#160;The Ohio operations are owned as a tenancy in common by Vectren Energy Delivery of Ohio, Inc. 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The transaction generated proceeds, net of underwriting discounts and commissions, of approximately $125.7 million.&#160; The Company executed an equity forward sale agreement (equity forward) in connection with the offering, and therefore, did not receive proceeds at the time of the equity offering.&#160; The equit y forward allowed the Company to price an offering under market conditions existing at that time, and to better match the receipt of the offering proceeds and the associated share dilution with the implementation of regulatory initiatives.</font></div><div style="DISPLAY: block; TEXT-INDENT: 0pt"><br /></div><div style="DISPLAY: block; MARGIN-LEFT: 0pt; TEXT-INDENT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="DISPLAY: inline; FONT-SIZE: 10pt; FONT-FAMILY: Times New Roman">On June 27, 2008, the Company physically settled the equity forward by delivering the 4.6 million shares, receiving proceeds of approximately $124.9 million.&#160; The slight difference between the proceeds generated by the public offering and those received by the Company were due to adjustments defined in the equity forward agreement including:&#160;&#160;1) daily increases in the forward sale price based on a floating interest factor equal to the federal funds rate, less a 35&am p;#160;basis point fixed spread, and 2) structured quarterly decreases to the forward sale price that align with expected Company dividend payments.&#160;</font></div><div style="DISPLAY: block; 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