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EX-32 - EXHIBIT 32 CERTIFICATIONS - VECTREN CORPex32.htm
EX-4.1 - EXHIBIT 4.1 SIG MORTGAGE INDENTURE AMENDMENT - VECTREN CORPex4_1.htm
EX-31.2 - EXHIBIT 31.2 CERTIFICATIONS - VECTREN CORPex31_2.htm
EX-31.1 - EXHIBIT 31.1 CERTIFICATIONS - VECTREN CORPex31_1.htm
EX-23.1 - EXHBIT 23.1 CONSENTS - VECTREN CORPex23_1.htm
EX-99.1 - EXHIBIT 99.1 PROLIANCE - VECTREN CORPex99_1.htm
EX-23.2 - EXHIBIT 23.2 CONSENTS - VECTREN CORPex23_2.htm
EX-10.1 - EXHIBIT 10.1 COAL SUPPLY AGREEMENT - VECTREN CORPexhbit10_1.htm
EX-21.1 - EXHIBIT 21.1 SUBSIDIARIES OF THE COMPANY - VECTREN CORPex21_1.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, 2009
OR

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

For the transition period from __________________ to ________________________


Commission file number:   1-15467



VECTREN CORPORATION

(Exact name of registrant as specified in its charter)


Vectren Logo

INDIANA
 
35-2086905
(State or other jurisdiction of incorporation or organization)
 
 
(IRS Employer Identification No.)
One Vectren Square
 
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 □  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 
(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, 2009, was $1,889,960,254.
 
 
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
­­­81,152,870
January 31, 2010
Class
Number of Shares
Date


Documents Incorporated by Reference


Certain information in the Company's definitive Proxy Statement for the 2010 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
 
MISO: Midwest Independent System Operator
ASC:  Accounting Standards Codification
 
MW:  megawatts
BTU / MMBTU:  British thermal units / millions of BTU
MWh / GWh:  megawatt hours / thousands of megawatt hours (gigawatt hours)
 
FASB:  Financial Accounting Standards Board
 
NERC:  North American Electric Reliability Corporation
FERC:  Federal Energy Regulatory Commission
 
OCC:  Ohio Office of the Consumer Counselor
IDEM:  Indiana Department of Environmental Management
 
OUCC:  Indiana Office of the Utility Consumer Counselor
IURC:  Indiana Utility Regulatory Commission
 
PUCO:  Public Utilities Commission of Ohio
IRC:  Internal Revenue Code
 
USEPA:  United States Environmental Protection Agency
 
MCF / BCF:  thousands / billions of cubic feet
 
Throughput:  combined gas sales and gas transportation volumes
MDth / MMDth: thousands / millions of dekatherms
 
Access to Information

Vectren Corporation makes available all SEC filings and recent annual reports free of charge through its website at www.vectren.com as soon as reasonably practicable after electronically filing or furnishing the reports to the SEC, or by request, directed to Investor Relations at the mailing address, phone number, or email address that follows:

Mailing Address:
One Vectren Square
Evansville, Indiana  47708
 
Phone Number:
(812) 491-4000
 
Investor Relations Contact:
Steven M. Schein
Vice President, Investor Relations
sschein@vectren.com
         

-3-
 

Table of Contents

Item
   
        Page
Number
 
Number
Part I
           
     
     
     
     
     
     
           
Part II
           
 
 5
   
     
 
 7
   
     
 
 8
   
 
 9
   
     
     
     
 
   
Part III
           
     
     
     
     
     
     
 
   
Part IV
           
     
       
           

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

Indiana Gas provides energy delivery services to over 567,000­ natural gas customers located in central and southern Indiana.  SIGECO provides energy delivery services to over 141,000 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 315,000 natural gas customers located near Dayton in west central Ohio.  The Ohio operations are owned as a tenancy in common by Vectren Energy Delivery of Ohio, Inc. (VEDO), a wholly owned subsidiary of Utility Holdings (53 percent ownership), and Indiana Gas (47 percent ownership).  The Ohio operations generally do business as Vectren Energy Delivery of Ohio.

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

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, 2009, the Company had $4.7 billion in total assets, with $3.8 billion (82 percent) attributed to the Utility Group and $0.8 billion (18 percent) 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, with net income of $107.4 million attributed to the Utility Group, $25.8 million attributed to the Nonutility Group, and a net loss of $0.1 million attributed to Corporate and Other.  Excluding the impact of a charge recorded in 2009 discussed in Note 5 in the Company’s Consolidated Financial Statements included under “Item 8 Financial Statements and Supplementary Data” totaling $11.9 million after tax, or $0.15 per share, related to ProLiance Holdings, LLC’s (ProLiance) investment in Liberty Gas Storage, for the year ended December 31, 2009, there was consolidated net income of $145.0 million, or $1.80 per share. Net income for the year ended December 31, 2008, was $129.0 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 Financial Statements included under “Item 8 Financial Statements and Supplementary Data.”

Following is a more detailed description of the Utility Group and Nonutility Group.  Corporate and Other operations are not significant.

Utility Group

The operations of the Utility Group consist of the Company’s regulated operations and other operations that provide information technology and other support services to those regulated operations.  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.  The Utility Group’s other operations are not significant.

Gas Utility Services

At December 31, 2009, the Company supplied natural gas service to approximately 993,100 Indiana and Ohio customers, including 907,500 residential, 84,000 commercial, and 1,600 industrial and other contract customers.  Average gas utility customers served were approximately 981,300 in 2009 and 986,700 in both 2008 and 2007.
 
 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, appliance manufacturing, 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, and 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 184.5 MMDth for the year ended December 31, 2009.  Gas sold and transported to residential and commercial customers was 106.5 MMDth representing 58 percent of throughput.  Gas transported or sold to industrial and other contract customers was 78.0 MMDth representing 42 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, 2009, gas utility revenues were approximately $1,066.0 million, of which residential customers accounted for 68 percent and commercial 26 percent. Industrial and other contract customers account for only 6 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 its affiliate, 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 & Services 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.

Natural Gas Purchasing Activity in Ohio
As a result of a June 2005 PUCO order, the Company established an annual bidding process for VEDO’s gas supply and portfolio administration services.  From November 1, 2005 through September 30, 2008, the Company used a third party provider for these services.  Prior to October 31, 2005, ProLiance also supplied natural gas to Utility Holdings’ Ohio operations.

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 initial phase of the plan was implemented on October 1, 2008 and continues through March 31, 2010.  During the initial phase, wholesale suppliers that were winning bidders in a PUCO approved auction provide the gas commodity to VEDO for resale to its residential and general service customers at auction-determined standard pricing.  This standard pricing is 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 now purchases natural gas from those suppliers (one of which is Vectren Retail, LLC, a wholly owned subsidiary of Vectren) essentially on demand.  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 begins on April 1, 2010, during which the Company will no longer sell natural gas directly to these customers.  Rather, state-certified Competitive Retail Natural Gas Suppliers, that are successful bidders in a second regulatory-approved auction, will sell the gas commodity to specific customers for 12 months at auction-determined standard pricing.  That auction was conducted on January 12, 2010, and the auction results were approved by the PUCO on January 13.  The plan approved by the PUCO requires that the Company conduct at least two auctions during this phase.  As such, the Company will conduct another auction in advance of the second 12-month term, which will commence on April 1, 2011.  Consistent with current practice, customers will continue to receive one bill for the delivery of natural gas service. 

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 has also provided for an Exit Transition Cost rider for the first two phases of the transition, which allows the Company to recover costs associated with the transition, and it is anticipated this rider will remain in effect throughout the entire transition.  Since the cost of gas is currently passed through to customers during phase one and two through a PUCO approved recovery mechanism, the impact of exiting the merchant function should not have a material impact on Company earnings or financial condition. 

Total Natural Gas Purchased Volumes
In 2009, Utility Holdings purchased 97,682 MDth volumes of gas at an average cost of $5.97 per Dth, of which approximately 76 percent was purchased from ProLiance, 4 percent was purchased from Vectren Retail, LLC (d/b/a Vectren Source), as discussed above, and 20 percent was purchased from third party providers.  The average cost of gas per Dth purchased for the previous four years was $9.61 in 2008, $8.14 in 2007, $8.64 in 2006, and $9.05 in 2005.

Electric Utility Services

At December 31, 2009, the Company supplied electric service to approximately 141,400 Indiana customers, including approximately 122,900 residential, 18,400 commercial, and 100 industrial and other customers.  Average electric utility customers served were approximately 140,900 in 2009; 141,100 in 2008; and 140,800 in 2007.

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

Revenues

For the year ended December 31, 2009, retail electricity sales totaled 5,039.7 GWh, resulting in revenues of approximately $493.2 million.  Residential customers accounted for 37 percent of 2009 revenues; commercial 28 percent; industrial 33 percent, and other 2 percent.  In addition, in 2009 the Company sold 603.6 GWh through wholesale activities principally to the MISO.  Wholesale revenues, including transmission-related revenue, totaled $35.4 million in 2009.

System Load

Total load for each of the years 2005 through 2009 at the time of the system summer peak, and the related reserve margin, is presented below in MW.  The peak loads in 2009 reflect the current weak industrial demand and mild weather.
                     
Date of summer peak load
 
6/22/2009
 
7/21/2008
 
8/08/2007
 
8/10/2006
 
7/25/2005
Total load at peak (1)
 
           1,143
 
           1,242
 
           1,341
 
           1,325
 
           1,315
                     
Generating capability
 
           1,295
 
           1,295
 
           1,295
 
           1,351
 
           1,351
Firm purchase supply
 
              136
 
              135
 
              130
 
              107
 
              107
Interruptible contracts & direct load control
 
                62
 
                62
 
                62
 
                62
 
                76
Total power supply capacity
 
           1,493
 
           1,492
 
           1,487
 
           1,520
 
           1,534
                     
Reserve margin at peak
 
31%
 
20%
 
11%
 
15%
 
17%
(1)  
The total load at peak is increased 25 MW in 2007-2005 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 and 2009 the Summer Cycler program was not activated.

The winter peak load for the 2008-2009 season of approximately 883 MW occurred on January 15, 2009.  The prior year winter peak load was approximately 960 MW, occurring on January 25, 2008.

Generating Capability
Installed generating capacity as of December 31, 2009, 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 2009 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 4,657 GWh in 2009.  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 2.8 million tons were purchased for generating electricity during 2009, of which approximately 86 percent was supplied by Vectren Fuels from its mines and third party purchases.  The average cost of coal paid by the utility in generating electric energy for the years 2005 through 2009 follows:

   
Year Ended December 31,
 
Average Delivered
 
2009
   
2008
   
2007
   
2006
   
2005
 
  Cost per Ton
  $ 61.67     $ 42.50     $ 40.23     $ 37.51     $ 30.27  
  Cost per MWh
    30.09       20.84       19.78       18.44       14.94  

As of January 1, 2009, SIGECO purchases 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.  New pricing reflects Illinois Basin market prices in effect when the contracts were executed and have resulted in higher costs compared to prior years.

The utility purchased approximately 13.3 percent less coal in 2009 compared to 2008.  Due to contractual obligations, its year end coal inventory rose to approximately 1.1 million tons, compared to 0.5 million tons at the end of 2008.

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 211 GWh from OVEC in 2009.

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.  The Company purchased insignificant amounts under this contract in 2009.

The Company executed a capacity contract with Benton County Wind Farm, LLC on April 15, 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 2009, the Company purchased approximately 91 GWh under this contract; however, none was purchased at the time of peak load on June 22, 2009.

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 insignificant amounts under this contract in 2009.
 
 
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 2009 totaled 855 GWh.

MISO Capacity Purchase
In May 2008, the Company executed a MISO capacity purchase from Sempra Energy Trading, LLC to purchase 100MW of name plate capacity from its generating facility in Dearborn, Michigan.  The term of the contract begins 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 historic ability to simultaneously interchange approximately 600 MW.  However, the ability of the Company to effectively utilize the electric transmission grid in order to achieve its desired import/export capability has been, and may continue to be, impacted as a result of the ongoing changes in the operation of the Midwestern transmission grid.  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 Company’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, 2009, over 117,000 customers in Vectren’s Ohio service territory purchase natural gas from a supplier other than VEDO.  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 three primary business areas: Energy Marketing and Services, Coal Mining, and Energy Infrastructure Services.

Energy Marketing and Services

The Energy Marketing and Services 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 retail gas supply operations, contracted for approximately 75 percent of its natural gas purchases through ProLiance in 2009.

For the year ended December 31, 2009, ProLiance’s revenues, including sales to Vectren companies, were $1.7 billion, compared to $2.9 billion in 2008 and $2.3 billion in 2007.  ProLiance’s audited financial statements as of and for its fiscal years ending September 30, 2009, 2008, and 2007, are included as Exhibit 99.1 to this Form 10-K.

Vectren Source
As of December 31, 2009, Vectren Source provided natural gas and other related products and services in the Midwest and Northeast United States to over 189,000 equivalent residential and commercial customers.  This customer base reflects approximately 62,000 of VEDO’s customers that have voluntarily opted to choose their natural gas supplier and the supply of natural gas to nearly 33,000 equivalent customers in VEDO’s service territory as part of VEDO’s process of exiting the merchant function, which began October 1, 2008.  Vectren Source generated approximately $157.2 million in revenues for 2009 compared to $182.6 million in 2008 and $168.3 million in 2007.  Gas sold approximated 18,457 MDth in 2009; 16,210 MDth in 2008; and 13,543 MDth in 2007.  Average equivalent customers served by Vectren Source were 179,000 in 2009; 157,000 in 2008; and 154,000 in 2007.

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.  In 2009, the Company operated one underground mine (Prosperity) and one surface mine (Cypress Creek).  Both 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.

Oaktown Mine Expansion
In April 2006, Vectren Fuels announced plans to open two new underground mines.  The first of two new underground mines located near Vincennes, Indiana, which began minor coal extraction in the latter half of 2009, is now operational.  The second mine is currently expected to open in 2011.  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 100 million tons of recoverable number-five coal at 11,200 BTU and less than 6-pound sulfur dioxide.  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.  Of the total $200 million expected investment, the Company has invested $174 million through December 31, 2009, inclusive of $46 million in land and buildings, $118 million in mine development and equipment, and $10 million in advanced 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.  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 surface.

Oaktown is a room and pillar underground mine 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.  There are two mines separated by a sandstone channel.  The coal seam thickness ranges from 4 feet to over 9 feet.  The mine’s wash plant is sized to process 800 tons per hour initially with a planned expansion to 1,600 tons per hour, which is currently under construction.  The mine is connected to a railway equipped to handle 110 to 120 car unit trains.

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/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 $175 million.  Through December 31, 2009, approximately 7,500 acres of coal have been mined with approximately 10,400 acres remaining. Reserves at December 31, 2009 approximate 35 million tons, not including possible nearby expansion opportunities.  The remaining unamortized plant balance as of December 31, 2009 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 completely accessed by 2019.

Cypress Creek
Cypress Creek is an above-ground, or surface mine, located on 155 acres about 4 miles north of Boonville in Warrick County, Indiana.  Cypress Creek is a combination truck/shovel, dozer push and high wall mining operation, meaning large shovels or front-end loaders remove earth and rock covering a coal seam and loading equipment place the coal into trucks for transportation to a blending and loading area.  Cypress Creek’s coal is sold as a raw product after sizing and blending with coal.  Because of the cost of extensive digging, the coal mining limit is 125 to 135 feet deep.  All coal mined from Cypress Creek is 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 December 31, 2009, no significant reserves remain.  The remaining unamortized plant balance as of December 31, 2009 approximates $7 million, inclusive of $1 million of land and buildings and $6 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)
                   
  2009
 
                     969
 
                  2,583
 
                         -
 
                        -
 
       3,552
  2008
 
                  1,150
 
                  2,378
 
                         -
 
                        -
 
       3,528
  2007
 
                  1,433
 
                  2,632
 
                         -
 
                        -
 
       4,065
                     
County Located in Indiana
 
 Warrick
 
 Pike
 
 Knox
 
 Knox
   
                     
Coal Reserves (thousands of tons)
                         -
 
               34,800
 
               62,400
 
              38,800
 
  136,000
                     
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 Infrastructure Services

Energy Infrastructure Services provides underground construction and repair to utility infrastructure through Miller Pipeline Corporation (Miller) and energy performance contracting and renewable energy services through Energy Systems Group, LLC (ESG).

Miller Pipeline
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’s customers include Vectren’s utilities.

Energy Systems Group
Performance-based energy contracting operations and renewable energy services are performed through 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.

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.  Major investments at December 31, 2009, include Haddington Energy Partnerships, two 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 has 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.  Partnership operations since that date have been insignificant.  See “Item 7 Management’s Discussion and Analysis of Results of Operations and Financial Condition” regarding the Company’s Synfuel-Related activities for additional information related to Pace Carbon.

Personnel

As of December 31, 2009, the Company and its consolidated subsidiaries had 3,700 employees, of which 1,600 are employees of Miller and 2,200 are subject to collective bargaining arrangements.

Utility Holdings

In October 2009, the Company’s existing agreement expired with Local 175 of the Utility Workers Union of America.  Employees continue to work without a contractual agreement and continue the negotiation process.

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.

In July 2007, the Company reached a three-year labor agreement with Local 702 of the International Brotherhood of Electrical Workers, ending June 2010.

Miller Pipeline

In 2008, the International Union of Operating Engineers reached an agreement with the Distribution Contractors Association.  The Company, through its wholly owned subsidiary, Miller, continues to honor national agreements negotiated by the Distribution Contractors Association.    

During 2006, Miller entered into several distributing and operating agreements with a variety of construction unions including Laborers International Union of America, the Teamsters, and the United Association of Journeymen and Apprentices of the Plumbing and Pipe Fitting Industry.  Miller negotiated these agreements through the Distribution and Contractors Association and the Pipeline Contractors Association.  These agreements expire at various dates through 2011.

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 covenants, including the maintenance of a total debt to total capitalization ratio, which could limit its ability to pay dividends.

Continued deterioration in general economic conditions may have adverse impacts.
 
The current economic environment is challenging and uncertain.  Despite the beginning of recovery, the consequences of the recent recession may continue to result in a lower level of economic activity and uncertainty regarding energy prices and the capital and commodity markets.  Further, the risks associated with industries in which the Company operates and serves become more acute in periods of a slowing economy or slow growth.  Economic declines may continue to be accompanied by a decrease in demand for natural gas and electricity.  The recent recession may continue to have some negative impact on both gas and electric large customers and wholesale power sales.  This impact may continue to include tempered growth, significant conservation measures, and perhaps even further plant closures or bankruptcies.  Deteriorating economic conditions may also continue to lead to further reductions in residential and commercial customer counts, lower Company revenues, and increasing coal inventories.  It is also possible that a weak economy could continue and further affect costs including pension costs, interest costs, and uncollectible accounts expense.

Further, the Company’s nonutility portfolio may also be negatively impacted if a weak economy continues.  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 recent recession may continue to have some negative impact on utility industry spending for construction projects, demand for coal, and spending on performance contracting and renewable energy expansion.  It is also possible that if the recession continues, there could be further reductions in the value of certain nonutility real estate and other legacy investments.

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, appliance manufacturing, 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.  While no one industrial customer comprises 10 percent of consolidated revenues, the top five industrial electric customers comprise approximately 12 percent of electric utility margin, and therefore any significant decline in their collective revenues could adversely impact operating results.
 
 
Current financial market volatility could have adverse impacts.

 
The capital and credit markets have been experiencing volatility and disruption.  If the level of market disruption and volatility worsen, 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 debt capital markets and the commercial paper market, increased borrowing costs associated with current 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
Baa1
A-
    Utility Holdings commercial paper program
P-2
A-2
    SIGECO’s senior secured debt
A-2
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.

Vectren may be required to obtain additional permanent financing (1) to fund its capital expenditures, investments and debt security redemptions and maturities and (2) to further strengthen its capital structure and the capital structures of its subsidiaries.  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 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 first of the three phase process to exit the merchant function in its 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 over a two year period per 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 USEPA, 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 emissions from electric generating facilities include particulate matter, sulfur dioxide (SO2), nitrogen oxide (NOx), and mercury, among others.

Environmental legislation 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 operating that equipment, have increased and are expected to increase in the future.

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 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, any legislation would likely impact the Company’s generation resource planning decisions.  At this time and in the absence of final legislation, compliance costs and other effects associated with reductions in greenhouse gas emissions or obtaining renewable energy sources remain uncertain.  The Company has gathered preliminary estimates of the costs to comply with a cap and trade approach to controlling greenhouse gas emissions.  A preliminary investigation demonstrated costs to comply would be significant, first with regard to operating expenses for the purchase of allowances, and later for capital expenditures as technology becomes available to control greenhouse gas emissions.  However, these compliance cost estimates are based on highly uncertain assumptions, including allowance prices and energy efficiency targets.

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.
 
 
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.

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.  Given the nature of MISO’s policies regarding use of transmission facilities, as well as ongoing FERC initiatives, and a Day 3 ancillary services market (ASM), where MISO provides bid-based regulation and contingency operating reserve markets which began on January 6, 2009, it is difficult to predict near term operational impacts.  The IURC has approved the Company’s participation in the ASM and has granted authority to defer costs associated with ASM.

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.

If Vectren does not accurately forecast future commodity prices, the Company’s net income could be reduced or the Company may experience losses.

The operations of ProLiance, as well as the Company’s nonutility gas retail supply and coal mining businesses, execute forward contracts and from time to time option contracts that commit them to purchase and sell natural gas and coal in the future, including forward contracts to purchase commodities to fulfill forecasted sales transactions that may or may not occur.  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, Vectren may experience losses.

To lower the financial exposure related to commodity price fluctuations, these nonutility businesses may execute contracts that hedge the value of commodity price risk and basis risks.  As part of this strategy, Vectren may utilize 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.  However, although almost all natural gas and coal positions are hedged, either with these contracts or with Vectren’s owned coal inventory and known reserves, Vectren does not hedge its entire exposure or its positions to market price volatility.  To the extent Vectren’s forecasts of future commodities prices are inaccurate, its hedging procedures do not work as planned, its coal reserves cannot be accessed or it has unhedged positions, fluctuating commodity prices are likely to cause the Company’s net income to be volatile and may lower its net income.

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

Execution of gas marketing strategies by ProLiance and the Company’s nonutility gas retail supply operations as well as the execution of the Company’s coal mining and energy infrastructure services 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; storage field and mining property development; increased coal mining industry regulation; potential legislation that may limit CO2 and other greenhouse gases emissions; creditworthiness of customers and joint venture partners; factors associated with physical energy trading activities, including price, basis, credit, liquidity, volatility, capacity, and interest rate risks; 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 energy 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 two new company-owned mines; to operate owned mines in accordance with Mine Safety and Health Administration (MSHA) guidelines and recent interpretations of those guidelines; 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.

Vectren’s nonutility group competes with larger, full-service 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.

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

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.

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 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 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 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, 2009, 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 purchased a landfill gas electric generation project in Pike County, Indiana with a total capability of 3 MW.

SIGECO's transmission system consists of 932 circuit miles of 138,000 and 69,000 volt lines.  The transmission system also includes 34 substations with an installed capacity of 4,500 megavolt amperes (Mva).  The electric distribution system includes 4,200 pole miles of lower voltage overhead lines and 358 trench miles of conduit containing 2,000 miles of underground distribution cable.  The distribution system also includes 97 distribution substations with an installed capacity of 2,900 Mva and 54,000 distribution transformers with an installed capacity of 2,500 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.”

ITEM 4.  SUBMISSION OF MATTERS TO VOTE OF SECURITY HOLDERS

No matters were submitted during the fourth quarter to a vote of security holders.


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 2009 and 2008, 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
 
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  
2008
                       
First Quarter
  $ 0.325     $ 29.20     $ 25.35  
Second Quarter
    0.325       32.20       26.66  
Third Quarter
    0.325       31.74       26.05  
Fourth Quarter
    0.335       29.00       19.48  
 
On February 3, 2010 the board of directors declared a dividend of $0.340 per share, payable on March 1, 2010, to common shareholders of record on February 16, 2010.

As of January 31, 2010, there were 9,611 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, 2009.

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 50 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)
    2009 1/       2008       2007       2006       2005  
                                         
Operating Data:
                                       
Operating revenues
  $ 2,088.9     $ 2,484.7     $ 2,281.9     $ 2,041.6     $ 2,028.0  
Operating income
  $ 280.1     $ 263.4     $ 260.5     $ 220.5     $ 213.1  
Net income
  $ 133.1     $ 129.0     $ 143.1     $ 108.8     $ 136.8  
Average common shares outstanding
    80.7       78.3       75.9       75.7       75.6  
Fully diluted common shares outstanding
    81.0       78.9       76.6       76.2       76.1  
Basic earnings per share
                                       
  on common stock
  $ 1.65     $ 1.65     $ 1.89     $ 1.44     $ 1.81  
Diluted earnings per share
                                       
  on common stock
  $ 1.64     $ 1.63     $ 1.87     $ 1.43     $ 1.80  
Dividends per share on common stock
  $ 1.345     $ 1.310     $ 1.270     $ 1.230     $ 1.190  
                                         
Balance Sheet Data:
                                       
Total assets
  $ 4,671.8     $ 4,632.9     $ 4,296.4     $ 4,091.6     $ 3,868.1  
Long-term debt, net
  $ 1,540.5     $ 1,247.9     $ 1,245.4     $ 1,208.0     $ 1,198.0  
Common shareholders' equity
  $ 1,397.2     $ 1,351.6     $ 1,233.7     $ 1,174.2     $ 1,143.3  

1/  The net income during the year ended December 31, 2009 includes the impact of a charge discussed in Note 5 in the Company’s Consolidated Financial Statements included under “Item 8 Financial Statements and Supplementary Data” totaling $11.9 million after tax, or $0.15 per share, related to ProLiance’s investment in Liberty Gas Storage.  Excluding this charge, there was consolidated net income of $145.0 million, or $1.80 per share in 2009.
 
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.

For the year ended December 31, 2009, consolidated net income was $133.1 million, or $1.65 per share, compared to earnings of $129.0 million, or $1.65 per share, in 2008 and $143.1 million, or $1.89 per share, in 2007.  Excluding the impact of a charge recorded in 2009 discussed below totaling $11.9 million after tax, or $0.15 per share, related to ProLiance’s investment in Liberty Gas Storage, for the year ended December 31, 2009, consolidated net income was $145.0 million, or $1.80 per share.

Utility Group results were down only modestly in 2009, even after considering the impacts of the recession; significant cost reductions helped offset those impacts to a large degree.  The Nonutility Group showed significantly improved performance, particularly in coal mining and retail gas marketing businesses.
 
2009 Charge Related to Liberty Gas Storage

During the second quarter of 2009, the Company recorded its share of the charge related to ProLiance’s investment in Liberty Gas Storage, LLC (herein referred to as the Liberty Charge).  In the Consolidated Statement of Income for the year ended December 31, 2009, the impact associated with the Liberty 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. The $11.9 million after tax, or $0.15 per share, charge is consistent with previous disclosures about development issues at the Louisiana site made in the prior year’s annual report.  More detailed information about ProLiance’s investment in Liberty is included in Note 5 to the consolidated financial statements.
 
Consolidated Results Excluding the Liberty Charge (See Page 42, Regarding the Use of Non-GAAP Measures)

Net income and earnings per share, excluding the Liberty Charge, in total and by group, for the years ended December 31, 2009, 2008, and 2007 follow:

                   
   
Year Ended December 31,
 
(In millions, except per share data)
 
2009
   
2008
   
2007
 
                   
Net income, excluding Liberty Charge
  $ 145.0     $ 129.0     $ 143.1  
Attributed to:
                       
Utility Group
  $ 107.4     $ 111.1     $ 106.5  
Nonutility Group, excluding Liberty Charge
    37.7       18.9       37.0  
Corporate & Other
    (0.1 )     (1.0 )     (0.4 )
                         
                         
Basic earnings per share, excluding Liberty Charge
  $ 1.80     $ 1.65     $ 1.89  
Attributed to:
                       
Utility Group
  $ 1.33     $ 1.42     $ 1.40  
Nonutility Group, excluding Liberty Charge
    0.47       0.24       0.49  
Corporate & Other
    -       (0.01 )     -  
 
Utility Group

In 2009, the Utility Group’s earnings were $107.4 million, compared to earnings of $111.1 million in 2008 and $106.5 million in 2007.  The decrease in 2009 compared to 2008 reflects lower large customer usage and lower wholesale power sales, both due to the recession, mild cooling weather, and an increase in depreciation expense associated with rate base growth.  Increased revenues associated with regulatory initiatives, lower operating expenses, and the return of market values associated with investments related benefit plans partially offset these declines.

In 2008 compared to 2007, the Utility Group earnings increased due primarily to a full year of base rate increases in the Indiana service territories and increased earnings from wholesale power operations.  Increases were offset somewhat by increased operating costs associated with maintenance and reliability programs contemplated in the base rate cases and favorable weather in 2007.

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, management estimates the margin impact of weather to be approximately $5.4 million unfavorable or $0.04 per share compared to normal temperatures.  In 2008, management estimates a $1.2 million favorable impact on margin compared to normal or $0.01 per share, and in 2007 a $5.5 million favorable impact on margin compared to normal or $0.04 per share.

Nonutility Group

In 2009, Nonutility Group earnings, excluding the Liberty Charge, were $37.7 million, compared to net income of $18.9 million 2008 and $37.0 million in 2007.  Inclusive of the Liberty Charge, 2009 Nonutility Group earnings were $25.8 million.

The 2009 improvement of $18.8 million compared to 2008 primarily reflects a $15.4 million increase in earnings from primary nonutility operations.  Primary nonutility business groups are Energy Marketing and Services, Coal Mining, and Energy Infrastructure Services companies.  Coal mining operations has shown improvement due to increased pricing effective January 1, 2009, increasing its contribution to earnings approximately $18.0 million.  Retail gas marketing earnings are $4.5 million higher than the prior year, and performance contracting activity at ESG increased its earnings contribution $2.1 million compared to 2008.  These increases were partially offset by lower earnings contributions from ProLiance and Miller Pipeline.

In 2008 compared to 2007, primary nonutility group results decreased $8.9 million. Coal Mining operated at a loss and results were approximately $6.6 million lower than the prior year due primarily to lower production and increased operating costs.  ProLiance’s earnings were $3.6 million lower than the prior year and reflect lower operating results as well as a reserve for a FERC matter.  In addition, the results from the other primary nonutility operations reflect increased earnings from performance contracting and renewable energy construction operations performed through ESG and retail gas marketing operations performed through Vectren Source.  Miller’s results were generally flat compared to 2007.

Other nonutility businesses operated at a loss of $2.5 million in 2009, compared to a loss of $5.9 million in 2008 and earnings of $0.3 million in 2007.  Other nonutility businesses are legacy investments, including investments in commercial real estate.  The lower results in 2008 were driven primarily by a charge associated with commercial real estate investments totaling $10.0 million, $5.9 million after tax, or $0.08 per share.

In 2007, the last year of synfuel operations, synfuel-related results generated earnings of $6.8 million.  Of those earnings, $3.8 million ($5.8 million on a pre tax basis) was contributed to the Vectren Foundation.  Net of that contribution, synfuel-related results were $3.0 million, or $0.04 per share, in 2007.  The Foundation contribution is included in Other operating expenses in the Consolidated Statements of Income.

Dividends

Dividends declared for the year ended December 31, 2009 were $1.345 per share compared to $1.310 in 2008 and $1.270 per share in 2007.  In October 2009, the Company’s board of directors increased its quarterly dividend to $0.340 per share from $0.335 per share.  The increase marks the 50th 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 and in 2008 compared to 2007.

Detailed Discussion of Results of Operations

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

Results of Operations of the Utility Group

The Utility Group is comprised of Utility Holdings’ operations.  The operations of the Utility Group consist of the Company’s regulated operations and other operations that provide information technology and other support services to those regulated operations.  Regulated operations consist of a natural gas distribution business that provides natural gas distribution and transportation services to nearly two-thirds of Indiana and to west central Ohio and an electric transmission and distribution business, which provides electric distribution services primarily to southwestern Indiana, and the Company’s power generating and wholesale power operations.  In total, these regulated operations supply natural gas and/or electricity to over one million customers. Utility Group operating results before certain intersegment eliminations and reclassifications for the years ended December 31, 2009, 2008, and 2007, follow:
   
Year Ended December 31,
 
(In millions, except per share data)
 
2009
   
2008
   
2007
 
OPERATING REVENUES
                 
  Gas utility
  $ 1,066.0     $ 1,432.7     $ 1,269.4  
  Electric utility
    528.6       524.2       487.9  
  Other
    1.6       1.8       1.7  
Total operating revenues
    1,596.2       1,958.7       1,759.0  
OPERATING EXPENSES
                       
  Cost of gas sold
    618.1       983.1       847.2  
  Cost of fuel & purchased power
    194.3       182.9       174.8  
  Other operating
    304.6       300.3       266.1  
  Depreciation & amortization
    180.9       165.5       158.4  
  Taxes other than income taxes
    60.3       72.3       68.1  
Total operating expenses
    1,358.2       1,704.1       1,514.6  
OPERATING INCOME
    238.0       254.6       244.4  
                         
Other income - net
    7.8       4.0       9.4  
                         
Interest expense
    79.2       79.9       80.6  
                         
INCOME BEFORE INCOME TAXES
    166.6       178.7       173.2  
                         
Income taxes
    59.2       67.6       66.7  
                         
NET INCOME
  $ 107.4     $ 111.1     $ 106.5  
CONTRIBUTION TO VECTREN BASIC EPS
  $ 1.33     $ 1.42     $ 1.40  

Trends in Utility Operations

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

Rate Design Strategies
Sales of natural gas and electricity to residential and commercial customers are seasonal and are impacted by weather.  Trends in average use among natural gas residential and commercial customers have tended to decline in recent years as more efficient appliances and furnaces are installed and the price of natural gas has been volatile.  Normal temperature adjustment (NTA) and lost margin recovery mechanisms largely mitigate the effect on Gas Utility margin that would otherwise be caused by variations in volumes sold to these customers due to weather and changing consumption patterns.  Indiana Gas’ territory has both an NTA since 2005 and lost margin recovery since 2006.  SIGECO’s natural gas territory has an NTA since 2005 and lost margin recovery since 2007.  The Ohio service territory had lost margin recovery since 2006.  The Ohio lost margin recovery mechanism ended when new base rates went into effect in February 2009.  This mechanism was replaced by a rate design, commonly referred to as a straight fixed variable rate design, which is more dependent on monthly service charge revenues and less dependent on volumetric revenues than previous rate designs. This new rate design, which will be fully implemented in February 2010, will mitigate most weather risk in Ohio.  SIGECO’s electric service territory has neither NTA nor lost margin recovery mechanisms; however, rate designs proposed in a recently filed rate case requests a lost margin recovery mechanism that works in tandem with conservation initiatives, similar to rate designs undertaken in the Indiana gas service territories. 

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

Recessionary Impacts
Gas and electric margin generated from sales to large customers (generally industrial and other contract customers) is primarily impacted by overall economic conditions and changes in demand for those customers’ products.  The recent recession has had and may continue to have some negative impact on sales to and usage by both gas and electric large customers.  This impact has included, and may continue to include, tempered growth, significant conservation measures, and increased plant closures and bankruptcies.  While no one industrial customer comprises 10 percent of consolidated revenues, the top five industrial electric customers comprise approximately 12 percent of electric utility margin for the year ended December 31, 2009, and therefore any significant decline in their collective margin could adversely impact operating results.  Deteriorating economic conditions may also lead to continued lower residential and commercial customer counts.  Further, resulting from the lower power prices, decreased demand for electricity and higher coal prices associated with contracts negotiated last year, the Company’s coal fired generation has been dispatched less often by the MISO.  This has resulted in lower wholesale sales, more power being purchased from the MISO for native load requirements, and larger coal inventories.

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

Gas Utility Margin (Gas utility revenues less Cost of gas sold)
Gas utility margin and throughput by customer type follows:
                   
   
Year Ended December 31,
 
(In millions)
 
2009
   
2008
   
2007
 
                   
Gas utility revenues
  $ 1,066.0     $ 1,432.7     $ 1,269.4  
Cost of gas sold
    618.1       983.1       847.2  
Total gas utility margin
  $ 447.9     $ 449.6     $ 422.2  
Margin attributed to:
                       
Residential & commercial customers
  $ 388.8     $ 385.5     $ 360.9  
Industrial customers
    46.8       51.2       48.7  
Other
    12.3       12.9       12.6  
                         
Sold & transported volumes in MMDth attributed to:
                 
Residential & commercial customers
    106.5       114.8       108.4  
Industrial customers
    78.0       91.5       86.2  
Total sold & transported volumes
    184.5       206.3       194.6  

For the year ended December 31, 2009, gas utility margins were $447.9 million, a slight decrease of $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 million 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 average cost per dekatherm of gas purchased during 2009 was $5.97 compared to $9.61 in 2008 and $8.14 in 2007.

For the year ended December 31, 2008, gas utility margins increased $27.4 million compared to 2007.  Regulatory initiatives, including the Vectren North base rate increase, effective February 2008 and the Vectren South base rate case effective August 2007, added $15.4 million in margin.  In 2008, Ohio weather was 8 percent colder than the prior year and resulted in an estimated increase in margin of approximately $3.2 million compared to 2007.  Operating costs, including revenue and usage taxes, recovered in margin, increased gas margin $7.8 million.

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)
 
2009
   
2008
   
2007
 
                   
Electric utility revenues
  $ 528.6     $ 524.2     $ 487.9  
Cost of fuel & purchased power
    194.3       182.9       174.8  
Total electric utility margin
  $ 334.3     $ 341.3     $ 313.1  
Margin attributed to:
                       
Residential & commercial customers
  $ 221.9     $ 218.6     $ 198.6  
Industrial customers
    84.5       82.9       78.3  
Municipals & other customers
    7.2       7.3       15.3  
Subtotal: Retail
  $ 313.6     $ 308.8     $ 292.2  
Wholesale margin
    20.7       32.5       20.9  
Total electric utility margin
  $ 334.3     $ 341.3     $ 313.1  
                         
Electric volumes sold in GWh attributed to:
                       
Residential & commercial customers
    2,760.8       2,850.5       3,042.9  
Industrial customers
    2,258.9       2,409.1       2,538.5  
Municipals & other
    20.0       63.8       635.1  
Total retail & firm wholesale volumes sold
    5,039.7       5,323.4       6,216.5  

Retail
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 are due primarily to lower usage; however, usage began to stabilize during the third and fourth quarters.

Electric retail utility margin was $308.8 million for the year ended December 31, 2008, an increase of approximately $16.6 million compared to 2007.  The base rate increase that went into effect on August 15, 2007, produced incremental margin of $27.0 million year over year when netted with municipal contracts that were allowed to expire.  Management estimates the year over year decreases in usage by residential and commercial customers due to weather, which was very warm the prior summer, to be $7.5 million.  Other usage declines due in part to a weakening economy and conservation measures were the primary reason for the remaining decrease.

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.  A majority of the margin generated from these activities is associated with wholesale off-system sales, and 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)
 
2009
   
2008
   
2007
 
Off-system sales
  $ 6.1     $ 23.2     $ 16.9  
Transmission system sales
    14.6       9.3       4.0  
Total wholesale margin
  $ 20.7     $ 32.5     $ 20.9  

For the year ended December 31, 2009, wholesale margin was $20.7 million, representing a decrease of $11.8 million, compared to 2008.  Of the decrease, $17.1 million relates to lower margin retained by the Company from off-system sales.  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.  During 2008, margin from off-system sales retained by the Company increased $6.3 million, compared to 2007, due to an increase in off peak volumes available for sale off system.  This increase in volumes was driven primarily by expiring municipal contracts and increases in wholesale prices.  Off-system sales totaled 603.6 GWh in 2009, compared to 1,512.9 GWh in 2008 and 921.3 GWh in 2007.  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 in 2008 and 2009 reflect the impact of that sharing.

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 and other transmission system operations increased $5.3 million in 2009 compared to 2008.  These returns also primarily account for the $5.3 million increase in transmission system sales in 2008 compared to 2007.

Purchased Power
The Company’s mix of generated and purchased electricity changed during 2009 compared to prior years.  For the years ended December 31, 2009, 2008, and 2007, respectively, the Company purchased approximately 1,159 GWh, 372 GWh, and 416 GWh of power from the MISO and other sources.  The total cost associated with these volumes of purchased power is approximately $43 million, $26 million, and $26 million in 2009, 2008, and 2007 respectively, and is included in the Cost of fuel & purchased power.

Utility Group Operating Expenses

Other Operating
For 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.  Examples of such tracked costs include Ohio uncollectible accounts expense, Indiana gas pipeline integrity management costs, costs to fund Indiana energy efficiency programs, and MISO transmission revenues and costs, among others.  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.  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, Indiana uncollectible accounts expense was only slightly favorable compared to 2008.
 
 
For the year ended December 31, 2008, other operating expenses were $300.3 million, which represents an increase of $34.2 million, compared to 2007.  Costs in 2008 resulting from increased maintenance and other reliability activities, including amortization of prior deferred costs contemplated in base rate increases, increased approximately $35.3 million year over year.  Operating costs that are directly recovered in utility margin increased $4.2 million year over year.  Costs associated with lower performance compensation and share based compensation and other cost reductions partially offset these increases.

Depreciation & Amortization
In 2009, depreciation & amortization expense increased $15.4 million compared to 2008.  The increase in depreciation is due largely to plant additions.  Plant additions include the approximate $100 million SO2 scrubber placed into service January 1, 2009, for which depreciation totaling $5.6 million is directly recovered in electric utility margin.  Depreciation expense increased $7.1 million in 2008 compared to 2007.  Expense in 2008 includes $3.8 million of increased amortization associated with prior electric demand side management costs to be recovered pursuant to the August 15, 2007 electric base rate order.  The remaining increases are also attributable to increased utility plant in service.

Taxes Other Than Income Taxes
Taxes other than income taxes decreased $12.0 million in 2009 compared to 2008 and increased $4.2 million in 2008 compared to 2007.  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 $7.8 in 2009, compared to $4.0 million in 2008 and $9.4 million in 2007.  The variations are primarily due to volatile market values associated with investments related to benefit plans.

Interest Expense

For the year ended December 31, 2009, interest expense was $79.2 million, which represents a slight decrease of $0.7 million compared to 2008.  Lower short-term interest rates and lower average short-term debt balances have favorably affected interest expense year over year and are reflective of lower gas prices and the issuance of new long-term debt.  Offsetting the favorable impacts of lower rates and short-term balances is the impact of two long-term financing transactions completed in 2009.  The long-term financing transactions include a second quarter issuance by Utility Holdings of $100 million in unsecured eleven year notes with an interest rate of 6.28 percent and a third quarter completion by SIGECO of a $22.3 million debt issuance of 31 year tax exempt first mortgage bonds with an interest rate of 5.4 percent.

For the year ended December 31, 2008, interest expense was $79.9 million, a decrease of $0.7 million compared to 2007, as lower average short-term debt levels and lower average short-term interest rates were partially offset by higher long-term balances and interest rates.

Income Taxes

Federal and state income taxes decreased $8.4 million in 2009 compared to 2008 and increased $0.9 million in 2008 compared to 2007.  The changes are impacted primarily by fluctuations in pre-tax income and lower effective tax rates.  The lower effective tax rate in 2009 results from more taxable income allocated to states with low, or no, state income taxes.

Environmental Matters

Clean Air Act

The Clean Air Interstate Rule (CAIR) is an allowance cap and trade program requiring further reductions from coal-burning power plants in NOx emissions beginning January 1, 2009 and SO2 emissions beginning January 1, 2010, with a second phase of reductions in 2015.  On July 11, 2008, the US Court of Appeals for the District of Columbia vacated the federal CAIR regulations.  Various parties filed motions for reconsideration, and on December 23, 2008, the Court reinstated the CAIR regulations and remanded the regulations back to the USEPA for promulgation of revisions in accordance with the Court’s July 11, 2008 Order.  Thus, the original version of CAIR promulgated in March of 2005 remains effective while USEPA revises it per the Court’s guidance.  SIGECO is in compliance with the current CAIR Phase I annual NOx reduction requirements in effect on January 1, 2009 and is also in compliance with SO2 reductions effective January 1, 2010.  It is possible that a revised CAIR will require further reductions in NOx and SO2 from SIGECO’s generating units.  Utilization of the Company’s inventory of NOx and SO2  allowances may also be impacted if CAIR is further revised; however, most of these allowances were granted to the Company at zero cost, so these changes will not impact the carrying value.

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

To comply with Indiana’s implementation plan of the Clean Air Act of 1990, the CAIR regulations, and to comply with potential future regulations of mercury and further NOx and SO2  reductions, SIGECO has IURC authority to invest in clean coal technology.  Using this authorization, SIGECO has invested approximately $307 million in pollution control equipment, including Selective Catalytic Reduction (SCR) systems and fabric filters.  SCR technology is the most effective method of reducing NOx emissions where high removal efficiencies are required and fabric filters control particulate matter emissions.  These investments were included in rate base for purposes of determining new base rates that went into effect on August 15, 2007.  Prior to being included in base rates, return on investments made and recovery of related operating expenses were recovered through a rider mechanism.

Further, the IURC granted SIGECO authority to invest in an SO2 scrubber at its generating facility that is jointly owned with ALCOA (the Company’s portion is 150 MW).  The order allows SIGECO to recover an approximate 8 percent return on capital investments through a rider mechanism, which is periodically updated for actual costs incurred less post in-service depreciation expense.  The Company has invested approximately $100 million in this project.  The scrubber was placed into service on January 1, 2009.  Recovery through a rider mechanism of associated operating expenses including depreciation expense associated with the scrubber also began on January 1, 2009.  The SO2 scrubber is in compliance with the additional SO2 reductions required by Phase I CAIR commencing on January 1, 2010.

SIGECO’s coal fired generating fleet is 100 percent scrubbed for SO2 and 90 percent controlled for NOx.  SIGECO's investments in scrubber, SCR and fabric filter technology allows for compliance with existing regulations and should position it to comply with future reasonable pollution control legislation, if and when, reductions in mercury and further reductions in NOx and SO2 are promulgated by USEPA.
 
 
Climate Change

Vectren is committed to responsible environmental stewardship and conservation efforts.  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)
 
2009
 
2008
 
2007
 
2006
 
2005
Direct CO2 Emissions (tons)
 
5,500
  1/
  8,029
 
  7,995
 
  7,827
 
  8,242
 
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 USEPA, the Company’s direct CO2 emissions from its fossil fuel electric generation that report under the Acid Rain Program were less than one half of one percent of all emissions in the United States from similar sources.

Emissions from other Company operations, including those from its natural gas distribution operations, are monitored internally using the Department of Energy 1605(b) Standard, and the Company is currently assessing how to effectively report these emissions in relation to the new mandatory reporting regulations set forth by the USEPA.

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;
·  
Participation in an electric conservation and demand side management collaborative with the OUCC and other customer advocate groups;
·  
Evaluating potential carbon requirements with regard to new generation, other fuel supply sources, and future environmental compliance plans;
·  
Reducing the Company’s carbon footprint by measures such as purchasing hybrid vehicles and optimizing generation efficiencies; and
·  
Developing renewable energy and energy efficiency performance contracting projects through its wholly owned subsidiary, Energy Systems Group.

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

In the absence of federal legislation, several regional initiatives throughout the United States are in the process of establishing regional cap and trade programs.  While no climate change legislation is pending in Indiana, the state is an observer to the Midwestern Regional Greenhouse Gas Reduction Accord.

In advance of a federal or state renewable portfolio standard, SIGECO received IURC 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.  At December 31, 2009, the Company’s renewable portfolio is approximately 5 percent of total generation sources.

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

Impact of Legislative Actions & Other Initiatives is Unknown
If legislation requiring reductions in CO2 and other greenhouse gases or legislation mandating a renewable energy portfolio standard is adopted, such regulation could substantially affect both the costs and operating characteristics of the Company’s fossil fuel generating plants, nonutility coal mining operations, and natural gas distribution businesses.  Further, any legislation would likely impact the Company’s generation resource planning decisions.  At this time and in the absence of final legislation, compliance costs and other effects associated with reductions in greenhouse gas emissions or obtaining renewable energy sources remain uncertain.  The Company has gathered preliminary estimates of the costs to comply with a cap and trade approach to controlling greenhouse gas emissions.  A preliminary investigation demonstrated costs to comply would be significant, first with regard operating expenses for the purchase of allowances, and later for capital expenditures as technology becomes available to control greenhouse gas emissions.  However, these compliance cost estimates are based on highly uncertain assumptions, including allowance prices and energy efficiency targets.  Costs to purchase allowances that cap greenhouse gas emissions should be considered a cost of providing electricity and gas, and as such, the Company believes recovery should be timely reflected in rates charged to customers.  Approximately 20 percent of electric volumes sold in 2008 were delivered to municipal and other wholesale customers.  As such, reductions in these volumes in 2009 coupled with the flexibility to further modify the level of these transactions in future periods may help with compliance since emission targets are expected to be based on pre-2008 levels.

Ash Ponds & Coal Ash Disposal Regulations

The USEPA is considering additional regulatory measures affecting the management and disposal of coal combustion products, such as ash generated by the Company’s coal-fired power plants.  Additional laws and regulations under consideration more stringently regulate these byproducts, including the potential for coal ash to be considered a hazardous waste in certain circumstances.  The USEPA has indicated that it intends to propose a rule during 2010.  At this time, the Company is unable to predict the outcome any such revised regulations might have on operating results, financial position, or liquidity.

Jacobsville Superfund Site

On July 22, 2004, the USEPA 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 USEPA 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 USEPA 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 USEPA 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 $23.2 million.  The estimated accrued costs are limited to Indiana Gas’ share of the remediation efforts.  Indiana Gas has arrangements in place for 19 of the 26 sites with other potentially responsible parties (PRP), which limit Indiana Gas’ costs at these 19 sites to between 20 percent and 50 percent.

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

In October 2002, SIGECO received a formal information request letter from the IDEM regarding five manufactured gas plants that it owned and/or operated and were not enrolled in the IDEM’s VRP.  In October 2003, SIGECO filed applications to enter four of the manufactured gas plant sites in IDEM's VRP.  The remaining site is currently being addressed in the VRP by another Indiana utility.  SIGECO added those four sites into the renewal of the global Voluntary Remediation Agreement that Indiana Gas has in place with IDEM for its manufactured gas plant sites.  That renewal was approved by the IDEM in February 2004.  SIGECO is also named in a lawsuit filed in federal district court in May 2007, involving another waste disposal site subject to potential environmental remediation efforts.  With respect to that lawsuit, in an October 2009 court decision, SIGECO was found to be a PRP at the site.  However, the Court must still determine whether such costs should be allocated among a number of PRPs, including the former owners of the 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 May 2007 lawsuit.

SIGECO has recorded cumulative costs that it reasonably expects to incur related to these environmental matters totaling approximately $11.1 million.  However, given the uncertainty surrounding the allocation of PRP responsibility associated with the May 2007 lawsuit and other matters, 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 settled with certain of its known insurance carriers under insurance policies in effect when these sites were in operation in an aggregate amount of $8.1 million; negotiations are ongoing with others.

Total costs expected to be incurred 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, 2009 and December 31, 2008, approximately $6.5 million of accrued, but not yet spent, remediation costs are included in Other Liabilities related to both the Indiana Gas and SIGECO sites.

Rate & Regulatory Matters

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

Gas rates in Indiana contain a gas cost adjustment (GCA) clause. The GCA clause allows the Company to charge for changes in the cost of purchased gas.  Electric rates contain a fuel adjustment clause (FAC) 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 IURC approved agreement authorizing this recovery expires in April 2010, and is subject to automatic annual renewals.

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 the estimated cost of gas, cost of fuel, and net energy cost of purchased power and actual costs incurred.  The Company records any under-or-over-recovery resulting from gas and fuel adjustment clauses each month in margin.  A corresponding asset or liability is recorded until the under-or-over-recovery is billed or refunded to utility customers.

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.

Prior to October 1, 2008, gas costs were recovered in Ohio through a gas cost recovery (GCR) clause.  The GCR clause operated similar to the GCA clause in Indiana.  The PUCO periodically audited the GCR rates.  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, and the GCR is no longer necessary.

Vectren South Electric Base Rate Filing

On December 11, 2009, the Company filed a request with the IURC to adjust its electric base rates in its South service territory.  The requested increase in base rates addresses capital investments, a modified electric rate design that facilitates a partnership between the Company and customers to pursue energy efficiency and conservation, and new energy efficiency programs to complement those currently offered for natural gas customers.  In total the request approximated $54 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.  Most of the remainder of the request is to account for the now lower overall sales levels resulting from the recession.  A portion of the request reflects a slight increase in annual operating and maintenance costs since the last rate case, nearly four years ago.  The rate design proposed in the filing would break the link between customers’ consumption and the utility’s rate of return, thereby aligning the utility’s and customers’ interests in using less energy.  The request assumes an overall rate of return of 7.62 percent on rate base of approximately $1,294 million and an allowed return on equity (ROE) of 10.7 percent.  Based upon timelines prescribed by the IURC at the start of these proceedings, a decision is expected to be issued at the end of 2010.

VEDO Gas Base Rate Order Received

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

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

With this rate order the Company has in place for its Ohio gas territory rates that allow for the phased implementation of a straight fixed variable rate design that mitigates both weather risk and lost margin; tracking of 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.  The straight fixed variable rate design will be fully phased in by February 2010.

VEDO Continues the Process to Exit the Merchant Function
On August 20, 2008, the PUCO approved 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 is comprised of the monthly NYMEX settlement price plus a fixed adder.  This auction, which is effective from October 1, 2008 through March 31, 2010, is 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, receiving proceeds of approximately $107 million.

The second phase of the exit process begins on April 1, 2010, during which the Company will no longer sell natural gas directly to these customers.  Rather, state-certified Competitive Retail Natural Gas Suppliers, that are successful bidders in a second regulatory-approved auction, will sell the gas commodity to specific customers for 12 months at auction-determined standard pricing.  That auction was conducted on January 12, 2010, and the auction results were approved by the PUCO on January 13.  The plan approved by the PUCO requires that the Company conduct at least two auctions during this phase.  As such, the Company will conduct another auction in advance of the second 12-month term, which will commence on April 1, 2011.  Consistent with current practice, customers will continue to receive one bill for the delivery of natural gas service. 

The PUCO has also provided for an Exit Transition Cost rider, which allows the Company to recover costs associated with the transition.  As the cost of gas is currently passed through to customers through a PUCO approved recovery mechanism, the impact of exiting the merchant function should not have a material impact on Company earnings or financial condition.

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 provides 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 on each project.

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

-35-
 
Vectren South Gas Base Rate Order Received
On August 1, 2007, the Company received an order from the IURC which approved the settlement reached in Vectren South’s gas rate case.  The order provided for a base rate increase of $5.1 million and a ROE of 10.15 percent, with an overall rate of return of 7.2 percent on rate base of approximately $122 million.  The order also provided for the recovery of $2.6 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 $3 million and the treatment cannot extend beyond three years on each project.

With this order, the Company now has in place for its South gas territory weather normalization, a conservation and lost margin recovery tariff, tracking of gas cost expense related to a uncollectible accounts expense level based on historical experience and unaccounted for gas through the existing gas cost adjustment mechanism, and tracking of pipeline integrity management expense. 
 
Vectren South Electric Base Rate Order Received
In August 2007, the Company received an order from the IURC which approved the settlement reached in Vectren South’s electric rate case.  The order provided for an approximate $60.8 million electric rate increase to cover the Company’s cost of system growth, maintenance, safety and reliability.  The order provided for, among other things: recovery of ongoing costs and deferred costs associated with the MISO; operations and maintenance (O&M) expense increases related to managing the aging workforce, including the development of expanded apprenticeship programs and the creation of defined training programs to ensure proper knowledge transfer, safety and system stability; increased O&M expense necessary to maintain and improve system reliability; benefit to customers from the sale of wholesale power by Vectren sharing equally with customers any profit earned above or below $10.5 million of wholesale power margin; recovery of and return on the investment in past demand side management programs to help encourage conservation during peak load periods; timely recovery of the Company’s investment in certain new electric transmission projects that benefit the MISO infrastructure; an overall rate of return of 7.32 percent on rate base of approximately $1,044 million and an allowed ROE of 10.4 percent.

MISO

Since 2002 and with the IURC’s approval, the Company has been 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.

Historically, the Company has typically been in a net sales position with MISO as generation capacity is in excess of that needed to serve native load and is from time to time in a net purchase position.  When the Company is a net seller such net revenues are included in Electric utility revenues and when the Company is a net purchaser such net purchases are included in Cost of fuel & purchased power.  Net positions are determined on an hourly basis.  Since the Company became an active MISO member, its generation optimization strategies primarily involve the sale of excess generation into the MISO Day Ahead and Real-Time markets.  The Company also has municipal customers served through the MISO and for which the Company transmits power to the MISO for delivery to those customers.  Net revenues from wholesale activities, inclusive of revenues associated with these municipal contracts, totaled $20.8 million in 2009, $57.6 million in 2008, and $35.0 million in 2007.  The base rate case effective August 17, 2007, requires that wholesale margin (net revenues less the cost of fuel & purchased power) inclusive of this MISO wholesale activity earned above or below $10.5 million be shared equally with retail customers as measured on a fiscal year ending in August.

Recently, MISO market prices have fallen and the Company has more frequently been a net purchaser.  In addition, the Company also receives power through the MISO associated with its wind and other power purchase agreements.  Including these power purchase agreements, the Company purchased energy from the MISO totaling $34.2 million in 2009, $16.6 million in 2008, and $18.2 million in 2007.  To the extent these power purchases are used for retail load, they are subject to FAC filings.
 
-36-
 
The Company also receives transmission revenue that results from other MISO 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.

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

The need to expend capital for improvements to the regional transmission system, both to SIGECO’s facilities as well as to those facilities of adjacent utilities, over the next several years is expected to be significant.  Beginning in June 2008, the Company began timely recovering its investment in certain new electric transmission projects that benefit the MISO regional infrastructure at a FERC approved rate of return.  Such revenues recorded in Electric utility revenues associated with projects meeting the criteria of MISO’s transmission expansion plans totaled $9.1 million in 2009 and $4.8 million in 2008.

One such project currently under construction is an interstate 345 kilovolt transmission line that will connect Vectren’s A.B. Brown Generating Station to a station in Indiana owned by Duke Energy to the north and to a station in Kentucky owned by Big Rivers Electric Corporation to the south.  Throughout the project, SIGECO is to recover an approximate 10 percent return, inclusive of the FERC approved equity rate of return of 12.38 percent, on capital investments through a rider mechanism which is updated annually for estimated costs to be incurred.  Of the total investment, which is expected to approximate $75 million, as of December 31, 2009, the Company has invested approximately $21.3 million.  The Company expects this project to be fully operational in 2011.  At that time, any operating expenses including depreciation expense are also expected to be recovered through a FERC approved rider mechanism.  Further, the approval allows for recovery of expenditures made even in the event currently unforeseen difficulties delay or permanently halt the project.

Results of Operations of the Nonutility Group

The Nonutility Group operates in three primary business areas: Energy Marketing and Services, Coal Mining, and Energy Infrastructure Services.  Energy Marketing and Services markets and supplies natural gas and provides energy management services.  Coal Mining mines and sells coal.  Energy Infrastructure Services provides underground construction and repair and provides performance contracting and renewable energy services.  There are also other legacy businesses that have invested in energy-related opportunities and services, real estate, and leveraged leases, among other investments.  The Nonutility Group supports the Company’s regulated utilities pursuant to service contracts by providing natural gas supply services, coal, and infrastructure services.  Nonutility Group earnings for the years ended December 31, 2009, 2008, and 2007, follow:
                   
   
Year Ended December 31,
 
(In millions, except per share amounts)
 
2009
   
2008
   
2007
 
NET INCOME EXCLUDING LIBERTY CHARGE
  $ 37.7     $ 18.9     $ 37.0  
                         
CONTRIBUTION TO VECTREN BASIC EPS,
     EXCLUDING LIBERTY CHARGE
  $ 0.47     $ 0.24     $ 0.49  
                         
NET INCOME ATTRIBUTED TO:
                       
  Energy Marketing & Services (Excluding Liberty Charge)
  $ 16.0     $ 18.0     $ 22.3  
Mining Operations
    13.4       (4.6 )     2.0  
Energy Infrastructure Services
    10.8       11.4       9.4  
Other Businesses
    (2.5 )     (5.9 )     0.3  
Synfuels-related
    -       -       3.0  
 
Including the Liberty Charge of $11.9 million after tax, the Nonutility Group generated net income of $­­­25.8 million for the year ended December 31, 2009.

Impact of the Recent Recession

Despite the beginning of recovery, the recent recession has resulted in, and may continue to result in, a lower level of economic activity and greater uncertainty regarding energy prices and other key factors that impact the Nonutility Group.  Economic declines have been accompanied by a decrease in demand for products and services offered by nonutility operations.  The recent recession has had, and may continue to have, some negative impact on utility industry spending for construction projects, demand for coal, and spending on performance contracting and renewable energy expansion.  It is also possible that if a weak economy continues, there could be further reductions in the value of certain nonutility real estate and other legacy investments.

Energy Marketing & Services

Energy Marketing and Services 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 but excluding the Liberty Charge of $11.9 million after tax, from Energy Marketing and Services for the year ended December 31, 2009, were earnings of $­­­­16.0 million, compared to $­­­­18.0 million in 2008 and $22.3 million in 2007.

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.  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.  For the year ended December 31, 2009, 2008, and 2007, the amounts recorded to Equity in earnings of unconsolidated affiliates related to ProLiance’s operations, excluding the Liberty Charge, totaled income of $23.6 million, $39.5 million, and $41.0 million, respectively.

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 related to the Company’s portion of ProLiance’s results.  During the year ended December 31, 2009, ProLiance’s earnings, inclusive of financing costs and income taxes, were approximately $9.6 million compared to $19.3 million in 2008 and $22.9 million in 2007.

During 2009, ProLiance’s earnings contribution decreased $9.7 million compared to 2008.  The decrease primarily 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 earnings contribution decreased $3.6 million in 2008 compared to 2007 and is reflective of lower operating results.  ProLiance’s storage capacity at December 31, 2009 is 46 Bcf compared to 42 Bcf at December 31, 2008 and 40 Bcf at December 31, 2007.

Investment in Liberty Gas Storage
Liberty Gas Storage, LLC (Liberty), a joint venture between a subsidiary of ProLiance and a subsidiary of Sempra Energy (SE), is a development project for salt-cavern natural gas storage facilities.  ProLiance is the minority member with a 25 percent interest, which it accounts for using the equity method.  The project was expected to include 17 Bcf of capacity in its north facility (previously referred to as the Sulfur site, located near Sulfur, Louisiana), and an additional 17 Bcf of capacity in its south facility (previously referred to as the Hackberry site, near Hackberry, Louisiana).  As more fully described below, it is now expected that only the south facility will be completed by the joint venture.  This facility is expected to provide at least 17 Bcf of capacity. The Liberty pipeline system is currently connected with several interstate pipelines, including the Cameron Interstate Pipeline operated by Sempra Pipelines & Storage, and will connect area LNG regasification terminals to an interstate natural gas transmission system and storage facilities.  ProLiance’s investment in Liberty is $37.3 million at December 31, 2009, after reflecting the charge discussed below.

In late 2008, SE advised ProLiance that the completion of the phase of Liberty’s development at the north site had been delayed by subsurface and well-completion problems.  Based on testing performed in the second quarter of 2009, SE determined that attempts at corrective measures had been unsuccessful 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 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.  The Company and ProLiance do not expect issues associated with Liberty to impact future liquidity or access to capital.  Further, it is not expected that the delay in Liberty’s development will impact ProLiance’s ability to meet the needs of its customers.

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

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 $6.4 million in 2009, compared to $1.9 million in 2008 and $1.2 million in 2007.  The record earnings in 2009 resulted primarily from favorable market conditions over the course of 2009’s first quarter as 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, 2009 was approximately 189,000 equivalent customers, compared to 170,000 at December 31, 2008 and 161,000 at December 31, 2007.  This customer base reflects nearly 33,000 equivalent customers in VEDO’s service territory as part of VEDO’s process of exiting the merchant function.  Vectren Source began providing services to these VEDO customers on October 1, 2008. This service will end March 31, 2010.  Vectren Source was a successful bidder in the second regulatory-approved auction that was conducted on January 12, 2010 related to VEDO’s exit the merchant function.  As a result of this auction, Vectren Source will sell gas commodity directly to approximately 35,000 equivalent customers in VEDO’s service territory through April 1, 2011. 

Coal Mining

Coal Mining mines and sells 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 $13.4 million in 2009, compared to a loss of $4.6 million in 2008 and earnings of $2.0 million in 2007.

Compared to 2008, Coal Mining earnings have increased based on new contract pricing effective January 1, 2009.  The impact of higher revenues has been somewhat offset by increased costs per ton mined and the recession.  The anticipated cost increase was reflective of efforts 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 lower than anticipated earnings from coal mining operations.  The lowered demand has caused some build up of coal inventory at most customer locations as well as at Vectren Fuels’ mines.  As a result of contracts with minimum delivery provisions, certain customers scaled back their deliveries within specified limits.  This resulted in less 2009 mine production as Vectren Fuels reduced production to align with customer’s needs.  Further, Vectren Fuels is currently in a dispute with one customer regarding its purchase contract, and Vectren Fuels is working to resolve the dispute.  In the current market conditions, Vectren Fuels sold 3.5 million tons in 2009 compared to 4.2 million tons in 2008 and 4.7 million tons in 2007.  The original expectation for 2009 was to sell between 4.6 and 5.2 million tons.  Further, the higher customer coal inventory levels will likely cause the current demand and supply imbalance to extend into 2010.  Early 2010 has shown some decline in customer inventory levels, due largely to colder weather and the resulting increased demand.

The decrease in earnings in 2008 compared to 2007 was primarily due to lower production and increased roofing structure costs as a result of revised MSHA regulatory guidelines which necessitated changes to the mining plan.  As a result, the yield at the Prosperity mine decreased approximately 4 percent in 2008 compared to 2007.  In addition, 2008 was impacted by higher diesel fuel costs and unfavorable geologic conditions at the Company’s surface mine, which resulted in more costs to enhance the BTU content of mined coal.

Oaktown Mines

The first of two new underground mines located near Vincennes, Indiana, which began minor coal extraction in the latter half of 2009, is now operational.  The second mine is currently expected to open in 2011.  However, Vectren Fuels may continue to change this time table as it evaluates the impacts of current market conditions.  Reserves at the two mines are estimated at about 100 million tons of recoverable number-five coal at 11,200 BTU and less than 6-pound sulfur dioxide.  The reserves at these new mines bring total coal reserves to approximately 135 million tons at December 31, 2009.  Once in production, the two new mines are capable of producing about 5 million tons of coal per year.  Due to the delay in the opening of the mines, management expects to incur approximately $200 million to access the coal reserves.  At December 31, 2009, Vectren Fuels has invested approximately $174 million in the new mines.

Energy Infrastructure Services

Energy Infrastructure Services provides energy performance contracting and renewable energy services through Energy Systems Group, LLC (ESG) and underground construction and repair to utility infrastructure through Miller Pipeline Corporation (Miller).  Inclusive of holding company costs, Energy Infrastructure’s operations contributed earnings of $10.8 million in 2009, compared to $11.4 million in 2008 and $9.4 million in 2007.

Energy Systems Group
 
ESG’s earnings were $8.8 million in 2009, compared to $6.7 million in 2008 and $4.0 million in 2007.  The increases are primarily due to the continued focus on renewable energy, energy conservation, and sustainability measures by ESG’s customers.  In 2009, the increase is primarily a result of increased performance contracting revenues.  As part of ESG’s ongoing renewable energy project development strategy, results in 2009 include the sale of a 3 MW self-developed landfill gas facility.  With approval from the IURC, the facility was sold to SIGECO, as part of the utility’s strategy to continue to build a renewable energy portfolio.  ESG’s results associated with this renewable project match the results of a similar land fill gas project completed near Atlanta, Georgia in 2008.  At December 31, 2009, ESG’s backlog was $70 million, compared to $65 million at December 31, 2008 and $52 million at December 31, 2007.  The national focus on a comprehensive energy strategy as evidenced by the Energy Independence and Security Act of 2007 and the American Recovery and Reinvestment Act of 2009 is likely to create favorable conditions for ESG’s growth and resulting earnings.

Miller Pipeline

Miller’s 2009 earnings were $3.1 million compared to $6.2 million in 2008 and $6.1 million in 2007.  The decrease in 2009 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 years ended December 31, 2008 and 2007 were record years in terms of earnings contribution from Miller.  As the country continues to replace its aging natural gas infrastructure and needs for shale gas infrastructure become more prevalent, Miller is positioned for future growth.

Other Businesses

Within the Nonutility business segment, there are legacy investments, outside of primary operations, involved in energy-related opportunities and services, real estate, leveraged leases, and other ventures, including investments in the Haddington Energy Partnerships (Haddington).

As of December 31, 2009, remaining legacy investments included in the Other Businesses portfolio total $64.5 million, of which $46.2 million are included in Other nonutility investments and $18.3 million are included in Investments in unconsolidated affiliates on the Consolidated Balance Sheet.  Further separation of that remaining investment by type of investment follows: commercial real estate $21.0 million; Haddington $9.7 million; affordable housing projects $7.8 million; leveraged leases $17.5 million, and other investments, including a note receivable from the City of Alameda, California, $8.5 million.  As of December 31, 2008, investments totaled $71.8 million.

Other Businesses reported a loss of $2.5 million in 2009, compared to a loss of $5.9 million in 2008 and earnings of $0.3 million in 2007.  Results in 2008 reflect a write-down associated with commercial real estate investments.

2008 Commercial Real Estate Charge

The recent economic recession impacted the value of commercial real estate investments within this portfolio, and the prospect for recovery of that value diminished.  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 of which the Company took possession when a leveraged lease expired in 2008 and that is currently for sale.

Synfuel-Related Activity

Tax laws authorizing synfuel credits expired on December 31, 2007.  Prior to that date, the Company had active synthetic fuel investments, including an investment in Pace Carbon Synfuels, LP (Pace Carbon).  In addition, Vectren Fuels generated processing fees from other synfuel producers.  Activity since December 31, 2007 has been insignificant and is generally focused on winding down partnership operations at Pace Carbon.

Generally, the statute of limitations for the IRS to audit a tax return is three years from filing.  Therefore, tax credits generated by the investment in Pace Carbon and utilized in 2006 – 2007 are still subject to IRS examination.  However, avenues remain where the IRS could challenge tax credits for the years prior to 2006.  As a partner of Pace Carbon, Vectren reflected cumulative synfuel tax credits of approximately $101 million in its consolidated results, of which approximately $22 million were generated in 2006 and 2007.  Vectren has utilized all of the credits generated.

Synfuel tax credits were only available when the price of oil was less than a base price specified by the IRC, as adjusted for inflation.  Due to high oil prices in 2007, only $6.0 million of the approximate $23.1 million in tax credits generated were reflected as a reduction to the Company’s income tax expense.  The Company executed several financial contracts to hedge oil price risk.  Income statement activity associated with these contracts was a gain of $13.4 million in 2007.  This activity is reflected in Other-net along with the effects of impairing the Pace Carbon investment in 2006 in advance of equity method losses experienced in 2007.

The investment in Pace Carbon resulted in losses reflected in Equity in earnings of unconsolidated affiliates totaling $20.0 million in 2007.  Synfuel-related results, inclusive of equity method losses and their related tax benefits as well as the tax credits and other related activity, were earnings of $6.8 million in 2007.  Of those earnings, which did not continue beyond 2007, $3.8 million ($5.8 million pre tax) was contributed to the Vectren Foundation in 2007.  Net of that contribution, synfuel-related results were $3.0 million in 2007.

Use of Non-GAAP Performance Measures

Contribution to Vectren’s basic EPS

Per share earnings contributions of the Utility Group, Nonutility Group, and Corporate and Other are presented.  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.  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.  Reconciliations of these non-GAAP measures to their most closely related GAAP measure of consolidated earnings per share are included throughout this discussion and analysis.

Results Excluding the Liberty Charge

This discussion and analysis contains other non-GAAP financial measures that exclude the charge related to ProLiance’s investment in Liberty Gas Storage, LLC (Liberty Charge) recorded during 2009.

Management uses consolidated net income, consolidated earnings per share, and Nonutility Group net income, excluding the Liberty Charge, to evaluate its results.  Management believes analyzing underlying business trends is aided by the removal of the Liberty Charge due to the significant impact it has on comparability between the periods reported.  The rationale for using such non-GAAP measures is that the charge in all cases substantially decreases the performance measures, and the period to period changes do not provide meaningful comparative information regarding typical operating results.

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

The following table reconciles consolidated net income, consolidated basic EPS, and Nonutility Group net income to those results excluding the Liberty Charge.

   
Year Ended December 31, 2009
 
(In Millions, except EPS)
 
GAAP-
Measure
   
Exclude Liberty Charge
   
Non-GAAP
Measure
 
Consolidated
                 
Net Income
  $ 133.1       11.9     $ 145.0  
Basic EPS
  $ 1.65       0.15     $ 1.80  
Nonutility Group Net Income
  $ 25.8       11.9     $ 37.7  
                         

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.

Impact of Recently Issued Accounting Guidance

Business Combinations

On January 1, 2009, the Company adopted new FASB guidance related to business combinations.  This guidance establishes principles and requirements for how the acquirer of an entity (1) recognizes and measures the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree (2) recognizes and measures acquired goodwill or a bargain purchase gain and (3) determines what information to disclose in its financial statements in order to enable users to assess the nature and financial effects of the business combination.  The guidance applies to all transactions or other events in which one entity acquires control of one or more businesses and applies to all business entities.  To date, the adoption of this standard has not had a material impact.

Noncontrolling Interests in Consolidated Financial Statements

On January 1, 2009, the Company adopted new FASB guidance related to noncontrolling interests in consolidated financial statements.  This guidance establishes accounting and reporting standards that require ownership percentages in material subsidiaries held by parties other than the parent be clearly identified, labeled, and presented separately from the parent’s equity in the equity section of the consolidated balance sheet; the amount of consolidated net income attributable to the parent and the noncontrolling interest to be clearly identified and presented on the face of the consolidated income statement; that changes in the parent’s ownership interest while it retains control over its subsidiary be accounted for consistently; that when a subsidiary is deconsolidated, any retained noncontrolling equity investment be initially measured at fair value; and that sufficient disclosure is made to clearly identify and distinguish between the interests of the parent and the noncontrolling owners.  The adoption of this guidance on January 1, 2009 had an immaterial impact to the Company’s presentation of its financial position and operating results.

Subsequent Events

The Company adopted new FASB guidance related to management’s review of subsequent events on June 30, 2009.  In the instance of a public registrant such as the Company, this guidance establishes the accounting for and disclosure of events that occur after the balance sheet date but before financial statements are “issued”, as that term is defined in the guidance.  Such disclosure is included in Note 2 to these consolidated financial statements.

Accounting Standards Codification

The Company adopted FASB guidance related to the FASB Accounting Standards Codification (ASC) and the Hierarchy of GAAP.  This statement identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of financial statements of nongovernmental entities that are presented in conformity with GAAP in the United States.  This statement replaces prior guidance related to the hierarchy of GAAP and establishes the FASB ASC as the source of authoritative accounting principles recognized by the FASB.  Rules and interpretive releases of the SEC under authority of federal securities laws are also sources of authoritative GAAP for all SEC registrants.  The adoption of this guidance did not have any impact on amounts recorded on the financial statements.

Accounting for Liabilities Measured at Fair Value with a Third-Party Credit Enhancement

On January 1, 2009, the Company adopted FASB guidance related to issuer’s accounting for liabilities measured at fair value with a third-party credit enhancement.  This guidance states that companies should not include the effect of third-party credit enhancements in the fair value measurement of the related liabilities.  The guidance also requires companies with outstanding liabilities measured or disclosed at fair value to disclose the existence of credit enhancements, to disclose valuation techniques used to measure liabilities and to include a discussion of changes, if any, from the valuation techniques used to measure liabilities in prior periods.

As of December 31, 2009, the Company has approximately $250.0 million of debt instruments that are supported by a third party credit enhancement feature such as insurance from a monoline insurer or a letter of credit posted by third party that supports the Company’s credit facilities.  The Company’s valuation techniques did not materially change as a result of the adoption of this guidance.

Determination of the Useful Life of Intangible Assets

In April 2008, the FASB issued guidance related to the determination of the useful life of intangible assets. This guidance amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under other guidance related to goodwill and other intangible assets.  On January 1, 2009, the Company adopted this guidance and such adoption did not have a material impact on the consolidated financial statements.

Employers’ Disclosures about Postretirement Benefit Plan Assets

In December 2009, the Company adopted new accounting guidance for employers’ disclosures about postretirement benefit plan assets.  This guidance amends the plan asset disclosures required under prior guidance by the FASB to provide guidance on an employer’s disclosures about plan assets of a defined benefit pension or other postretirement plan. The guidance relates to disclosures about investment policies and strategies, categories of plan assets, fair value measurements of plan assets, and significant concentrations of risk. Such disclosure is included in Note 9 to the financial statements.

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 Company does not expect the adoption will have a material 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 will adopt this guidance in its first quarter 2010 reporting.  The Company does not expect the adoption will have a material impact on the consolidated financial statements.

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 to 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 one of these investments 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, and the prospect for recovery of that value has diminished.  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 have increased in the recent economic and credit constrained environment.  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 2009, noting that current capitalization rates and other assumptions indicate no further impairment at December 31, 2009.  Actual realized values, however, could differ from these estimates.

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 reporting unit.  Nonutility Group reporting units are generally defined as the operating companies that aggregate that operating segment.  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 2009 periodic benefit cost:  a discount rate of 6.25 percent, an expected return on plan assets of 8.25 percent, a rate of compensation increase of 3.75 percent, and an inflation assumption of 3.5 percent.  These key assumptions were unchanged from the assumptions utilized in 2008.  To estimate 2010 costs, the discount rate, expected return on plan assets, rate of compensation increase, and inflation assumption were 6.0 percent, 8.0 percent, 3.5 percent, and 3.0 percent respectively.  Management currently estimates a pension and postretirement cost of approximately $13 million in 2010, compared to approximately $15 million in 2009, $11 million in 2008, and $14 million in 2007.  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 2010 projected costs would generally increase periodic benefit cost by approximately $1.6 million.  A 50 basis point decrease in the discount rate used to estimate 2009 periodic cost would have increased costs by approximately $1.7 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.  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, 2009 approximated $332 million and $197 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 and short-term obligations outstanding at December 31, 2009 approximated $920 million and $16 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, 2009, are A-/Baa1 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/A2.  Utility Holdings’ commercial paper has a credit rating of A-2/P-2.  The current outlook of both Moody’s and Standard and Poor’s is stable.  During the third quarter of 2009, Moody’s raised its credit rating on SIGECO’s secured debt from A3 to A2; otherwise, these ratings and outlooks did not change during 2009.  A security rating is not a recommendation to buy, sell, or hold securities.  The rating is subject to revision or withdrawal at any time, and each rating should be evaluated independently of any other rating.  Standard and Poor’s and Moody’s lowest level investment grade rating is BBB- and Baa3, respectively.

The Company’s consolidated equity capitalization objective is 45-55 percent of long-term capitalization.  This objective may have varied, and will vary, depending on particular business opportunities, capital spending requirements, execution of long-term financing plans, and seasonal factors that affect the Company’s operations.  The Company’s equity component was 46 percent and 50 percent of long-term capitalization at December 31, 2009 and 2008, respectively.  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, 2009, the Company was in compliance with all financial covenants.
Available Liquidity in Current Credit Conditions

The Company’s A-/Baa1 investment grade credit ratings have allowed it to access the capital markets as needed during this period of financial market volatility.  Over the last twelve to twenty four months, the Company has significantly enhanced its short-term borrowing capacity with the completion of several long-term financing transactions including the issuance of long-term debt in both 2008 and 2009 and the settlement of an equity forward contract in 2008.  The liquidity provided by these transactions, when coupled with existing cash and expected internally generated funds, is expected to be sufficient over the near term to fund anticipated capital expenditures, investments, debt security redemptions, and other working capital requirements.

Debt redemptions total $48 million in 2010.  In 2011, $250 million is due.  The Company is currently considering the level of  need for Nonutility Group long-term debt and whether to prefund a portion of the $250 million Utility Group debt redemption with a long-term debt issuance in 2010.  In addition, investors have the one-time option to put $10 million in May of 2010 and a one time option to put $30 million in 2011.

Long-term debt transactions completed in 2009 include a $150 million issuance by Vectren Capital and a $100 million issuance by Vectren Utility Holdings.  SIGECO also recently remarketed $41.3 million of long-term debt, supported by letters of credit issued under Vectren Utility Holdings' credit facility and completed a $22.3 million tax-exempt first mortgage bond issuance.  These transactions, along with financing transactions completed in 2008 and 2007, are more fully described below.

Consolidated Short-Term Borrowing Arrangements

At December 31, 2009, the Company had $775 million of short-term borrowing capacity, including $520 million for the Utility Group and $255 million for the wholly owned Nonutility Group and corporate operations.  As reduced by letters of credit and borrowings currently outstanding, approximately $462 million was available for the Utility Group operations and approximately $48 million was available for the wholly owned Nonutility Group and corporate operations.  Of the $520 million in Utility Group capacity, $5 million is available through June, 2010 and $515 million is available through November, 2010; and the $255 million in Nonutility Group capacity is available through November, 2010.  In September of 2009, approximately $120 million of short-term credit capacity specific to the Nonutility Group was no longer needed as a result of the recent long-term debt issuance by Vectren Capital and was not renewed.  In addition, a $10 million credit facility at Energy Systems Group, one of the Company's wholly-owned nonutility subsidiaries, also expired during 2009.  This supplemental facility was no longer needed and thus was not renewed. 

Historically, the Company uses short-term borrowings to supplement working capital needs and also to fund capital investments and debt redemptions until financed on a long-term basis.  The Company has historically funded the short-term borrowing needs of Utility Holdings’ operations through the commercial paper market.  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 A2/P2 commercial paper issuances and draws on Utility Holdings’ $515 million commercial paper back-up credit facilities.  Throughout 2009, the Company has been able to place commercial paper without any significant issues.  However, the level of required short-term borrowings is significantly lower compared to historical trends due to the recently completed long-term financing transactions.

Compared to historical trends, the Company anticipates over the next several years a greater use of the long-term capital markets to more timely finance capital investments and other growth as well as debt security redemptions.  This change comes as short-term borrowing arrangements have become less certain, more volatile, and the cost of unutilized capacity is expected to increase significantly.  Thus, while the Company expects to renew these facilities in 2010, the Company anticipates that borrowing levels will be lower due to the reduced requirements for short-term borrowings described above.  Under current market conditions, this change is expected to yield greater certainty to financing business operations at the expense of some increase in interest costs.

ProLiance Short-Term Borrowing Arrangements

ProLiance, a nonutility energy marketing affiliate of the Company, has separate borrowing capacity available through a syndicated credit facility.  ProLiance renegotiated a new credit facility with terms to expire June 14, 2010.  The terms of this facility allow for $315 million of capacity, as adjusted for letters of credit and current inventory and receivable balances. This credit facility, when coupled with internally generated funds, is expected to provide sufficient liquidity to meet ProLiance's operational needs.  As of December 31, 2009, no borrowings 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 $5.8 million in 2009, $1.2 million in 2008 and $5.2 million in 2007.  In 2010, new issuances required to meet these various plan requirements are estimated to be consistent with issuances in 2009.

Potential Uses of Liquidity

Pension & Postretirement Funding Obligations

As of December 31, 2009, asset values of the Company’s qualified pension plans were approximately 82 percent of the projected benefit obligation.  In order to increase the funded status, management currently estimates the qualified pension plans require Company contributions of $12 million in 2010.  Under current market conditions, the Company estimates similar funding in 2011.  During 2009, approximately $34 million in contributions to qualified pension plans were made.  In addition to the qualified plan funding, the Company anticipates payments totaling $20 million in 2010 associated with its other retirement and deferred compensation plans.

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, 2009, corporate issued guarantees support a portion of ESG’s performance contracting commitments and warranty obligations described below.  In addition, the Company has approximately $60 million of other guarantees outstanding supporting other consolidated subsidiary operations, of which $46 million support non-regulated retail gas supply operations.  Guarantees issued and outstanding on behalf of unconsolidated affiliates approximated $3 million at December 31, 2009. These guarantees relate primarily to arrangements between ProLiance and various natural gas pipeline operators. The Company has not been called upon to satisfy any obligations pursuant to these parental guarantees and has accrued no significant liabilities related to these guarantees.

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

Specific to ESG, in its role as a general contractor in the performance contracting industry, at December 31, 2009, there are 54 open surety bonds supporting future performance. The average face amount of these bonds is $3.6 million, and the largest obligation has a face amount of $30.4 million.  These surety bonds are guaranteed by Vectren Corporation.  The maximum exposure of these obligations is less than these amounts for several factors, including the level of work already completed.  At December 31, 2009, over 50 percent of work was completed on projects with open surety bonds.  A significant portion of these commitments will be fulfilled within one year.  In instances where ESG operates facilities, project guarantees extend over a longer period.

In addition to its performance obligations, ESG also warrants the functionality of certain installed infrastructure generally for one year and the associated energy savings over a specified number of years.  In certain instances, these warranty obligations are also backed by Vectren Corporation.

Planned Capital Expenditures & Investments

Planned utility and nonutility capital expenditures and investments, including contractual purchase and investment commitments discussed below, for the five-year period 2010 - 2014 are estimated as follows:
                                       
(In millions)
 
2010
       
2011
       
2012
   
2013
   
2014
 
Utility Group
  $ 245         $ 230         $ 210     $ 195     $ 215  
Nonutility Group
    120           80           75       70       70  
    Total capital expenditures & investments
  $ 365         $ 310         $ 285     $ 265     $ 285  
 
Contractual Obligations

The following is a summary of contractual obligations at December 31, 2009:
                                           
(In millions)
 
Total
   
2010
   
2011
   
2012
   
2013
   
2014
   
Thereafter
 
                                           
Long-term debt (1)
  $ 1,639.8     $ 48.0     $ 250.0     $ 60.0     $ 105.0     $ 30.0     $ 1,146.8  
Short-term debt
    213.5       213.5       -       -       -       -       -  
Long-term debt interest commitments
    1,179.3       98.8       94.5       77.5       73.0       68.1       767.4  
Nonutility commodity purchase commitments
    33.9       4.9       3.8       8.2       8.4       8.6       -  
Operating leases
    10.3       4.5       2.6       1.4       0.8       0.7       0.3  
    Total (2)
  $ 3,076.8     $ 369.7     $ 350.9     $ 147.1     $ 187.2     $ 107.4     $ 1,914.5  
 
(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 2009 (in millions) is $10.0 in 2010, $30.0 in 2011, zero in 2012 and thereafter.
(2)  
The Company has other long-term liabilities that total approximately $205 million.  This amount is comprised of the following:  pension obligations $55 million, postretirement obligations $71 million, deferred compensation and share-based compensation obligations $24 million, asset retirement obligations $33 million, investment tax credits $6 million, environmental remediation obligations $6 million, and other obligations including unrecognized tax benefits totaling $10 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 $449.6 million in 2009, compared to $423.2 million in 2008 and $298.1 million in 2007.

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.  Tax payments in both 2009 and 2008 were favorably impacted by federal stimulus plans authorizing bonus depreciation and IRS approval in 2009 to change its tax method for recognizing repair and maintenance activities.  In addition, 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.

In 2008, cash flow from operating activities increased $125.1 million compared to 2007.  Higher levels of deferred taxes due primarily to federal stimulus plans authorizing bonus depreciation on qualifying capital expenditures increased cash flow approximately $52.6 million.  Working capital changes generated cash of $9.2 million in 2008 compared to cash used of $27.0 million in 2007.  The increase in cash from working capital results primarily from the permanent reduction of natural gas inventory associated with VEDO’s exit of the merchant function, offset by growth in recoverable fuel balances.  The remaining increase in operating cash flow is primarily due to the cash collection of previously deferred regulatory assets.

Financing Cash Flow

Although working capital requirements are generally funded by cash flow from operations, the Company uses short-term borrowings to supplement working capital needs when accounts receivable balances are at their highest and gas storage is refilled.  Additionally, short-term borrowings are required for capital projects and investments until they are financed on a long-term basis.

During 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.  The Company’s 2009 and 2008 operating cash flow funded over 80 percent of capital expenditures and dividends in those years.  Recently completed long-term financing transactions have allowed for the repayment of nearly $350 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 are more fully described below.

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

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

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

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

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

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
On December 6, 2007, SIGECO closed on $17 million of auction rate tax-exempt long-term debt.  The debt had a life of 33 years, maturing on January 1, 2041.  The initial interest rate was set at 4.50 percent but the rate was to reset every 7 days through an auction process that began December 13, 2007.  This new debt was collateralized through the issuance of first mortgage bonds and the payment of interest and principal was insured through Ambac Assurance Corporation (Ambac).

In February 2008, SIGECO provided notice to the current holders of approximately $103 million of tax-exempt auction rate mode long-term debt, including the $17 million issued in December 2007, 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 backed by Utility Holdings’ $515 million short-term credit facility.  The notes are collateralized by SIGECO’s utility plant, and $9.8 million are due in 2015 and $31.5 million are due in 2025.  The initial interest rate paid to investors was 0.55 percent.  The equivalent rate of the debt at inception, inclusive of interest, weekly remarketing fees, and letter of credit fees, approximated 1 percent.  Since Utility Holdings’ short-term facility has a remaining term of less than one year, these obligations are classified as Long-term debt subject to tender in current liabilities.

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 2009 and 2008, the Company repaid approximately $3.0 million and $1.6 million, respectively, related to death puts.  In 2007, no debt was put to the Company.  Debt which may be put to the Company for reasons other than a death during the years following 2009 (in millions) is $10.0 in 2010, $30.0 in 2011, zero in 2012 and thereafter.

Investing Cash Flow

Cash flow required for investing activities was $431.1 million in 2009, $402.4 million in 2008, and $303.0 million in 2007.  Capital expenditures are the primary component of investing activities and totaled $432.0 million in 2009 compared to $391.0 million in 2008 and $334.5 million in 2007.  The increase in capital expenditures in 2009 compared to 2008 reflects increased expenditures for coal mine development and also was impacted by the January 2009 ice storm that resulted in approximately $20 million in capital expenditures.  The year ended December 31, 2008 includes increased capital expenditures for coal mine development and for environmental compliance equipment, compared to 2007.  Other investments in 2009 and 2008 include minor acquisitions by Miller, among other items.  Investing cash flow in 2007 includes the receipt of $44.9 million in proceeds from the sale of SIGECOM.

Forward-Looking Information

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

· 
Factors affecting utility operations such as unusual weather conditions; catastrophic weather-related damage; unusual maintenance or repairs; unanticipated changes to 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 recent  recession, which may be more prolonged and more severe than cyclical downturns, including significantly lower levels of economic activity; uncertainty regarding energy prices and the capital and commodity markets; decreases in 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.
 
 
·  
Increased 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 coal mining, gas marketing, and energy infrastructure strategies.
·  
Factors affecting coal mining operations including  MSHA guidelines and interpretations of those guidelines; 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 and occasionally offsetting forward purchase contracts.  The Company accounts for any energy contracts that are derivatives at fair value with the offset marked to market through earnings.  No market sensitive derivative positions were outstanding on December 31, 2009 and 2008.

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, 2009 or 2008.

Other Operations

Other commodity-related operations are exposed to commodity price risk associated with fluctuating commodity prices including natural gas and coal.  Other commodity-related operations include nonutility retail gas marketing and coal mining operations.  Open positions in terms of price, volume, and specified delivery points may occur and are managed using methods described below with frequent management reporting.

The Company purchases and sells commodities, including electricity, natural gas, and coal to meet customer demands and operational needs.  The Company executes forward contracts and occasionally option contracts that commit the Company to purchase and sell commodities in the future.  Price risk from forward positions obligating the Company to deliver commodities is mitigated using stored inventory, generating capability, and offsetting forward purchase contracts.  Price risk also results from forward contracts obligating the Company to purchase commodities to fulfill forecasted nonregulated sales of natural gas and coal that may or may not occur.  With the exception of a small portion of contracts that are derivatives and that qualify as hedges of forecasted transactions, these contracts are expected to be settled by physical receipt or delivery of the commodity.

Unconsolidated Affiliate

ProLiance, a nonutility energy marketing affiliate, engages in energy hedging activities to manage pricing decisions, minimize the risk of price volatility, and minimize price risk exposure in the energy markets.  ProLiance's market exposure arises from storage inventory, imbalances, and fixed-price forward purchase and sale contracts, which are entered into to support its operating activities.  Currently, ProLiance buys and sells physical commodities and utilizes financial instruments to hedge its market exposure.  However, net open positions in terms of price, volume and specified delivery point do occur.  ProLiance manages open positions with policies which limit its exposure to market risk and require reporting potential financial exposure to its management and its members.

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 manages this risk by allowing an annual average of 20 percent and 30 percent of its total debt to be exposed to variable rate volatility.  However, this targeted range may be exceeded during the seasonal increases in short-term borrowing.  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 2009 and 2008, the weighted average combined borrowings under these arrangements approximated $211 million and $412 million, respectively.  At December 31, 2009 and 2008, combined borrowings under these arrangements were $255 million and $519 million, respectively.  Based upon average borrowing rates under these facilities during the years ended December 31, 2009 and 2008, an increase of 100 basis points (one percentage point) in the rates would have increased interest expense by $2.1 million and $4.1 million, respectively.

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 establishing 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, 2009.  Management certified this in its Sarbanes Oxley Section 302 certifications, which are attached as exhibits to this 2009 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, 2009 and 2008, 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, 2009. 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, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009, 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, 2009, 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 25, 2010 expressed an unqualified opinion on the Company’s internal control over f