10-K

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, 2011

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)

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.YesýNo□

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 □ Noý

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.  YesýNo□

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 ýNo □

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.  ý

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 filerý                                                                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□Noý

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, 2011, was $2,270,509,262.

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	81,934,781	January 31, 2012
Class	Number of Shares	Date

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Documents Incorporated by Reference

Certain information in the Company's definitive Proxy Statement for the 2012 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission pursuant to Regulation 14A, not later than 120 days after the end of the fiscal year, is incorporated by reference in Part III of this Form 10-K.

Definitions

AFUDC:  allowance for funds used during construction	MCF / BCF:  thousands / billions of cubic feet
ASC:  Accounting Standards Codification	MDth / MMDth: thousands / millions of dekatherms
BTU / MMBTU:  British thermal units / millions of BTU	MISO: Midwest Independent System Operator
DOT:  Department of Transportation	MW:  megawatts
EPA:  Environmental Protection Agency	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	Throughput:  combined gas sales and gas transportation volumes
Kv:  Kilovolt

Access to Information

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

Mailing Address: One Vectren Square Evansville, Indiana  47708 Phone Number: (812) 491-4000 Investor Relations Contact: Robert L. Goocher Treasurer and Vice President, Investor Relations  rgoocher@vectren.com

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Table of Contents

Item				Page
Number				Number
Part I
	1		Business		5
	1A		Risk Factors		14
	1B		Unresolved Staff Comments		20
	2		Properties		20
	3		Legal Proceedings		21
	4		Mine Safety Disclosures		22
Part II
	5		Market for the Company’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities		22
	6		Selected Financial Data		23
	7		Management's Discussion and Analysis of Results of Operations and Financial Condition		24
	7A		Qualitative and Quantitative Disclosures About Market Risk		55
	8		Financial Statements and Supplementary Data		57
	9		Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		108
	9A		Controls and Procedures, including Management’s Assessment of Internal Controls over Financial ReportingControls and Procedures		108
	9B		Other Information		108
Part III
	10		Directors, Executive Officers and Corporate Governance		108
	11		Executive Compensation		109
	12		Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.		109
	13		Certain Relationships, Related Transactions and Director Independence		110
	14		Principal Accountant Fees and Services		110
Part IV
	15	Exhibits and Financial Statement Schedules			110
		Signatures			116

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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 Vectren Energy Delivery of Ohio, Inc. (VEDO).  Utility Holdings also has other assets that provide information technology and other services to the three utilities.  Utility Holdings’ consolidated operations are collectively referred to as the Utility Group.  Both Vectren and Utility Holdings are holding companies as defined by the Energy Policy Act of 2005 (Energy Act).  Vectren was incorporated under the laws of Indiana on June 10, 1999.

Indiana Gas provides energy delivery services to approximately 563,000 natural gas customers located in central and southern Indiana.  SIGECO provides energy delivery services to approximately 141,000 electric customers and approximately 110,000 gas customers located near Evansville in southwestern Indiana.  SIGECO also owns and operates electric generation assets to serve its electric customers and optimizes those assets in the wholesale power market.  Indiana Gas and SIGECO generally do business as Vectren Energy Delivery of Indiana.  VEDO provides energy delivery services to over 310,000 natural gas customers located near Dayton in west central Ohio.

The Company, through Vectren Enterprises, Inc. (Enterprises), is involved in nonutility activities in four primary business areas:  Infrastructure Services, Energy Services, Coal Mining, and Energy Marketing.  Infrastructure Services provides underground construction and repair services.  Energy Services provides performance contracting and renewable energy services.  Coal Mining mines and sells coal.  Energy Marketing markets and supplies natural gas and provides energy management services.  Enterprises also has other legacy businesses that have invested in energy-related opportunities and services, real estate, and leveraged leases, among other investments.  All of the above are collectively referred to as the Nonutility Group.  Enterprises supports the 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, 2011, the Company had $4.9 billion in total assets, with $4.0 billion (82 percent) attributed to the Utility Group, $0.9 billion (18 percent) attributed to the Nonutility Group.  Net income for the year ended December 31, 2011, was $141.6 million, or $1.73 per share of common stock, with net income of $122.9 million attributed to the Utility Group, $23.8 million attributed to the Nonutility Group, and a loss of $5.1 million attributed to Corporate & Other.  Net income for the year ended December 31, 2010, was $133.7 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 22 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.

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Utility Group

The Utility Group consists of the Company’s regulated operations and other operations that provide information technology and other support services to those regulated operations.  The Company segregates its regulated operations into a Gas Utility Services operating segment and an Electric Utility Services operating segment.  The Gas Utility Services segment includes the operations of Indiana Gas, VEDO, and SIGECO’s natural gas distribution business and provides natural gas distribution and transportation services to nearly two-thirds of Indiana and to west central Ohio.  The Electric Utility Services segment includes the operations of SIGECO’s electric transmission and distribution services, which provides electric distribution services primarily to southwestern Indiana, and the Company’s power generating and wholesale power operations.  In total, these regulated operations supply natural gas and/or electricity to over one million customers.  Following is a more detailed description of the Utility Group’s Gas Utility and Electric Utility operating segments.

Gas Utility Services

At December 31, 2011, the Company supplied natural gas service to approximately 993,300 Indiana and Ohio customers, including 908,100 residential, 83,600 commercial, and 1,600 industrial and other contract customers.  Average gas utility customers served were approximately 983,700 in 2011, 982,100 in 2010, and 981,300 in 2009.

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

Revenues

The Company receives gas revenues by selling gas directly to customers at approved rates or by transporting gas through its pipelines at approved rates to customers that have purchased gas directly from other producers, brokers, or marketers.  Total throughput was 196.9 MMDth for the year ended December 31, 2011.  Gas sold and transported to residential and commercial customers was 99.9 MMDth representing 51 percent of throughput.  Gas transported or sold to industrial and other contract customers was 97.0 MMDth representing 49 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, 2011, gas utility revenues were approximately $819.1 million, of which residential customers accounted for 67 percent and commercial 24 percent. Industrial and other contract customers account for only 9 percent of revenues due to the high number of transportation customers in that customer class.

Availability of Natural Gas

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

Natural Gas Purchasing Activity in Indiana

The Indiana utilities also contract with a wholly-owned subsidiary of ProLiance Holdings, LLC (ProLiance), to ensure availability of gas.  ProLiance is an unconsolidated, nonutility, energy marketing affiliate of Vectren and Citizens Energy Group (Citizens).  (See the discussion of Energy Marketing below and Note 7 in the Company’s Consolidated Financial Statements included in “Item 8 Financial Statements and Supplementary Data” regarding transactions with ProLiance).  The Company also prepays ProLiance for natural gas delivery services during the seven months prior to the peak heating season in lieu of maintaining gas storage.  Vectren received regulatory approval on April 25, 2006, from the IURC for ProLiance to continue to provide natural gas supply services to the Company’s Indiana utilities through March 2011.  On March 17, 2011, an order was received from the IURC providing for ProLiance’s continued provision of gas supply services to the Company’s Indiana utilities and Citizens Gas through March 2016. 

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Natural Gas Purchasing Activity in Ohio

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

On August 20, 2008, the PUCO approved the results of an auction selecting qualified wholesale suppliers to provide the gas commodity to the Company for resale to its customers at auction-determined standard pricing.  This standard pricing was comprised of the monthly NYMEX settlement price plus a fixed adder.  This standard pricing, which was effective from October 1, 2008 through March 31, 2010, was the initial step in exiting the merchant function in the Company’s Ohio service territory.  During the initial phase, wholesale suppliers that were winning bidders in a PUCO approved auction provided the gas commodity to VEDO for resale to its residential and general service customers at auction-determined standard pricing.  This standard pricing was comprised of the monthly NYMEX settlement price plus a fixed adder.  On October 1, 2008, the Company transferred its natural gas inventory at book value to the winning bidders, receiving proceeds of approximately $107 million, and began purchasing natural gas from those suppliers (one of which was Vectren Source, see the discussion of Vectren Source in Note 6 of the Company’s Consolidated Financial Statements included in “Item 8 Financial Statements and Supplementary Data”).  This method of purchasing gas eliminated the need for monthly gas cost recovery (GCR) filings and prospective PUCO GCR audits. 

The second phase of the exit process began on April 1, 2010.  During this phase, the Company no longer sells natural gas directly to customers.  Rather, state-certified Competitive Retail Natural Gas Suppliers, that were successful bidders in a similar regulatory-approved auction, sell the gas commodity to specific customers for a 12-month period at auction-determined standard pricing.  The first auction was conducted on January 12, 2010, and the auction results were approved by the PUCO on January 13, 2010.  The plan approved by the PUCO required that the Company conduct at least two annual auctions during this phase.  As such, the Company conducted another auction on January 18, 2011 in advance of the second 12-month term which commenced on April 1, 2011.  The results of that auction were approved by the PUCO on January 19, 2011.Vectren Source was also a successful bidder in both auctions winning one tranche of customers in the first auction and two tranches of customers in the second auction.  Each tranche of customers equates to approximately 28,000 customers.  As per the terms of the plan approved by the PUCO, because no application for a full exit of the merchant function was neither sought nor approved by April 1, 2011, VEDO conducted a third retail auction on January 31, 2012 to address the 12-month term beginning April 1, 2012.  The results of that auction were approved by the PUCO on February 1, 2012.  Consistent with current practice, customers continue to receive a single bill for the commodity as well as the delivery component of natural gas service from VEDO.

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

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

Total Natural Gas Purchased Volumes

In 2011, Utility Holdings purchased 71.2 MMDth volumes of gas at an average cost of $5.30 per Dth, of which approximately 97 percent was purchased from ProLiance, 1 percent was purchased from Vectren Source, and 2 percent was purchased from third party providers.  The average cost of gas per Dth purchased for the previous four years was $5.99 in 2010, $5.97 in 2009, $9.61 in 2008, and $8.14 in 2007.

Electric Utility Services

At December 31, 2011, the Company supplied electric service to approximately 141,600 Indiana customers, including approximately 123,200 residential, 18,300 commercial, and 100 industrial and other customers.  Average electric utility customers served were approximately 141,400 in 2011, 141,300 in 2010, and 140,900 in 2009.

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

Revenues

For the year ended December 31, 2011, retail electricity sales totaled 5,594.8 GWh, resulting in revenues of approximately $593.4 million.  Residential customers accounted for 36 percent of 2011 revenues; commercial 27 percent; industrial 36 percent; and other 1 percent.  In addition, in 2011 the Company sold 586.7 GWh through wholesale activities principally to the MISO.  Wholesale revenues, including transmission-related revenue, totaled $42.5 million in 2011.

System Load

Total load for each of the years 2007 through 2011 at the time of the system summer peak, and the related reserve margin, is presented below in MW.

Date of summer peak load	7/21/2011			8/4/2010			6/22/2009			7/21/2008			8/8/2007
Total load at peak (1)		1,220			1,275			1,143			1,167			1,341
Generating capability		1,298			1,298			1,295			1,295			1,295
Firm purchase supply		136			136			136			135			130
Interruptible contracts & direct load control		60			62			62			62			62
Total power supply capacity		1,494			1,496			1,493			1,492			1,487
Reserve margin at peak		22	%		17	%		31	%		28	%		11	%

(1)   The total load at peak is increased 25 MW in 2007 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 that year.  During the time of peak in 2008-2011 the Summer Cycler program was not activated.

The winter peak load for the 2010-2011 season of approximately 943 MW occurred on December 14, 2010.  The prior winter peak load for the 2009-2010 season was approximately 916 MW, occurring on January 8, 2010.

Generating Capability

Installed generating capacity as of December 31, 2011, 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 2011 was fueled by coal (97 percent) and natural gas (3 percent).  Oil was used only for testing of gas/oil-fired peaking units.  The Company generated approximately 4,631 GWh in 2011.  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 2.3 million tons were purchased for generating electricity during 2011, of which approximately 90 percent was supplied by Vectren Fuels from its mines.  This compares to 2.2 million tons and 2.8 million tons purchased in 2010 and 2009, respectively.  The utility’s coal inventory was approximately 1 million tons at December 31, 2011 and 2010.

Coal Purchases

The average cost of coal per ton purchased for the last five years was $75.04 in 2011, $70.47 in 2010, $64.28 in 2009, $42.76 in 2008, and $40.86 in 2007.  Effective January 1, 2009, SIGECO began purchasing coal from Vectren Fuels under new coal purchase agreements.  The term of these coal purchase agreements continues to December 31, 2015, with prices specified originally ranging from two to four years.  The prices in these contracts were at or below market prices for Illinois Basin coal at the time of execution and were subject to a bidding process with third parties.  The IURC has found that costs incurred under these contracts are reasonable.  For contracts with price reopeners, amendments were finalized in 2011 for coal deliveries beginning in 2012 at lower prices.

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The Company received an order on January 25, 2012 to allow for the lower prices that are set to begin late in 2012 and beyond to be reflected in customer bills beginning in early 2012.  Because the cost of coal expensed in 2012 will be lower than amounts paid under existing contracts and included in the carrying amount of inventory at December 31, 2011, the IURC authorized deferral of the difference between costs paid under these contracts and that charged to customers for future recovery over a six year period beginning in 2014.  See Rate and Regulatory Matters in Item 7 regarding coal procurement procedures and electric fuel cost reductions.

Firm Purchase Supply

The Company has a 1.5 percent interest in the Ohio Valley Electric Corporation (OVEC).  OVEC is owned by 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 197 GWh from OVEC in 2011.

The Company executed a capacity contract with Benton County Wind Farm, LLC in April 2008 to purchase as much as 30 MW from a wind farm located in Benton County, Indiana, with the approval of the IURC.  The contract expires in 2029.  In 2011, the Company purchased approximately 80 GWh under this contract.

In­­­­ December 2009, the Company executed a 20 year power purchase agreement with Fowler Ridge II Wind Farm, LLC to purchase as much as 50 MW of energy from a wind farm located in Benton and Tippecanoe Counties in Indiana, with the approval of the IURC.  The Company purchased 129 GWh under this contract in 2011.

The Company had a capacity contract with Duke Energy Marketing America, LLC to purchase as much as 100 MW at any time from a power plant located in Vermillion County, Indiana.  The contract expired on December 31, 2009 and was not renewed.

Other Power Purchases

The Company occasionally enters into short-term purchased power agreements with various suppliers.  During 2011, total purchases under these contracts totaled 67 GWh.  In addition, the Company also purchases power from the MISO to supplement its generation and firm purchase supply.  Volumes purchased from the MISO in 2011 totaled 1,230 GWh.

MISO Capacity Purchase

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

Interconnections

The Company has interconnections with Louisville Gas and Electric Company, Duke Energy Shared Services, Inc., Indianapolis Power & Light Company, Hoosier Energy Rural Electric Cooperative, Inc., Big Rivers Electric Corporation, and the City of Jasper, Indiana, providing the ability to simultaneously interchange approximately 655 MW.  This interchange capability has been impacted in recent years as a result of ongoing initiatives to improve the transmission grid throughout the Midwest.  As an example, once completed, a 345 kV Vectren transmission project that is currently in process will result in the ability to simultaneously interchange an additional 100 MW.  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.

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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, 2011, approximately 129,000 customers in Vectren’s Ohio service territory have opted to purchase natural gas from a supplier other than VEDO.  In addition, VEDO’s service territory continues transition toward a choice model for all gas customers.  Margin earned for transporting natural gas to those customers, who have purchased natural gas from another supplier, are generally the same as those earned by selling gas under Ohio tariffs.  Indiana has not adopted any regulation requiring gas choice; however, the Company operates under approved tariffs permitting certain industrial and commercial large volume customers to choose their commodity supplier.

Regulatory and Environmental Matters

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

Nonutility Group

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

Infrastructure Services

Infrastructure Services provides underground construction and repair to utility infrastructure through its wholly owned subsidiaries Miller Pipeline, LLC (Miller) and Minnesota Limited, Inc. (Minnesota Limited).  The Company, through its wholly owned subsidiary Vectren Infrastructure Services Company, Inc., purchased Minnesota Limited on March 31, 2011 (see Note 5 in the Company’s Consolidated Financial Statements included under “Item 8 Financial Statements and Supplementary Data”).  Infrastructure Services provides services to many utilities, including the Company’s utilities.  Infrastructure Services generated approximately $421 million in gross revenues for 2011, compared to $236 million in 2010 and $202 million in 2009.  Man hours worked within Infrastructure Services were 3.9 million in 2011, compared to 2.6 million in 2010 and 2.5 million in 2009.  Of these 2011 revenues and man hours, $117 million in revenues and 0.7 million in man hours, respectively, related to Minnesota Limited’s operations.

Energy Services

Performance-based energy contracting operations and renewable energy services are performed through Energy Systems Group, LLC (ESG).  ESG assists schools, hospitals, governmental facilities, and other private institutions to reduce energy and maintenance costs by upgrading their facilities with energy-efficient equipment.  ESG is also involved in creating renewable energy projects, including projects to process landfill gas into usable natural gas and electricity.  During 2009, SIGECO purchased one such project with IURC approval.  ESG’s customer base is located throughout the Midwest, Mid-Atlantic, Southern and Southwestern United States.  ESG generated revenues of approximately $162 million in 2011, compared to $147 million in 2010 and $121 million in 2009.  ESG’s backlog at December 31, 2011 was $82 million, compared to $118 million at December 31, 2010.

Coal Mining

The Coal Mining group mines and sells coal to the Company’s utility operations and to other third parties through its wholly owned subsidiary, Vectren Fuels.  The Company owns three underground mines (Prosperity, Oaktown 1, and Oaktown 2) and one surface mine (Cypress Creek).  All mines are located in Indiana.  All coal is high-to-mid sulfur bituminous coal from the Illinois Basin.  The Company engages contract mining companies to perform substantially all mining operations.  Coal mining generated approximately $286 million in revenues in 2011, compared to $210 million in 2010 and $193 million in 2009.

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Oaktown Mine Expansion

In April 2006, Vectren Fuels announced plans to open two new underground mines.  The first of two underground mines located near Vincennes, Indiana, began full operations in 2010.  The second mine is currently expected to open in the third quarter of 2012.  However, Vectren Fuels may continue to change this time table as it evaluates the impacts of market conditions.  Reserves at the two mines are estimated at about 102 million tons of recoverable number-five coal at 11,200 BTU and less than 6-pound sulfur dioxide.  Once in full production, the two mines are capable of producing about 5 million tons of coal per year.  The Company estimates approximately $10 million of additional capital is required to complete the second mine. 

The Oaktown mine infrastructure is located on 1,100 acres near Oaktown in Knox County, Indiana.  Oaktown’s location is within 50 miles of multiple coal-fired power plants including a coal gasification plant currently under construction.  It is estimated approximately 25,000 acres of coal will be mined during the life of both mines.  Through December 31, 2011, approximately 900 acres of coal have been mined with approximately 24,100 acres remaining.  Access to the Oaktown 1 mine was accomplished via a 90 foot deep box cut and a 2,200 foot slope on a 14 percent grade, reaching coal in excess of 375 feet below the surface.  Access to the Oaktown 2 mine is planned via an 80 foot deep box cut and a 2,600 foot slope on a 14 percent grade, reaching coal in excess of 400 feet below the surface.

Both Oaktown mines are room and pillar underground mines meaning that main airways and transportation entries are developed and maintained while remote-controlled continuous miners extract coal from so-called rooms by removing coal from the seam, leaving pillars to support the roof.  Shuttle cars or similar transportation is used to transport coal to a conveyor belt for transport to the surface.  The two Oaktown mines are separated by a sandstone channel.  The coal seam thickness ranges from 4 feet to over 9 feet.  The mine’s wash plant was originally sized to process 800 tons per hour and has been expanded to 1,600 tons per hour, although the addition to the wash plant will not be utilized until the Oaktown 2 mine is opened.  The two mines are connected to a railway equipped to handle 110 to 120 car unit trains.  Coal is also transported via truck to its customers, which include the Company’s power supply operations and other third party utilities.  The total plant and development costs to date for the Oaktown mining complex are $224 million, inclusive of advance royalty payments.  The remaining unamortized plant balance as of December 31, 2011 approximates $196 million, inclusive of $45 million in land and buildings, $147 million in mine development and equipment, and $4 million in advance royalty payments.  Reserves, absent expansion, are expected to be completely exhausted over the next 20 years.

Prosperity Mine

Prosperity is an underground mine located on 1,100 surface acres outside of Petersburg in Pike County, Indiana.  Prosperity is also a room and pillar mine where coal removal is accomplished with continuous mining machines.  The mine entrance slopes gradually for 500 ft on a 9 degree grade and is more than 250 feet below ground level.  The coal seam varies in thickness from 4-1/2 to 8 feet.  The mine has a wash plant sized to process 1,000 tons per hour.  The mine is connected to a railway and can handle 110 to 120 car unit trains.  Coal is also transported via truck to its customers, which include Vectren’s power supply operations and other third party utilities.  The mine opened in 2001, and the total plant and development costs to date are $193 million.  Through December 31, 2011, approximately 7,000 acres of coal have been mined with approximately 13,000 acres remaining. Reserves at December 31, 2011 approximate 30 million tons, not including possible nearby expansion opportunities.  The remaining unamortized plant balance as of December 31, 2011 approximates $81 million, inclusive of $3 million of land and buildings and $78 million of mine development and equipment.  Reserves, absent expansion, are expected to be exhausted by 2021.

Cypress Creek

Cypress Creek was an above-ground, or surface mine, located on 155 acres about 4 miles north of Boonville in Warrick County, Indiana.  Cypress Creek was a combination truck/shovel, dozer push and high wall mining operation, meaning large shovels or front-end loaders removed earth and rock covering a coal seam and loading equipment placed the coal into trucks for transportation to a blending and loading area.  Due to the cost of extensive digging, the coal mining limit was 125 to 135 feet deep.  All coal mined from Cypress Creek was transported via truck to Vectren’s power supply operations.  The mine opened in 1998 and as of December 31, 2011, no significant reserves remain, the mine is substantially reclaimed, and the remaining carrying amount is not significant.

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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)
2011		-		2,457		2,668		-		5,125
2010		91		2,685		995		-		3,771
2009		969		2,583		-		-		3,552
County Located in Indiana	Warrick		Pike		Knox		Knox
Coal Reserves (thousands of tons)		-		30,400		62,900		38,800		132,100
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

Mine Safety Information

The Company, through its wholly owned subsidiary Vectren Fuels, Inc., owns coal mines and related assets located in Indiana.  The Company has retained independent third party contract mining companies to operate its coal mines.  Five Star Mining LLC ("Five Star") is the contract mining company at the Prosperity underground mine and Black Panther Mining LLC ("Black Panther") is the contract mining company at the Oaktown underground mines.  While in operation, Vigo-Cypress Creek, LLC was the contract mining company at Cypress Creek surface mine. The contract mining companies are the mine “operator”, as that term is used in both the Federal Mine Safety and Health Act of 1977 (the “Mine Act”) and the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010.  All employees at the coal mines are hired, supervised, and paid by the contract mining companies.  As the mine operator, the contract mining companies make all regulatory filings required by the MSHA.  In most circumstances, however, the cost of fines and penalties assessed by MSHA are contractually passed through from the contract mining company to Vectren Fuels.  The process of settling such claims can take years in certain circumstances.  During the year ended December 31, 2011, the Company paid approximately $0.7 million related to assessments issued to the mine operators.

More detailed information about the Company’s mines, including safety-related data, can be found at MSHA’s website, www.MSHA.gov.  Prosperity operates under the MSHA identification number 1202249; Oaktown 1 operates under the identification number 1202394; Oaktown 2’s identification number is 1202418; and Cypress Creek’s identification number is 1202178.  Mine safety-related data included on the MSHA website is influenced by the size of the mine, the level of activity at the mine, and the mine inspector’s judgment, among other factors. These factors can impact the comparability of information from mine to mine and time period to time period.  Given the recent incidents at coal mines of other companies, a significant increase in the frequency and scope of MSHA inspections continues.  In addition, both houses of Congress are considering new mine safety legislation.  The Company is currently assessing the impact new laws and regulations may have on its investments.

Energy Marketing

ProLiance

ProLiance, a nonutilityenergy 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 former nonutility retail gas marketing operations, contracted for approximately 69 percent of its natural gas purchases through ProLiance in 2011.

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For the year ended December 31, 2011, ProLiance’s revenues, including sales to Vectren companies, were $1.4 billion, compared to $1.5 billion in 2010 and $1.7 billion in 2009.  Summarized financial data regarding ProLiance’s operations are included in Note 7 to the Consolidated Financial Statements included in Item 8.  At December 31, 2011, the ProLiance customer base was 1,950 customers, compared to 1,789 customers in 2010 and 1,578 customers in 2009.

Vectren Source

Vectren Source, a former wholly owned subsidiary, provided natural gas and other related products and services in the Midwest and Northeast United States to approximately 283,000 residential and commercial customers, as of December 31, 2011.  This customer base reflected approximately 143,000 customers in VEDO’s service territory that have either voluntarily opted to choose their natural gas supplier or are supplied natural gas by Vectren Source but remain customers of the regulated utility as part of VEDO’s exit the merchant function process.  Gas sold by Vectren Source approximated 25.3 MMDth in 2011; 21.0 MMDth in 2010; and 18.5 MMDth in 2009.  Average customers served by Vectren Source were 254,000 in 2011; 203,000 in 2010; and 179,000 in 2009.  Vectren Source generated approximately $150 million in revenues for 2011 compared to $143 million in 2009 and $157 million in 2009.  On December 31, 2011, the Company sold Vectren Source for $84.3 million, including, and subject to a final determination of, working capital.

Other Businesses

The Other Businesses group includes a variety of legacy, wholly owned operations and investments that have invested in energy-related opportunities and services, real estate, and leveraged leases, among other investments.  Investments at December 31, 2011, include two Haddington Energy Partnerships both approximately 40 percent owned; and wholly owned subsidiaries, Southern Indiana Properties, Inc. and Energy Realty, Inc.

Synthetic Fuel

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

Personnel

As of December 31, 2011, the Company and its consolidated subsidiaries had approximately 4,500 employees.  Of those employees, 700 are subject to collective bargaining arrangements negotiated by Utility Holdings and 2,200 are subject to collective bargaining arrangements negotiated by Infrastructure Services.

Utility Holdings

In December 2011, the Company reached a three year labor agreement, ending December 1, 2014, with Local 1393 of the International Brotherhood of Electrical Workers and United Steelworkers of America Locals 12213 and 7441.

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

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

In September 2009, the Company reached a three year agreement with Local 135 of the Teamsters, Chauffeurs, Warehousemen, and Helpers Union, ending September 23, 2012.

Infrastructure Services

The Company, through its Infrastructure Services subsidiaries, negotiates various trade agreements through contractor associations.  The two primary associations are the Distribution Contractors Association (DCA) and the Pipeline Contractors Association (PLCA).  These trade agreements are with a variety of construction unions including Laborer’s International Union of North America, International Union of Operating Engineers, United Association of Journeymen and Apprentices of the Plumbing and Pipe Fitting Industry, and Teamsters.  The trade agreements through the DCA have varying expiration dates ranging from 2012 through 2015.  The trade agreements through the PLCA recently expired, and most agreements have been renegotiated into 2014.  Negotiations continue with the Teamsters, and the parties continue to work under expired agreements with a current extension through April 13, 2012.  A primary issue in these negotiations is certain member companies of the PLCA, including the Company's infrastructure subsidiaries, withdrawing from the Teamsters multiemployer defined benefit pension plan.  In addition, these subsidiaries have various project agreements and small local agreements.  These agreements expire upon completion of a specific project or on various dates throughout the year.

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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.

Corporate Risks

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.

Deterioration in general economic conditions may have adverse impacts.

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

Financial market volatility could have adverse impacts.

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

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

The following table shows the current ratings assigned to certain outstanding debt by Moody’s and Standard & Poor’s:

	Current Rating
		Standard
	Moody’s	& Poor’s
Utility Holdings and Indiana Gas senior unsecured debt	A3	A-
Utility Holdings commercial paper program	P-2	A-2
SIGECO’s senior secured debt	A1	A

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

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

Utility Operating Risks

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

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

Vectren’s regulated utilities operate in an increasingly competitive industry, which may affect its future earnings.

The utility industry has been undergoing structural change for several years, resulting in increasing competitive pressure faced by electric and gas utility companies.  Increased competition may create greater risks to the stability of Vectren’s earnings generally and may in the future reduce its earnings from retail electric and gas sales.  Currently, several states, including Ohio, have passed legislation that allows customers to choose their electricity supplier in a competitive market.  Indiana has not enacted such legislation.  Ohio regulation also provides for choice of commodity providers for all gas customers.  In 2003, the Company implemented this choice for its gas customers in Ohio and is currently in the second of the three phase process to exit the merchant function in 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 in a January 2009 PUCO order mitigates most weather risk related to Ohio residential gas sales.

Vectren’s utilities are exposed to increasing regulation, including environmental and pipeline safety regulation.

Vectren’s utilities are subject to regulation by federal, state, and local regulatory authorities and are exposed to public policy decisions that may negatively impact the Company’s earnings.  In particular, Vectren is subject to regulation by the FERC, the NERC, the EPA, the IURC, the PUCO, and the DOT.  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.

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Vectren’s utility operations and properties are subject to extensive environmental regulation pursuant to a variety of federal, state and municipal laws and regulations.  These environmental regulations impose, among other things, restrictions, liabilities, and obligations in connection with storage, transportation, treatment, and disposal of hazardous substances and waste in connection with spills, releases, and emissions of various substances in the environment.  Such airborne emissions from electric generating facilities include particulate matter, sulfur dioxide (SO2), nitrogen oxide (NOx), and mercury, among others.  Environmental legislation/regulation also requires that facilities, sites, and other properties associated with Vectren’s operations be operated, maintained, abandoned, and reclaimed to the satisfaction of applicable regulatory authorities.  The Company’s current costs to comply with these laws and regulations are significant to its results of operations and financial condition.  In addition, claims against the Company under environmental laws and regulations and other laws and regulations could result in material costs and liabilities.

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

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 regulation, its investment in compliant infrastructure, and the associated operating costs have increased and are expected to increase in the future.  As examples of the trend toward stricter regulation, the EPA is currently reviewing/revising regulations involving fly ash disposal, cooling tower intake facilities, greenhouse gases, and airborne emissions such as SO2, NOx, and mercury.  In addition, the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011was signed into law on January 3, 2012 and may result in increased operating expenses and capital expenditures for the Company.

Increasing regulation could affect Vectren’s utility rates charged to customers, its costs, and its profitability.

Any additional expenses or capital incurred by Vectren’s utilities, as it relates to complying with increasing regulation 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’s utilities’ ability to obtain rate increases and to maintain 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 currently authorized rates of return.  Both Indiana and Ohio have passed laws allowing utilities to recover at least some of the cost of complying with federal mandates outside of a base rate proceeding.

Vectren regulated energy delivery operations are subject to various risks.

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

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Vectren’sregulated power supply 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 Company participates in the MISO.

The Company is a member of the MISO, which 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 such control, SIGECO’s continued ability to import power, when necessary, and export power to the wholesale market has been, and may continue to be, impacted. 

The need to expend capital for improvements to the regional transmission system, both to SIGECO’s facilities as well as to those facilities of adjacent utilities, over the next several years is expected to be significant.  The Company timely recovers its investment in certain new electric transmission projects that benefit the MISO infrastructure at a FERC approved rate of return.

Also, the MISO allocates operating costs and the cost of multi value projects throughout the region to its participating utilities such as SIGECO and such costs are significant.  Adjustments to these operating costs, including adjustments that result from participants entering or leaving the MISO, could cause increases or decreases to customer bills.  The Company timely recovers its portion of MISO operating expenses as tracked costs.

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 $7.5 million is shared evenly with customers.  These earnings from wholesale marketing activities may vary based on fluctuating prices for electricity and the amount of electric generating capacity or purchased power available beyond that needed to meet firm service requirements.  In addition, this earnings sharing approach may be modified in future regulatory proceedings.

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

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

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Nonutility Operating Risks

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

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

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

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

The success of coal mining operations is predicated on the ability to fully access coal at company-owned mines; for the contract operator to operate owned mines in accordance with MSHA guidelines and regulations, recent interpretations of those guidelines and regulations, and any new guidelines or regulations that could result from the recent mining incidents at coal mines of other companies and to respond to more frequent and broader inspections; to negotiate and execute new sales contracts; to adapt to any new laws or rules, such as climate change or air quality legislation, that impact users of coal; 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 including impacts of fuel switching to alternative sources; 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.  Coal sales and production could be impacted by significant variations in weather and have a material impact on the Company’s earnings.

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

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

ProLiance relies on long-term firm transportation and storage contracts with pipeline companies to deliver natural gas to its customer base.  Those contracts are optimized by balancing physical and financial markets and summer and winter time horizons.  Therefore, recovery of the these contracts’ fixed costs is dependent on a number of factors, including the health of the economy, weather, changes in the availability and location of natural gas supply and related transmission assets, the price of natural gas, and the availability of credit.  Optimization opportunities at current market prices or a deterioration of the customer base may result in the inability to fully recover these fixed price obligations.

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

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

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

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

Other Corporate Operating Risks

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.

Increased derivative regulation could impact results.

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

New regulations related to the use of derivatives became law in 2010.  These regulations include a requirement that certain transactions be cleared on exchanges and a requirement to post cash collateral for certain transactions.  Depending on the regulations adopted by the Commodities Futures Trading Commission (CFTC) and other agencies, the Company and ProLiance could be required to post additional collateral with dealer counterparties for commitments and interest rate derivative transactions. Requirements to post collateral could limit cash for investment and for other corporate purposes or could increase debt levels. In addition, a requirement for counterparties to post collateral could result in additional costs associated with executing transactions, thereby decreasing profitability.  An increased collateral requirement could also reduce the Company’s and ProLiance’s ability to execute derivative transactions to reduce commodity price and interest rate uncertainty and to protect cash flows.  The new regulations may also limit the pool of potential counterparties.

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

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

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

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

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

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

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

Catastrophic events, such as cyber-attacks, terrorist attacks, acts of war, and acts of God, may adversely affect Vectren’s facilities and operations.

Catastrophic events such as fires, earthquakes, explosions, floods, ice storms, tornados, terrorist acts, cyber-attacks, or similar occurrences could adversely affect Vectren’s facilities, operations, financial condition and results of operations.  Either a direct act against company-owned generating facilities or transmission and distribution infrastructure or an act against the infrastructure of neighboring utilities or interstate pipelines that are used by the Company to transport power and natural gas could result in the Company being unable to deliver natural gas or electricity for a prolonged period.  Further, Vectren relies on information technology networks and systems to operate its generating facilities, engage in asset management activities, and process, transmit and store electronic information. Security breaches of this information technology infrastructure, including cyber-attacks and cyber-terrorism, could lead to system disruptions, generating facility shutdowns or unauthorized disclosure of confidential information. In the event of a severe disruption resulting from such events, Vectren has contingency plans and employs crisis management to respond and recover operations. Despite these measures, if such an attack or security breach were to occur, results of operations and financial condition could be materially adversely affected.

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 5.6 BCF of gas with maximum peak day delivery capabilities of 143,500 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 16.5 BCF of interstate natural gas pipeline storage service with a maximum peak day delivery capability of 245,867 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.

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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 108,000 MCF per day.  In addition to its company owned storage delivery capabilities, SIGECO has contracted with ProLiance for 0.4 BCF of interstate pipeline storage service with a maximum peak day delivery capability of 16,812 MMBTU per day.  SIGECO's gas delivery system includes 3,200 miles of distribution and transmission mains, all of which are located in Indiana.

VEDO owns 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, VEDO has contracted for 11.8 BCF of natural gas delivery service with a maximum peak day delivery capability of 246,080 MMBTU per day.  While the Company still has title to this delivery capability, it has released it to those retail gas marketers now supplying VEDO’s customers with natural gas, and those suppliers are responsible for the demand charges.  VEDO’s 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, 2011, 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 withtwo units of 360 MW of combined capacity, and Warrick Unit 4 with 150 MW of capacity.  Both the Culley and Warrick Stations are located in Warrick County near Yankeetown, Indiana.  SIGECO's gas-fired turbine peaking units are:  two 80 MW gas turbines (Brown Unit 3 and Brown Unit 4) located at the Brown Station; two Broadway Avenue Gas Turbines located in Evansville, Indiana with a combined capacity of 115 MW (Broadway Avenue Unit 1, 50 MW and Broadway Avenue Unit 2, 65 MW); and two Northeast Gas Turbines located northeast of Evansville in Vanderburgh County, Indiana with a combined capacity of 20 MW.  The Brown Unit 3 and Broadway Avenue Unit 2 turbines are also equipped to burn oil.  Total capacity of SIGECO's six gas turbines is 295 MW, and they are generally used only for reserve, peaking, or emergency purposes due to the higher per unit cost of generation.  In 2009, SIGECO, with IURC approval, purchased a landfill gas electric generation project in Pike County, Indiana with a total capability of 3 MW.

SIGECO's transmission system consists of 989 circuit miles of 345Kv, 138Kv and 69Kv lines.  The transmission system also includes 35 substations with an installed capacity of 4,863 megavolt amperes (Mva).  The electric distribution system includes 4,281 pole miles of lower voltage overhead lines and 372 trench miles of conduit containing 1,999 miles of underground distribution cable.  The distribution system also includes 96 distribution substations with an installed capacity of 2,929 Mva and 54,000 distribution transformers with an installed capacity of 2,349 Mva.

SIGECO owns utility property outside of Indiana approximating nine miles of 138,000 volt electric transmission line, which is included in the 989 circuit miles discussed above, 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 financial statements are included in “Item 8 Financial Statements and Supplementary Data.”

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ITEM 4.  MINE SAFETY DISCLOSURES

Not Applicable.

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 2011 and 2010, 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
2011
	First Quarter	$      0.345	$      27.31	$      25.33
	Second Quarter	0.345	28.84	26.66
	Third Quarter	0.345	28.73	23.65
	Fourth Quarter	0.350	30.65	25.49
2010
	First Quarter	$      0.340	$      25.07	$      22.14
	Second Quarter	0.340	25.60	21.66
	Third Quarter	0.340	26.05	22.97
	Fourth Quarter	0.345	27.85	24.18

On January 31, 2012 the board of directors declared a dividend of $0.350 per share, payable on March 1, 2012, to common shareholders of record on February 15, 2012.

As of January 31, 2012, there were 9,091 registered shareholders 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.  The following chart contains information regarding open market purchases made by the Company to satisfy share-based compensation requirements during the quarter ended December 31, 2011.

Period	Number of Shares Purchased	Average Price Paid Per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans	Maximum Number of Shares That May Be Purchased Under These Plans
October 1-31	-	$	-	-	-
November 1-30	221,368		29.22	-	-
December 1-31	20,500		28.67	-	-

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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 52 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.

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)	2011		2010		2009		2008		2007
Operating Data:
Operating revenues	$	2,325.2	$	2,129.5	$	2,088.9	$	2,484.7	$	2,281.9
Operating income	$	370.0	$	316.8	$	280.1	$	263.4	$	260.5
Net income	$	141.6	$	133.7	$	133.1	$	129.0	$	143.1
Average common shares outstanding		81.8		81.2		80.7		78.3		75.9
Fully diluted common shares outstanding		81.8		81.3		81.0		78.7		76.4
Basic earnings per share
on common stock	$	1.73	$	1.65	$	1.65	$	1.65	$	1.89
Diluted earnings per share
on common stock	$	1.73	$	1.64	$	1.64	$	1.63	$	1.87
Dividends per share on common stock	$	1.385	$	1.365	$	1.345	$	1.310	$	1.270
Balance Sheet Data:
Total assets	$	4,878.9	$	4,764.2	$	4,671.8	$	4,632.9	$	4,296.4
Long-term debt, net	$	1,559.6	$	1,435.2	$	1,540.5	$	1,247.9	$	1,245.4
Common shareholders' equity	$	1,465.5	$	1,438.9	$	1,397.2	$	1,351.6	$	1,233.7

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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.

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

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

Net income and earnings per share, in total and by group, for the years ended December 31, 2011, 2010, and 2009 follow:

	Year Ended December 31,
(In millions, except per share data)	2011			2010		2009
Net income	$	141.6		$	133.7	$	133.1
Attributed to:
Utility Group	$	122.9		$	123.9	$	107.4
Nonutility Group		23.8			9.8		25.8
Corporate & Other		(5.1	)		-		(0.1	)
Basic earnings per share	$	1.73		$	1.65	$	1.65
Attributed to:
Utility Group	$	1.50		$	1.53	$	1.33
Nonutility Group		0.29			0.12		0.32
Corporate & Other		(0.06	)		-		-

Results

For the year ended December 31, 2011, consolidated net income was $141.6 million, or $1.73 per share, compared to earnings of $133.7 million, or $1.65 per share in 2010 and $133.1 million, or $1.65 per share in 2009.

In 2011, the Company advanced initiatives to grow its nonutility infrastructure services segment; to reduce exposure to volatile commodity-related businesses; and to permit its utilities to earn their allowed returns.  During the first quarter of 2011, the Company purchased Minnesota Limited, a transmission pipe construction company.  Earnings were favorably impacted by this acquisition along with increased demand in the services offered by the nonutility infrastructure services segment.  During the fourth quarter of 2011, the Company sold its wholly owned retail natural gas marketer, Vectren Source.  New base rates were established in the Company’s electric utility service territory in May providing for the opportunity to earn on the $325 million of rate base added since the last base rate case.  Further, multiple Utility Group refinancing transactions were completed in 2011 at favorable interest rates.

Natural gas market conditions continued to impact the Company’s investment in wholesale energy marketer ProLiance Holdings, LLC, and the continued soft real estate market resulted in impairment charges associated with legacy real estate holdings.  These transactions, along with other operating trends, are further described below.

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Utility Group

During 2011, the Utility Group earned $122.9 million, compared to $123.9 million earned in 2010 and $107.4 million earned in 2009. The results in 2011 reflect an increase in earnings from electric operations and slightly lower earnings from gas operations.  Utility results also include an unfavorable income tax adjustment associated with the sale of Vectren Source.  The increase in 2010 compared to 2009 results from the return of large customer usage, summer cooling weather that was significantly warmer than normal and the prior year, and lower operating expenses.

Gas utility services

The gas utility segment earned $52.5 million during the year ended December 31, 2011, compared to earnings of $53.7 million in 2010 and $50.2 million in 2009. Results over the periods presented have been impacted by continued growth in large customer margin and return on bare steel, cast iron, and distribution riser replacement activities in Ohio.  In 2011 increased operating expenses associated with planned maintenance activities, environmental remediation efforts, and a brief work stoppage related to bargaining unit labor negotiations unfavorably impacted year over year trends. In 2010 results were favorably impacted by the phased implementation of a straight fixed variable rate design in the Ohio service territory and by lower operating expenses.

Electric utility services

The electric operations earned $65.0 million during 2011, compared to $60.9 million in 2010 and $48.3 million in 2009. The year ended 2011 has been positively impacted by new electric base rates implemented on May 3, 2011 and negatively impacted by summer weather that, while warmer than normal, was cooler than the extreme summer temperatures in 2010.  Earnings in 2011 were also reduced by increased power supply operating expenses associated with planned electric generating maintenance activities.  The increase in 2010 compared to 2009 is principally due to extreme summer weather and increased large customer margins.

Management estimates the impact of weather on electric margin, compared to normal temperatures, to be approximately $3.0 million favorable in 2011.  This compares to 2010, where management estimated a $10.4 million favorable impact on margin compared to normal.  In 2010 summer cooling weather was 34 percent warmer than normal.  In 2009, there was mild cooling weather, and management estimates the impact on electric margin to be $4.8 million unfavorable compared to normal in that year.  Although summer temperatures were warmer than normal in 2011, year over year compared to 2010, there was a decline in earnings of approximately $4.4 million after tax, or $0.05 per share.  In 2010 compared to 2009, there was an estimated increase of $9.0 million after tax, or $0.11 per share, due to electric weather.

Other utility operations

In 2011 earnings from other utility operations were $5.4 million compared to $9.3 million in 2010 and $8.9 million in 2009.  The decrease in 2011 is primarily due to a higher effective income tax rate. The higher income tax rate results primarily from the revaluation of existing Utility Group deferred income taxes as a result of the fourth quarter sale of Vectren Source.  The charge to income taxes as a result of the revaluation was approximately $2.8 million.

Nonutility Group

In 2011, Nonutility Group earnings were $23.8 million compared to earnings of $9.8 million in 2010 and $25.8 million in 2009.  The infrastructure services, energy services, and coal mining operations combined for $38.2 million of earnings contribution in 2011 compared to $21.4 million of earnings contribution in 2010 and $24.2 million in 2009.  In 2011, Infrastructure Services earnings increased $11.8 million compared to 2010, driven by increased demand and the Minnesota Limited acquisition.  Coal Mining earnings also increased $4.7 million year over year due to increased third party sales resulting from the opening of Oaktown 1.  Both 2011 and 2010 reflect reduced optimization opportunities at ProLiance, which resulted in its contribution to Vectren’s results being a loss of $22.9 million in 2011 and $7.9 million in 2010.  In 2009 ProLiance contributed earnings of approximately $14.2 million, before the impacts of an impairment charge associated with an investment in a storage asset held by ProLiance (the Liberty Charge). 

Overall results were impacted by the sale of retail natural gas marketer Vectren Source in 2011 and certain charges throughout the years presented.  In 2011, the sale of Vectren Source, net of transaction costs, resulted in a pretax gain of $25.4 million.  After current taxes and the impact of the revaluation of deferred taxes resulting from the sale of $3.5 million ($2.8 million at the Utility Group and $0.7 million at the Nonutility Group), the after tax consolidated gain was approximately $12.4 million.  Legacy real estate charges totaled $15.4 million, or $9.2 million after tax, in 2011.  Results in 2010 were also impacted by charges related to legacy investments totaling $6.9 million after tax, and 2009 contains an $11.9 million after tax charge associated with the Liberty Charge.  In the consolidated financial statements, Note 6 describes the sale of Vectren Source, Note 8 describes the legacy investment charges, and Note 7 describes the Liberty Charge.

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Corporate & Other

The 2011 results in corporate and other primarily reflect a contribution to the Vectren Foundation, a 501(c)(3) charitable organization, totaling $6.0 million, or $3.9 after tax.  The contribution is reflected in Other operating expenses in the consolidated financial statements.

Dividends

Dividends declared for the year ended December 31, 2011 were $1.385 per share, compared to $1.365 in 2010 and $1.345 per share in 2009.  In November 2011, the Company’s board of directors increased its quarterly dividend to $0.350 per share from $0.345 per share.  The increase marks the 52nd consecutive year Vectren and predecessor companies’ have increased annual dividends paid.

Use of Non-GAAP Performance Measures and Per Share Measures

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

Detailed Discussion of Results of Operations

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

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Results of Operations of the Utility Group

The Utility Group is comprised of Utility Holdings’ operations and consists of the Company’s regulated operations and other operations that provide information technology and other support services to those regulated operations.  Regulated operations consist of a natural gas distribution business that provides natural gas distribution and transportation services to nearly two-thirds of Indiana and to west central Ohio and an electric transmission and distribution business, which provides electric distribution services primarily to southwestern Indiana, and the Company’s power generating and wholesale power operations.  In total, these regulated operations supply natural gas and/or electricity to over one million customers.Utility Group operating results before certain intersegment eliminations and reclassifications for the years ended December 31, 2011, 2010, and 2009, follow:

	Year Ended December 31,
(In millions, except per share data)	2011		2010		2009
OPERATING REVENUES
Gas utility	$	819.1	$	954.1	$	1,066.0
Electric utility		635.9		608.0		528.6
Other		2.0		1.6		1.6
Total operating revenues		1,457.0		1,563.7		1,596.2
OPERATING EXPENSES
Cost of gas sold		375.4		504.7		618.1
Cost of fuel & purchased power		240.4		235.0		194.3
Other operating		313.1		299.2		304.6
Depreciation & amortization		192.3		188.2		180.9
Taxes other than income taxes		54.0		59.6		60.3
Total operating expenses		1,175.2		1,286.7		1,358.2
OPERATING INCOME		281.8		277.0		238.0
Other income - net		4.3		5.4		7.8
Interest expense		80.3		81.4		79.2
INCOME BEFORE INCOME TAXES		205.8		201.0		166.6
Income taxes		82.9		77.1		59.2
NET INCOME	$	122.9	$	123.9	$	107.4
CONTRIBUTION TO VECTREN BASIC EPS	$	1.50	$	1.53	$	1.33

Trends in Utility Operations

The Regulatory Environment

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

Over the last five years, orders establishing new base rates have been received by each utility.  SIGECO’s electric territory received an order in April 2011, effective May 2011, and its gas territory received an order in August 2007.  Indiana Gas received its most recent base rate order in February 2008 and VEDO in January 2009.  The orders authorize a return on equity ranging from 10.15 percent to 10.40 percent.  The authorized returns reflect the impact of innovative rate design strategies having been authorized by these state commissions.  Outside of a full base rate proceeding, these innovative approaches to some extent mitigate the impacts of investments in government-mandated projects, operating costs that are volatile or that increase with government mandates, and changing consumption patterns.  In addition to timely gas and fuel cost recovery, approximately $41 million of the Utility Group’s approximate $313 million in Other operating expenses incurred during 2011 are subject to a recovery mechanism outside of base rates.  In 2011, state laws in both Indiana and Ohio were passed that expand the ability of utilities to recover certain costs of federally mandated projects, and in Ohio other projects, outside of a base rate proceeding.  Therefore, utilization of these mechanisms will likely increase in the coming years.

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Rate Design Strategies

Sales of natural gas and electricity to residential and commercial customers are seasonal and are impacted by weather.  Trends in average use among natural gas residential and commercial customers have tended to decline as more efficient appliances and furnaces are installed and the Company’s utilities have implemented conservation programs.  In the Company’s two Indiana natural gas service territories, normal temperature adjustment (NTA) and lost margin recovery mechanisms largely mitigate the effect that would otherwise be caused by variations in volumes sold to these customers due to weather and changing consumption patterns.  The Ohio natural gas service territory has a straight fixed variable rate design.  This rate design, which was fully implemented in February 2010, mitigates most of the Ohio service territory’s weather risk and risk of decreasing consumption.  Prior to the implementation of this rate design, the Ohio service territory had a lost margin recovery mechanism.  In all natural gas service territories, commissions have authorized bare steel and cast iron replacement programs.  SIGECO’s electric service territory currently recovers certain transmission investments outside of base rates.  The electric service territory has neither an NTA nor a decoupling mechanism; however, rate designs provide for a lost margin recovery mechanism that works in tandem with conservation initiatives.

Tracked Operating Expenses

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

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

The IURC has also applied the statute authorizing GCA and FAC procedures to reduce rates when necessary to limit net operating income to a level authorized in its last general rate order through the application of an earnings test.  These earnings tests have not had any material impact to the Company’s recent operating results and are not expected to have any material impact in the foreseeable future.  Since October of 2008, the Company has not been the supplier of natural gas in its Ohio territory.

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

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

Utility Group Margin

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

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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)	2011		2010		2009
Gas utility revenues	$	819.1	$	954.1	$	1,066.0
Cost of gas sold		375.4		504.7		618.1
Total gas utility margin	$	443.7	$	449.4	$	447.9
Margin attributed to:
Residential & commercial customers	$	375.2	$	384.7	$	387.2
Industrial customers		56.4		52.2		46.6
Other		12.1		12.5		14.1
Sold & transported volumes in MMDth attributed to:
Residential & commercial customers		99.9		106.2		106.5
Industrial customers		97.0		90.8		78.0
Total sold & transported volumes		196.9		197.0		184.5

Over the three years ended December 31, 2011, volumes sold to residential and commercial customers have been impacted by weather, lower gas prices, conservation initiatives, and changing consumption patterns.  However, the impact on margin has been generally offset as planned by rate design strategies.  Large customer volumes were impacted by the recession, falling approximately 15 percent in 2009.  With the economy stabilizing in 2010, volumes in 2010 returned to pre-recession levels with additional growth in 2011.  The recovery from the recession and increasing ethanol production were the principal reasons for the change in large customer margin over the years presented.  The average cost per dekatherm of gas purchased during 2011 was $5.30, compared to $5.99 in 2010 and $5.97 in 2009.

Gas utility margins were $443.7 million for year ended December 31, 2011, and compared to 2010 decreased $5.7 million.  Margin decreased $8.0 million year over year due to lower revenue taxes and operating costs recovered in margin.  Management estimates a decrease of $3.5 million due to Ohio rate design changes, as described below.  Returns generated on investments in bare steel/ cast iron and distribution riser replacement in Ohio increased margins $2.7 million year over year.  Large customer margin, net of the impacts of regulatory initiatives and tracked costs, increased by $3.8 million due primarily to ethanol producers.

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

The rate design approved by the PUCO on January 7, 2009, and initially implemented on February 22, 2009, allowed for the phased movement toward a straight fixed variable rate design.  This rate design places substantially all of the fixed cost recovery in the monthly customer service charge.  This rate design mitigates most weather risk as well as the effects of declining usage, similar to the company’s lost margin recovery mechanism in place in the Indiana natural gas service territories and the mechanism in place in Ohio prior to this rate order.  Since the straight fixed variable rate design was fully implemented in February 2010, nearly 90 percent of the combined residential and commercial base rate gas margins were recovered through the customer service charge.  As a result of the timing of this conversion, margin in 2010 was favorably impacted by the volumetric rate design in place during the peak delivery winter months of January and the first half of February.  Margin recognized in 2011 reflects the full implementation of the rate design which resulted in a decrease in margin in 2011 compared to 2010.

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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)	2011		2010		2009
Electric utility revenues	$	635.9	$	608.0	$	528.6
Cost of fuel & purchased power		240.4		235.0		194.3
Total electric utility margin	$	395.5	$	373.0	$	334.3
Margin attributed to:
Residential & commercial customers	$	255.8	$	241.2	$	224.6
Industrial customers		101.6		97.1		81.7
Municipals & other customers		8.5		8.5		7.3
Subtotal: Retail	$	365.9	$	346.8	$	313.6
Wholesale margin		29.6		26.2		20.7
Total electric utility margin	$	395.5	$	373.0	$	334.3
Electric volumes sold in GWh attributed to:
Residential & commercial customers		2,827.2		2,964.0		2,760.8
Industrial customers		2,744.8		2,630.3		2,258.9
Municipals & other		22.8		22.6		20.0
Total retail & firm wholesale volumes sold		5,594.8		5,616.9		5,039.7

Retail

Electric retail utility margins were $­­­365.9 million for the year ended December 31, 2011 and compared to 2010 increased by $19.1 million.  The impact of new base rates increased margin $23.7 million.  Management estimates the impact of weather, which was warmer than normal but cooler compared to the prior year, to have decreased residential and commercial margin $7.4 million.  Margin increased $2.4 million year over year due to increased MISO operating costs that are directly recovered in margin.

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

Margin from Wholesale Electric Activities

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

	Year Ended December 31,
(In millions)	2011		2010		2009
Transmission system margin	$	23.5	$	18.8	$	14.6
Off-system margin		6.1		7.4		6.1
Total wholesale margin	$	29.6	$	26.2	$	20.7

The Company earns a return on electric transmission projects constructed by the Company in its service territory that meet the criteria of MISO’s regional transmission expansion plans.  Margin associated with these projects, including the reconciliation of recovery mechanisms, and other transmission system operations, totaled $23.5 million during 2011, compared to $18.8 million in 2010 and $14.6 million in 2009.  Increases are primarily due to increased investment in qualifying projects.

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One such project currently under construction meeting these expansion plan criteria is an interstate 345 Kv transmission line that connects Vectren’s A.B. Brown Generating Station to a station in Indiana owned by Duke Energy to the north and will connect to a station in Kentucky owned by Big Rivers Electric Corporation to the south.  During the construction of these transmission assets and while these assets are in service, SIGECO will recover an approximate 10 percent return, inclusive of the FERC approved equity rate of return of 12.38 percent, on capital investments through a rider mechanism which is projected annually and reconciled the following year based on actual results.  Of the total investment, which is expected to approximate $100 million, the Company has invested approximately $74 million as of December 31, 2011.  The north leg of this expansion was placed in service in November 2010, and the south leg of this project is expected to be operational in 2012. 

For the year ended December 31, 2011, margin from off-system sales was $6.1 million, compared to $7.4 million in 2010 and $6.1 million in 2009.  The base rate changes implemented in May 2011 require that wholesale margin from off-system sales earned above or below $7.5 million be shared equally with customers.  This compares to a $10.5 million sharing threshold established in 2007.  Results for the periods presented reflect the impact of that sharing.  Off-system sales totaled 586.7 GWh in 2011, compared to 587.6 GWh in 2010, and 603.6 GWh in 2009.

Utility Group Operating Expenses

Other Operating

For the year ended December 31, 2011, Other operating expenses were $313.1 million, and compared to 2010 reflect an increase of $13.9 million.  The increase is primarily attributable to higher electric power supply operating expenses.  Such expenses increased $10.8 million year over year with $6.9 million attributed to planned outage maintenance and $3.1 million attributed to variable production costs.  The remaining variance is primarily attributable to higher planned energy delivery costs.

For the year ended December 31, 2010, Other operating expenses decreased $5.4 million compared to 2009.  Excluding expenses tracked directly in margin, operating costs decreased $7.9 million.  There was a $3.0 million reduction in Indiana uncollectible accounts expense.  And in 2009, the Company incurred $5.3 million related to environmental remediation efforts.

Depreciation & Amortization

For the year ended December 31, 2011, depreciation and amortization expense was $192.3 million, compared to $188.2 million in 2010 and $180.9 million in 2009.  These increases reflect utility investments placed into service.  The higher deprecation as a result of increasing rate base was offset by lower amortization of certain deferred costs pursuant to the May 2011 electric base rate order.  Such decreased amortizations were $2.5 million in 2011.

Taxes Other Than Income Taxes

Taxes other than income taxes decreased $5.6 million in 2011 compared to 2010 and decreased $0.7 million in 2010 compared to 2009.  The decreases are primarily attributable to lower Ohio excise and usage taxes associated with that territory’s ongoing process of exiting the merchant function, which started in the second quarter of 2010.  These taxes are primarily revenue-related taxes and are offset dollar-for-dollar with lower gas utility revenues.

Other Income-Net

Other income-net reflects income of $4.3 million in 2011, compared to $5.4 million in 2010 and $7.8 million in 2009. The declines among the years principally reflect lower returns associated with investments that fund benefit plans.  The earnings in 2009 reflect the partial recovery of those investments from the significant market declines in 2008 associated with the recession.

Interest Expense

For year ended December 31, 2011, interest expense was $80.3 million, and is a slight decrease compared to 2010.  The decrease is primarily due to fourth quarter 2011 refinancing activity in which $250 million of long-term debt with a 6.625 percent interest rate matured and was replaced with $150 million of new long-term debt with an average interest rate of 5.12 percent and $100 million of short-term borrowings.  During the fourth quarter, the Company also called $96.2 million of long-term debt at a rate of 5.95 percent and replaced that issuance in February 2012 with new debt at a rate of 5.0 percent.  The impacts of refinancing at lower rates will decrease interest more significantly in 2012.

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The $2.2 million increase in 2010 compared to 2009 reflects the impact of long-term financing transactions completed in 2009, offset by lower interest from less debt outstanding overall.  The long-term financing transactions completed in 2009 include a second quarter issuance by Utility Holdings of $100 million in unsecured eleven year notes with an interest rate of 6.28 percent and a third quarter completion by SIGECO of a $22.3 million debt issuance of 31 year tax exempt first mortgage bonds with an interest rate of 5.4 percent.

Income Taxes

In 2011, Utility Group federal and state income taxes were $82.9 million, compared to $77.1 million in 2010 and $59.2 million in 2009.  The $5.8 million increase in 2011 primarily reflects a higher effective income tax rate.  The higher income tax rate includes a $2.8 million charge that results from the revaluation of existing Utility Group deferred income taxes as a result of the fourth quarter sale of Vectren Source.

Federal and state income taxes increased $17.9 million in 2010 compared to 2009.  The increase is primarily impacted by greater pre-tax income in 2010 and no manufacturing tax deduction in 2010 as a result of significant bonus depreciation driving down qualifying income.  In addition, the lower effective tax rate in 2009 reflects a greater share of taxable income in states with low, or no, state income taxes.

Legislative Matters

Pipeline Safety Law

On January 3, 2012 the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 was signed into law.  This new law, which reauthorizes federal pipeline safety programs through fiscal year 2015, provides for enhanced safety, reliability and environmental protection in the transportation of energy products by pipeline. The new law increases federal enforcement authority, grants the federal government expanded authority over pipeline safety, provides for new safety regulations and standards, and authorizes or requires the completion of several pipeline safety-related studies.  The DOT is required to promulgate a number of new regulatory requirements.  The direction of those regulations will be based on the results of the studies and reports required or authorized by the new law and may eventually lead to further regulatory or statutory requirements.

The Company continues to study the impact of the new law and potential new regulations associated with its implementation.  At this time, compliance costs and other effects associated with the increased pipeline safety regulations remain uncertain.  However, the new law is expected to result in further investment in pipeline inspections, and where necessary, additional modernization of pipeline infrastructure; and therefore, result in both increased levels of operating expenses and capital expenditures associated with the Company’s natural gas distribution businesses.  Operating expenses associated with expanded compliance requirements may grow to approximately $9 million annually, with $6 million attributable to the Indiana operations.  The Company expects to seek recovery under Senate Bill 251 referenced below, or such costs may be recoverable through current tracking mechanisms.  Capital investments, driven by the pipeline safety regulations, associated with the Company’s Indiana gas utilities are expected to be approximately $80 million over the next five years, which would likely qualify as federally mandated regulatory requirements.  In Ohio, capital investments are expected to be approximately $55 million over the next five years.  The Company expects to seek recovery of capital investments associated with complying with these federal mandates in accordance with Senate Bill 251 in Indiana and House Bill 95 in Ohio (referenced below).

Indiana House Bill 1004

In May 2011, House Bill 1004 was signed into law.  This legislation phases in over four years a two percent rate reduction to the Indiana Adjusted Gross Income Tax for corporations.  Pursuant to House Bill 1004, the tax rate will be lowered by one-half percent each year beginning on July 1, 2012, to the final rate of six and one-half percent effective July 1, 2015.  Pursuant to FASB guidance, the Company accounted for the effect of the change in tax law on its deferred taxes in the second quarter of 2011, the period of enactment.  The impact was not material to results of operations or financial condition as the decrease in Deferred tax liabilities was generally offset by a $17.1 million decrease in Regulatory assets.

Indiana Senate Bill 251

In April 2011, Senate Bill 251 was signed into law.  While the bill is broad in scope, it allows for cost recovery outside of a base rate proceeding for federal government mandated projects and provides for a voluntary clean energy portfolio standard. 

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The law applies to both gas and electric utility operations and provides a framework to recover 80 percent of federally mandated costs through a periodic rate adjustment mechanism outside of a general rate case.  Such costs include construction, depreciation, operating and other costs.  The remaining 20 percent of those costs are to be deferred for recovery in the utility’s next general rate case.  The Company is currently evaluating the impact this law may have on its operations, including applicability to expenditures associated with the integrity, safety, and reliable operation of natural gas pipelines and facilities; ash disposal; water regulations; and air pollution, including greenhouse gas emissions, among other federally mandated projects and potential projects. 

The legislation establishes a voluntary clean energy portfolio standard that provides incentives to electricity suppliers participating in the program.  The goal of the program is that by 2025, at least 10 percent of the total electricity obtained by the supplier to meet the energy needs of its Indiana retail customers will be provided by clean energy sources, as defined.  The financial incentives include an enhanced return on equity and tracking mechanisms to recover program costs.  In advance of a federal portfolio standard and Senate Bill 251, SIGECO received regulatory approval to purchase a 3 MW landfill gas generation facility from a related entity.  The facility was purchased in 2009 and is directly connected 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.  Before the impacts of efficiency measures, the Company currently stands at approximately 5 percent of its electricity being provided by clean energy sources due to the long-term wind contracts and landfill gas investments.  The Company continues to evaluate whether to participate in this voluntary program.

Ohio House Bill 95

In June 2011, Ohio House Bill 95 was signed into law.  The law adjusts, among other things, the manner in which gas utilities file for rate changes, including the implementation of base rate changes, alternative rate plans, and automatic rate adjustment mechanisms.  Outside of a base rate proceeding, the legislation permits a natural gas company to apply to implement a capital expenditure program for infrastructure expansion, upgrade, or replacement; installation, upgrade, or replacement of information technology systems; or any program necessary to comply with government regulation.  Once such application is approved, the legislation authorizes recovery or deferral of program costs, such as depreciation, property taxes, and carrying costs.  The Company is assessing the impact this legislation may have on its operations.  On February 3, 2012, the Company initiated a filing under House Bill 95.  This filing requests accounting authority to defer depreciation, post in service carrying costs and property taxes for its approximate $25 million 2012 capital expenditure program.  The capital expenditure program includes infrastructure expansion and improvements not covered by the Company’s distribution replacement rider as well as expenditures necessary to comply with PUCO rules, regulations and orders.  A procedural schedule associated with the filing has not yet been set.

Environmental Matters

Air Quality

Cross-State Air Pollution Rule (Formerly Clean Air Interstate Rule (CAIR))

On July 7, 2011, EPA finalized the Cross-State Air Pollution Rule (CSAPR).  CSPAR is the EPA’s response to the US Court of Appeals for the District of Columbia’s (the Court) remand of the Clean Air Interstate Rule (CAIR). CAIR was originally established in 2005 as an allowance cap and trade program that required reductions from coal-burning power plants for NOx emissions beginning January 1, 2009 and SO2 emissions beginning January 1, 2010, with a second phase of reductions in 2015.

In an effort to address the Court’s finding that CAIR did not adequately ensure attainment of pollutants in certain downwind states due to unlimited trading of SO2and NOx allowances, CSPAR reduces the ability of facilities to meet emission reduction targets through allowance trading.  Like CAIR, CSPAR sets individual state caps for SO2and NOx emissions.  However, unlike CAIR in which states allocated allowances through state implementation plans, CSPAR allowances were allocated to individual units directly through the federal rule.  As finalized, CSAPR requires a 71 percent reduction of SO2 emissions compared to 2005 national levels and a 52 percent reduction of NOx emissions compared to 2005 national levels and that such reductions are to be achieved with initial step reductions beginning January 1, 2012, with final compliance to be achieved in 2014.  Multiple administrative and judicial challenges have been filed, including requests to stay CSPAR’s implementation.

On December 30, 2011, the Court granted a stay of CSPAR and ordered expedited briefing schedules be submitted by January 18, 2012, that would allow for completion of briefing and a hearing in April 2012.  Two primary issues are before the Court for review:  (1) EPA’s use of air modeling data (as opposed to exclusive reliance on actual monitoring data) to support state contribution levels, and (2) EPA’s allocation of allowances directly through a federal implementation plan as opposed to setting state caps and providing states the opportunity to submit individual state implementation plans.  In addition, there are initiatives in the Congress that, if adopted, would suspend CSPAR’s implementation.

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Utility Hazardous Air Pollutants (HAPs) Rule

On December 21, 2011, the EPA finalized the Utility HAPs rule.  The HAPs Rule is the EPA’s response to the US Court of Appeals for the District of Columbia vacating the Clean Air Mercury Rule (CAMR) in 2008.  CAMR was originally established in 2005 as a nation-wide mercury emission allowance cap and trade system which sought to reduce utility emissions of mercury starting in 2010.

The HAPs rule sets emission limits for hazardous air pollutants for existing and new coal-fired power plants and identifies the following broad categories of hazardous air pollutants:  mercury, non-mercury hazardous air pollutants (primarily arsenic, chromium, cobalt, and selenium) and acid gases (hydrogen cyanide, hydrogen chloride, and hydrogen fluoride).  The rule imposes mercury emission limits for two sub-categories of coal, and proposed surrogate limits for non-mercury and acid gas hazardous air pollutants. The EPA did not grant blanket compliance extensions, but asserted that states have broad authority to grant one year extensions for individual units where potential reliability impacts have been demonstrated.  Reductions are to be achieved within three years of publication of the final rule in the Federal register (early 2015).  Initiatives to suspend CSPAR’s implementation by the Congress also apply to the implementation of the HAPs Rule.

Conclusions Regarding Air Regulations

To comply with Indiana’s implementation plan of the Clean Air Act, and other federal air quality standards, the Company obtained authority from the IURC to invest in clean coal technology.  Using this authorization, the Company invested approximately $411 million starting in 2001 with the last equipment being placed into service on January 1, 2010.  The pollution control equipment included Selective Catalytic Reduction (SCR) systems, fabric filters, and an SO2 scrubber at its generating facility that is jointly owned with ALCOA (the Company’s portion is 150 MW).  SCR technology is the most effective method of reducing NOx emissions where high removal efficiencies are required and fabric filters control particulate matter emissions.  The unamortized portion of the $411 million clean coal technology investment was included in rate base for purposes of determining SIGECO’s new electric base rates approved in the latest base rate order obtained April 27, 2011.  SIGECO’s coal fired generating fleet is 100 percent scrubbed for SO2 and 90 percent controlled for NOx. 

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

The Company is currently reviewing the sufficiency of its existing pollution control equipment in relation to the requirements described in CSPAR and the Utility HAPs Rule.  Based upon an initial review of the final rules, including minor revisions made to CSPAR in October 2011, the Company believes that it will be able to meet these requirements with its existing suite of pollution control equipment and the anticipated allotment of new emission allowances.  However, it is possible some minor modifications to the control equipment and additional operating expenses could be required.  The Company believes that such additional costs, if necessary, would be recoverable under Indiana Senate Bill 251 referenced above.

Water

Section 316(b) of the Clean Water Act requires that generating facilities use the “best technology available” to minimize adverse environmental impacts in a body of water.  More specifically, Section 316(b) is concerned with impingement and entrainment of aquatic species in once-through cooling water intake structures used at electric generating facilities.  In April 2009, the U.S. Supreme Court affirmed that the EPA could, but was not required to, consider costs and benefits in making the evaluation as to the best technology available for existing generating facilities.  The regulation was remanded back to the EPA for further consideration.  In March 2011, the EPA released its proposed Section 316(b) regulations.  The EPA did not mandate the retrofitting of cooling towers in the proposed regulation, but if finalized the regulation will leave it to the state to determine whether cooling towers should be required on a case by case basis.  A final rule is expected in 2012.  Depending on the final rule and on the Company’s facts and circumstances, capital investments could be in the $40 million range if new infrastructure, such as new cooling water towers, is required.  Costs for compliance with these final regulations would likely qualify as federally mandated regulatory requirements under Indiana Senate Bill 251 referenced above.

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Coal Ash Waste Disposal & Ash Ponds

In June 2010, the EPA issued proposed regulations affecting the management and disposal of coal combustion products, such as ash generated by the Company’s coal-fired power plants.  The proposed rules more stringently regulate these byproducts and would likely increase the cost of operating or expanding existing ash ponds and the development of new ash ponds.  The alternatives include regulating coal combustion by-products that are not being beneficially reused as hazardous waste.  The EPA did not offer a preferred alternative, but took public comment on multiple alternative regulations.  Rules may not be finalized in 2012 given oversight hearings, congressional interest, and other factors.

At this time, the majority of the Company’s ash is being beneficially reused.  However, the alternatives proposed would require some retrofitting or closure of existing ash ponds.  The Company estimates capital expenditures to comply could be as much as $30 million, and such expenditures could exceed $100 million if the most stringent of the alternatives is selected.  Annual compliance costs could increase slightly or be impacted by as much as $5 million.  Costs for compliance with these regulations would likely qualify as federally mandated regulatory requirements under Senate Bill 251 referenced above. 

Climate Change

Vectren is committed to responsible environmental stewardship and conservation efforts and if a national climate change policy is implemented believes it should have the following elements:

·   An inclusive scope that involves all sectors of the economy and sources of greenhouse gases, and recognizes early actions and investments made to mitigate greenhouse gas emissions;

·   Provisions for enhanced use of renewable energy sources as a supplement to 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.

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)	2011		2010		2009		2008		2007
Direct CO2 Emissions (tons)		5,645		6,120		5,500		8,029		7,995

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

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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;

·   Implementing conservation and demand side management initiatives in the electric service territory;

·   Evaluating potential carbon requirements with regard to new generation, other fuel supply sources, and future environmental compliance plans;

·   Reducing the Company’s carbon footprint by measures such as utilizing hybrid vehicles and optimizing generation efficiencies by utilizing dense pack technology; and

·   Developing renewable energy and energy efficiency performance contracting projects through its wholly owned subsidiary, Energy Systems Group.

Legislative Actions & Other Climate Change Initiatives

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

Numerous competing federal legislative proposals have also been introduced in recent years that involve carbon, energy efficiency, and renewable energy.  Comprehensive energy legislation at the federal level continues to be debated, but there has been little progress to date.  The progression of regional initiatives throughout the United States has also slowed.

Impact of Legislative Actions & Other Initiatives is Unknown

If regulations are enacted by the EPA or other agencies or if legislation requiring reductions in CO2 and other greenhouse gases or legislation mandating a renewable energy portfolio standard is adopted, such regulation could substantially affect both the costs and operating characteristics of the Company’s fossil fuel generating plants, nonutility coal mining operations, and natural gas distribution businesses.  At this time and in the absence of final legislation or rulemaking, compliance costs and other effects associated with reductions in greenhouse gas emissions or obtaining renewable energy sources remain uncertain.  The Company has gathered preliminary estimates of the costs to control greenhouse gas emissions.  A preliminary investigation demonstrated costs to comply would be significant, first with regard to operating expenses and later for capital expenditures as technology becomes available to control greenhouse gas emissions.  However, these compliance cost estimates are based on highly uncertain assumptions, including allowance prices if a cap and trade approach were employed, and energy efficiency targets.  Costs to purchase allowances that cap greenhouse gas emissions or expenditures made to control emissions should be considered a cost of providing electricity, and as such, the Company believes such costs and expenditures would be recoverable from customers through Senate Bill 251.  Customer rates may also be impacted should decisions be made to reduce the level of sales to municipal and other wholesale customers in order to meet emission targets.

Manufactured Gas Plants

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

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

The Company has accrued the estimated costs for further investigation, remediation, groundwater monitoring, and related costs for the sites.  While the total costs that may be incurred in connection with addressing these sites cannot be determined at this time, the Company has recorded cumulative costs that it reasonably expects to incur totaling approximately $41.6 million ($23.1 million at Indiana Gas and $18.5 million at SIGECO).  The estimated accrued costs are limited to the Company’s share of the remediation efforts and are therefore net of exposures of other potentially responsible parties (PRP).

With respect to insurance coverage, Indiana Gas has received approximately $20.8 million from all known insurance carriers under insurance policies in effect when these plants were in operation.  SIGECO 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 another site subject to a lawsuit that has been settled.  In November 2011, the Court ruled on two motions for summary judgment, finding for SIGECO and against certain insurers on indemnification and defense obligations in the policies at issue.  SIGECO has settlement agreements with all known insurance carriers and has recorded approximately $15.1 million of expected insurance recoveries.

The costs the Company expects to incur are estimated by management using assumptions based on actual costs incurred, the timing of expected future payments, and inflation factors, among others.  While the Company’s utilities have recorded all costs which they presently expect to incur in connection with activities at these sites, it is possible that future events may require 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, 2011 and 2010, respectively, approximately $6.5 million and $5.5 million of accrued, but not yet spent, costs are included in Other Liabilities related to both the Indiana Gas and SIGECO sites.

Jacobsville Superfund Site

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

Rate & Regulatory Matters

Vectren South Electric Base Rate Filing

On December 11, 2009, Vectren South filed a request with the IURC to adjust its base electric rates.  The requested increase in base rates addressed capital investments, a modified electric rate design that would facilitate a partnership between Vectren South and customers to pursue energy efficiency and conservation, and new energy efficiency programs to complement those currently offered for natural gas customers.  The IURC issued an order in the case on April 27, 2011.  The order provides for an approximate $28.6 million revenue increase to recover costs associated with approximately $325 million in system upgrades that were completed in the three years leading up to the December 2009 filing and modest increases in maintenance and operating expenses.  The approved revenue increase is based on rate base of $1,295.6 million, return on equity of 10.4 percent and an overall rate of return of 7.29 percent.  The new rates were effective May 3, 2011.  The IURC, in its order, denied the Company’s request for implementation of the decoupled rate design, which is discussed further below.  Addressing issues raised in the case concerning coal supply contracts and related costs, the IURC found that current coal contracts remain effective and that a prospective review process of future procurement decisions would be initiated.

Coal Procurement Procedures

Vectren South submitted a request for proposal in April 2011 regarding coal purchases for a four year period beginning in 2012.  After negotiations with bidders, Vectren South has reached an agreement in principle for multi-year purchases with two suppliers, one of which is Vectren Fuels, Inc.  Consistent with the IURC direction in the electric rate case, a sub docket proceeding was established to review the Company’s prospective coal procurement procedures, and the Company submitted evidence related to its recent request for proposal (RFP) and those coal procurement procedures to the IURC in September 2011.  In October 2011, the OUCC filed its testimony which, while suggesting enhancements to the process to be considered, does not challenge the results of the RFP and the resulting new contracts.  All hearings were completed in December 2011 and an order is expected in early 2012.

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Vectren South Electric Fuel Cost Reduction

On December 5, 2011 within the quarterly Fuel Adjustment Clause (FAC) filing, Vectren South submitted a joint proposal with the OUCC to reduce its fuel costs by accelerating the impact of lower cost coal contracts to be effective after 2012.  In the spring of 2011, Vectren secured contracts for lower coal costs through a formal bidding process. This lower-priced coal is expected to start being delivered and used at Vectren’s power plants by late 2012 to early 2013 and beyond. The agreement to accelerate savings into early 2012 means that the existing 2012 coal costs that are above the new, lower prices will be deferred to a regulatory asset and recovered over a six-year period without interest beginning in 2014.  This deferral also includes a reduction to the coal inventory balance at December 31, 2011 of approximately $17.7 million to reflect existing inventory at the new, lower price.  The IURC approved this proposal on January 25, 2012, with an impact to customer’s rates effective February 1, 2012.

Vectren South Electric Demand Side Management Program Filing

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

On August 31, 2011 the IURC issued an order approving an initial three year DSM plan in the Vectren South service territory that complies with the IURC’s energy saving targets.  Consistent with the Company’s proposal, the order approved, among other items, the following: 1) recovery of costs associated with implementing the DSM Plan; 2) the recovery of a performance incentive mechanism based on measured savings related to certain DSM programs; 3) lost margin recovery associated with the implementation of DSM programs for large customers; and 4) deferral of lost margin up to $1 million in 2011 associated with small customer DSM programs for subsequent recovery under a tracking mechanism to be proposed by the Company.  This mechanism is an alternative to the electric decoupling proposal that was denied by the IURC in the order received April 27, 2011.  On January 26, 2012, the Company filed with the IURC a proposal for a small customer lost margin recovery mechanism within the existing Demand Side Management Adjustment (DSMA).  The proposal includes a request for recovery of the $1 million deferred in 2011, and a request for continued deferral of lost margins in 2012 until such point as these lost margins are included in DSMA rates.  The procedural schedule has not been set in this filing, but the Company expects an order in 2012.

Vectren South Electric Dense Pack Filing

On September 14, 2011, Vectren South filed a petition with the IURC seeking recovery of and return on the capital investment in dense pack technology to improve the efficiency of its A.B. Brown Generating Station.  This investment is expected to be approximately $32 million over the next two years, of which approximately $19 million has been invested to date.  This technology is expected to allow the A.B. Brown units to run at least 5 percent more efficient, thereby burning less fuel, and reducing fuel costs and emissions of pollutants.  Indiana statute provides for timely recovery of investments, with a return, in instances where the investment increases the efficiency of existing generating plants that are fueled by coal.  Several parties have intervened in the case and are requesting that the IURC deny recovery of these project costs outside of a base rate proceeding.The IURC will conduct a hearing in February 2012.

Vectren North Reporting Location Consolidation Proceeding

Vectren North implemented a reporting location  consolidation plan in 2011 and closed certain locations throughout the North territory.  On May 26, 2011, the International Brotherhood of Electrical Workers Local 1393, United Steel Workers Locals 12213 and 7441 and others filed a formal complaint with the IURC claiming that the consolidation and simultaneous closing by Vectren North of select reporting locations endangers public safety and impairs Vectren North's ability to provide adequate, safe and reliable service.  These parties have asked the IURC to require Vectren North to reopen previously consolidated reporting locations and maintain and staff those locations.  A hearing in this case was held in February  2012, and the Company expects the IURC to act some time in 2012.

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Vectren North & Vectren South Gas Decoupling Extension Filing

On April 14, 2011, the Company’s Indiana based gas companies (Vectren North and Vectren South) filed with the IURC a joint settlement agreement with the OUCC on an extension of the offering of conservation programs and the supporting gas decoupling mechanism originally approved in December 2006.  On August 18, 2011, the IURC issued an order approving the settlement as filed, granting the extension of the current decoupling mechanism in place at both gas companies and recovery of new conservation program costs through December 2015.

VEDO Gas Rate Design

The rate design approved by the PUCO on January 7, 2009, and initially implemented on February 22, 2009, allowed for the phased movement toward a straight fixed variable rate design, which places substantially all of the fixed cost recovery in the monthly customer service charge.  This rate design mitigates most weather risk as well as the effects of declining usage, similar to the company’s lost margin recovery mechanism in place in the Indiana natural gas service territories and the mechanism in place in Ohio prior to this rate order.  Since the straight fixed variable rate design was fully implemented in February 2010, nearly 90 percent of the combined residential and commercial base rate gas margins were recovered through the customer service charge.  As a result, some margin previously recovered during the peak delivery winter months, such as January and the first half of February 2010, is more ratably recognized throughout the year.

In addition in 2010, the Company began recognizing a return on and of investments made to replace distribution risers and bare steel and cast iron infrastructure per a PUCO order.

VEDO Continues the Process to Exit the Merchant Function

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

The second phase of the exit process began on April 1, 2010.  During this phase, the Company no longer sells natural gas directly to customers.  Rather, state-certified Competitive Retail Natural Gas Suppliers, that were successful bidders in a similar regulatory-approved auction, sell the gas commodity to specific customers for a 12-month period at auction-determined standard pricing.  The first auction was conducted on January 12, 2010, and the auction results were approved by the PUCO on January 13, 2010.  The plan approved by the PUCO required that the Company conduct at least two annual auctions during this phase.  As such, the Company conducted another auction on January 18, 2011 in advance of the second 12-month term which commenced on April 1, 2011.  The results of that auction were approved by the PUCO on January 19, 2011.Vectren Source, the Company’s former wholly owned nonutility retail gas marketer, was a successful bidder in both auctions winning one tranche of customers in the first auction and two tranches of customers in the second auction.  Each tranche of customers equates to approximately 28,000 customers.  As per the terms of the plan approved by the PUCO, because no application for a full exit of the merchant function was neither sought nor approved by April 1, 2011, VEDO conducted a third retail auction on January 31, 2012 to address the 12-month term beginning April 1, 2012.  The results of that auction were approved by the PUCO on February 1, 2012.  Consistent with current practice, customers continue to receive a single bill for the commodity as well as the delivery component of natural gas service from VEDO.

The PUCO provided for an Exit Transition Cost rider, which allows the Company to recover costs associated with the transition process.  Exiting the merchant function has not had a material impact on earnings or financial condition.  It, however, has and will continue to reduce Gas utility revenues and have an equal and offsetting impact to Cost of gas sold and revenue related taxes recorded in Taxes other than income taxes as VEDO no longer purchases gas for resale to these customers.  VEDO’s gas costs were $12.7 million, $89.5 million, and $157.4 million for the twelve months ended December 31, 2011, 2010, and 2009, respectively, while revenue taxes were $11.5 million, $15.6 million, and $18.6 million, respectively.  Therefore, Gas utility revenues resulting from VEDO’s exit of the merchant function decreased $80.9 million in 2011 compared to 2010 and $70.9 million in 2010 compared to 2009.

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Results of Operations of the Nonutility Group

The Nonutility Group operates in four primary business areas: Infrastructure Services, Energy Services, Coal Mining, and Energy Marketing.  Infrastructure Services provides underground construction and repair.  Energy Services provides performance contracting and renewable energy services.  Coal Mining mines and sells coal.  Energy Marketing markets and supplies natural gas and provides energy management services.  There are also other legacy businesses that have invested in energy-related opportunities and services, real estate, and leveraged leases, among other investments.  The Nonutility Group supports the Company’s regulated utilities pursuant to service contracts by providing natural gas supply services, coal, and infrastructure services.  Nonutility Group earnings for the years ended December 31, 2011, 2010, and 2009, follow:

	Year Ended December 31,
(In millions, except per share amounts)	2011			2010			2009
NET INCOME	$	23.8		$	9.8		$	25.8
CONTRIBUTION TO VECTREN BASIC EPS	$	0.29		$	0.12		$	0.32
NET INCOME (LOSS) ATTRIBUTED TO:
Infrastructure Services	$	14.9		$	3.1		$	2.4
Energy Services		6.7			6.4			8.4
Coal Mining		16.6			11.9			13.4
Energy Marketing
Vectren Source		18.7			3.7			6.4
ProLiance		(22.9	)		(7.9	)		(2.3	)
Other Businesses		(10.2	)		(7.4	)		(2.5	)

Infrastructure Services

Infrastructure Services provides underground construction and repair to utility infrastructure through Miller Pipeline (Miller) and Minnesota Limited, which was acquired on March 31, 2011.  Inclusive of holding company costs, results from Infrastructure’s operations for the year ended December 31, 2011 were earnings of $14.9 million, compared to earnings of $3.1 million in 2010 and $2.4 million in 2009.  In 2011, Minnesota Limited contributed earnings of $9.4 million and reflects increased demand for work on transmission pipeline repairs.  The remainder of the increase, totaling $2.4 million, relates to Miller’s ongoing operations and is representative of increased demand.  In 2010, earnings increased $0.7 million, compared to earnings generated in 2009.  Even with cold weather conditions in the first quarter of 2010 restricting construction levels, results in 2010 compared to 2009 reflect higher revenues and man hours worked.  Man hours worked were 3.9 million in 2011, compared to 2.6 million in 2010 and 2.5 million in 2009 with Minnesota Limited contributing 0.7 million man hours in 2011.  Construction activity generally is expected to remain strong as utilities and pipeline operators continue to replace their aging natural gas and oil infrastructure and as the need for shale gas and oil infrastructure becomes more prevalent.

Acquisition of Minnesota Limited

On March 31, 2011, the Company purchased Minnesota Limited, Inc., excluding certain assets.  Minnesota Limited is a specialty contractor focusing on transmission pipeline construction and maintenance; pump station, compressor station, terminal and refinery construction; gas distribution; and hydrostatic testing.  Minnesota Limited is headquartered in Big Lake, Minnesota and the majority of its customers are generally located in the northern Midwest region.  This acquisition positions the Company for anticipated growth in demand for gas transmission construction resulting from the need to transport new sources of natural gas and oil found in shale formations and the need to upgrade the nation’s aging pipelines.

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The following table summarizes the allocation of the purchase price to the fair value of the assets acquired and liabilities assumed.

(In millions)
Working capital assets	$	21.5
Working capital liabilities		(6.7	)
Net working capital		14.8
Property, plant & equipment		34.4
Identifiable intangible assets		19.1
Goodwill		20.3
Net assets acquired		88.6
Debt obligation assumed		(5.2	)
Cash paid in acquisition, net of cash acquired	$	83.4

Level 3 market inputs, such as discounted cash flows, revenue growth rates, royalty rates, and dealer and auction values of used equipment, were used to derive the preliminary fair values of the identifiable intangible assets and property plant and equipment.  Identifiable intangible assets include backlog, long-term customer relationships, and trade name.  The Company intends to use the acquired assets for an extended period and is amortizing them on a straight-line basis over their estimated useful lives.  Goodwill arising from the purchase represents intangible value the Company expects to realize over time.  This value includes but is not limited to: 1) expected synergies from more efficient utilization of equipment and human resources within the combined entities; 2) the experience and size of the acquired work force; and 3) the reputation of the current Minnesota Limited management team.  The purchase price and its allocation remain preliminary and could still change during the first quarter of 2012.

Transaction costs associated with the acquisition and expensed by the Company totaled approximately $0.6 million, of which $0.2 million are included in Other operating expenses during the year ended December 31, 2011 and the remainder was expensed in 2010.  For the period from April 1, 2011 through December 31, 2011, Minnesota Limited contributed approximately $116.5 million to the Company's Nonutility revenues, $29.1 million of Cost of nonutility revenues, and $63.4 million of Other operating expenses.

Concurrent with the purchase agreement, the Company executed a lease arrangement at fair value for the Minnesota Limited corporate headquarters, which is owned by a member of the Minnesota Limited management team and certain family members.  The lease obligates the Company to pay approximately $83,333 per month for 10 years along with certain executory costs for taxes and other operating expenses.  Pursuant to FASB guidance, the Company accounts for the obligation as an operating lease, expensing the lease payments and executory costs as incurred.

Energy Services

Energy Services provides energy performance contracting and renewable energy services through Energy Systems Group, LLC (ESG).  Inclusive of holding company costs, Energy Services’ operations contributed earnings of $6.7 million in 2011, compared to earnings of $6.4 million in 2010 and $8.4 million in 2009.

The 5 percent increase in earnings in 2011 compared to 2010 reflects a 10 percent increase in revenues.  The increased sales and related tax impacts provided an offset to increased sales force ramp up including recruitment costs incurred throughout the year.  Results in 2009 were favorably impacted by a renewable energy project.  As part of ESG’s ongoing renewable energy project development strategy, results in 2009 include the sale of a 3 megawatt landfill gas facility.  With IURC approval, the facility was sold to SIGECO, to further the utility’s strategy of building a renewable energy portfolio.

At December 31, 2011, backlog was $82 million compared to $118 million at December 31, 2010, and $70 million at December 31, 2009.  The national focus on a comprehensive energy strategy and a continued focus on energy conservation, renewable energy, and sustainability are expected to create favorable conditions for long-term growth in this area.

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Coal Mining

Coal Mining owns mines that produce and sell coal to the Company’s utility operations and to third parties through its wholly owned subsidiary Vectren Fuels, Inc. (Vectren Fuels).  Coal Mining, inclusive of holding company costs, earned approximately $16.6 million, compared to earnings of $11.9 million in 2010 and $13.4 million in 2009. 

Coal Mining revenues were $285.6 million in 2011 and represent increases of $75.7 million compared to 2010 and $92.2 million compared to 2009.  The increase in revenues reflects increased sales to third parties as a result of opening Oaktown 1 in 2010.  Revenues from Oaktown 1 more than offset lost revenues from the Cypress Creek surface mine which closed in 2010 with only limited production.  In 2010, the expected higher depreciation and other mining costs as well as higher interest costs associated with the ramp up of mining at the Oaktown mine complex more than offset the increase in sales.  Coal sold in 2011 was 5.2 million tons, compared to 3.7 million tons in 2010 and 3.5 million tons in 2009.

Vectren Fuels is currently in negotiation with a number of customers regarding sales in 2012 and beyond.  Vectren Fuels and Vectren South have adjusted both the price and quantity of coal through the remaining terms of contracts that had price reopener clauses.  Pursuant to the supply contracts, Vectren Fuels expects to supply Vectren South, including its plant jointly owned with ALCOA, approximately 1.8 million tons in 2012.  Sales to Vectren South are estimated between 2.1 million and 2.5 million tons in 2013.  While both production and sales are expected to increase in 2012, the impact of lower prices is expected to more than offset the higher volumes, and earnings from Coal Mining operations in 2012 are expected to be lower than results in 2011.  However, changes in market conditions or other circumstances could cause actual results to be materially different from this expectation.

Coal Reserves

As of December 31, 2011 management estimates the Company’s total Illinois Basin coal reserves to be approximately 132 million tons.  Of this amount, approximately 39 million tons are attributable to a mine located at the Company’s Oaktown mining complex that is currently under construction and is expected to open in the third quarter of 2012.  However, Vectren Fuels may continue to adjust this timing as it evaluates the impacts of market conditions.  The Company estimates approximately $10 million of additional capital is required to complete the mine.  Once this mine is in production, Vectren Fuels underground mines are capable of producing about 7.5 million tons of coal per year.

Energy Marketing

Energy Marketing is comprised of the Company’s gas marketing operations, energy management services, and retail gas supply operations.  Inclusive of holding company costs, results from Energy Marketing were a loss of $4.2 million for the years ended December 31, 2011 and 2010 and earnings of $4.1 million in 2009.  The loss in 2011 includes a gain on the sale of Vectren Source which totaled $15.8 million after current taxes.   The earnings in 2009 include the $11.9 million after tax Liberty Charge

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 Citizens’ utilities.  ProLiance’s primary businesses include gas marketing, gas portfolio optimization, and other portfolio and energy management services.  Consistent with its ownership percentage, Vectren is allocated 61 percent of ProLiance’s profits and losses; however, governance and voting rights remain at 50 percent for each member.  Therefore, the Company accounts for its investment in ProLiance using the equity method of accounting.  On March 17, 2011, an order was received from the IURC providing for ProLiance’s continued provision of gas supply services to the Company’s Indiana utilities and Citizens Energy Group through March 2016. 

Vectren Energy Marketing and Services, Inc (EMS), a wholly owned subsidiary, holds the Company’s investment in ProLiance.  Within the consolidated entity, EMS is responsible for certain financing costs associated with ProLiance and is also responsible for income taxes and allocated corporate expenses related to the Company’s portion of ProLiance’s results.  During the year ended December 31, 2011, EMS’ results related to the Company’s share of ProLiance’s results, which include financing costs and income taxes, was a loss of approximately $22.9 million, compared to a loss of $7.9 million in 2010 and a loss of $2.3 million in 2009.

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The $15.0 million increased loss in 2011 and $22.1 million of the increased loss in 2010 (which is before the Liberty Charge) reflect the impact on the market of new natural gas sources from shale and greater transmission capacity, as well as the impacts of reduced industrial demand for natural gas in the Midwest.  These conditions have resulted in plentiful natural gas supply and lower and less volatile natural gas prices. Historical basis differences between physical and financial markets and summer and winter prices narrowed in 2011.  As a result, there were reduced opportunities to optimize ProLiance’s firm transportation and storage capacity.  ProLiance has structured optimization activities to remain flexible to maximize potential opportunities if market conditions improve and as an example has hedged nearly 25 Bcf of storage against next winter at higher margins than in 2011.

Various profit improvement initiatives are underway, including efforts to lower the cost of pipeline and storage demand costs through ongoing renegotiations.  Through these negotiations and by dropping some uneconomical contracts as they expire, pipeline transportation and storage costs have been lowered to approximately $55 million in 2012, compared to $73 million in 2011.  In addition to this reduction, additional opportunities exist to renegotiate or drop the remaining contracts, including those with annual demand costs of $18 million that are scheduled to expire through 2015.  At December 31, 2011, ProLiance had just over $160 million of members’ equity on its balance sheet, no long-term debt outstanding, and $86 million in seasonal borrowings on its short-term credit facility.  Depressed market conditions continue, but the demand savings and other actions are expected to reduce ProLiance’s losses in 2012.  Changes in these market conditions or other circumstances could cause actual results to be materially above or below this range.

For the year ended December 31, 2011, the amounts recorded to Equity in earnings (losses) of unconsolidated affiliates related to ProLiance’s operations totaled a pre-tax loss of $28.6 million, compared to a loss of $2.5 million in 2010 and earnings of $3.6 million in 2009.

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 site, and an additional capacity of at least 17 Bcf at the South site.  The South site also has the potential for further expansion.  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. 

In late 2008, the project at the North site was halted due to subsurface and well-completion problems, resulting in Liberty recording a $132 million impairment charge related to the North site in 2009.  ProLiance recorded its share of the charge in 2009 totaling $33 million.  The Company’s share was $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 (losses) of unconsolidated affiliates and an income tax benefit reflected in Income taxes of approximately $8.0 million.  ProLiance’s ability to meet the needs of its customers has not been, nor does it expect it to be, impacted.  Approximately 12 Bcf of the storage at the South site, which comprises three of the four FERC certified caverns, is fully completed and tested.  As a result of the issues encountered at the North site, Liberty requested and the FERC approved the separation of the North site from the South site.  As of December 31, 2011 and 2010, ProLiance’s investment in Liberty approximated $35.1 million and $36.7 million, respectively.

Liberty received a Demand for Arbitration from Williams Midstream Natural Gas Liquids, Inc. (“Williams”) on February 8, 2011 related to a Sublease Agreement (“Sublease”) between Liberty and Williams at the North site.  Williams alleges that Liberty was negligent in its attempt to convert certain salt caverns to natural gas storage and thereby damaged the caverns.  Williams alleges damages of $56.7 million.  Liberty intends to vigorously defend itself and has asserted counterclaims substantially in excess of the amounts asserted by Williams. 

Vectren Source

Vectren Source, a former wholly owned subsidiary, provides natural gas and other related products and services to customers opting for choice among energy providers.  On December 31, 2011, the Company sold Vectren Source receiving proceeds of approximately $84.3 million, including, and subject to a final determination of, working capital.  The sale, net of transaction costs, resulted in a pretax gain included in Other operating expenses of $25.4 million, or $12.4 million after all associated tax impacts.  VEDO continues doing business with Vectren Source, now owned by a third party.  Vectren Source sells natural gas directly to customers in VEDO’s service territory, and VEDO purchases receivables and natural gas from Vectren Source.  Prior to the sale, Vectren Source earned $2.8 million in 2011, compared to $3.7 million in 2010 and $6.4 million in 2009. Vectren Source’s customer count at the time of sale was approximately 283,000 customers.

 

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Other Businesses

Within the Nonutility business segment, there are legacy investments involved in energy-related opportunities and services, real estate, leveraged leases, and other ventures.  As of December 31, 2011, remaining legacy investments included in the Other Businesses portfolio total $36.9 million, of which $29.6 million are included in Other nonutility investments and $7.3 million are included in Investments in unconsolidated affiliates.  Further separation of that remaining investment by type of investment follows: commercial real estate $8.0 million; leveraged leases $18.5 million; affordable housing projects $3.1 million; Haddington Energy Partners $3.4 million; and other investments $3.9 million.  Net of deferred taxes related to these leveraged leases, the net investment at December 31, 2011 was $23.1 million.  Subsequent to year end, the Company sold one of its leverage leases with a book value of $5.2 million, before the consideration of related deferred taxes of $2.5 million, at a small gain.

Other Businesses losses were $10.2 million in 2011, compared to a loss of $7.4 million in 2010 and a loss of $2.5 million in 2009. Results in 2011 include charges totaling $9.2 million after tax associated with legacy real estate holdings.  Results in 2010 reflect a $4.0 million after tax charge related to a decline in the fair value of an energy-related investment originally made in 2004 by Haddington Energy Partners and a $2.9 million after tax charge related to the reduction in value of a note receivable recorded in 2002 related to a previously exited business.

2011 Commercial Real Estate Charge

During the fourth quarter of 2011, the Company obtained new evidence confirming further weakness in markets where the Company holds legacy real estate investments.  The Company holds real estate investments such as an office building, affordable housing projects, and second mortgages. The evaluation of the evidence resulted in a $15.4 million, or $9.2 million after tax, charge in 2011. Of the $15.4 million charge, $8.8 million is reflected in Other-net, $3.6 million is reflected in Equity in earnings/losses of unconsolidated affiliates, and $3.0 million is reflected in Other operating expenses.

Haddington Energy Partnerships

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

During 2010, the Company recorded its share of the decline in fair value and also impaired a note receivable associated with Haddington’s investment in a liquefied natural gas facility.  In total, the charge was approximately $6.5 million, of which, $6.1 million is reflected in Equity in earnings of unconsolidated affiliates and $0.4 million is reflected in Other-net.  At December 31, 2011, the Company’s remaining $3.4 million investment in the Haddington ventures is related to payments to be received associated with the sale of a compressed air storage facility sold in 2009.  The Company has no further commitments to invest in either Haddington I or II.  

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Impact of Recently Issued Accounting Guidance

Other Comprehensive Income (OCI)

In June 2011, the FASB issued new accounting guidance regarding the presentation of comprehensive income within financial statements.  The new guidance will require entities to report components of comprehensive income in either (1) a continuous statement of comprehensive income or (2) two separate but consecutive statements.  Under the two-statement approach, the first statement would include components of net income, which is consistent with the income statement format used today, and the second statement would include components of OCI.  The guidance does not change the items that must be reported in OCI.  The new guidance is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011 and retrospective application is required.  The Company will adopt this guidance for its quarterly reporting period ending March 31, 2012.  The adoption of this guidance will have no material impacts to the Company’s financial statements.

Goodwill Testing

In September 2011, the FASB issued new accounting guidance regarding testing goodwill for impairment.  The new guidance will allow the Company an option to first assess qualitative factors to determine whether it is necessary to perform the two-step quantitative goodwill impairment test.  Using the new guidance, the Company no longer would be required to calculate the fair value of a reporting unit unless the Company determines, based on that qualitative assessment, that it is more likely than not that its fair value is less than its carrying amount.  The new guidance is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011.  The adoption of this guidance will have no material impact to the Company’s financial statements.

Multiemployer Pension Plan Disclosures

In September 2011, the FASB issued new accounting guidance that requires enhanced disclosures regarding an employer’s participation in multiemployer pension plans.  For plans that are individually significant, these enhanced disclosures include the legal name of the plan, the plan’s Employer Identification Number, the employer’s contributions made to the plan, the expiration date(s) of the collective-bargaining agreement(s) requiring contributions to the plan, the most recently available certified zone status provided by the plan, and several other disclosures.  The Company participates in several multiemployer pension plans and has adopted this guidance for the Company’s 2011 financial statements as required.

Fair Value Measurement and Disclosure

In May 2011, the FASB issued accounting guidance to improve the comparability of fair value measurements presented and disclosed in financial statements prepared in accordance with U.S. GAAP and International Financial Reporting Standards (IFRS). The amendments are not intended to change the application of the current fair value requirements, but to clarify the application of existing requirements. The guidance does change particular principles or requirements for measuring fair value or disclosing information about fair value measurements. To improve consistency, language has been changed to ensure that U.S. GAAP and IFRS fair value measurement and disclosure requirements are described in the same way. The guidance will be effective for interim and annual periods beginning after December 15, 2011. The Company will adopt this guidance for its quarterly reporting period ending March 31, 2012.  We do not expect the adoption of this guidance to have a material impact on our financial position, results of operations or cash flows.

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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, and estimating uncollectible accounts and coal reserves, among others.  Actual results could differ from these estimates.

Impairment Review of Investments and Long-Lived Assets

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

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

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.

Over the year’s presented, the Company has recorded charges associated with legacy commercial real estate and other investments using the methods described above and also has reflected its portion of charges taken by equity method investees using these or similar methods.  The $15.4 million in charges impacting 2011 operating results principally reflects recent appraisals and third party offers on similar properties.  Should market conditions worsen, additional impairments affecting these and other assets could result and actual realized values could differ from the current carrying values.

Goodwill & Intangible Assets

The Company performs an annual impairment analysis of its goodwill, most of which resides in the Gas Utility Services operating segment, at the beginning of each year, and more frequently if events or circumstances indicate that an impairment loss may have been incurred.  Impairment tests are performed at the reporting unit level.  The Company has determined its Gas Utility Services operating segment as identified in Note 22 to the consolidated financial statements to be the level at which impairment is tested as its components are similar.  Nonutility Group impairment testing for its infrastructure services and energy services segments are also performed at the operating segment level.  An impairment test requires fair value to 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.  Goodwill related to the Nonutility Group is also tested using market comparable data, if readily available, or a discounted cash flow model.  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.

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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 2011 periodic benefit cost:  a discount rate of 5.5 percent, an expected return on plan assets of 8.0 percent, a rate of compensation increase of 3.5 percent, and an inflation assumption of 3.0 percent.  Due to low interest rates, the discount rate is 50 basis points lower from the assumption used in 2010.  To estimate 2012 costs, the discount rate, expected return on plan assets, rate of compensation increase, and inflation assumption were approximately 4.80 percent, 7.75 percent, 3.5 percent, and 2.75 percent respectively, reflecting the further reductions in interest rates.  Management currently estimates a pension and postretirement cost of approximately $16 million in 2012, compared to approximately $13 million in 2011, $14 million in 2010, and $15 million in 2009.  Future changes in health care costs, work force demographics, interest rates, asset values or plan changes could significantly affect the estimated cost of these future benefits.

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

Unbilled Revenues

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

Regulation

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

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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 debt, including current maturities, and short-term obligations outstanding at December 31, 2011 approximated $410 million and $84 million, respectively.  Utility Holdings’ outstanding long-term and short-term borrowing arrangements are jointly and severally guaranteed by Indiana Gas, SIGECO, and VEDO.  Utility Holdings’ long-term debt, including current maturities, and short-term obligations outstanding at December 31, 2011 approximated $722 million and $243 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.  Total Indiana Gas and SIGECO long-term debt outstanding at December 31, 2011, was $388 million.

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, 2011, are A-/A3 as rated by Standard and Poor's Ratings Services (Standard and Poor’s) and Moody’s Investors Service (Moody’s), respectively.  The credit ratings on SIGECO's secured debt are A/A1.  Utility Holdings’ commercial paper has a credit rating of A-2/P-2.  The current outlook of both Moody’s and Standard and Poor’s is stable.  A security rating is not a recommendation to buy, sell, or hold securities.  The rating is subject to revision or 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 47 percent and 46 percent of long-term capitalization at December 31, 2011 and 2010, respectively.  Long-term capitalization includes long-term debt, including current maturities and debt subject to tender, as well as common shareholders’ equity.

Both long-term and short-term borrowing arrangements contain customary default provisions; restrictions on liens, sale-leaseback transactions, mergers or consolidations, and sales of assets; and restrictions on leverage and interest coverage, among other restrictions.  Multiple debt agreements contain a covenant that the ratio of consolidated total debt to consolidated total capitalization will not exceed 65 percent.  As of December 31, 2011, the Company was in compliance with all debt covenants.

Available Liquidity in Current Credit Conditions

The Company’s A-/A3 investment grade credit ratings have allowed it to access the capital markets as needed.  The Company anticipates funding future capital expenditures and dividends principally through internally generated funds.  Available liquidity has been enhanced by the extension of bonus depreciation legislation.  However, the resources required for capital investment remain uncertain for a variety of factors including pending legislative and regulatory initiatives involving gas pipeline modernization; coal mine safety; and expanded EPA regulations for air, water, and fly ash.  In addition, the Company may expand its businesses through acquisitions and/or joint venture investment.  The timing and amount of such investments depends on a variety of factors, including the availability of acquisition targets and forecasted liquidity.  The Company plans to enhance its liquidity as needed by accessing the capital markets.  The Company may also consider disposing of certain assets, investments, or businesses to enhance or accelerate internally generated cash flow.

Long-term debt transactions completed in 2011, 2010, and 2009 include issuances by Vectren Capital totaling $275 million and issuances by Vectren Utility Holdings totaling $250 million.  SIGECO also remarketed $41.3 million of long-term debt and completed a $22.3 million tax-exempt first mortgage bond issuance.  Vectren Utility Holdings also issued $100 million of long-term debt in February 2012.  These transactions are more fully described below.  (See Financing Cash Flow.)

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Consolidated Short-Term Borrowing Arrangements

At December 31, 2011, the Company has $600 million of short-term borrowing capacity, including $350 million for the Utility Group and $250 million for the wholly owned Nonutility Group and corporate operations.  As reduced by borrowings currently outstanding, approximately $107 million was available for the Utility Group operations and approximately $166 million was available for the wholly owned Nonutility Group and corporate operations.  These facilities are used to supplement working capital needs and also to fund capital investments and debt redemptions until financed on a long-term basis.  Liquidity was increased by the $100 million Utility Holdings debt issuance in February 2012, the net proceeds of which were used to repay short-term indebtedness.

Both Vectren Capital’s and Utility Holdings’ short-term credit facilities were renewed in November 2011 and are available through September 2016.  The maximum limit of both facilities remained unchanged.  The Company has historically funded the short-term borrowing needs of Utility Holdings’ operations through the commercial paper market and expects to use the Utility Holdings short-term borrowing facility in instances where the commercial paper market is not efficient.  Following is certain information regarding these short-term borrowing arrangements.

	Utility Group Borrowings									Nonutility Group Borrowings
(In millions)	2011			2010			2009			2011			2010			2009
Year End
Balance Outstanding	$	242.8		$	47.0		$	16.4		$	84.3		$	71.3		$	197.1
Weighted Average Interest Rate		0.57	%		0.41	%		0.25	%		1.45	%		2.01	%		0.60	%
Annual Average
Balance Outstanding	$	39.6		$	14.0		$	29.2		$	124.9		$	143.2		$	151.8
Weighted Average Interest Rate		0.48	%		0.40	%		1.28	%		1.92	%		0.93	%		0.78	%
Maximum Month End Balance Outstanding	$	242.8		$	47.0		$	151.1		$	180.1		$	174.6		$	256.5

Throughout 2011, 2010, and most of 2009, the Company has placed commercial paper without any significant issues and only had to borrow from its backup credit facility in early 2009 on a limited basis.

ProLiance Short-Term Borrowing Arrangements

ProLiance, a nonutility energy marketing affiliate of the Company, has separate borrowing capacity available through a syndicated credit facility.  This facility was renewed on May 18, 2011 at a $130 million capacity level as adjusted for letters of credit and current inventory and receivable balances.  This new one year credit facility reflects the impact of lower gas prices and resulting lower working capital need.  As of December 31, 2011, $85.5 million in borrowings were outstanding.  The facility is not guaranteed by Vectren or Citizens.  ProLiance is currently working with financial institutions on replacement of the facility before expiration.

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 $7.9 million in 2011, $14.0 million in 2010, and $5.8 million in 2009.

Potential Uses of Liquidity

Pension & Postretirement Funding Obligations

As of December 31, 2011, asset values of the Company’s qualified pension plans were approximately 83 percent of the projected benefit obligation.  Management currently estimates contributing approximately $15 million to qualified pension plans in 2012. Contributions in 2013 and beyond are dependent on a variety of factors, including the Company’s progress toward attaining its long-term goal of being fully funded related to the plans’ accrued benefit obligations and the available sources of cash to fund such additional contributions.

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Corporate Guarantees

The Company issues parent level 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, 2011, parent level guarantees support a maximum of $25 million of ESG’s performance contracting commitments and warranty obligations and $27 million of other project guarantees.  The broader scope of ESG’s performance contracting obligations, including those not guaranteed by the parent company, are described below.  In addition, the parent company has approximately $25 million of other guarantees outstanding supporting other consolidated subsidiary operations, of which $20 million represent letters of credit supporting other nonutility operations.  Guarantees issued and outstanding on behalf of unconsolidated affiliates approximated $3 million at December 31, 2011.  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.

As a result of the sale of Vectren Source on December 31, 2011, the Company has $56 million of outstanding guarantees related to this formerly wholly owned subsidiary that will remain in effect for up to 90 days after the closing.  The buyer’s parent will hold the Company harmless if any amounts are required to be paid pursuant to these guarantees and, within the 90 day period, the buyer is required to provide its own guarantees in substitution for the Company guarantees.

Performance Guarantees & Product Warranties

In the normal course of business, wholly owned subsidiaries, including ESG, 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, 2011, there are 78 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 $25.7 million.  The maximum exposure of these obligations is less than these amounts for several factors, including the level of work already completed.  At December 31, 2011, approximately 60 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.

Other Letters of Credit

As of December 31, 2011, Utility Holdings has letters of credit outstanding in support of two SIGECO tax exempt adjustable rate first mortgage bonds totaling $41.7 million.  In the unlikely event the letters of credit were called, the Company could settle with the financial institutions supporting these letters of credit with general assets or by drawing from its credit facility that expires in September 2016.  Due to the long-term nature of the credit agreement, such debt is classified as long-term at December 31, 2011.

Planned Capital Expenditures & Investments

During 2011 capital expenditures and other investments approximated $320 million, of which approximately $230 million related to Utility Group expenditures.  This compares to 2010 where consolidated investments were approximately $280 million with $230 million attributed to the Utility Group and 2009 where consolidated investments exceeded $400 million with over $300 million attributed to the Utility Group.  Planned Utility Group capital expenditures, including contractual purchase commitments, for the five-year period 2012 – 2016 are expected to be more consistent with expenditures made in 2011 and 2010 and total approximately (in millions):  $250, $270, $260, $260, and $260, respectively.

Planned Nonutility Group capital expenditures for mine development and recurring infrastructure investments, including contractual purchase commitments, for the five-year period 2012 – 2016 are expected to total (in millions):  $120, $80, $70, $80, and $80, respectively.  In addition, the Company may expand its Infrastructure Services business through acquisitions and/or make investments in renewable energy projects, among other growth strategies.  The timing and amount of such investments depends on a variety of factors, including the availability of acquisition targets, energy demand, and forecasted liquidity.

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Contractual Obligations

The following is a summary of contractual obligations at December 31, 2011:

(In millions)	Total		2012		2013		2014		2015		2016		Thereafter
Long-term debt (1)	$	1,622.3	$	62.7	$	106.4	$	30.0	$	179.8	$	73.0	$	1,170.4
Short-term debt		227.1		227.1		-		-		-		-		-
Long-term debt interest commitments		1,174.3		88.7		84.6		79.9		78.7		66.1		776.3
Nonutility commodity purchase commitments		4.3		2.9		1.4		-		-		-		-
Plant purchase commitments		60.1		52.9		3.6		-		-		-		-
Operating leases		17.9		4.7		3.8		2.5		1.5		1.1		4.3
Total (2)	$	3,106.0	$	439.0	$	199.8	$	112.4	$	260.0	$	140.2	$	1,951.0

(1)   The debt due in 2012 is comprised of debt issued by Vectren Capital totaling $60 million and $2.7 million associated with the Company’s nonutility operations.

(2)   The Company has other long-term liabilities that total approximately $239 million.  This amount is comprised of the following:  pension obligations $68 million, postretirement obligations $75 million, deferred compensation and share-based compensation obligations $30 million, asset retirement obligations $44 million, investment tax credits $4 million, environmental remediation obligations $6 million, and other obligations including unrecognized tax benefits totaling $12 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 $416.9 million in 2011, compared to $384.8 million in 2010 and $449.6 million in 2009.

The $32.1 million increase in operating cash flow in 2011 compared to 2010 is primarily due to a much greater level of cash utilized from working capital in 2010 and increased earnings and non-cash charges in 2011.  These increases were partially offset by a higher level of employer contributions to pension and postretirement plans in 2011.

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

Tax payments in the periods presented were favorably impacted by federal legislation extending bonus depreciation and a change in the tax method for recognizing repair and maintenance activities.  Federal legislation allowing bonus depreciation on qualifying capital expenditures was increased to 100 percent for 2011 and continues at 50 percent for 2012.  A significant portion of the Company’s capital expenditures qualify for this bonus treatment.

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Financing Cash Flow

Financing cash flow reflects the Company’s utilization of the long-term capital markets and the current low interest rate environment. In 2011, and as impacted by the $100 million long-term debt issuance in February 2012, the Company has refinanced at lower rates approximately $346.2 million of maturing or callable long-term debt, with $250 million of new long-term debt and short-term borrowings.  These lower rates began to favorably impact interest expense in the fourth quarter of 2011, and will decrease interest more significantly in 2012.  Long-term financing transactions completed in 2010 and 2009 were used to refinance over $400 million of short-term borrowings.  The Company’s operating cash flow funded over 95 percent of capital expenditures and dividends in 2011 and 2010 and over 80 percent in 2009.  Recently completed long-term financing transactions are more fully described below.

Utility Holdings 2012 Debt Issuance

On February 1, 2012, Utility Holdings issued $100 million of senior unsecured notes at an interest rate of 5.00 percent per annum and with a maturity date of February 3, 2042.  The notes were sold to various institutional investors pursuant to a private placement note purchase agreement executed in November 2011 with a delayed draw feature.  These senior notes are unsecured and jointly and severally guaranteed by Utility Holdings’ regulated utility subsidiaries, Southern Indiana Gas and Electric Company (SIGECO), Indiana Gas Company, Inc. (Indiana Gas), and Vectren Energy Delivery of Ohio, Inc. (VEDO).  The proceeds from the sale of the notes, net of issuance costs, totaled approximately $99.5 million.  These notes have no sinking fund requirements and interest payments are due semi-annually.  These notes contain customary representations, warranties and covenants, including a leverage covenant consistent with leverage covenants contained in other Utility Holdings’ borrowing arrangements.As of December 31, 2011, the Company has reclassified $100 million of short-term borrowings as long-term debt to reflect those borrowings were refinanced with the proceeds received.  The proceeds received from the issuance of the senior notes was used to refinance VUHI’s $96.2 million 5.95 percent senior notes due 2036, that were called at par and retired on Nov. 21, 2011.

Utility Holdings 2011 Debt Issuance

On November 30, 2011, Utility Holdings closed a financing under a private placement note purchase agreement pursuant to which various institutional investors purchased the following tranches of notes:  (i) $55 million of 4.67 percent Senior Guaranteed Notes, due November 30, 2021, (ii) $60 million of 5.02 percent Senior Guaranteed Notes, due November 30, 2026, and (iii) $35 million of 5.99 percent Senior Guaranteed Notes, due December 2, 2041.  These senior notes are unsecured and jointly and severally guaranteed by Utility Holdings’ regulated utility subsidiaries, SIGECO, Indiana Gas, and VEDO.  The proceeds from the sale of the notes, net of issuance costs, totaled approximately $148.9 million.  These notes have no sinking fund requirements and interest payments are due semi-annually.  These notes contain customary representations, warranties and covenants, including a leverage covenant consistent with leverage covenants contained in other Utility Holdings’ borrowing arrangements.Proceeds received from the issuance were used to partially refinance $250 million of VUHI long-term debt with an interest rate of 6.625 percent that matured Dec. 1, 2011.

Vectren Capital Corp. 2010 Debt Issuance

On December 15, 2010, the Company and Vectren Capital closed a financing under a private placement note purchase agreement pursuant to which various institutional investors purchased the following tranches of notes from Vectren Capital:  (i) $75 million 3.48 percent Senior Notes, Series A due 2017, and (ii) $50 million 4.53 percent Senior Notes, Series B due 2025.  These Senior Notes are unconditionally guaranteed by Vectren.  The proceeds from the issuance replaced $48 million debt maturities due in December 2010 and provided long-term financing for some nonutility investments originally financed with short-term borrowings.  These notes have no sinking fund requirements and interest payments are due semi-annually.  The proceeds from the sale of the notes, net of issuance costs, totaled approximately $124.2 million.  These notes contain customary representations, warranties and covenants, including a leverage covenant consistent with leverage covenants contained in other Vectren Capital borrowing arrangements.

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Vectren Capital Corp. 2009 Debt Issuance

On March 11, 2009, Vectren and Vectren Capital closed a financing under a private placement Note Purchase Agreement (the “2009 Note Purchase Agreement”) pursuant to which various institutional investors purchased the following tranches of notes from Vectren Capital: (i) $30 million in 6.37 percent senior notes, Series A due 2014, (ii) $60 million in 6.92 percent senior notes, Series B due 2016 and (iii) $60 million in 7.30 percent senior notes, Series C due 2019. These senior notes are unconditionally guaranteed by Vectren, the parent of Vectren Capital.  These notes have no sinking fund requirements and interest payments are due semi-annually.  The proceeds from the sale of the notes, net of issuance costs, totaled approximately $149.0 million.  The 2009 Note Purchase Agreement contains customary representations, warranties and covenants, including a leverage covenant consistent with leverage covenants contained in other Vectren Capital borrowing arrangements.  On March 11, 2009, Vectren and Vectren Capital also entered into a first amendment with respect to prior note purchase agreements for the remaining outstanding Vectren Capital debt, other than the $22.5 million series due in 2010, to conform the covenants in certain respects to those contained in the 2009 Note Purchase Agreement.

Utility Holdings 2009 Debt Issuance

On April 7, 2009, Utility Holdings closed a financing under a private placement note purchase agreement pursuant to which institutional investors purchased from Utility Holdings $100 million in 6.28 percent senior unsecured notes due April 7, 2020 (2020 Notes).  The 2020 Notes are guaranteed by Utility Holdings’ three utilities:  SIGECO, Indiana Gas, and VEDO.  These guarantees are full and unconditional and joint and several.  The proceeds from the sale of the 2020 Notes, net of issuance costs, totaled approximately $99.5 million.  The 2020 Notes have no sinking fund requirements and interest payments are due semi-annually.  The 2020 Notes contain customary representations, warranties and covenants, including a leverage covenant consistent with leverage covenants contained in other Utility Holdings’ borrowing arrangements.

SIGECO 2009 Debt Issuance

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

Auction Rate Securities

On March 26, 2009, SIGECO remarketed the remaining $41.3 million of its auction rate securities obligations, receiving proceeds, net of issuance costs of approximately $40.6 million.  The remarketed notes have a variable rate interest rate which is reset weekly and are supported by a standby letter of credit.  The notes are collateralized by SIGECO’s utility plant, and $9.8 million are due in 2015 and $31.5 million are due in 2025.

Long-Term Debt Puts & Calls

Certain long-term debt issues contain put and call provisions that can be exercised on various dates before maturity.  Certain instruments can be put to the Company upon the death of the holder (death puts).  During 2011, 2010, and 2009, the Company repaid approximately $0.8 million, $1.8 million, and $3.0 million, respectively, related to death puts.

On October 21, 2011, the Company notified holders of Utility Holdings $96.2 million 5.95 percent senior notes due 2036, of its intent to call those notes.  This call option was exercised at par on November 21, 2011.

Investing Cash Flow

Cash flow required for investing activities was $319.7 million in 2011, $269.0 million in 2010, and $431.1 million in 2009.  Capital expenditures are the primary component of investing activities and totaled $321.3 million in 2011, $277.2 million in 2010 compared to $431.1 million in 2009.  The increase in capital expenditures in 2011 compared to 2010 primarily reflects a $35.8 million increase in nonutility projects including expenditures for the Oaktown coal mines, infrastructure services equipment, and renewable energy projects.  Increased capital expenditures within the Utility Group primarily related to bare steel cast iron replacement projects.  Investing cash flow in 2011 was also impacted by the purchase of Minnesota Limited and the sale of Vectren Source.

The decrease in capital expenditures in 2010 compared to 2009 reflects the roughly $20 million spent in 2009 associated with the January 2009 ice storm restoration projects and approximately $55 million in lower other utility capital spending as well as approximately $90 million in lower expenditures relating to Coal Mining, primarily Oaktown mine development costs.

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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 inflation rates, commodity prices, and monetary fluctuations.

·   Economic conditions surrounding the current economic uncertainty, including significantly lower levels of economic activity; uncertainty regarding energy prices and the capital and commodity markets; volatile changes in the demand for natural gas, electricity, coal, and other nonutility products and services; impacts on both gas and electric large customers; lower residential and commercial customer counts; higher operating expenses; and further reductions in the value of certain nonutility real estate and other legacy investments.

·   Volatile natural gas and coal commodity prices and the potential impact on customer consumption, uncollectible accounts expense, unaccounted for gas and interest expense.

·   Changing market conditions and a variety of other factors associated with physical energy and financial trading activities including, but not limited to, price, basis, credit, liquidity, volatility, capacity, interest rate, and warranty risks.

·   Direct or indirect effects on the Company’s business, financial condition, liquidity and results of operations resulting from changes in credit ratings, changes in interest rates, and/or changes in market perceptions of the utility industry and other energy-related industries.

·   The performance of projects undertaken by the Company’s nonutility businesses and the success of efforts to invest in and develop new opportunities, including but not limited to, the Company’s infrastructure, energy services, coal mining, and energy marketing strategies.

·   Factors affecting coal mining operations including MSHA guidelines and interpretations of those guidelines, as well as additional mine regulations and more frequent and broader inspections that could result from the recent mining incidents at coal mines of other companies; geologic, equipment, and operational risks; the ability to execute and negotiate new sales contracts and resolve contract interpretations; volatile coal market prices and demand;  supplier and contract miner performance; the availability of key equipment, contract miners and commodities; availability of transportation; and the ability to access/replace coal reserves.

·   Factors affecting the Company’s investment in ProLiance including natural gas price volatility and basis; the ability to lower fixed contract costs; and availability of credit.

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·   Employee or contractor workforce factors including changes in key executives, collective bargaining agreements with union employees, aging workforce issues, work stoppages, or pandemic illness.

·   Risks associated with material business transactions such as mergers, acquisitions and divestitures, including, without limitation, legal and regulatory delays; the related time and costs of implementing such transactions; integrating operations as part of these transactions; and possible failures to achieve expected gains, revenue growth and/or expense savings from such transactions.

·   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.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

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

Commodity Price Risk

Regulated Operations

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

Wholesale Power Marketing

The Company’s wholesale power marketing activities undertake strategies to optimize electric generating capacity beyond that needed for native load.  In recent years, the primary strategy involves the sale of excess generation into the MISO Day Ahead and Real-time markets.  As part of these strategies, the Company may also from time to time execute energy contracts that commit the Company to purchase and sell electricity in future periods.  Commodity price risk results from forward positions that commit the Company to deliver electricity.  The Company mitigates price risk exposure with planned unutilized generation capability.  The Company accounts for any energy contracts that are derivatives at fair value with the offset marked to market through earnings.  No market sensitive derivative positions were outstanding on December 31, 2011 and 2010.

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, 2011 or 2010.

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Other Operations

Other commodity-related operations are exposed to commodity price risk associated with natural gas and coal.  Other commodity-related operations include Vectren Source, a nonutility retail gas marketer prior to its sale on December 31, 2011, coal mining operations, and the operations at ProLiance.  Open positions in terms of price, volume, and specified delivery points may occur and are managed using methods described below with frequent management reporting.

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

Interest Rate Risk

The Company is exposed to interest rate risk associated with its borrowing arrangements.  Its risk management program seeks to reduce the potentially adverse effects that market volatility may have on interest expense.  The Company limits this risk by allowing only an annual average of 15 percent to 25 percent of its total debt to be exposed to variable rate volatility.  However, this targeted range may not always be attained during the seasonal increases in short-term borrowings.  To manage this exposure, the Company may use derivative financial instruments.

Market risk is estimated as the potential impact resulting from fluctuations in interest rates on adjustable rate borrowing arrangements exposed to short-term interest rate volatility.  During 2011 and 2010, the weighted average combined borrowings under these arrangements approximated $206 million and $198 million, respectively.  At December 31, 2011, combined borrowings under these arrangements were $368 million, which excludes the impact of a $100 million long-term debt issuance occurring February 2012.  As December 31, 2010 combined borrowings under these arrangements were $160 million.  Based upon average borrowing rates under these facilities during the years ended December 31, 2011 and 2010, an increase of 100 basis points (one percentage point) in the rates would have increased interest expense by approximately $2 million in each year.

Other Risks

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

The Company’s customer receivables associated with utility operations are primarily derived from residential, commercial, and industrial customers located in Indiana and west central Ohio.  However, some exposure from nonutility operations extends throughout the United States.  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.

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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, 2011.  Management certified this in its Sarbanes Oxley Section 302 certifications, which are attached as exhibits to this 2011 Form 10-K.

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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, 2011 and 2010, 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, 2011. 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, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011, 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, 2011, 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 16, 2012 expressed an unqualified opinion on the Company’s internal control over financial reporting.

/s/ DELOITTE & TOUCHE LLP

Indianapolis, Indiana

February 16, 2012

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of Vectren Corporation:

We have audited the internal control over financial reporting of Vectren Corporation and subsidiaries (the “Company”) as of December 31, 2011, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

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

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

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

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedule as of and for the year ended December 31, 2011 of the Company and our report dated February 16, 2012 expressed an unqualified opinion on those financial statements and financial statement schedule.

/s/ DELOITTE & TOUCHE LLP

Indianapolis, Indiana

February 16, 2012

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VECTREN CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(In millions)

	At December 31,
	2011		2010
ASSETS
Current Assets
Cash & cash equivalents	$	8.6	$	10.4
Accounts receivable - less reserves of $6.7 &           $5.3, respectively		221.3		176.6
Accrued unbilled revenues		121.5		162.0
Inventories		161.9		187.1
Recoverable fuel & natural gas costs		12.4		7.9
Prepayments & other current assets		84.3		101.2
Total current assets		610.0		645.2
Utility Plant
Original cost		4,979.9		4,791.7
Less:  accumulated depreciation & amortization		1,947.3		1,836.3
Net utility plant		3,032.6		2,955.4
Investments in unconsolidated affiliates		92.9		135.2
Other utility & corporate investments		34.4		34.1
Other nonutility investments		29.6		40.9
Nonutility plant - net		550.8		488.3
Goodwill - net		262.3		242.0
Regulatory assets		226.0		189.4
Other assets		40.3		33.7
TOTAL ASSETS	$	4,878.9	$	4,764.2

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

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VECTREN CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(In millions)

	At December 31,
	2011			2010
LIABILITIES & SHAREHOLDERS' EQUITY
Current Liabilities
Accounts payable	$	185.8		$	183.7
Accounts payable to affiliated companies		36.8			59.6
Accrued liabilities		181.1			178.4
Short-term borrowings		227.1			118.3
Current maturities of long-term debt		62.7			250.7
Long-term debt subject to tender		-			30.0
Total current liabilities		693.5			820.7
Long-term Debt - Net of Current Maturities &           Debt Subject to Tender		1,559.6			1,435.2
Deferred Income Taxes & Other Liabilities
Deferred income taxes		575.7			515.3
Regulatory liabilities		345.2			333.5
Deferred credits & other liabilities		239.4			220.6
Total deferred credits & other liabilities		1,160.3			1,069.4
Commitments & Contingencies (Notes 7, 17-20)
Common Shareholders' Equity
Common stock (no par value) – issued & outstanding           81.9 and 81.7, respectively		692.6			683.4
Retained earnings		786.2			759.9
Accumulated other comprehensive income/(loss)		(13.3	)		(4.4	)
Total common shareholders' equity		1,465.5			1,438.9
TOTAL LIABILITIES & SHAREHOLDERS' EQUITY	$	4,878.9		$	4,764.2

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

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VECTREN CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF INCOME

(In millions, except per share amounts)

	Year Ended December 31,
	2011			2010			2009
OPERATING REVENUES
Gas utility	$	819.1		$	954.1		$	1,066.0
Electric utility		635.9			608.0			528.6
Nonutility		870.2			567.4			494.3
Total operating revenues		2,325.2			2,129.5			2,088.9
OPERATING EXPENSES
Cost of gas sold		375.4			504.7			618.1
Cost of fuel & purchased power		240.4			235.0			194.3
Cost of nonutility revenues		385.3			243.3			207.5
Other operating		652.2			538.4			514.0
Depreciation & amortization		244.3			229.1			211.9
Taxes other than income taxes		57.6			62.2			63.0
Total operating expenses		1,955.2			1,812.7			1,808.8
OPERATING INCOME		370.0			316.8			280.1
OTHER INCOME (EXPENSE)
Equity in earnings (losses) of unconsolidated affiliates		(32.0	)		(8.6	)		3.4
Other  income (expense) – net		(3.5	)		4.8			13.7
Total other income (expense)		(35.5	)		(3.8	)		17.1
Interest expense		106.5			104.6			100.0
INCOME BEFORE INCOME TAXES		228.0			208.4			197.2
Income taxes		86.4			74.7			64.1
NET INCOME	$	141.6		$	133.7		$	133.1
AVERAGE COMMON SHARES OUTSTANDING		81.8			81.2			80.7
DILUTED COMMON SHARES OUTSTANDING		81.8			81.3			81.0
EARNINGS PER SHARE OF COMMON STOCK:
BASIC	$	1.73		$	1.65		$	1.65
DILUTED	$	1.73		$	1.64		$	1.64

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

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VECTREN CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)

	Year Ended December 31,
	2011			2010			2009
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	141.6		$	133.7		$	133.1
Adjustments to reconcile net income to cash from operating activities:
Depreciation & amortization		244.3			229.1			211.9
Deferred income taxes & investment tax credits		71.7			69.3			84.9
Equity in (earnings) losses of unconsolidated affiliates		32.0			8.6			(3.4	)
Provision for uncollectible accounts		11.8			16.8			15.1
Expense portion of pension & postretirement benefit cost		9.0			10.0			10.4
(Gain) on sale of business in 2011, net of other non-cash charges		(0.1	)		15.9			13.3
Changes in working capital accounts:
Accounts receivable & accrued unbilled revenue		(17.5	)		(48.3	)		96.9
Inventories		(26.1	)		(19.3	)		(36.1	)
Recoverable/refundable fuel & natural gas costs		(4.5	)		(30.2	)		21.3
Prepayments & other current assets		17.9			(23.5	)		43.1
Accounts payable, including to affiliated companies		(21.2	)		5.5			(85.8	)
Accrued liabilities		6.4			10.2			4.0
Unconsolidated affiliate dividends		0.1			42.7			12.6
Employer contributions to pension & postretirement plans		(38.8	)		(22.0	)		(38.5	)
Changes in noncurrent assets		0.3			(7.6	)		0.2
Changes in noncurrent liabilities		(10.0	)		(6.1	)		(33.4	)
Net cash flows from operating activities		416.9			384.8			449.6
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from:
Long-term debt, net of issuance costs		148.9			124.2			312.5
Dividend reinvestment plan & other common stock issuances		7.9			14.0			5.8
Requirements for:
Dividends on common stock		(113.2	)		(110.8	)		(108.6	)
Retirement of long-term debt		(349.1	)		(49.3	)		(3.5	)
Other financing activities		(2.3	)		(0.2	)		-
Net change in short-term borrowings		208.8			(95.2	)		(306.0	)
Net cash flows from financing activities		(99.0	)		(117.3	)		(99.8	)
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from:
Sale of business		84.3			-			-
Unconsolidated affiliate distributions		0.5			0.5			4.6
Other collections		1.1			10.8			1.5
Requirements for:
Capital expenditures, excluding AFUDC equity		(321.3	)		(277.2	)		(432.0	)
Business acquisition, net of cash acquired		(83.4	)		-
Other investments		(0.9	)		(3.1	)		(5.2	)
Net cash flows from investing activities		(319.7	)		(269.0	)		(431.1	)
Net change in cash & cash equivalents		(1.8	)		(1.5	)		(81.3	)
Cash & cash equivalents at beginning of period		10.4			11.9			93.2
Cash & cash equivalents at end of period	$	8.6		$	10.4		$	11.9

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

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VECTREN CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY

(In millions, except per share amounts)

									Accumulated
	Common Stock								Other
						Retained			Comprehensive
	Shares			Amount		Earnings			Income (Loss)			Total
Balance at January 1, 2009		81.0			659.1		712.8			(20.3	)		1,351.6
Comprehensive income:
Net income							133.1						133.1
Pension/OPEB funded status adjustment - net of $0.4 million in tax										0.5			0.5
Comprehensive income of unconsolidated  affiliates - net of $8.9 million in tax										13.0			13.0
Total comprehensive income													146.6
Common stock:
Issuance:  option exercises & dividend reinvestment plan		0.3			5.8								5.8
Dividends ($1.345 per share)							(108.6	)					(108.6	)
Other		(0.2	)		1.9		(0.1	)					1.8
Balance at December 31, 2009		81.1			666.8		737.2			(6.8	)		1,397.2
Comprehensive income:
Net income							133.7						133.7
Pension/OPEB funded status adjustment - net of $0.2 million in tax										(0.3	)		(0.3	)
Cash flow hedges:
unrealized gains (losses) - net of $1.5 million in tax										2.5			2.5
reclassifications to net income- net of tax										(0.1	)		(0.1	)
Comprehensive income of unconsolidated  affiliates - net of $0.2 million in tax										0.3			0.3
Total comprehensive income													136.1
Common stock:
Issuance:  option exercises & dividend reinvestment plan		0.6			14.0								14.0
Dividends ($1.365 per share)							(110.8	)					(110.8	)
Other					2.6		(0.2	)					2.4
Balance at December 31, 2010		81.7			683.4		759.9			(4.4	)		1,438.9
Comprehensive income:
Net income							141.6						141.6
Pension/OPEB funded status adjustment - net of $0.7 million in tax										(1.0	)		(1.0	)
Cash flow hedges:
unrealized gains (losses) - net of $1.5 million in tax										(2.1	)		(2.1	)
reclassifications to net income- net of tax										(0.3	)		(0.3	)
Comprehensive income of unconsolidated  affiliates - net of $3.8 million in tax										(5.5	)		(5.5	)
Total comprehensive income													132.7
Common stock:
Issuance:  option exercises & dividend reinvestment plan		0.2			7.9								7.9
Dividends ($1.385 per share)							(113.2	)					(113.2	)
Other					1.3		(2.1	)					(0.8	)
Balance at December 31, 2011		81.9		$	692.6	$	786.2		$	(13.3	)	$	1,465.5

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

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VECTREN CORPORATION AND SUBSIDIARY COMPANIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

1.     Organization and Nature of Operations

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

Indiana Gas provides energy delivery services to approximately 563,000 natural gas customers located in central and southern Indiana.  SIGECO provides energy delivery services to approximately 141,000 electric customers and approximately 110,000 gas customers located near Evansville in southwestern Indiana.  SIGECO also owns and operates electric generation assets to serve its electric customers and optimizes those assets in the wholesale power market.  Indiana Gas and SIGECO generally do business as Vectren Energy Delivery of Indiana.  VEDO provides energy delivery services to over 310,000 natural gas customers located near Dayton in west central Ohio.

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

2.     Summary of Significant Accounting Policies

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

Principles of Consolidation

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

Subsequent Events Review

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

Cash & Cash Equivalents

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

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Allowance for Uncollectible Accounts

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

Inventories

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

Property, Plant & Equipment

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

Utility Plant & Related Depreciation

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

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

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

Nonutility Plant & Related Depreciation

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

Impairment Reviews

Property, plant and equipment along with other long-lived assets are reviewed as facts and circumstances indicate that the carrying amount may be impaired.  This impairment review involves the comparison of an asset’s (or group of assets’) carrying value to the estimated future cash flows the asset (or asset group) is expected to generate over a remaining life.  If this evaluation were to conclude that the carrying value is impaired, an impairment charge would be recorded based on the difference between the carrying amount and its fair value (less costs to sell for assets to be disposed of by sale) as a charge to operations or discontinued operations.  There were no impairments related to property, plant and equipment during the periods presented.

Investments in Unconsolidated Affiliates

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

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Goodwill

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

Regulation

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

Refundable or Recoverable Gas Costs & Cost of Fuel & Purchased Power

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

Regulatory Assets & Liabilities

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

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

Postretirement Obligations & Costs

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

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

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Asset Retirement Obligations

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

Product Warranties, Performance Guarantees & Other Guarantees

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

While not significant at December 31, 2011 or 2010, the Company does recognize the fair value of an obligation at the inception of a guarantee in certain circumstances.  These circumstances would include executing certain indemnification agreements and guaranteeing operating lease residual values, the performance of a third party, or the indebtedness of a third party.

Energy Contracts & Derivatives

The Company will periodically execute derivative contracts in the normal course of operations while buying and selling commodities to be used in operations, optimizing its generation assets, and managing risk.  A derivative is recognized on the balance sheet as an asset or liability measured at its fair market value and the change in the derivative's fair market value is recognized currently in earnings unless specific hedge criteria are met.

When an energy contract that is a derivative is designated and documented as a normal purchase or normal sale (NPNS), it is exempted from mark-to-market accounting.  Most energy contracts executed by the Company are subject to the NPNS exclusion or are not considered derivatives.  Such energy contracts include Real Time and Day Ahead purchase and sale contracts with the MISO, natural gas purchases from ProLiance and others, and wind farm and other electric generating contracts.

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

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Income Taxes

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

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

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

Revenues

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

MISO Transactions

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

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

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

Share-Based Compensation

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

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Excise & Utility Receipts Taxes

Excise taxes and a portion of utility receipts taxes are included in rates charged to customers.  Accordingly, the Company records these taxes received as a component of operating revenues, which totaled $29.3 million in 2011, $33.8 million in 2010, and $36.3 million in 2009.  Expense associated with excise and utility receipts taxes are recorded as a component of Taxes other than income taxes.

Operating Segments

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

Fair Value Measurements

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

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

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

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3.     Utility & Nonutility Plant

The original cost of Utility Plant, together with depreciation rates expressed as a percentage of original cost, follows:

	At December 31,
(In millions)	2011					2010
	Original Cost		Depreciation Rates as a Percent of  Original Cost			Original Cost		Depreciation Rates as a Percent of  Original Cost
Gas utility plant	$	2,516.8		3.5	%	$	2,410.2		3.6	%
Electric utility plant		2,316.8		3.3	%		2,258.6		3.4	%
Common utility plant		51.6		2.9	%		49.7		3.1	%
Construction work in progress		94.7		-			73.2		-
Total original cost	$	4,979.9				$	4,791.7

SIGECO and Alcoa Generating Corporation (AGC), a subsidiary of ALCOA, own the 300 MW Unit 4 at the Warrick Power Plant as tenants in common.  SIGECO's share of the cost of this unit at December 31, 2011, is $182.6 million with accumulated depreciation totaling $70.3 million.  AGC and SIGECO also share equally in the cost of operation and output of the unit.  SIGECO's share of operating costs is included in Other operating expenses in the Consolidated Statements of Income.

Nonutility plant, net of accumulated depreciation and amortization follows:

	At December 31,
(In millions)	2011		2010
Coal mine development costs & equipment	$	222.0	$	196.9
Computer hardware & software		101.9		114.5
Land & buildings		112.0		112.8
Vehicles & equipment		92.5		46.9
All other		22.4		17.2
Nonutility plant - net	$	550.8	$	488.3

Nonutility plant is presented net of accumulated depreciation and amortization totaling $418.5 million and $385.5 million as of December 31, 2011 and 2010, respectively.  For the years ended December 31, 2011, 2010, and 2009, the Company capitalized interest totaling $2.1 million, $2.1 million, and $6.0 million, respectively, on nonutility plant construction projects.

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4.     Regulatory Assets & Liabilities

Regulatory Assets

Regulatory assets consist of the following:

	At December 31,
(In millions)	2011		2010
Future amounts recoverable from ratepayers related to:
Benefit obligations (See Note 11)	$	126.0	$	92.5
Deferred Income taxes (See Notes 10 & 18)		1.3		19.2
Asset retirement obligations & other		2.3		2.1
		129.6		113.8
Amounts deferred for future recovery related to:
Deferred coal costs (See Note 20)		17.7		-
Cost recovery riders & other		6.4		2.8
		24.1		2.8
Amounts currently recovered in customer rates related to:
Unamortized debt issue costs & hedging proceeds		34.3		35.7
Demand side management programs		6.3		9.5
Indiana authorized trackers		24.3		17.3
Ohio authorized trackers		1.0		2.0
Premiums paid to reacquire debt		3.3		3.8
Other base rate recoveries		3.1		4.5
		72.3		72.8
Total regulatory assets	$	226.0	$	189.4

Of the $72.3 million currently being recovered in customer rates, $6.3 million that is associated with demand side management programs is earning a return.  The weighted average recovery period of regulatory assets currently being recovered is 17 years.  The Company has rate orders for all deferred costs not yet in rates and therefore believes that future recovery is probable.

Assets arising from benefit obligations represent the funded status of retirement plans less amounts previously recognized in the statement of income.  The Company records a Regulatory asset for that portion related to its rate regulated utilities. If the cost is ultimately recognized as a periodic cost, it will be recovered through rates charged to customers.  See Note 11.

Regulatory Liabilities

At December 31, 2011 and 2010, the Company has approximately $345.2 million and $333.5 million, respectively, in Regulatory liabilities.  Of these amounts, $320.9 million and $307.5 million relate to cost of removal obligations.  The remaining amounts primarily relate to timing differences associated with asset retirement obligations and deferred financing costs.

5.     Acquisition of Minnesota Limited, Inc.

On March 31, 2011, the Company, through its wholly owned subsidiary Vectren Infrastructure Services Company, Inc., purchased Minnesota Limited, Inc., excluding certain assets.  Minnesota Limited is a specialty contractor focusing on transmission pipeline construction and maintenance; pump station, compressor station, terminal and refinery construction; gas distribution; and hydrostatic testing.  Minnesota Limited is headquartered in Big Lake, Minnesota and the majority of its customers are generally located in the northern Midwest region.

Along with the Company’s wholly owned subsidiary, Miller Pipeline LLC, Minnesota Limited is included in the Company’s nonutility Infrastructure Services operating segment.  This acquisition positions the Company for anticipated growth in demand for gas transmission construction resulting from the need to transport new sources of natural gas and oil found in shale formations and the need to upgrade the nation’s aging pipelines.

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The Company accounted for the cash acquisition in accordance with FASB authoritative guidance for business combinations, which requires the Company to recognize the assets acquired and the liabilities assumed, measured at their fair values as of the date of acquisition.  The following table summarizes the allocation of the purchase price to the fair value of the assets acquired and liabilities assumed.

(In millions)
Working capital assets	$       21.5
Working capital liabilities	(6.7)
Net working capital	14.8
Property, plant & equipment	34.4
Identifiable intangible assets	19.1
Goodwill	20.3
Net assets acquired	88.6
Debt obligation assumed	(5.2)
Cash paid in acquisition, net of cash acquired	$       83.4

The purchase price and its allocation remain preliminary and could change in subsequent periods.  Any subsequent material changes to the purchase price and its allocation will be adjusted pursuant to FASB guidance. Since the initial purchase price allocation was disclosed only minor adjustments have been made.  The final purchase price and the allocation are dependent on final reconciliations of working capital and other items.

Level 3 market inputs, such as discounted cash flows, revenue growth rates, royalty rates, and dealer and auction values of used equipment, were used to derive the preliminary fair values of the identifiable intangible assets and property plant and equipment.  Identifiable intangible assets include back log, long-term customer relationships, and trade name.  The Company intends to use the acquired assets for an extended period and is amortizing them on a straight-line basis over their estimated useful lives.  Goodwill arising from the purchase represents intangible value the Company expects to realize over time.  This value includes but is not limited to: 1) expected synergies from more efficient utilization of equipment and human resources within the combined entities; 2) the experience and size of the acquired work force; and 3) the reputation of the current Minnesota Limited management team.  The goodwill, which does not amortize pursuant to FASB guidance, is deductible over a 15 year period for purposes of computing current income tax expense.

Transaction costs associated with the acquisition and expensed by the Company totaled approximately $0.6 million, of which $0.2 million are included in Other operating expenses during the twelve months ended December 31, 2011 and the remainder was expensed in 2010.  For the period from April 1, 2011 through December 31, 2011, Minnesota Limited contributed approximately $116.5 million and $9.4 million to the Company's revenue and net income, respectively.

The following table presents the Company's unaudited proforma results of operations for the twelve months ended December 31, 2011, 2010, and 2009 as if the acquisition had occurred on January 1, 2009.

	Year Ended December 31,
(In millions, except per share data)	2011		2010		2009
Total operating revenues	$	2,346.3	$	2,239.7	$	2,210.0
Net income	$	141.4	$	134.6	$	138.1
Basic earnings per share	$	1.73	$	1.66	$	1.71
Diluted earnings per share	$	1.73	$	1.66	$	1.70

In addition to the incremental revenues and expenses recorded by Minnesota Limited during this period, the proforma financial data for all periods presented contain several adjustments including the following: recording the additional amortization expense from the identifiable intangible assets; adjusting the estimated tax provision of the proforma combined results; and adjusting for the issuance of short-term debt to facilitate the acquisition.  The Company prepared the proforma financial information for the combined entities for comparative purposes only, and it may not be indicative of what actual results would have been if the acquisition had taken place on the proforma date, or of future results.

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Concurrent with the purchase agreement, the Company executed a lease arrangement at fair value for the Minnesota Limited corporate headquarters, which is owned by a member of the Minnesota Limited management team and certain family members.  The lease obligates the Company to pay approximately $83,333 per month for 10 years along with certain executory costs for taxes and other operating expenses.  Pursuant to FASB guidance, the Company accounts for the obligation as an operating lease, expensing the lease payments and executory costs as incurred.

6.     Sale of Retail Gas Marketing Operations

On December 31, 2011, the Company sold its retail gas marketing operations performed through Vectren Source receiving cash proceeds of approximately $84.3 million, including, and subject to a final determination of, working capital.  The sale, net of transaction costs, resulted in a pretax gain of approximately $25.4 million, which is included in Other operating expenses in the Consolidated Statements of Income. VEDO continues doing business with Vectren Source.  Vectren Source sells natural gas directly to customers in VEDO’s service territory, and VEDO purchases receivables and natural gas from Vectren Source.  Vectren Source is a component of the Energy Marketing operating segment.

7.     Investment in ProLiance Holdings, LLC

ProLiance Holdings, LLC (ProLiance), a nonutility energy marketing affiliate of Vectren and Citizens Energy Group (Citizens), provides services to a broad range of municipalities, utilities, industrial operations, schools, and healthcare institutions located throughout the Midwest and Southeast United States.  ProLiance’s customers include Vectren’s Indiana utilities and nonutility gas supply operations as well as Citizens’ utilities.  ProLiance’s primary businesses include gas marketing, gas portfolio optimization, and other portfolio and energy management services.  Consistent with its ownership percentage, Vectren is allocated 61 percent of ProLiance’s profits and losses; however, governance and voting rights remain at 50 percent for each member; and therefore, the Company accounts for its investment in ProLiance using the equity method of accounting.  The Company, including its former retail gas supply operations, contracted for a substantial portion of its natural gas purchases through ProLiance in 2011, 2010, and 2009.

Summarized Financial Information

	Year Ended December 31,
(In millions)	2011			2010			2009
Summarized Statement of Income information:
Revenues	$	1,410.5		$	1,497.0		$	1,654.9
Operating income (loss)		(44.5	)		(3.1	)		35.2
Charge related to Investment in Liberty Gas Storage		-			-			(32.7	)
ProLiance's earnings (losses)		(47.3	)		(3.7	)		4.5

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	As of December 31,
(In millions)	2011			2010
Summarized balance sheet information:
Current assets	$	381.9		$	441.4
Noncurrent assets		56.1			59.1
Current liabilities		298.5			298.1
Noncurrent liabilities		0.7			0.4
Members' equity		161.5			208.9
Accumulated other comprehensive income (loss)		(26.0	)		(10.8	)
Noncontrolling interest		3.3			3.9

Vectren records its 61 percent share of ProLiance’s results in Equity in earnings (losses) of unconsolidated affiliates.  Interest expense and income taxes associated with the investment are recorded separately within the statements of income in those line items.  As of December 31, 2011 and 2010, the Company’s investment balance is $85.4 million and $123.2 million, respectively. The amounts recorded to Equity in earnings (losses) of unconsolidated affiliates related to ProLiance’s operations totaled a pre-tax loss of $28.6 million and $2.5 million for the twelve months ended December 31, 2011 and 2010, respectively, and pre-tax income of $3.6 million for the twelve months ended December 31, 2009.  Lower natural gas prices, which have resulted in narrowed summer/winter spreads and locational margins, have negatively impacted ProLiance’s results. 

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 site, and an additional capacity of at least 17 Bcf at the South site.  The South site also has the potential for further expansion.  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. 

In late 2008, the project at the North site was halted due to subsurface and well-completion problems, resulting in Liberty recording a $132 million impairment charge related to the North site in 2009.  ProLiance recorded its share of the charge in 2009 totaling $33 million; the Company recorded its share of the charge in 2009 totaling $11.9 million after tax.  In the Consolidated Statement of Income for the year ended December 31, 2009, the charge is an approximate $19.9 million reduction to Equity in earnings of unconsolidated affiliates and an income tax benefit reflected in Income taxes of approximately $8.0 million.  ProLiance’s ability to meet the needs of its customers has not been, nor does it expect it to be, impacted.  Approximately 12 Bcf of the storage at the South site, which comprises three of the four FERC certified caverns, is fully completed and tested.  As a result of the issues encountered at the North site, Liberty requested and the FERC approved the separation of the North site from the South site.  As of December 31, 2011 and December 31, 2010, ProLiance’s investment in Liberty approximated $35.1 million and $36.7 million, respectively.

Liberty received a Demand for Arbitration from Williams Midstream Natural Gas Liquids, Inc. (“Williams”) on February 8, 2011 related to a Sublease Agreement (“Sublease”) between Liberty and Williams at the North site.  Williams alleges that Liberty was negligent in its attempt to convert certain salt caverns to natural gas storage and thereby damaged the caverns.  Williams alleges damages of $56.7 million.  Liberty believes that it has complied with all of its obligations to Williams, including properly terminating the Sublease.  Liberty intends to vigorously defend itself and has asserted counterclaims substantially in excess of the amounts asserted by Williams. 

Firm Transportation and Storage Commitments

ProLiance has various firm transportation and storage agreements with only minimal support from Vectren or Citizens. (See Note 17 regarding corporate guarantees.)  Under these agreements, ProLiance must make specified minimum payments which extend through 2029.  At December 31, 2011, the estimated aggregated amounts of such required future payments were $55.5 million, $49.0 million, $46.6 million, $38.2 million, $33.9 million, and $247.9 million for 2012, 2013, 2014, 2015, 2016, and thereafter, respectively.  During 2011, 2010, and 2009, fixed payments under these agreements were $73.0 million, $76.8 million, and $63.0 million, respectively.  ProLiance also made variable payments under these agreements in 2011, 2010, and 2009. Variable payments include storage injection and withdrawal charges, and commodity transportation charges.

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Transactions with ProLiance

Purchases from ProLiance for resale and for injections into storage for the years ended December 31, 2011, 2010, and 2009, totaled $378.7 million, $437.7 million, and $533.4 million, respectively.  Amounts owed to ProLiance at December 31, 2011, and 2010, for those purchases were $36.8 million and $59.6 million, respectively, and are included in Accounts payable to affiliated companies in the Consolidated Balance Sheets.  Vectren received regulatory approval on April 25, 2006, from the IURC for ProLiance to provide natural gas supply services to the Company’s Indiana utilities through March 2011.  On March 17, 2011, an order was received from the IURC providing for ProLiance’s continued provision of gas supply services to the Company’s Indiana utilities and Citizens Energy Group through March 2016.  Amounts charged by ProLiance for gas supply services are established by supply agreements with each utility.

8.     Nonutility Real Estate & Other Legacy Holdings

Within the Nonutility business segment, there are legacy investments involved in energy-related infrastructure and services, real estate, leveraged leases, and other ventures.  As of December 31, 2011 and 2010, total remaining legacy investments included in the Other Businesses portfolio total $36.9 million and $52.7 million, respectively.  Further separation of that 2011 investment by type of investment follows:

	December 31, 2011
			Value Included In
(In millions)	Carrying Value		Other Nonutility Investments		Investments in Unconsolidated Affiliates
Commercial real estate investments	$	8.0	$	8.0	$	-
Leveraged leases		18.5		18.5		-
Affordable housing projects		3.1		0.1		3.0
Haddington energy partnerships		3.4		-		3.4
Other investments		3.9		3.0		0.9
	$	36.9	$	29.6	$	7.3

Net of deferred taxes related to these leveraged leases, the net investment at December 31, 2011 was $23.1 million. 

Commercial Real Estate Charge

During the fourth quarter of 2011, the Company obtained new evidence confirming further weakness in markets where the Company holds legacy real estate investments.  The Company holds real estate investments such as an office building, affordable housing projects, and second mortgages. The evaluation of the evidence resulted in a $15.4 million charge in 2011. Of the $15.4 million charge, $8.8 million is reflected in Other-net, $3.6 million is reflected in Equity in earnings/losses of unconsolidated affiliates, and $3.0 million is reflected in Other operating expenses.

Leveraged Leases

The Company is a lessor in leveraged lease agreements under which real estate or equipment is leased to third parties.  The total equipment and facilities cost was approximately $45.2 million at December 31, 2011.  The cost of the equipment and facilities was partially financed by non-recourse debt provided by lenders who have been granted an assignment of rentals due under the leases and a security interest in the leased property, which they accepted as their sole remedy in the event of default by the lessee.  Such debt amounted to approximately $39.8 million at December 31, 2011.  Subsequent to year end on January 3, 2012 the Company divested of one leveraged lease with a book value of approximately $5.2 million, and net of deferred taxes a net book value of $2.7 million at December 31, 2011, at a small gain.

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Notes Receivable

At December 31, 2011 and 2010, notes receivable totaled $2.1 million and $10.9 million, respectively, and reflect the impairment charges discussed above.  These amounts are inclusive of accrued interest and net of reserves totaling $15.7 million and $6.1 million, respectively.  As of December 31, 2011, the Company is recognizing interest on the cash basis for substantially the entire note portfolio.  Such interest income has been insignificant during the past three years.  Second mortgages serve as collateral for notes associated with the commercial real estate investments.

Haddington Energy Partnerships

The Company has an approximate 40 percent ownership interest in Haddington Energy Partners, LP (Haddington I) and Haddington Energy Partners II, LP (Haddington II).  As of December 31, 2011, these Haddington ventures have interests in two remaining mid-stream energy related investments.  Both Haddington ventures are investment companies accounted for using the equity method of accounting.  During 2010, the Company recorded its share of the decline in fair value and also impaired a note receivable associated with Haddington’s investment in a liquefied natural gas facility.  In total, the charge was approximately $6.5 million, of which, $6.1 million is reflected in Equity in earnings (losses) of unconsolidated affiliates and $0.4 million is reflected in Other income-net,for the twelve months ended December 31, 2010.  At December 31, 2011, the Company’s remaining $3.4 million investment in the Haddington ventures is related to payments to be received associated with the sale of a compressed air storage facility sold in 2009.  The Company has no further commitments to invest in either Haddington I or II.  

The following is summarized financial information as to the results of operations of Haddington.  For the year ended December 31, 2011, operating results were insignificant.  For the year ended December 31, 2010, revenues, operating loss, and net loss were (in millions) zero, $(0.3), and $(18.1), respectively.  For the year ended December 31, 2009, revenues, operating loss, and net income were (in millions) zero, $(0.4), and $7.9, respectively.

Variable Interest Entities

Some of these legacy nonutility investments are partnership-like structures involved in activities surrounding multifamily housing and office properties and are variable interest entities.  The Company is either a limited partner or a subordinated lender and does not consolidate any of these entities.  The Company’s exposure to loss is limited to its investment which as of December 31, 2011, and 2010, totaled $3.0 million and $7.0 million, respectively, recorded in Investments in unconsolidated affiliates, and $0.1 million and $9.0 million, respectively, recorded in Other nonutility investments.

9.     Intangible Assets

Intangible assets, which are included in Other assets, consist of the following:

(In millions)	At December 31,
	2011				2010
	Amortizing		Non-amortizing		Amortizing		Non-amortizing
Customer-related assets	$	20.6	$	-	$	7.4	$	-
Market-related assets		3.6		7.0		-		7.0
Intangible assets, net	$	24.2	$	7.0	$	7.4	$	7.0

As of December 31, 2011, the weighted average remaining life for amortizing customer-related assets and all amortizing intangibles is 14 years.  These amortizing intangible assets have no significant residual values.  Intangible assets are presented net of accumulated amortization totaling $5.1 million for customer-related assets and $0.9 million for market-related assets at December 31, 2011 and $3.4 million for customer-related assets and $0.3 million for market-related assets at December 31, 2010.  Annual amortization associated with intangible assets totaled $2.3 million in 2011 and $0.6 million in 2010 and 2009.  Amortization should approximate $2.6 million, $2.3 million, $2.3 million, $2.2 million, and $1.6 million in 2012, 2013, 2014, 2015, and 2016, respectively. Intangible assets are primarily in the Nonutility Group.

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10.   Income Taxes

A reconciliation of the federal statutory rate to the effective income tax rate follows:

	Year Ended December 31,
	2011		2010		2009
Statutory rate:	35.0	%	35.0	%	35.0	%
State & local taxes-net of federal benefit	4.2		3.8		2.3
Amortization of investment tax credit	(0.3	)	(0.4	)	(0.5	)
Depletion	(1.9	)	(2.0	)	(2.0	)
Other tax credits	(0.2	)	(0.2	)	(0.2	)
Adjustment of income tax accruals and all other-net	1.1		(0.4	)	(2.1	)
Effective tax rate	37.9	%	35.8	%	32.5	%

Significant components of the net deferred tax liability follow:

	At December 31,
(In millions)	2011			2010
Noncurrent deferred tax liabilities (assets):
Depreciation & cost recovery timing differences	$	625.5		$	565.7
Leveraged leases		13.8			14.2
Regulatory assets recoverable through future rates		25.1			20.1
Other comprehensive income		(10.2	)		(4.2	)
Alternative minimum tax carryforward		(35.1	)		(48.6	)
Employee benefit obligations		(9.4	)		(18.9	)
Net operating loss & other carryforwards		(6.7	)		(3.8	)
Regulatory liabilities to be settled through future rates		(17.2	)		(4.8	)
Impairments		(11.4	)		(4.4	)
Other – net		1.3			-
Net noncurrent deferred tax liability		575.7			515.3
Current deferred tax (assets)/liabilities:
Deferred fuel costs-net		6.0			2.4
Demand side management programs		0.7			2.5
Alternative minimum tax carryforward		(15.6	)		(0.8	)
Other – net		(7.1	)		(7.9	)
Net current deferred tax asset		(16.0	)		(3.8	)
Net deferred tax liability	$	559.7		$	511.5

At December 31, 2011 and 2010, investment tax credits totaling $4.3 million and $5.0 million, respectively, are included in Deferred credits & other liabilities.  At December 31, 2011, the Company has alternative minimum tax carryforwards which do not expire.  In addition, the Company has $6.7 million in net operating loss and general business credit carryforwards, which will expire in 5 to 20 years.

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The components of income tax expense and utilization of investment tax credits follow:

	Year Ended December 31,
(In millions)	2011			2010			2009
Current:
Federal	$	4.4		$	(0.8	)	$	(21.4	)
State		10.3			6.2			0.6
Total current taxes		14.7			5.4			(20.8	)
Deferred:
Federal		66.0			65.6			78.7
State		6.4			4.5			7.3
Total deferred taxes		72.4			70.1			86.0
Amortization of investment tax credits		(0.7	)		(0.8	)		(1.1	)
Total income tax expense	$	86.4		$	74.7		$	64.1

Uncertain Tax Positions

Following is a roll forward of unrecognized tax benefits for the three years ended December 31, 2011:

(In millions)	2011			2010			2009
Unrecognized tax benefits at January 1	$	13.3		$	11.5		$	2.2
Gross increases - tax positions in prior periods		3.3			1.6			1.1
Gross decreases - tax positions in prior periods		(4.5	)		(0.3	)		(1.8	)
Gross increases - current period tax positions		0.6			1.0			9.0
Settlements		(0.3	)		-			(0.1	)
Lapse of statute of limitations		-			(0.5	)		1.1
Unrecognized tax benefits at December 31	$	12.4		$	13.3		$	11.5

Of the change in unrecognized tax benefits during 2011, 2010, and 2009, almost none impacted the effective rate.  The amount of unrecognized tax benefits, which if recognized, that would impact the effective tax rate was $0.7 million at December 31, 2011, $0.7 million at December 31, 2010 and $0.5 million at December 31, 2009.  As of December 31, 2011, the unrecognized tax benefit relates to tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility.  Because of the impact of deferred tax accounting, other than interest and penalties, the disallowance of the shorter deductibility period would not affect the annual effective tax rate but would accelerate the payment of cash to the taxing authority. Thus, it is not expected that any changes to these tax positions would have a significant impact on earnings.

The Company recognized expense related to interest and penalties totaling approximately $0.4 million in 2011, $0.3 million in 2010, and $0.2 million in 2009.  The Company had approximately $1.3 million and $0.9 million for the payment of interest and penalties accrued as of December 31, 2011 and 2010, respectively.

The net liability on the Consolidated Balance Sheet for unrecognized tax benefits inclusive of interest, penalties and net of secondary impacts which are a component of the Deferred income taxes and are benefits, totaled $10.1 million and $9.8 million, respectively, at December 31, 2011 and 2010.

The Company and/or certain of its subsidiaries file income tax returns in the U.S. federal jurisdiction and various states.  The Internal Revenue Service (IRS) has concluded examinations of the Company’s U.S. federal income tax returns for tax years through December 31, 2005.  Tax years 2006 and 2008 are currently under IRS examination.  The primary focus of the IRS examination is certain repairs and maintenance deductions, an area of particular focus by the IRS throughout the utility industry.  The Company received Notices of Assessment from the IRS related to these deductions.  The Company responded to the assessments in January 2012 and continues to follow industry activities in this area.  However, in the event the IRS assessments related to these deductions are upheld, any impact is not expected to be material to the Company’s results of operations or financial condition.  Further, the Company does not expect any changes to this liability for unrecognized income tax benefits within the next 12 months that would significantly impact the Company’s results of operations or financial condition.  The State of Indiana, the Company’s primary state tax jurisdiction, has conducted examinations of state income tax returns for tax years through December 31, 2007.  The statutes of limitations for assessment of federal income tax have expired with respect to tax years through 2005 and through 2007 for Indiana income tax.

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11.   Retirement Plans & Other Postretirement Benefits

At December 31, 2011, the Company maintains three qualified defined benefit pension plans, a nonqualified supplemental executive retirement plan (SERP), and three other postretirement benefit plans.  The defined benefit pension and other postretirement benefit plans, which cover eligible full-time regular employees, are primarily noncontributory.  The postretirement health care and life insurance plans are a combination of self-insured and fully insured plans.  The qualified pension plans and the SERP are aggregated under the heading “Pension Benefits.”  Other postretirement benefit plans are aggregated under the heading “Other Benefits.”

Net Periodic Benefit Costs

A summary of the components of net periodic benefit cost for the three years ended December 31, 2011 follows:

	Pension Benefits									Other Benefits
(In millions)	2011			2010			2009			2011			2010			2009
Service cost	$	6.9		$	6.3		$	6.3		$	0.5		$	0.5		$	0.5
Interest cost		15.9			15.9			15.8			4.3			4.6			4.4
Expected return on plan assets		(21.2	)		(18.4	)		(16.4	)		-			(0.4	)		(0.3	)
Amortization of prior service cost (benefit)		1.7			1.6			1.7			(0.8	)		(0.8	)		(0.8	)
Amortization of actuarial loss (gain)		3.8			3.2			2.2			0.6			0.5			0.4
Amortization of transitional obligation					-			-			1.1			1.2			1.1
Net periodic benefit cost	$	7.1		$	8.6		$	9.6		$	5.7		$	5.6		$	5.3

A portion of benefit costs are capitalized as Utility plant.  Costs capitalized in 2011, 2010, and 2009 are estimated at $3.9 million, $4.3 million, and $4.5 million, respectively.

The Company lowered the discount rate used to measure periodic cost from 6.0 percent in 2010 to 5.50 percent in 2011 due to lower benchmark interest rates that approximate the expected duration of the Company’s benefit obligations.  For fiscal year 2012, the weighted average discount rate will be 4.82 percent for the defined benefit pension plans.  Over the periods presented other assumptions have also declined reflecting the lower interest rate environment.

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

	Pension Benefits									Other Benefits
	2011			2010			2009			2011			2010			2009
Discount rate		5.50	%		6.00	%		6.25	%		5.50	%		6.00	%		6.25	%
Rate of compensation increase		3.50	%		3.50	%		3.75	%		N/A			N/A			N/A
Expected return on plan assets		8.00	%		8.00	%		8.25	%		8.00	%		8.00	%		8.25	%
Expected increase in Consumer Price Index		N/A			N/A			N/A			3.00	%		3.00	%		3.50	%

Health care cost trend rate assumptions do not have a material effect on the service and interest cost components of benefit costs.  The Company’s plans limit its exposure to increases in health care costs to annual changes in the Consumer Price Index (CPI).  Any increase in health care costs in excess of the CPI increase is the responsibility of the plan participants.

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Benefit Obligations

A reconciliation of the Company’s benefit obligations at December 31, 2011 and 2010 follows:

	Pension Benefits						Other Benefits
(In millions)	2011			2010			2011			2010
Benefit obligation, beginning of period	$	297.3		$	271.5		$	80.7		$	79.6
Service cost – benefits earned during the period		6.9			6.3			0.5			0.5
Interest cost on projected benefit obligation		15.9			15.9			4.3			4.6
Plan participants' contributions		-			-			1.9			1.7
Plan amendments		-			0.8			-			-
Actuarial loss (gain)		23.1			21.3			(0.5	)		1.2
Medicare subsidy receipts		-			-			1.0			0.5
Benefit payments		(14.0	)		(18.5	)		(8.2	)		(7.4	)
Benefit obligation, end of period	$	329.2		$	297.3		$	79.7		$	80.7

The accumulated benefit obligation for all defined benefit pension plans was $310.9 and $280.5 million at December 31, 2011 and 2010, respectively.

The benefit obligation as of December 31, 2011 and 2010 was calculated using the following weighted average assumptions:

	Pension Benefits						Other Benefits
	2011			2010			2011			2010
Discount rate		4.82	%		5.50	%		4.78	%		5.50	%
Rate of compensation increase		3.50	%		3.50	%		N/A			N/A
Expected increase in Consumer Price Index		N/A			N/A			2.75	%		3.00	%

To calculate the 2011 ending postretirement benefit obligation, medical claims costs in 2012 were assumed to be 8 percent higher than those incurred in 2011.  That trend was assumed to reach its ultimate trending increase of 5 percent by 2018 and remain level thereafter.  A one-percentage point change in assumed health care cost trend rates would have changed the benefit obligation by approximately $2.5 million.

Plan Assets

A reconciliation of the Company’s plan assets at December 31, 2011 and 2010 follows:

	Pension Benefits						Other Benefits
(In millions)	2011			2010			2011			2010
Plan assets at fair value, beginning of period	$	237.2		$	211.1		$	3.1		$	4.0
Actual return on plan assets		2.1			26.8			0.1			0.3
Employer contributions		35.7			17.8			3.1			4.5
Plan participants' contributions		-			-			1.9			1.7
Benefit payments		(14.0	)		(18.5	)		(8.2	)		(7.4	)
Fair value of plan assets, end of period	$	261.0		$	237.2		$	-		$	3.1

The Company’s overall investment strategy for its retirement plan trusts is to maintain investments in a diversified portfolio, comprised of primarily equity and fixed income investments, which are further diversified among various asset classes.  The diversification is designed to minimize the risk of large losses while maximizing total return within reasonable and prudent levels of risk.  The investment objectives specify a targeted investment allocation for the pension plans of 60 percent equities, 35 percent debt, and 5 percent for other investments, including real estate.  Both the equity and debt securities have a blend of domestic and international exposures.  Objectives do not target a specific return by asset class.  The portfolios’ return is monitored in total.  Following is a description of the valuation methodologies used for trust assets measured at fair value.

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Mutual Funds

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

Common Collective Trust Funds (CTF’s)

The Company’s plans have investments in trust funds similar to mutual funds in that they are created by pooling of funds from investors into a common trust and such funds are managed by a third party investment manager.  These trust funds typically give investors a wider range of investment options through this pooling of funds than that generally available to investors on an individual basis.  However, unlike mutual funds, these trusts are not publicly traded in an active market.  The fair values of these trusts are derived from Level 2 market inputs based on a daily calculated unit value as determined by the issuer.  This daily calculated value is based on the fair market value of the underlying investments.  These funds are primarily comprised of investments in equity and fixed income securities which represent approximately 52 percent and 40 percent, respectively, of their fair value as of December 31, 2011 and approximately 55 percent and 37 percent, respectively, as of December 31, 2010.  Equity securities within these funds are primarily valued using quoted market prices as these instruments have active markets.  From time to time, less liquid equity securities are valued using Level 2 inputs, such as bid prices or a closing price, as determined in good faith by the investment manager.  Fixed income securities are valued at the last available bid prices quoted by an independent pricing service.  When valuations are not readily available, fixed income securities are valued using primarily other Level 2 inputs as determined in good faith by the investment manager.

The fair value of these funds totals $128.2 million at December 31, 2011 and $110.4 million at December 31, 2010.  In relation to these investments, there are no unfunded commitments.  Also, the Plan can exchange shares with minimal restrictions.  However, in certain events, a restriction of up to 31 days may exist.

Guaranteed Annuity Contract

One of the Company’s pension plans is party to a group annuity contract with John Hancock Life Insurance Company.  At December 31, 2011 and 2010, the estimate of undiscounted funds necessary to satisfy John Hancock’s remaining obligation was $3.4 million and $3.1 million, respectively.  If funds retained by John Hancock are not sufficient to satisfy retirement payments due these retirees, the shortfall must be funded by the Company. The composite investment return, net of manager fees and other charges for the years ended December 31, 2011 and 2010 was 5.26 percent and 5.37 percent, respectively.  The Company values this illiquid investment using long-term interest rate and mortality assumptions, among others, and is therefore considered a Level 3 investment.  There is no unfunded commitment related to this investment.

The fair values of the Company’s pension and other retirement plan assets at December 31, 2011 and December 31, 2010 by asset category and by fair value hierarchy are as follows:

	As of December 31, 2011
(In millions)	Level 1		Level 2		Level 3		Total
Domestic equities & equity funds	$	54.7	$	66.5	$	-	$	121.2
International equities & equity funds		28.6		-		-		28.6
Domestic bonds & bond funds		38.2		39.1		-		77.3
Inflation protected security fund		-		11.8		-		11.8
Real estate, commodities & other		7.5		10.8		3.8		22.1
Total Plan Investments	$	129.0	$	128.2	$	3.8	$	261.0

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	As of December 31, 2010
(In millions)	Level 1		Level 2		Level 3		Total
Domestic equities & equity funds	$	54.6	$	60.8	$	-	$	115.4
International equities & equity funds		29.7		-		-		29.7
Domestic bonds & bond funds		35.3		31.3		-		66.6
Inflation protected security fund		-		9.2		-		9.2
Real estate, commodities & other		6.6		9.1		3.7		19.4
Total Plan Investments	$	126.2	$	110.4	$	3.7	$	240.3

A roll forward of the fair value of the guaranteed annuity contract calculated using Level 3 valuation assumptions follows:

(In millions)	2011			2010
Fair value, beginning of year	$	3.7		$	3.6
Unrealized gains related to    investments still held at reporting date		0.2			0.2
Purchases, sales and settlements, net		(0.1	)		(0.1	)
Fair value, end of year	$	3.8		$	3.7

Funded Status

The funded status of the plans as of December 31, 2011 and 2010 follows:

	Pension Benefits						Other Benefits
(In millions)	2011			2010			2011			2010
Qualified Plans
Benefit obligation, end of period	$	(314.7	)	$	(285.5	)	$	(79.7	)	$	(80.7	)
Fair value of plan assets, end of period		261.0			237.2			-			3.1
Funded Status of Qualified Plans, end of period		(53.7	)		(48.3	)		(79.7	)		(77.6	)
Benefit obligation of SERP Plan, end of period		(14.5	)		(11.8	)		-			-
Total funded status, end of period	$	(68.2	)	$	(60.1	)	$	(79.7	)	$	(77.6	)
Accrued liabilities	$	0.7		$	0.7		$	5.1		$	4.6
Deferred credits & other liabilities	$	67.5		$	59.4		$	74.6		$	73.0

Expected Cash Flows

In 2012, the Company expects to make contributions of approximately $15 million to its pension plan trusts.  In addition, the Company expects to make payments totaling approximately $0.7 million directly to SERP participants and approximately $5.1 million directly to those participating in other postretirement plans.

Estimated retiree pension benefit payments, including the SERP, projected to be required during the years following 2011 (in millions) are approximately $16.4 in 2012, $17.3 in 2013 $17.9 in 2014, $18.7 in 2015, $19.8 in 2016 and $125.2 in years 2017-2021.  Expected benefit payments projected to be required for postretirement benefits during the years following 2011 (in millions) are approximately $7.5 in 2012, $8.1 in 2013, $8.7 in 2014, $9.2 in 2015, and $9.8 in 2016 and $58.1 in years 2017-2021.

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

Following is a roll forward of prior service cost, actuarial gains and losses, and transition obligations.

(In millions)	Pensions						Other Benefits
	Prior Service Cost			Net Gain or Loss			Prior Service Cost			Net Gain or Loss			Transition Obligation
Balance January 1, 2009	$	9.5		$	90.9		$	(3.7	)	$	3.5		$	6.2
Amounts arising during the period		0.1			(20.2	)		0.1			6.6			(0.1	)
Reclassification to benefit costs		(1.7	)		(2.2	)		0.8			(0.4	)		(1.1	)
Balance December 31, 2009	$	7.9		$	68.5		$	(2.8	)	$	9.7		$	5.0
Amounts arising during the period		0.8			12.9			-			1.1			-
Reclassification to benefit costs		(1.6	)		(3.2	)		0.8			(0.5	)		(1.2	)
Balance December 31, 2010	$	7.1		$	78.2		$	(2.0	)	$	10.3		$	3.8
Amounts arising during the period		-			42.2			-			(0.6	)		-
Reclassification to benefit costs		(1.7	)		(3.8	)		0.8			(0.6	)		(1.1	)
Balance December 31, 2011	$	5.4		$	116.6		$	(1.2	)	$	9.1		$	2.7

Following is a reconciliation of the amounts in Accumulated other comprehensive income (AOCI) and Regulatory assets related to retirement plan obligations at December 31, 2011 and 2010:

(In millions)	2011						2010
	Pensions			Other Benefits			Pensions			Other Benefits
Prior service cost	$	5.4		$	(1.2	)	$	7.1		$	(2.0	)
Unamortized actuarial gain/(loss)		116.6			9.1			78.2			10.3
Transition obligation		-			2.7			-			3.8
		122.0			10.6			85.3			12.1
Less: Regulatory asset deferral		(115.9	)		(10.1	)		(81.0	)		(11.5	)
AOCI before taxes	$	6.1		$	0.5		$	4.3		$	0.6

Related to pension plans, $1.6 million of prior service cost and $6.8 million of actuarial gain/loss is expected to be amortized to cost in 2012.  Related to other benefits, $1.1 million of the transition obligation and $0.5 million of actuarial gain/loss is expected to be amortized to periodic cost in 2012, and $0.8 million of prior service cost is expected to reduce cost in 2012.

Multiemployer Benefit Plan

The Company, through its Infrastructure Services operating segment, participates in several industry wide multiemployer pension plans for its union employees which provide for monthly benefits based on length of service. Expense is recognized as payments are accrued for work performed or when withdrawal liabilities are probable and estimable.  Expense associated with multiemployer plans was $18.3 million for the year ended December 31, 2011 and includes results from Minnesota Limited and a small withdrawal liability from one plan.  Expense in 2010 and 2009 was $10.0 million and $8.8 million, respectively.  During 2011, the Company made contributions on behalf of employees that participate in over 260 unions.  The average contribution to each union was less than $0.1 million, and the largest contribution was $1.1 million.  Multiple unions can contribute to a single multiemployer plan.  The Company identified contributions to at least 17 plans in 2011 and total contributions to each plan were not significant.

Defined Contribution Plan

The Company also has defined contribution retirement savings plans that are qualified under sections 401(a) and 401(k) of the Internal Revenue Code and include an option to invest in Vectren common stock, among other alternatives.  During 2011, 2010 and 2009, the Company made contributions to these plans of $6.2 million, $6.6 million, and $4.6 million, respectively.

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12.   Borrowing Arrangements

Long-Term Debt

Long-term senior unsecured obligations and first mortgage bonds outstanding by subsidiary follow:

			At December 31,
(In millions)			2011	2010
Utility Holdings
	Fixed Rate Senior Unsecured Notes
		2011, 6.625%	$                 -	$        250.0
		2013, 5.25%	100.0	100.0
		2015, 5.45%	75.0	75.0
		2018, 5.75%	100.0	100.0
		2020, 6.28%	100.0	100.0
		2021, 4.67%	55.0	-
		2026, 5.02%	60.0	-
		2035, 6.10%	75.0	75.0
		2036, 5.95%	-	96.7
		2039, 6.25%	121.6	121.9
		2041, 5.99%	35.0	-
		Total Utility Holdings	721.6	918.6
Indiana Gas
	Fixed Rate Senior Unsecured Notes
		2013, Series E, 6.69%	5.0	5.0
		2015, Series E, 7.15%	5.0	5.0
		2015, Series E, 6.69%	5.0	5.0
		2015, Series E, 6.69%	10.0	10.0
		2025, Series E, 6.53%	10.0	10.0
		2027, Series E, 6.42%	5.0	5.0
		2027, Series E, 6.68%	1.0	1.0
		2027, Series F, 6.34%	20.0	20.0
		2028, Series F, 6.36%	10.0	10.0
		2028, Series F, 6.55%	20.0	20.0
		2029, Series G, 7.08%	30.0	30.0
		Total Indiana Gas	121.0	121.0
SIGECO
	First Mortgage Bonds
		2015, 1985 Pollution Control Series A, current adjustable rate 0.10%, tax exempt,
		2011 weighted average: 0.19%	9.8	9.8
		2016, 1986 Series, 8.875%	13.0	13.0
		2020, 1998 Pollution Control Series B, 4.50%, tax exempt	4.6	4.6
		2023, 1993 Environmental Improvement Series B, 5.15%, tax exempt	22.6	22.6
		2024, 2000 Environmental Improvement Series A, 4.65%, tax exempt	22.5	22.5
		2025, 1998 Pollution Control Series A, current adjustable rate 0.08%, tax exempt,
		2011 weighted average: 0.19%	31.5	31.5
		2029, 1999 Senior Notes, 6.72%	80.0	80.0
		2030, 1998 Pollution Control Series B, 5.00%, tax exempt	22.0	22.0
		2030, 1998 Pollution Control Series C, 5.35%, tax exempt	22.2	22.2
		2040, 2009 Environmental Improvement Series, 5.40%, tax exempt	22.3	22.3
		2041, 2007 Pollution Control Series, 5.45%, tax exempt	17.0	17.0
		Total SIGECO	267.5	267.5

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(In millions)			2011	2010
Vectren Capital Corp.
	Fixed Rate Senior Unsecured Notes
		2012, 5.13%	25.0	25.0
		2012, 7.43%	35.0	35.0
		2014, 6.37%	30.0	30.0
		2015, 5.31%	75.0	75.0
		2016, 6.92%	60.0	60.0
		2017, 3.48%	75.0	75.0
		2019, 7.30%	60.0	60.0
		2025, 4.53%	50.0	50.0
		Total Vectren Capital Corp.	410.0	410.0
Other Long-Term Notes Payable			4.1	1.1
Total long-term debt outstanding			1,524.2	1,718.2
	Current maturities of long-term debt		(62.7)	(250.7)
	Short-term borrowings refinanced in 2012		100.0	-
	Debt subject to tender		-	(30.0)
	Unamortized debt premium & discount - net		(1.9)	(2.3)
		Total long-term debt-net	$       1,559.6	$    1,435.2

Utility Holdings 2012 Debt Issuance

On February 1, 2012, Utility Holdings issued $100 million of senior unsecured notes at an interest rate of 5.00 percent per annum and with a maturity date of February 3, 2042.  The notes were sold to various institutional investors pursuant to a private placement note purchase agreement executed in November 2011 with a delayed draw feature.  These senior notes are unsecured and jointly and severally guaranteed by Utility Holdings’ regulated utility subsidiaries, SIGECO, Indiana Gas, and VEDO.  The proceeds from the sale of the notes, net of issuance costs, totaled approximately $99.5 million.  These notes have no sinking fund requirements and interest payments are due semi-annually.  These notes contain customary representations, warranties and covenants, including a leverage covenant consistent with leverage covenants contained in other Utility Holdings’ borrowing arrangements.As of December 31, 2011, the Company has reclassified $100 million of short-term borrowings as long-term debt to reflect those borrowings were refinanced with the proceeds received.

Utility Holdings 2011 Debt Issuance

On November 30, 2011, Utility Holdings closed a financing under a private placement note purchase agreement pursuant to which various institutional investors purchased the following tranches of notes:  (i) $55 million of 4.67 percent Senior Guaranteed Notes, due November 30, 2021, (ii) $60 million of 5.02 percent Senior Guaranteed Notes, due November 30, 2026, and (iii) $35 million of 5.99 percent Senior Guaranteed Notes, due December 2, 2041.  These senior notes are unsecured and jointly and severally guaranteed by Utility Holdings’ regulated utility subsidiaries, SIGECO, Indiana Gas, and VEDO.  The proceeds from the sale of the notes, net of issuance costs, totaled approximately $148.9 million.  These notes have no sinking fund requirements and interest payments are due semi-annually.  These notes contain customary representations, warranties and covenants, including a leverage covenant consistent with leverage covenants contained in other Utility Holdings’ borrowing arrangements.

Vectren Capital Corp. 2010 Debt Issuance

On December 15, 2010, the Company and Vectren Capital closed a financing under a private placement note purchase agreement pursuant to which various institutional investors agreed to purchase the following tranches of notes from Vectren Capital:  (i) $75 million 3.48 percent Senior Notes, Series A due 2017, and (ii) $50 million 4.53 percent Senior Notes, Series B due 2025.  These Senior Notes are unconditionally guaranteed by Vectren.  The proceeds from the issuance replaced $48 million debt maturities due in December 2010 and provided long-term financing for some nonutility investments originally financed with short-term borrowings.  These notes have no sinking fund requirements and interest payments are due semi-annually.  The proceeds from the sale of the notes, net of issuance costs, totaled approximately $124.2 million.  These notes contain customary representations, warranties and covenants, including a leverage covenant consistent with leverage covenants contained in other Vectren Capital borrowing arrangements.

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Vectren Capital Corp. 2009 Debt Issuance

On March 11, 2009, Vectren and Vectren Capital closed a financing under a private placement Note Purchase Agreement (the “2009 Note Purchase Agreement”) pursuant to which various institutional investors purchased the following tranches of notes from Vectren Capital: (i) $30 million in 6.37 percent senior notes, Series A due 2014, (ii) $60 million in 6.92 percent senior notes, Series B due 2016 and (iii) $60 million in 7.30 percent senior notes, Series C due 2019. These senior notes are unconditionally guaranteed by Vectren, the parent of Vectren Capital.  These notes have no sinking fund requirements and interest payments are due semi-annually.  The proceeds from the sale of the notes, net of issuance costs, totaled approximately $149.0 million.  The 2009 Note Purchase Agreement contains customary representations, warranties and covenants, including a leverage covenant consistent with leverage covenants contained in other Vectren Capital borrowing arrangements.  On March 11, 2009, Vectren and Vectren Capital also entered into a first amendment with respect to prior note purchase agreements for the remaining outstanding Vectren Capital debt, other than the $22.5 million series due in 2010, to conform the covenants in certain respects to those contained in the 2009 Note Purchase Agreement.

Utility Holdings 2009 Debt Issuance

On April 7, 2009, Utility Holdings closed a financing under a private placement note purchase agreement pursuant to which institutional investors purchased from Utility Holdings $100 million in 6.28 percent senior unsecured notes due April 7, 2020 (2020 Notes).  The 2020 Notes are guaranteed by Utility Holdings’ three utilities:  SIGECO, Indiana Gas, and VEDO.  These guarantees are full and unconditional and joint and several.  The proceeds from the sale of the 2020 Notes, net of issuance costs, totaled approximately $99.5 million.  The 2020 Notes have no sinking fund requirements and interest payments are due semi-annually.  The 2020 Notes contain customary representations, warranties and covenants, including a leverage covenant consistent with leverage covenants contained in other Utility Holdings’ borrowing arrangements.

SIGECO 2009 Debt Issuance

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

Auction Rate Securities

On March 26, 2009, SIGECO remarketed the remaining $41.3 million of its auction rate securities obligations, receiving proceeds, net of issuance costs of approximately $40.6 million.  The remarketed notes have a variable rate interest rate which is reset weekly and are supported by a standby letter of credit.  The notes are collateralized by SIGECO’s utility plant, and $9.8 million are due in 2015 and $31.5 million are due in 2025.

Long-Term Debt Puts & Calls

Certain long-term debt issues contain put and call provisions that can be exercised on various dates before maturity.  Certain instruments can be put to the Company upon the death of the holder (death puts).  During 2011, 2010, and 2009, the Company repaid approximately $0.8 million, $1.8 million, and $3.0 million, respectively, related to death puts.

On October 21, 2011, the Company notified holders of Utility Holdings $96.2 million 5.95 percent senior notes due 2036, of its intent to call those notes.  This call option was exercised at par on November 21, 2011.

Future Long-Term Debt Sinking Fund Requirements and Maturities

The annual sinking fund requirement of SIGECO's first mortgage bonds is 1 percent of the greatest amount of bonds outstanding under the Mortgage Indenture.  This requirement may be satisfied by certification to the Trustee of unfunded property additions in the prescribed amount as provided in the Mortgage Indenture.  SIGECO intends to meet the 2011 sinking fund requirement by this means and, accordingly, the sinking fund requirement for 2011 is excluded from Current liabilities in the Consolidated Balance Sheets.  At December 31, 2011, $1.3 billion of SIGECO's utility plant remained unfunded under SIGECO's Mortgage Indenture.  SIGECO’s gross utility plant balance subject to the Mortgage Indenture approximated $2.7 billion at December 31, 2011.

Consolidated maturities of long-term debt during the five years following 2011 (in millions) are $62.7 in 2012, $106.4 in 2013, $30.0 in 2014, $179.8 in 2015, $73.0 in 2016, and $1,170.4 thereafter.

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Debt Guarantees

Vectren Corporation guarantees Vectren Capital’s long-term and short-term debt, which totaled $410 million and $84 million, respectively, at December 31, 2011.  Utility Holdings’ currently outstanding long-term and short-term debt is jointly and severally guaranteed by Indiana Gas, SIGECO, and VEDO.  Utility Holdings’ long-term debt, including current maturities, and short-term debt outstanding at December 31, 2011, totaled $722 million and $243 million, respectively.

Covenants

Both long-term and short-term borrowing arrangements contain customary default provisions; restrictions on liens, sale-leaseback transactions, mergers or consolidations, and sales of assets; and restrictions on leverage and interest coverage, among other restrictions.  Multiple debt agreements contain a covenant that the ratio of consolidated total debt to consolidated total capitalization will not exceed 65 percent.  As of December 31, 2011, the Company was in compliance with all debt covenants.

Short-Term Borrowings

At December 31, 2011, the Company has $600 million of short-term borrowing capacity, including $350 million for the Utility Group and $250 million for the wholly owned Nonutility Group and corporate operations.  As reduced by borrowings currently outstanding, approximately $107 million was available for the Utility Group operations and approximately $166 million was available for the wholly owned Nonutility Group and corporate operations.  This short-term borrowing facility was amended effective November 10, 2011 to extend its maturity date from 2013 to 2016 at current market rates.  The $350 million of capacity remains unchanged.  The Company has historically funded the short-term borrowing needs of Utility Holdings’ operations through the commercial paper market and expects to use the Utility Holdings short-term borrowing facility in instances where the commercial paper market is not efficient. 

Following is certain information regarding these short-term borrowing arrangements.

	Utility Group Borrowings									Nonutility Group Borrowings
(In millions)	2011			2010			2009			2011			2010			2009
Year End
Balance Outstanding	$	242.8		$	47.0		$	16.4		$	84.3		$	71.3		$	197.1
Weighted Average Interest Rate		0.57	%		0.41	%		0.25	%		1.45	%		2.01	%		0.60	%
Annual Average
Balance Outstanding	$	39.6		$	14.0		$	29.2		$	124.9		$	143.2		$	151.8
Weighted Average Interest Rate		0.48	%		0.40	%		1.28	%		1.92	%		0.93	%		0.78	%
Maximum Month End Balance Outstanding	$	242.8		$	47.0		$	151.1		$	180.1		$	174.6		$	256.5

Throughout 2011, 2010, and most of 2009, the Company has placed commercial paper without any significant issues and only had to borrow from its backup credit facility in early 2009 on a limited basis.  As noted above, $100 million of the outstanding borrowings are presented as long-term at December 31, 2011.

13.   Common Shareholders’ Equity

Authorized, Reserved Common and Preferred Shares

At December 31, 2011 and 2010, the Company was authorized to issue 480.0 million shares of common stock and 20.0 million shares of preferred stock.  Of the authorized common shares, approximately 6.8 million shares at December 31, 2011 and 5.5 million shares at December 31, 2010, were reserved by the board of directors for issuance through the Company’s share-based compensation plans, benefit plans, and dividend reinvestment plan.  At December 31, 2011 and 2010, there were 391.3 million and 392.8 million, respectively, of authorized shares of common stock and all authorized shares of preferred stock, available for a variety of general corporate purposes, including future public offerings to raise additional capital and for facilitating acquisitions.

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14.   Earnings Per Share

The Company uses the two class method to calculate earnings per share (EPS).  The two class method is an earnings allocation formula that treats a participating security as having rights to earnings that otherwise would have been available to common shareholders.  Under the two class method, earnings for a period are allocated between common shareholders and participating security holders based on their respective rights to receive dividends as if all undistributed book earnings for the period were distributed.  Basic EPS is computed by dividing net income attributable to only the common shareholders by the weighted-average number of common shares outstanding for the period.  Diluted EPS includes the impact of stock options and other equity based instruments to the extent the effect is dilutive.

The following table illustrates the basic and dilutive EPS calculations for the three years ended December 31, 2011:

	Year Ended December 31,
(In millions, except per share data)	2011		2010		2009
Numerator:
Numerator for basic EPS	$	141.6	$	133.6	$	132.9
Add back earnings attributable to participating securities		-		0.1		0.2
Reported net income (Numerator for Diluted EPS)	$	141.6	$	133.7	$	133.1
Denominator:
Weighted average common shares outstanding (Basic EPS)		81.8		81.2		80.7
Conversion of share based compensation arrangements		-		0.1		0.3
Adjusted weighted average shares outstanding and
assumed conversions outstanding (Diluted EPS)		81.8		81.3		81.0
Basic earnings per share	$	1.73	$	1.65	$	1.65
Diluted earnings per share	$	1.73	$	1.64	$	1.64

For the year ended December 31, 2011, there were no antidilutive options outstanding.  For the years ended December 31, 2010 and 2009, options to purchase 308,800 and 837,100, respectively, of additional shares of the Company’s common stock were outstanding, but were not included in the computation of diluted EPS because their effect would be antidilutive.  The exercise prices for these options ranged from $24.90 to $27.15 and $23.19 to $27.15 for the years ended December 31, 2010 and 2009, respectively.

15.   Accumulated Other Comprehensive Income

A summary of the components of and changes in Accumulated other comprehensive income for the past three years follows:

	2009									2010						2011
	Beginning			Changes			End			Changes			End			Changes			End
	of Year			During			of Year			During			of Year			During			of Year
(In millions)	Balance			Year			Balance			Year			Balance			Year			Balance
Unconsolidated affiliates	$	(29.0	)	$	21.9		$	(7.1	)	$	0.5		$	(6.6	)	$	(9.3	)	$	(15.9	)
Pension & other benefit costs		(5.3	)		0.9			(4.4	)		(0.5	)		(4.9	)		(1.7	)		(6.6	)
Cash flow hedges		0.1			-			0.1			3.9			4.0			(3.9	)		0.1
Deferred income taxes		13.9			(9.3	)		4.6			(1.5	)		3.1			6.0			9.1
Accumulated other comprehensive income (loss)	$	(20.3	)	$	13.5		$	(6.8	)	$	2.4		$	(4.4	)	$	(8.9	)	$	(13.3	)

Accumulated other comprehensive income arising from unconsolidated affiliates is primarily the Company’s portion of ProLiance Holdings, LLC’s accumulated comprehensive income related to use of cash flow hedges.  (See Note 7 for more information on ProLiance.)

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16.   Share-Based Compensation & Deferred Compensation Arrangements

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

Following is a reconciliation of the total cost associated with share-based awards recognized in the Company’s financial statements to its after tax effect on net income:

	Year ended December 31,
(In millions)	2011		2010		2009
Total cost of share-based compensation	$	5.8	$	4.9	$	4.6
Less capitalized cost		0.8		1.7		1.6
Total in other operating expense		5.0		3.2		3.0
Less income tax benefit in earnings		2.0		1.3		1.2
After tax effect of share-based compensation	$	3.0	$	1.9	$	1.8

Restricted Stock & Restricted Stock Unit Plans

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

A summary of the status of the Company’s restricted stock and restricted unit awards separated between those accounted for as liabilities and equity as of December 31, 2011, and changes during the year ended December 31, 2011, follows:

	Equity Awards
				Wtd. Avg.
				Grant Date		Liability Awards
	Shares			Fair value		Shares/Units			Fair value
Restricted awards at January 1, 2011		41,458		$	26.19		668,892
Granted		27,518			25.64		277,480
Vested		(7,226	)		28.63		(108,390	)
Forfeited		(7,737	)		28.61		(139,872	)
Restricted awards at December 31, 2011		54,013		$	25.22		698,110		$           30.23

As of December 31, 2011, there was $7.6 million of total unrecognized compensation cost related to restricted stock awards.  That cost is expected to be recognized over a weighted-average period of 1.6 years.  The total fair value of shares vested for liability awards during the years ended December 31, 2011, 2010, and 2009, was $3.0 million, $5.0 million, and $2.8 million, respectively.  The total fair value of equity awards vesting during the year ended December 31, 2011, 2010, and 2009 was $0.2 million, $0.2 million, $0.1 million, respectively.

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Stock Option Plans

In the past, option awards were granted to executives and other key employees with an exercise price equal to the market price of the Company’s stock at the date of grant; those option awards generally required 3 years of continuous service and have 10-year contractual terms.  These awards generally vested on a pro-rata basis over 3 years.  The last option grant occurred in 2005, and the Company does not intend to issue options in the future.  All compensation cost has been recognized.  A summary of the status of the Company’s stock option awards as of December 31, 2011, and changes during the year ended December 31, 2011, follows:

				Weighted average				Aggregate
						Remaining		Intrinsic
	Shares			Exercise		Contractual		Value
				Price		Term (years)		(In millions)
Outstanding at January 1, 2011		929,806		$	24.55
Exercised		(522,173	)	$	23.61
Outstanding at December 31, 2011		407,633		$	25.74		2.5	$	1.8
Exercisable at December 31, 2011		407,633		$	25.74		2.5	$	1.8

The total intrinsic value of options exercised during the year ended December 31, 2011 and 2010 was $2.4 million and $1.3 million, respectively.  The actual tax benefit realized for tax deductions from option exercises was approximately $1.0 million and $0.5 million in 2011 and 2010, respectively.

The Company periodically issues new shares and also from time to time repurchases shares to satisfy share option exercises.  During the year ended December 31, 2011 and 2010, the Company received cash upon exercise of stock options totaling approximately $12.3 million and $9.5 million, respectively.  During these periods, the Company repurchased shares totaling approximately $12.8 million and $1.2 million respectively.  During the year ended December 31, 2009, stock option activity was insignificant.

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

Deferred Compensation Plans

The Company has nonqualified deferred compensation plans, which permit eligible executives and non-employee directors to defer portions of their compensation and vested restricted stock or units.  A record keeping account is established for each participant, and the participant chooses from a variety of measurement funds for the deemed investment of their accounts.  The measurement funds are similar to the funds in the Company's defined contribution plan and include an investment in phantom stock units of the Company.  The account balance fluctuates with the investment returns on those funds.  At December 31, 2011 and 2010, the liability associated with these plans totaled $21.1 million and $19.1 million, respectively.  Other than $0.7 million and $0.5 million which are classified in Accrued liabilities at December 31, 2011 and 2010, respectively, the liability is included in Deferred credits & other liabilities.  The impact of these plans on Other operating expenses was expense of $2.1 million in 2011, $2.3 million in 2010 and income of $0.8 million in 2009.  The amount recorded in earnings related to the investment activities in Vectren phantom stock associated with these plans during the years ended December 31, 2011, 2010, and 2009, was a cost of $1.7 million, a cost of $1.6 million and a benefit of $1.5 million, respectively.

The Company has certain investments currently funded primarily through corporate-owned life insurance policies.  These investments, which are consolidated, are available to pay deferred compensation benefits.  These investments are also subject to the claims of the Company's creditors.  The cash surrender value of these policies included in Other corporate & utility investments on the Consolidated Balance Sheets were $27.3 million and $27.5 million at December 31, 2011 and 2010, respectively.  Earnings from those investments, which are recorded in Other-net, were earnings $0.1 million in 2011, $1.9 million in 2010, and $4.1 million in 2009. 

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17.   Commitments & Contingencies

Commitments

Future minimum lease payments required under operating leases that have initial or remaining noncancelable lease terms in excess of one year during the five years following 2011 and thereafter (in millions) are $4.7 in 2012, $3.8 in 2013, $2.5 in 2014, $1.5 in 2015, $1.1 in 2016, and $4.3 thereafter.  Total lease expense (in millions) was $6.9 in 2011, $7.3 in 2010, and $8.0 in 2009.

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

Corporate Guarantees

The Company issues parent level 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, 2011, parent level guarantees support a maximum of $25 million of ESG’s performance contracting commitments and warranty obligations and $27 million of other project guarantees.  The broader scope of ESG’s performance contracting obligations, including those not guaranteed by the parent company, are described below.  In addition, the parent company has approximately $25 million of other guarantees outstanding supporting other consolidated subsidiary operations, of which $20 million represent letters of credit supporting other nonutility operations.  Guarantees issued and outstanding on behalf of unconsolidated affiliates approximated $3 million at December 31, 2011.  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.

As a result of the sale of Vectren Source on December 31, 2011, the Company has $56 million of outstanding guarantees related to this formerly wholly owned subsidiary that will remain in effect for up to 90 days after the closing.  The buyer’s parent will hold the Company harmless if any amounts are required to be paid pursuant to these guarantees and, within the 90 day period, the buyer is required to provide its own guarantees in substitution for the Company guarantees.

Performance Guarantees & Product Warranties

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

Specific to ESG, in its role as a general contractor in the performance contracting industry, at December 31, 2011, there are 78 open surety bonds supporting future performance.  The average face amount of these obligations is $3.6 million, and the largest obligation has a face amount of $25.7 million.  The maximum exposure of these obligations is less than these amounts for several factors, including the level of work already completed.  At December 31, 2011, approximately 60 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.  The Company has no significant accruals for these warranty obligations as of December 31, 2011.

Legal & Regulatory Proceedings

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

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18.   Legislative Matters

Pipeline Safety Law

On January 3, 2012 the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 was signed into law.  This new law, which reauthorizes federal pipeline safety programs through fiscal year 2015, provides for enhanced safety, reliability and environmental protection in the transportation of energy products by pipeline. The new law increases federal enforcement authority, grants the federal government expanded authority over pipeline safety, provides for new safety regulations and standards, and authorizes or requires the completion of several pipeline safety-related studies.  The DOT is required to promulgate a number of new regulatory requirements.  The direction of those regulations will be based on the results of the studies and reports required or authorized by the new law and may eventually lead to further regulatory or statutory requirements.

The Company continues to study the impact of the new law and potential new regulations associated with its implementation.  At this time, compliance costs and other effects associated with the increased pipeline safety regulations remain uncertain.  However, the new law is expected to result in further investment in pipeline inspections, and where necessary, additional modernization of pipeline infrastructure; and therefore, result in both increased levels of operating expenses and capital expenditures associated with the Company’s natural gas distribution businesses.  Operating expenses associated with expanded compliance requirements may grow to approximately $9 million annually, with $6 million attributable to the Indiana operations.  The Company expects to seek recovery under Senate Bill 251 referenced below, or such costs may be recoverable through current tracking mechanisms.  Capital investments, driven by the pipeline safety regulations, associated with the Company’s Indiana gas utilities are expected to be approximately $80 million over the next five years, which would likely qualify as federally mandated regulatory requirements.  In Ohio, capital investments are expected to be approximately $55 million over the next five years.  The Company expects to seek recovery of capital investments associated with complying with these federal mandates in accordance with Senate Bill 251 in Indiana and House Bill 95 in Ohio (referenced below).

Indiana House Bill 1004

In May 2011, House Bill 1004 was signed into law.  This legislation phases in over four years a two percent rate reduction to the Indiana Adjusted Gross Income Tax for corporations.  Pursuant to House Bill 1004, the tax rate will be lowered by one-half percent each year beginning on July 1, 2012, to the final rate of six and one-half percent effective July 1, 2015.  Pursuant to FASB guidance, the Company accounted for the effect of the change in tax law on its deferred taxes in the second quarter of 2011, the period of enactment.  The impact was not material to results of operations or financial condition as the decrease in Deferred tax liabilities was generally offset by a $17.1 million decrease in Regulatory assets.

Indiana Senate Bill 251

In April 2011, Senate Bill 251 was signed into law.  While the bill is broad in scope, it allows for cost recovery outside of a base rate proceeding for federal government mandated projects and provides for a voluntary clean energy portfolio standard. 

The law applies to both gas and electric utility operations and provides a framework to recover 80 percent of federally mandated costs through a periodic rate adjustment mechanism outside of a general rate case.  Such costs include construction, depreciation, operating and other costs.  The remaining 20 percent of those costs are to be deferred for recovery in the utility’s next general rate case.  The Company is currently evaluating the impact this law may have on its operations, including applicability to expenditures associated with the integrity, safety, and reliable operation of natural gas pipelines and facilities; ash disposal; water regulations; and air pollution, including greenhouse gas emissions, among other federally mandated projects and potential projects. 

The legislation establishes a voluntary clean energy portfolio standard that provides incentives to electricity suppliers participating in the program.  The goal of the program is that by 2025, at least 10 percent of the total electricity obtained by the supplier to meet the energy needs of its Indiana retail customers will be provided by clean energy sources, as defined.  The financial incentives include an enhanced return on equity and tracking mechanisms to recover program costs.  In advance of a federal portfolio standard and Senate Bill 251, SIGECO received regulatory approval to purchase a 3 MW landfill gas generation facility from a related entity.  The facility was purchased in 2009 and is directly connected 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.  Before the impacts of efficiency measures, the Company currently stands at approximately 5 percent of its electricity being provided by clean energy sources due to the long-term wind contracts and landfill gas investments.  The Company continues to evaluate whether to participate in this voluntary program.

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Ohio House Bill 95

In June 2011, Ohio House Bill 95 was signed into law.  The law adjusts, among other things, the manner in which gas utilities file for rate changes, including the implementation of base rate changes, alternative rate plans, and automatic rate adjustment mechanisms.  Outside of a base rate proceeding, the legislation permits a natural gas company to apply to implement a capital expenditure program for infrastructure expansion, upgrade, or replacement; installation, upgrade, or replacement of information technology systems; or any program necessary to comply with government regulation.  Once such application is approved, the legislation authorizes recovery or deferral of program costs, such as depreciation, property taxes, and carrying costs.  The Company is assessing the impact this legislation may have on its operations.  On February 3, 2012, the Company initiated a filing under House Bill 95.  This filing requests accounting authority to defer depreciation, post in service carrying costs and property taxes for its approximate $25 million 2012 capital expenditure program.  The capital expenditure program includes infrastructure expansion and improvements not covered by the Company’s distribution replacement rider as well as expenditures necessary to comply with PUCO rules, regulations and orders.  A procedural schedule associated with the filing has not yet been set.

19.   Environmental Matters

Air Quality

Cross-State Air Pollution Rule (Formerly Clean Air Interstate Rule (CAIR))

On July 7, 2011, EPA finalized the Cross-State Air Pollution Rule (CSAPR).  CSPAR is the EPA’s response to the US Court of Appeals for the District of Columbia’s (the Court) remand of the Clean Air Interstate Rule (CAIR). CAIR was originally established in 2005 as an allowance cap and trade program that required reductions from coal-burning power plants for NOx emissions beginning January 1, 2009 and SO2 emissions beginning January 1, 2010, with a second phase of reductions in 2015.

In an effort to address the Court’s finding that CAIR did not adequately ensure attainment of pollutants in certain downwind states due to unlimited trading of SO2and NOx allowances, CSPAR reduces the ability of facilities to meet emission reduction targets through allowance trading.  Like CAIR, CSPAR sets individual state caps for SO2and NOx emissions.  However, unlike CAIR in which states allocated allowances through state implementation plans, CSPAR allowances were allocated to individual units directly through the federal rule.  As finalized, CSAPR requires a 71 percent reduction of SO2 emissions compared to 2005 national levels and a 52 percent reduction of NOx emissions compared to 2005 national levels and that such reductions are to be achieved with initial step reductions beginning January 1, 2012, with final compliance to be achieved in 2014.  Multiple administrative and judicial challenges have been filed, including requests to stay CSPAR’s implementation.

On December 30, 2011, the Court granted a stay of CSPAR and ordered expedited briefing schedules be submitted by January 18, 2012, that would allow for completion of briefing and a hearing in April 2012.  Two primary issues are before the Court for review:  (1) EPA’s use of air modeling data (as opposed to exclusive reliance on actual monitoring data) to support state contribution levels, and (2) EPA’s allocation of allowances directly through a federal implementation plan as opposed to setting state caps and providing states the opportunity to submit individual state implementation plans.  In addition, there are initiatives in the Congress that, if adopted, would suspend CSPAR’s implementation.

Utility Hazardous Air Pollutants (HAPs) Rule

On December 21, 2011, the EPA finalized the Utility HAPs rule.  The HAPs Rule is the EPA’s response to the US Court of Appeals for the District of Columbia vacating the Clean Air Mercury Rule (CAMR) in 2008.  CAMR was originally established in 2005 as a nation-wide mercury emission allowance cap and trade system which sought to reduce utility emissions of mercury starting in 2010.

The HAPs rule sets emission limits for hazardous air pollutants for existing and new coal-fired power plants and identifies the following broad categories of hazardous air pollutants:  mercury, non-mercury hazardous air pollutants (primarily arsenic, chromium, cobalt, and selenium) and acid gases (hydrogen cyanide, hydrogen chloride, and hydrogen fluoride).  The rule imposes mercury emission limits for two sub-categories of coal, and proposed surrogate limits for non-mercury and acid gas hazardous air pollutants. The EPA did not grant blanket compliance extensions, but asserted that states have broad authority to grant one year extensions for individual units where potential reliability impacts have been demonstrated.  Reductions are to be achieved within three years of publication of the final rule in the Federal register (early 2015).  Initiatives to suspend CSPAR’s implementation by the Congress also apply to the implementation of the HAPs Rule.

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Conclusions Regarding Air Regulations

To comply with Indiana’s implementation plan of the Clean Air Act, and other federal air quality standards, the Company obtained authority from the IURC to invest in clean coal technology.  Using this authorization, the Company invested approximately $411 million starting in 2001 with the last equipment being placed into service on January 1, 2010.  The pollution control equipment included Selective Catalytic Reduction (SCR) systems, fabric filters, and an SO2 scrubber at its generating facility that is jointly owned with ALCOA (the Company’s portion is 150 MW).  SCR technology is the most effective method of reducing NOx emissions where high removal efficiencies are required and fabric filters control particulate matter emissions.  The unamortized portion of the $411 million clean coal technology investment was included in rate base for purposes of determining SIGECO’s new electric base rates approved in the latest base rate order obtained April 27, 2011.  SIGECO’s coal fired generating fleet is 100 percent scrubbed for SO2 and 90 percent controlled for NOx. 

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

The Company is currently reviewing the sufficiency of its existing pollution control equipment in relation to the requirements described in CSPAR and the Utility HAPs Rule.  Based upon an initial review of the final rules, including minor revisions made to CSPAR in October 2011, the Company believes that it will be able to meet these requirements with its existing suite of pollution control equipment and the anticipated allotment of new emission allowances.  However, it is possible some minor modifications to the control equipment and additional operating expenses could be required.  The Company believes that such additional costs, if necessary, would be recoverable under Indiana Senate Bill 251 referenced above.

Water

Section 316(b) of the Clean Water Act requires that generating facilities use the “best technology available” to minimize adverse environmental impacts in a body of water.  More specifically, Section 316(b) is concerned with impingement and entrainment of aquatic species in once-through cooling water intake structures used at electric generating facilities.  In April 2009, the U.S. Supreme Court affirmed that the EPA could, but was not required to, consider costs and benefits in making the evaluation as to the best technology available for existing generating facilities.  The regulation was remanded back to the EPA for further consideration.  In March 2011, the EPA released its proposed Section 316(b) regulations.  The EPA did not mandate the retrofitting of cooling towers in the proposed regulation, but if finalized the regulation will leave it to the state to determine whether cooling towers should be required on a case by case basis.  A final rule is expected in 2012.  Depending on the final rule and on the Company’s facts and circumstances, capital investments could be in the $40 million range if new infrastructure, such as new cooling water towers, is required.  Costs for compliance with these final regulations would likely qualify as federally mandated regulatory requirements under Indiana Senate Bill 251 referenced above.

Coal Ash Waste Disposal & Ash Ponds

In June 2010, the EPA issued proposed regulations affecting the management and disposal of coal combustion products, such as ash generated by the Company’s coal-fired power plants.  The proposed rules more stringently regulate these byproducts and would likely increase the cost of operating or expanding existing ash ponds and the development of new ash ponds.  The alternatives include regulating coal combustion by-products that are not being beneficially reused as hazardous waste.  The EPA did not offer a preferred alternative, but took public comment on multiple alternative regulations.  Rules may not be finalized in 2012 given oversight hearings, congressional interest, and other factors.

At this time, the majority of the Company’s ash is being beneficially reused.  However, the alternatives proposed would require some retrofitting or closure of existing ash ponds.  The Company estimates capital expenditures to comply could be as much as $30 million, and such expenditures could exceed $100 million if the most stringent of the alternatives is selected.  Annual compliance costs could increase slightly or be impacted by as much as $5 million.  Costs for compliance with these regulations would likely qualify as federally mandated regulatory requirements under Senate Bill 251 referenced above. 

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Climate Change

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

Numerous competing federal legislative proposals have also been introduced in recent years that involve carbon, energy efficiency, and renewable energy.  Comprehensive energy legislation at the federal level continues to be debated, but there has been little progress to date.  The progression of regional initiatives throughout the United States has also slowed.

Impact of Legislative Actions & Other Initiatives is Unknown

If regulations are enacted by the EPA or other agencies or if legislation requiring reductions in CO2 and other greenhouse gases or legislation mandating a renewable energy portfolio standard is adopted, such regulation could substantially affect both the costs and operating characteristics of the Company’s fossil fuel generating plants, nonutility coal mining operations, and natural gas distribution businesses.  At this time and in the absence of final legislation or rulemaking, compliance costs and other effects associated with reductions in greenhouse gas emissions or obtaining renewable energy sources remain uncertain.  The Company has gathered preliminary estimates of the costs to control greenhouse gas emissions.  A preliminary investigation demonstrated costs to comply would be significant, first with regard to operating expenses and later for capital expenditures as technology becomes available to control greenhouse gas emissions.  However, these compliance cost estimates are based on highly uncertain assumptions, including allowance prices if a cap and trade approach were employed, and energy efficiency targets.  Costs to purchase allowances that cap greenhouse gas emissions or expenditures made to control emissions should be considered a cost of providing electricity, and as such, the Company believes such costs and expenditures would be recoverable from customers through Senate Bill 251.  Customer rates may also be impacted should decisions be made to reduce the level of sales to municipal and other wholesale customers in order to meet emission targets.

Manufactured Gas Plants

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

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

The Company has accrued the estimated costs for further investigation, remediation, groundwater monitoring, and related costs for the sites.  While the total costs that may be incurred in connection with addressing these sites cannot be determined at this time, the Company has recorded cumulative costs that it reasonably expects to incur totaling approximately $41.6 million ($23.1 million at Indiana Gas and $18.5 million at SIGECO).  The estimated accrued costs are limited to the Company’s share of the remediation efforts and are therefore net of exposures of other potentially responsible parties (PRP).

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With respect to insurance coverage, Indiana Gas has received approximately $20.8 million from all known insurance carriers under insurance policies in effect when these plants were in operation.  SIGECO 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 another site subject to a lawsuit that has been settled.  In November 2011, the Court ruled on two motions for summary judgment, finding for SIGECO and against certain insurers on indemnification and defense obligations in the policies at issue.  SIGECO has settlement agreements with all known insurance carriers and has recorded approximately $15.1 million of expected insurance recoveries.

The costs the Company expects to incur are estimated by management using assumptions based on actual costs incurred, the timing of expected future payments, and inflation factors, among others.  While the Company’s utilities have recorded all costs which they presently expect to incur in connection with activities at these sites, it is possible that future events may require 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, 2011 and 2010, respectively, approximately $6.5 million and $5.5 million of accrued, but not yet spent, costs are included in Other Liabilities related to both the Indiana Gas and SIGECO sites.

Jacobsville Superfund Site

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

20.   Rate & Regulatory Matters

Vectren South Electric Base Rate Filing

On December 11, 2009, Vectren South filed a request with the IURC to adjust its base electric rates.  The requested increase in base rates addressed capital investments, a modified electric rate design that would facilitate a partnership between Vectren South and customers to pursue energy efficiency and conservation, and new energy efficiency programs to complement those currently offered for natural gas customers.  The IURC issued an order in the case on April 27, 2011.  The order provides for an approximate $28.6 million revenue increase to recover costs associated with approximately $325 million in system upgrades that were completed in the three years leading up to the December 2009 filing and modest increases in maintenance and operating expenses.  The approved revenue increase is based on rate base of $1,295.6 million, return on equity of 10.4 percent and an overall rate of return of 7.29 percent.  The new rates were effective May 3, 2011.  The IURC, in its order, denied the Company’s request for implementation of the decoupled rate design, which is discussed further below.  Addressing issues raised in the case concerning coal supply contracts and related costs, the IURC found that current coal contracts remain effective and that a prospective review process of future procurement decisions would be initiated.

Coal Procurement Procedures

Vectren South submitted a request for proposal in April 2011 regarding coal purchases for a four year period beginning in 2012.  After negotiations with bidders, Vectren South has reached an agreement in principle for multi-year purchases with two suppliers, one of which is Vectren Fuels, Inc.  Consistent with the IURC direction in the electric rate case, a sub docket proceeding was established to review the Company’s prospective coal procurement procedures, and the Company submitted evidence related to its recent request for proposal (RFP) and those coal procurement procedures to the IURC in September 2011.  In October 2011, the OUCC filed its testimony which, while suggesting enhancements to the process to be considered, does not challenge the results of the RFP and the resulting new contracts.  All hearings were completed in December 2011, and an order is expected in early 2012.

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Vectren South Electric Fuel Cost Reduction

On December 5, 2011 within the quarterly Fuel Adjustment Clause (FAC) filing, Vectren South submitted a joint proposal with the OUCC to reduce its fuel costs by accelerating the impact of lower cost coal contracts to be effective after 2012.  In the spring of 2011, Vectren secured contracts for lower coal costs through a formal bidding process. This lower-priced coal is expected to start being delivered and used at Vectren’s power plants by late 2012 to early 2013 and beyond. The agreement to accelerate savings into early 2012 means that the existing 2012 coal costs that are above the new, lower prices will be deferred to a regulatory asset and recovered over a six-year period without interest beginning in 2014.  This deferral also includes a reduction to the coal inventory balance at December 31, 2011 of approximately $17.7 million to reflect existing inventory at the new, lower price.  The IURC approved this proposal on January 25, 2012, with an impact to customer’s rates effective February 1, 2012.

Vectren South Electric Demand Side Management Program Filing

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

On August 31, 2011 the IURC issued an order approving an initial three year DSM plan in the Vectren South service territory that complies with the IURC’s energy saving targets.  Consistent with the Company’s proposal, the order approved, among other items, the following: 1) recovery of costs associated with implementing the DSM Plan; 2) the recovery of a performance incentive mechanism based on measured savings related to certain DSM programs; 3) lost margin recovery associated with the implementation of DSM programs for large customers; and 4) deferral of lost margin up to $1 million in 2011 associated with small customer DSM programs for subsequent recovery under a tracking mechanism to be proposed by the Company.  This mechanism is an alternative to the electric decoupling proposal that was denied by the IURC in the order received April 27, 2011.  On January 26, 2012, the Company filed with the IURC a proposal for a small customer lost margin recovery mechanism within the existing Demand Side Management Adjustment (DSMA).  The proposal includes a request for recovery of the $1 million deferred in 2011, and a request for continued deferral of lost margins in 2012 until such point as these lost margins are included in DSMA rates.  The procedural schedule has not been set in this filing, but the Company expects an order in 2012.

Vectren South Electric Dense Pack Filing

On September 14, 2011, Vectren South filed a petition with the IURC seeking recovery of and return on the capital investment in dense pack technology to improve the efficiency of its A.B. Brown Generating Station.  This investment is expected to be approximately $32 million over the next two years, of which approximately $19 million has been invested to date.  This technology is expected to allow the A.B. Brown units to run at least 5 percent more efficient, thereby burning less fuel, and reducing fuel costs and emissions of pollutants.  Indiana statute provides for timely recovery of investments, with a return, in instances where the investment increases the efficiency of existing generating plants that are fueled by coal.  Several parties have intervened in the case and are requesting that the IURC deny recovery of these project costs outside of a base rate proceeding.The IURC will conduct a hearing in February 2012.

Vectren North Reporting Location Consolidation Proceeding

Vectren North implemented a reporting location consolidation plan in 2011 and closed certain locations throughout the North territory.  On May 26, 2011, the International Brotherhood of Electrical Workers Local 1393, United Steel Workers Locals 12213 and 7441 and others filed a formal complaint with the IURC claiming that the consolidation and simultaneous closing by Vectren North of select reporting locations endangers public safety and impairs Vectren North's ability to provide adequate, safe and reliable service.  These parties have asked the IURC to require Vectren North to reopen previously consolidated reporting locations and maintain and staff those locations.  A hearing in this case was held in February 2012, and the Company expects the IURC to act some time in 2012.

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Vectren North & Vectren South Gas Decoupling Extension Filing

On April 14, 2011, the Company’s Indiana based gas companies (Vectren North and Vectren South) filed with the IURC a joint settlement agreement with the OUCC on an extension of the offering of conservation programs and the supporting gas decoupling mechanism originally approved in December 2006.  On August 18, 2011, the IURC issued an order approving the settlement as filed, granting the extension of the current decoupling mechanism in place at both gas companies and recovery of new conservation program costs through December 2015.

VEDO Gas Rate Design

The rate design approved by the PUCO on January 7, 2009, and initially implemented on February 22, 2009, allowed for the phased movement toward a straight fixed variable rate design, which places substantially all of the fixed cost recovery in the monthly customer service charge.  This rate design mitigates most weather risk as well as the effects of declining usage, similar to the company’s lost margin recovery mechanism in place in the Indiana natural gas service territories and the mechanism in place in Ohio prior to this rate order.  Since the straight fixed variable rate design was fully implemented in February 2010, nearly 90 percent of the combined residential and commercial base rate gas margins were recovered through the customer service charge.  As a result, some margin previously recovered during the peak delivery winter months, such as January and the first half of February 2010, is more ratably recognized throughout the year.

In addition in 2010, the Company began recognizing a return on and of investments made to replace distribution risers and bare steel and cast iron infrastructure per a PUCO order.

VEDO Continues the Process to Exit the Merchant Function

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

The second phase of the exit process began on April 1, 2010.  During this phase, the Company no longer sells natural gas directly to customers.  Rather, state-certified Competitive Retail Natural Gas Suppliers, that were successful bidders in a similar regulatory-approved auction, sell the gas commodity to specific customers for a 12-month period at auction-determined standard pricing.  The first auction was conducted on January 12, 2010, and the auction results were approved by the PUCO on January 13, 2010.  The plan approved by the PUCO required that the Company conduct at least two annual auctions during this phase.  As such, the Company conducted another auction on January 18, 2011 in advance of the second 12-month term which commenced on April 1, 2011.  The results of that auction were approved by the PUCO on January 19, 2011.Vectren Source, the Company’s former wholly owned nonutility retail gas marketer, was a successful bidder in both auctions winning one tranche of customers in the first auction and two tranches of customers in the second auction.  Each tranche of customers equates to approximately 28,000 customers.  As per the terms of the plan approved by the PUCO, because no application for a full exit of the merchant function was neither sought nor approved by April 1, 2011, VEDO conducted a third retail auction on January 31, 2012 to address the 12-month term beginning April 1, 2012.  The results of that auction were approved by the PUCO on February 1, 2012.  Consistent with current practice, customers continue to receive a single bill for the commodity as well as the delivery component of natural gas service from VEDO.

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

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21.   Fair Value Measurements

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

	At December 31,
	2011				2010
(In millions)	Carrying Amount		Est. Fair Value		Carrying Amount		Est. Fair Value
Long-term debt	$	1,622.3	$	1,804.4	$	1,715.9	$	1,841.2
Short-term borrowings & notes payable		227.1		227.1		118.3		118.3
Cash & cash equivalents		8.6		8.6		10.4		10.4

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

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

Under current regulatory treatment, call premiums on reacquisition of long-term debt are generally recovered in customer rates over the life of the refunding issue or over a 15-year period.  Accordingly, any reacquisition would not be expected to have a material effect on the Company's results of operations.

Because of the customized nature of notes receivable investments and lack of a readily available market, it is not practical to estimate the fair value of these financial instruments at specific dates without considerable effort and cost.  At December 31, 2011 and 2010, the fair value for these financial instruments was not estimated.  The carrying value of notes receivable, inclusive of any accrued interest and net of impairment reserves, was approximately $2.1 million and $10.9 million December 31, 2011 and 2010.

The fair value table in Note 18 of the financial statements in the 2010 Form 10-K excluded the estimated fair value of a long-term debt instrument.  The chart above now includes the amount and reflects an increase in the estimated fair value of long-term debt of approximately $73.9 million.  This change in the disclosed fair value of long-term debt had no effect on the carrying value of debt included in the consolidated balance sheet.

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22.   Segment Reporting

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

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

The Nonutility Group is comprised of five operating segments:  Infrastructure Services, Energy Services, Coal Mining, Energy Marketing, and Other Businesses.

Corporate and Other includes unallocated corporate expenses such as advertising and charitable contributions, among other activities, that benefit the Company’s other operating segments.  Net income is the measure of profitability used by management for all operations.  The acquisition of Minnesota Limited was completed on March 31, 2011 (See Note 5) and is included in the Infrastructure Services nonutility operating segment.  Information related to the Company’s business segments is summarized as follows:

	Year Ended December 31,
(In millions)	2011			2010			2009
Revenues
Utility Group
Gas Utility Services	$	819.1		$	954.1		$	1,066.0
Electric Utility Services		635.9			608.0			528.6
Other Operations		43.9			44.5			42.8
Eliminations		(41.9	)		(42.9	)		(41.2	)
Total Utility Group		1,457.0			1,563.7			1,596.2
Nonutility Group
Infrastructure Services		421.3			235.6			202.0
Energy Services		161.8			146.9			121.3
Coal Mining		285.6			209.9			193.4
Energy Marketing		149.9			142.8			157.2
Total Nonutility Group		1,018.6			735.2			673.9
Eliminations		(150.4	)		(169.4	)		(181.2	)
Consolidated Revenues	$	2,325.2		$	2,129.5		$	2,088.9
Profitability Measures - Net Income
Utility Group Net Income
Gas Utility Services	$	52.5		$	53.7		$	50.2
Electric Utility Services		65.0			60.9			48.3
Other Operations		5.4			9.3			8.9
Total Utility Group Net Income		122.9			123.9			107.4
Nonutility Group Net Income
Infrastructure Services		14.9			3.1			2.4
Energy Services		6.7			6.4			8.4
Coal Mining		16.6			11.9			13.4
Energy Marketing		(4.2	)		(4.2	)		4.1
Other Businesses		(10.2	)		(7.4	)		(2.5	)
Total Nonutility Group Net Income		23.8			9.8			25.8
Corporate & Other Net Loss		(5.1	)		-			(0.1	)
Consolidated Net Income	$	141.6		$	133.7		$	133.1

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	Year Ended December 31,
(In millions)	2011			2010			2009
Amounts Included in Profitability Measures
Depreciation & Amortization
Utility Group
Gas Utility Services	$	84.3		$	80.7		$	76.9
Electric Utility Services		80.2			80.8			77.5
Other Operations		27.8			26.7			26.5
Total Utility Group		192.3			188.2			180.9
Nonutility Group
Infrastructure Services		14.9			8.8			8.3
Energy Services		1.5			1.2			1.2
Coal Mining		35.1			30.4			21.0
Energy Marketing		0.5			0.5			0.5
Total Nonutility Group		52.0			40.9			31.0
Consolidated Depreciation & Amortization	$	244.3		$	229.1		$	211.9
Interest Expense
Utility Group
Gas Utility Services	$	37.1		$	38.8		$	38.8
Electric Utility Services		36.4			36.4			34.8
Other Operations		6.8			6.2			5.6
Total Utility Group		80.3			81.4			79.2
Nonutility Group
Infrastructure Services		7.4			3.3			2.6
Energy Services		0.6			0.2			0.6
Coal Mining		11.3			10.1			8.1
Energy Marketing		6.4			8.5			8.3
Other Businesses		1.3			1.5			1.3
Total Nonutility Group		27.0			23.6			20.9
Corporate & Other		(0.8	)		(0.4	)		(0.1	)
Consolidated Interest Expense	$	106.5		$	104.6		$	100.0
Income Taxes
Utility Group
Gas Utility Services	$	34.5		$	35.1		$	31.3
Electric Utility Services		45.3			40.8			27.4
Other Operations		3.1			1.2			0.5
Total Utility Group		82.9			77.1			59.2
Nonutility Group
Infrastructure Services		10.7			2.7			2.1
Energy Services		1.1			2.5			1.6
Coal Mining		3.9			1.9			4.1
Energy Marketing		(2.4	)		(2.7	)		0.3
Other Businesses		(7.0	)		(5.9	)		(2.2	)
Total Nonutility Group		6.3			(1.5	)		5.9
Corporate & Other		(2.8	)		(0.9	)		(1.0	)
Consolidated Income Taxes	$	86.4		$	74.7		$	64.1

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	Year Ended December 31,
(In millions)	2011			2010			2009
Capital Expenditures
Utility Group
Gas Utility Services	$	113.5		$	88.7		$	121.1
Electric Utility Services		102.2			120.1			154.1
Other Operations		17.8			22.5			16.7
Non-cash costs & changes in accruals		(0.1	)		(6.2	)		10.8
Total Utility Group		233.4			225.1			302.7
Nonutility Group
Infrastructure Services		22.8			12.0			11.0
Energy Services		9.7			1.2			1.9
Coal Mining		55.1			38.7			126.8
Energy Marketing		0.3			0.2			0.6
Other Businesses, net of eliminations		-			-			(11.0	)
Total Nonutility Group		87.9			52.1			129.3
Consolidated Capital Expenditures	$	321.3		$	277.2		$	432.0
	At December 31,
(In millions)		2011			2010			2009
Assets
Utility Group
Gas Utility Services	$	2,125.2		$	2,161.7		$	2,102.4
Electric Utility Services		1,656.5			1,666.5			1,592.4
Other Operations, net of eliminations		192.8			96.3			128.3
Total Utility Group		3,974.5			3,924.5			3,823.1
Nonutility Group
Infrastructure Services		295.0			174.6			141.4
Energy Services		81.2			67.4			54.5
Coal Mining		352.8			362.5			342.8
Energy Marketing		112.5			209.1			229.6
Other Businesses		39.6			57.1			65.7
Eliminations & Reclassifications		7.2			(2.2	)		2.0
Total Nonutility Group		888.3			868.5			836.0
Corporate & Other		727.3			706.2			715.9
Eliminations		(711.2	)		(735.0	)		(703.2	)
Consolidated Assets	$	4,878.9		$	4,764.2		$	4,671.8

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23.   Additional Balance Sheet & Operational Information

Inventories consist of the following:

	At December 31,
(In millions)	2011		2010
Gas in storage – at LIFO cost	$	31.8	$	26.2
Gas in storage – at average cost		-		23.6
Total Gas in storage		31.8		49.8
Coal & Oil for electric generation - at average cost		60.6		70.1
Materials & supplies		54.9		48.8
Nonutility Coal - at LIFO cost		13.0		16.2
Other		1.6		2.2
Total inventories	$	161.9	$	187.1

Based on the average cost of gas purchased and coal produced during December, the cost of replacing inventories carried at LIFO cost exceeded that carrying value at December 31, 2011, and 2010, by approximately $12 million and $16 million, respectively.

Prepayments & other current assets in the Consolidated Balance Sheets consist of the following:

	At December 31,
(In millions)	2011		2010
Prepaid gas delivery service	$	42.4	$	40.7
Deferred income taxes		16.0		3.8
Prepaid taxes		5.1		31.5
Other prepayments & current assets		20.8		25.2
Total prepayments & other current assets	$	84.3	$	101.2

Investments in unconsolidated affiliates consist of the following:

	At December 31,
(In millions)	2011		2010
ProLiance Holdings, LLC	$	85.4	$	123.2
Haddington Energy Partnerships		3.4		3.4
Other non-utility partnerships & corporations		3.9		8.4
Other utility investments		0.2		0.2
Total investments in unconsolidated affiliates	$	92.9	$	135.2

Other utility & corporate Investments in the Consolidated Balance Sheets consist of the following:

	At December 31,
(In millions)	2011		2010
Cash surrender value of life insurance policies	$	27.3	$	27.5
Municipal bond		3.9		4.1
Restricted cash		1.9		1.2
Other investments		1.3		1.3
Other utility & corporate investments	$	34.4	$	34.1

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Goodwill by operating segment follows:

	At December 31,
(In millions)	2011		2010
Utility Group
Gas Utility Services	$	205.0	$	205.0
Nonutility Group
Infrastructure Services		55.2		34.9
Energy Services		2.1		2.1
Consolidated goodwill	$	262.3	$	242.0

Accrued liabilities in the Consolidated Balance Sheets consist of the following:

	At December 31,
(In millions)	2011		2010
Refunds to customers & customer deposits	$	56.4	$	54.8
Accrued taxes		33.5		40.9
Accrued interest		21.7		23.8
Accrued retirement		6.5		5.8
Accrued salaries & other		63.0		53.1
Total accrued liabilities	$	181.1	$	178.4

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

(In millions)	2011		2010
Asset retirement obligation, January 1	$	38.7	$	36.1
Accretion		2.5		2.1
Increases in estimates, net of cash payments		2.5		0.5
Asset retirement obligation, December 31		43.7		38.7
Accrued liabilities	$	0.2	$	0.3
Deferred credits & other liabilities	$	43.5	$	38.4

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

	Year Ended December 31,
(In millions)	2011			2010			2009
ProLiance Holdings, LLC	$	(28.6	)	$	(2.5	)	$	3.6
Haddington Energy Partners, LP		-			(6.1	)		0.9
Other		(3.4	)		-			(1.1	)
Total equity in earnings (losses) of unconsolidated affiliates	$	(32.0	)	$	(8.6	)	$	3.4

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Other income (expense) – net in the Consolidated Statements of Income consists of the following:

	Year Ended December 31,
(In millions)	2011			2010			2009
AFUDC – borrowed funds	$	2.5		$	1.4		$	1.3
AFUDC – equity funds		0.2			0.3			0.7
Nonutility plant capitalized interest		2.1			2.1			6.0
Interest income, net		1.4			1.7			1.4
Other nonutility investment impairment charges		(9.9	)		(4.7	)		-
Cash surrender value of life insurance policies		0.1			1.9			4.1
All other income		0.1			2.1			0.2
Total other income (expense) – net	$	(3.5	)	$	4.8		$	13.7

Supplemental Cash Flow Information:

	Year Ended December 31,
(In millions)	2011			2010		2009
Cash paid (received) for:
Interest	$	108.6		$	104.5	$	95.5
Income taxes		(9.0	)		8.1		(12.2	)

As of December 31, 2011 and 2010, the Company has accruals related to utility and nonutility plant purchases totaling approximately $15.9 million and $13.9 million, respectively.

24.   Impact of Recently Issued Accounting Guidance

Other Comprehensive Income (OCI)

In June 2011, the FASB issued new accounting guidance regarding the presentation of comprehensive income within financial statements.  The new guidance will require entities to report components of comprehensive income in either (1) a continuous statement of comprehensive income or (2) two separate but consecutive statements.  Under the two-statement approach, the first statement would include components of net income, which is consistent with the income statement format used today, and the second statement would include components of OCI.  The guidance does not change the items that must be reported in OCI.  The new guidance is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011 and retrospective application is required.  The Company will adopt this guidance for its quarterly reporting period ending March 31, 2012.  The adoption of this guidance will have no material impacts to the Company’s financial statements.

Goodwill Testing

In September 2011, the FASB issued new accounting guidance regarding testing goodwill for impairment.  The new guidance will allow the Company an option to first assess qualitative factors to determine whether it is necessary to perform the two-step quantitative goodwill impairment test.  Using the new guidance, the Company no longer would be required to calculate the fair value of a reporting unit unless the Company determines, based on that qualitative assessment, that it is more likely than not that its fair value is less than its carrying amount.  The new guidance is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011.  The adoption of this guidance will have no material impact to the Company’s financial statements.

Multiemployer Pension Plan Disclosures

In September 2011, the FASB issued new accounting guidance that requires enhanced disclosures regarding an employer’s participation in multiemployer pension plans.  For plans that are individually significant, these enhanced disclosures include the legal name of the plan, the plan’s Employer Identification Number, the employer’s contributions made to the plan, the expiration date(s) of the collective-bargaining agreement(s) requiring contributions to the plan, the most recently available certified zone status provided by the plan, and several other disclosures.  The Company participates in several multiemployer pension plans and has adopted this guidance for the Company’s 2011 financial statements as required.

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Fair Value Measurement and Disclosure

In May 2011, the FASB issued accounting guidance to improve the comparability of fair value measurements presented and disclosed in financial statements prepared in accordance with U.S. GAAP and International Financial Reporting Standards (IFRS). The amendments are not intended to change the application of the current fair value requirements, but to clarify the application of existing requirements. The guidance does change particular principles or requirements for measuring fair value or disclosing information about fair value measurements. To improve consistency, language has been changed to ensure that U.S. GAAP and IFRS fair value measurement and disclosure requirements are described in the same way. The guidance will be effective for interim and annual periods beginning after December 15, 2011. The Company will adopt this guidance for its quarterly reporting period ending March 31, 2012.  We do not expect the adoption of this guidance to have a material impact on our financial position, results of operations or cash flows.

25.   Quarterly Financial Data (Unaudited)

Information in any one quarterly period is not indicative of annual results due to the seasonal variations common to the Company’s utility operations.  Summarized quarterly financial data for 2011 and 2010 follows:

(In millions, except per share amounts)			Q1		Q2		Q3		Q4
2011
	Operating revenues	$	682.6	$	475.8	$	539.4	$	627.4
	Operating income		103.3		61.6		94.1		111.0
	Net income		44.6		15.1		35.3		46.6
	Earnings per share:
	Basic	$	0.55	$	0.19	$	0.43	$	0.56
	Diluted		0.55		0.18		0.43		0.56
2010
	Operating revenues	$	740.3	$	402.4	$	422.7	$	564.1
	Operating income		116.2		52.1		58.6		89.9
	Net income		63.2		8.7		16.4		45.4
	Earnings per share:
	Basic	$	0.78	$	0.11	$	0.20	$	0.56
	Diluted		0.78		0.11		0.20		0.55

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

None.

ITEM 9A.  CONTROLS AND PROCEDURES

Changes in Internal Controls over Financial Reporting

During the quarter ended December 31, 2011, there have been no changes to the Company’s internal controls over financial reporting that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

As of December 31, 2011, the Company conducted an evaluation under the supervision and with the participation of the Chief Executive Officer and Chief Financial Officer of the effectiveness and the design and operation of the Company's disclosure controls and procedures.  Based on that evaluation, the Chief Executive Officer and the Chief Financial Officer have concluded that the Company's disclosure controls and procedures are effective as of December 31, 2011, to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is:

 1) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and

 2) accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

Management’s Report on Internal Control over Financial Reporting

Vectren Corporation’s management is responsible for establishing and maintaining adequate internal control over financial reporting.  Under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, the Company conducted an evaluation of the effectiveness of its internal control over financial reporting based on the framework in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.  Based on that evaluation under the framework in Internal Control — Integrated Framework, the Company concluded that its internal control over financial reporting was effective as of December 31, 2011.

The effectiveness of internal control over financial reporting as of December 31, 2011, has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report which is included in Item 8 of this annual report.

ITEM 9B.  OTHER INFORMATION

None.

PART III

ITEM 10.  DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The information required by Part III, Item 10 of this Form 10-K is incorporated by reference herein, and made part of this Form 10-K, from the Company's Proxy Statement for its 2012 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission pursuant to Regulation 14A, within 120 days after the end of the fiscal year.  The Company’s executive officers are the same as those named executive officers detailed in the Proxy Statement.

Corporate Code of Conduct

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

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ITEM 11.  EXECUTIVE COMPENSATION

Information required by Part III, Item 11 of this Form 10-K is incorporated by reference herein, and made part of this Form 10-K, from the Company's Proxy Statement for its 2012 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission pursuant to Regulation 14A, within 120 days after the end of the fiscal year.

ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Except with respect to equity compensation plan information of the Registrant, which is included herein, the information required by Part III, Item 12 of this Form 10-K is incorporated by reference herein, and made part of this Form 10-K, from the Company's Proxy Statement for its 2012 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission pursuant to Regulation 14A, within 120 days after the end of the fiscal year.

Shares Issuable under Share-Based Compensation Plans

As of December 31, 2011, the following shares were authorized to be issued under share-based compensation plans:

	A		B		C
Plan category	Number of securities to be issued upon exercise of outstanding options, warrants and rights		Weighted average exercise price of outstanding options, warrants and rights		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
Equity compensation plans approved by
security holders	407,633	(1)	$                25.74	(1)	3,552,563	(2)
Equity compensation plans not approved
by security holders	-		-		-
Total	407,633		$                25.74		3,552,563

(1)   Under the Vectren At-Risk Compensation Plan, the Company may buy shares on the open market during periods when there are no restrictions on insider transactions to fulfill these obligations.

(2)   Effective January 1, 2012, 217,290 restricted units were issued to management by the Compensation and Benefits Committee of the Board of Directors.  In addition, participants forfeited 214,827 shares related to awards measured during the three year performance period ending December 31, 2011.  The issuance and forfeiture of shares are not included in the above table.

The At-Risk Compensation plan was approved by Vectren Corporation common shareholders after the merger forming Vectren and was most recently amended and reapproved at the 2011 annual meeting of shareholders.

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ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

Information required by Part III, Item 13 of this Form 10-K is incorporated by reference herein, and made part of this Form 10-K, from the Company's Proxy Statement for its 2012 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission pursuant to Regulation 14A, within 120 days after the end of the fiscal year.

ITEM 14.  PRINCIPAL ACCOUNTANT FEES AND SERVICES

Information required by Part III, Item 14 of this Form 10-K is incorporated by reference herein, and made part of this Form 10-K, from the Company's Proxy Statement for its 2012 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission pursuant to Regulation 14A, within 120 days after the end of the fiscal year.

PART IV

ITEM 15.  EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

List of Documents Filed as Part of This Report

Consolidated Financial Statements

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

Supplemental Schedules

For the years ended December 31, 2011, 2010, and 2009, the Company’s Schedule II -- Valuation and Qualifying Accounts Consolidated Financial Statement Schedules is presented herein.  The report of Deloitte & Touche LLP on the schedule may be found in Item 8.  All other schedules are omitted as the required information is inapplicable or the information is presented in the Consolidated Financial Statements or related notes in Item 8.

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SCHEDULE II

Vectren Corporation and Subsidiaries

VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

Column A	Column B		Column C				Column D		Column E
			Additions
	Balance at		Charged		Charged		Deductions		Balance at
	Beginning		to		to Other		from		End of
Description	of Year		Expenses		Accounts		Reserves, Net		Year
(In millions)
VALUATION AND QUALIFYING ACCOUNTS:
Year 2011 – Accumulated provision for
uncollectible accounts	$	5.3	$	11.8	$	-	$	10.4	$	6.7
Year 2010 – Accumulated provision for
uncollectible accounts	$	5.2	$	16.8	$	-	$	16.7	$	5.3
Year 2009 – Accumulated provision for
uncollectible accounts	$	5.6	$	15.1	$	-	$	15.5	$	5.2
Year 2011 – Reserve for impaired
notes receivable	$	6.1	$	9.6	$	-	$	-	$	15.7
Year 2010 – Reserve for impaired
notes receivable	$	9.2	$	1.2	$	-	$	4.3	$	6.1
Year 2009 – Reserve for impaired
notes receivable	$	6.3	$	2.9	$	-	$	-	$	9.2
OTHER RESERVES:
Year 2011 – Restructuring costs	$	0.4	$	-	$	-	$	-	$	0.4
Year 2010 – Restructuring costs	$	0.5	$	-	$	-	$	0.1	$	0.4
Year 2009 – Restructuring costs	$	0.6	$	-	$	-	$	0.1	$	0.5

List of Exhibits

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

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Vectren Corporation

Form 10-K

Attached Exhibits

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

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

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

Exhibit Number	Document
10.1	First Amendment to Credit Agreement, dated September 30, 2010, among Vectren Capital Corp., and each of the financial institutions named therein.
21.1	List of Company’s Significant Subsidiaries
23.1	Consent of Independent Registered Public Accounting Firm
101.INS*	XBRL Instance Document
101.SCH*	XBRL Taxonomy Extension Schema
101.CAL*	XBRL Taxonomy Calculation Linkbase
101.DEF*	XBRL Taxonomy Extension Definition Linkbase
101.LAB*	XBRL Taxonomy Extension Labels Linkbase
101.PRE*	XBRL Taxonomy Extension Presentation Linkbase

INDEX TO EXHIBITS

3.  Articles of Incorporation and By-Laws

3.1   Amended and Restated Articles of Incorporation of Vectren Corporation effective March 31, 2000.  (Filed and designated in Current Report on Form 8-K filed April 14, 2000, File No. 1-15467, as Exhibit 4.1.)

3.2   Code of By-Laws of Vectren Corporation as Most Recently Amended and Restated as of May 11, 2011.  (Filed and designated in Current Report on Form 8-K filed May 13, 2011, File No. 1-15467, as Exhibit 3.1.)

4.   Instruments Defining the Rights of Security Holders, Including Indentures

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

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

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

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

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

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

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

4.8   Note Purchase Agreement, dated April 5, 2011, among Vectren Utility Holdings, Inc., Indiana Gas Company, Inc., Southern Indiana Gas and Electric Company and Vectren Energy Delivery of Ohio, Inc. and the purchasers named therein.  (Filed and designated in Form 8-K dated April 8, 2011 File No. 1-15467, as Exhibit 4.1)

4.9   Note Purchase Agreement, dated November 15, 2011, among Vectren Utility Holdings, Inc., Indiana Gas Company, Inc., Southern Indiana Gas and Electric Company and Vectren Energy Delivery of Ohio, Inc. and the purchasers named therein.  (Filed and designated in Form 8-K dated November 17, 2011 File No. 1-15467, as Exhibit 4.1)

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10. Material Contracts

10.1   Vectren Corporation At Risk Compensation Plan effective May 1, 2001, (as most recently amended and restated as of May 1, 2011).  (Filed and designated in Form 8-K dated May 17, 2011, File No. 1-15467, as Exhibit 10.1.)

10.2   Vectren Corporation Non-Qualified Deferred Compensation Plan, as amended and restated effective January 1, 2001.  (Filed and designated in Form 10-K, for the year ended December 31, 2001, File No. 1-15467, as Exhibit 10.32.)

10.3   Vectren Corporation Nonqualified Deferred Compensation Plan, effective January 1, 2005.  (Filed and designated in Form 8-K dated September 29, 2008, File No. 1-15467, as Exhibit 10.3.)

10.4   Vectren Corporation Unfunded Supplemental Retirement Plan for a Select Group of Management Employees (As Amended and Restated Effective January 1, 2005).(Filed and designated in Form 8-K dated December 17, 2008, File No. 1-15467, as Exhibit 10.1.)

10.5   Vectren Corporation Nonqualified Defined Benefit Restoration Plan (As Amended and Restated Effective January 1, 2005). (Filed and designated in Form 8-K dated December 17, 2008, File No. 1-15467, as Exhibit 10.2.)

10.6   Vectren Corporation At Risk Compensation Plan specimen unit award agreement for officers, effective January 1, 2010.  (Filed and designated in Form 8-K, dated January 7, 2010, File No. 1-15467, as Exhibit 10.1.)

10.7   Vectren Corporation At Risk Compensation Plan specimen unit award agreement for officers, effective January 1, 2009.  (Filed and designated in Form 8-K, dated February 17, 2009, File No. 1-15467, as Exhibit 10.1.)

10.8   Vectren Corporation At Risk Compensation Plan specimen restricted stock grant agreement for officers, effective January 1, 2008.  (Filed and designated in Form 8-K, dated December 28, 2007, File No. 1-15467, as Exhibit 99.1.)

10.9   Vectren Corporation At Risk Compensation Plan specimen restricted stock units agreement for officers, effective January 1, 2008.  (Filed and designated in Form 8-K, dated December 28, 2007, File No. 1-15467, as Exhibit 99.2.)

10.10   Vectren Corporation At Risk Compensation Plan specimen Stock Option Grant Agreement for officers, effective January 1, 2005.  (Filed and designated in Form 8-K, dated January 1, 2005, File No. 1-15467, as Exhibit 99.2.)

10.11   Vectren Corporation At Risk Compensation Plan stock unit award agreement for non-employee directors, effective May 1, 2009. (Filed and designation in Form 8-K, dated February 20, 2009, File No. 1-15467, as Exhibit 10.1)

10.12   Vectren Corporation specimen change in control agreement dated December 31, 2011.  (Filed and designated in Form 8-K, dated January 5, 2012, File No. 1-15467, as Exhibit 10.1)  The specimen agreement significantly differs among the named executive officers only to the extent change in control benefits are provided in the amount of three times base salary and bonus for Mr. Carl L. Chapman and two times base salary and bonus for Messer’s Jerome A. Benkert, Jr., Ronald E. Christian, William S. Doty, and John M. Bohls.

10.13   Vectren Corporation specimen severance plan agreement dated December 31, 2011.  (Filed and designated in Form 8-K, dated January 5, 2012 File No. 1-15467, as Exhibit 10.2)  The severance plan differs among the named executive officers only to the extent where severance benefits are provided in the amount of two times base salary for Mr. Chapman and one and one half times base salary for Messer’s Benkert, Christian, Doty, and Bohls.  

10.14   Coal Supply Agreement for Warrick 4 Generating Station between Southern Indiana Gas and Electric Company and Vectren Fuels, Inc., effective January 1, 2009.  (Filed and designated in Form 8-K dated January 5, 2009, File No. 1-15467, as Exhibit 10.1.)

10.15   Coal Supply Agreement for F.B. Culley Generating Station between Southern Indiana Gas and Electric Company and Vectren Fuels, Inc., effective January 1, 2009.  (Filed and designated in Form 8-K dated January 5, 2009, File No. 1-15467, as Exhibit 10.2.)

10.16   Coal Supply Agreement for A.B. Brown Generating Station for 410,000 tons between Southern Indiana Gas and Electric Company and Vectren Fuels, Inc., effective January 1, 2009.  (Filed and designated in Form 8-K dated January 5, 2009, File No. 1-15467, as Exhibit 10.3.)

10.17   Coal Supply Agreement for A.B. Brown Generating Station for 1 million tons between Southern Indiana Gas and Electric Company and Vectren Fuels, Inc., effective January 1, 2009.  (Filed and designated in Form 8-K dated January 5, 2009, File No. 1-15467, as Exhibit 10.4.)

10.18   Amendment to F.B. Culley and A.B. Brown Coal Supply Agreements dated December 21, 2009. (Filed and designated in Form 10-K, for the year ended December 31, 2009, File No. 1-15467, as Exhibit 10.1)

10.19   Amendment No. 1 to Coal Supply Agreement for Warrick 4 Generating Station between Southern Indiana Gas and Electric Company and Vectren Fuels, Inc., effective October 31, 2011.  (Filed and designated in Form 8-K dated November 1, 2011, File No. 1-15467, as Exhibit 10.1.)  Portions of the document have been omitted and filed separately pursuant to a request for confidential treatment filed with the Securities and Exchange Commission which was granted.

10.20   Amendment No. 2 to Coal Supply Agreement for F.B. Culley Generating Station between Southern Indiana Gas and Electric Company and Vectren Fuels, Inc., effective October 31, 2011.  (Filed and designated in Form 8-K dated November 1, 2011, File No. 1-15467, as Exhibit 10.2.)  Portions of the document have been omitted and filed separately pursuant to a request for confidential treatment filed with the Securities and Exchange Commission which was granted.

10.21   Amendment No. 2 to Coal Supply Agreement for A.B. Brown Generating Station between Southern Indiana Gas and Electric Company and Vectren Fuels, Inc., effective October 31, 2011.  (Filed and designated in Form 8-K dated November 1, 2011, File No. 1-15467, as Exhibit 10.3.)  Portions of the document have been omitted and filed separately pursuant to a request for confidential treatment filed with the Securities and Exchange Commission which was granted.

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10.22   Gas Sales and Portfolio Administration Agreement between Indiana Gas Company, Inc. and ProLiance Energy, LLC, effective April 1, 2011.  (Filed and designated in Form 8-K, dated November 1, 2011, File No. 1-15467, as Exhibit 10.1.)

10.23   Gas Sales and Portfolio Administration Agreement between Southern Indiana Gas and Electric Company and ProLiance Energy, LLC, effective April 1, 2011.  (Filed and designated in Form 8-K, dated November 1, 2011, File No. 1-15467, as Exhibit 10.2.)

10.24   Formation Agreement among Indiana Energy, Inc., Indiana Gas Company, Inc., IGC Energy, Inc., Indiana Energy Services, Inc., Citizens Energy Group, Citizens Energy Services Corporation and ProLiance Energy, LLC, effective March 15, 1996.  (Filed and designated in Form 10-Q for the quarterly period ended March 31, 1996, File No. 1-9091, as Exhibit 10-C.)

10.25   Credit Agreement, dated September 30, 2010, among Vectren Utility Holdings, Inc., and each of the financial institutions named therein.  (Filed and designated in Form 8-K dated October 5, 2010, File No. 1-15467, as Exhibit 10.1)

10.26   Credit Agreement, dated September 30, 2010, among Vectren Capital Corp., and each of the financial institutions named therein.  (Filed and designated in Form 8-K dated October 5, 2010, File No. 1-15467, as Exhibit 10.2)

10.27   First Amendment to Credit Agreement, dated November 10, 2011, among Vectren Utility Holdings, Inc., and each of the financial institutions named therein.  (Filed and designated in Form 8-K dated November 14, 2011, File No. 1-15467, as Exhibit 10.1)

10.28   First Amendment to Credit Agreement, dated September 30, 2010, among Vectren Capital Corp., and each of the financial institutions named therein.  (Filed herewith as Exhibit 10.1)

10.29   Second Amendment to Credit Agreement, dated November 10, 2011, among Vectren Capital Corp., and each of the financial institutions named therein.  (Filed and designated in Form 8-K dated November 14, 2011, File No. 1-15467, as Exhibit 10.2)

21. Subsidiaries of the Company

The list of the Company's significant subsidiaries is attached hereto as Exhibit 21.1. (Filed herewith.)

23. Consents of Experts and Counsel

The consents of Deloitte & Touche LLP are attached hereto as Exhibit 23.1. (Filed herewith.)

31. Certification Pursuant To Section 302 of the Sarbanes-Oxley Act of 2002

Chief Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act Of 2002 is attached hereto as Exhibit 31.1 (Filed herewith.)

Chief Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act Of 2002 is attached hereto as Exhibit 31.2 (Filed herewith.)

32. Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

Certification Pursuant To Section 906 of the Sarbanes-Oxley Act Of 2002 is attached hereto as Exhibit 32 (Filed herewith.)

101 Interactive Data File

101.INS*  XBRL Instance Document (Furnished herewith.)

101.SCH*  XBRL Taxonomy Extension Schema (Furnished herewith.)

101.CAL*   XBRL Taxonomy Extension Calculation Linkbase (Furnished herewith.)

101.DEF*   XBRL Taxonomy Extension Definition Linkbase (Furnished herewith.)

101.LAB*   XBRL Taxonomy Extension Labels Linkbase (Furnished herewith.)

101.PRE*   XBRL Taxonomy Extension Presentation Linkbase (Furnished herewith.)

* Users of the XBRL-related information in Exhibit 101 to this Annual Report on Form 10-K are advised in accordance with Rule 406T of Regulation S-T promulgated by the Securities and Exchange Commission that this Interactive Data File is deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, is deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934, and otherwise is not subject to liability under these sections.  The financial information contained in the XBRL-related documents is “unaudited” and “unreviewed.”

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SIGNATURES

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

VECTREN CORPORATION

Dated February 16, 2012                                                                         /s/ Carl L. Chapman                                                                

Carl L. Chapman,

Chairman, President, and Chief Executive Officer

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

Signature	Title	Date
/s/ Carl L. Chapman	Chairman, President, and Chief Executive Officer	February 16, 2012
Carl L. Chapman	(Principal Executive Officer)
/s/ Jerome A. Benkert, Jr.	Executive Vice President and Chief Financial Officer	February 16, 2012
Jerome A. Benkert, Jr.	(Principal Financial Officer)
/s/ M. Susan Hardwick	Vice President, Controller and Assistant Treasurer	February 16, 2012
M. Susan Hardwick	(Principal Accounting Officer)
/s/ James H. DeGraffenreidt	Director	February 16, 2012
James H. DeGraffenreidt
/s/ Niel C. Ellerbrook	Director	February 16, 2012
Niel C. Ellerbrook
/s/ John D. Engelbrecht	Director	February 16, 2012
John D. Engelbrecht
/s/ Anton H. George	Director	February 16, 2012
Anton H. George
/s/ Martin C. Jischke	Director	February 16, 2012
Martin C. Jischke

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/s/ Robert G. Jones	Director	February 16, 2012
Robert G. Jones
/s/ William G. Mays	Director	February 16, 2012
William G. Mays
/s/ J. Timothy McGinley	Director	February 16, 2012
J. Timothy McGinley
/s/ R. Daniel Sadlier	Director	February 16, 2012
R. Daniel Sadlier
/s/ Michael L. Smith	Director	February 16, 2012
Michael L. Smith
/s/ Jean L. Wojtowicz	Director	February 16, 2012
Jean L. Wojtowicz

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EX-10.1

Exhibit 10.1

FIRST AMENDMENT

Reference is made to that certain Credit Agreement, dated as of September 30, 2010 (as amended and modified from time to time, the "Credit Agreement"), by and among Vectren Capital Corp., an Indiana corporation (the "Borrower"), the Guarantor, the Lenders and Wells Fargo Bank, National Association, as administrative agent (the "Administrative Agent").  Capitalized terms used herein without definition shall have the meanings ascribed to such terms in the Credit Agreement.

The parties hereto agree that a mutual error was made in drafting Section 7.13(i) of the Credit Agreement and that Section 7.13(i) of the Credit Agreement is hereby amended and restated in its entirety to read as follows:

(i)           in addition to Liens covered by (a)-(h) above, Liens securing Indebtedness not exceeding 15% of the Guarantor's Consolidated Net Worth in the aggregate outstanding at any time.

This First Amendment is a Loan Document.  All references in the Credit Agreement and the other Loan Documents to the Credit Agreement shall be deemed to refer to the Credit Agreement as amended hereby.  Except as modified hereby, all of the terms and provisions of the Credit Agreement and the other Loan Documents shall remain in full force and effect.

This First Amendment may be executed by the parties hereto in several counterparts, each of which shall be deemed to be an original and all of which shall constitute together but one and the same agreement.  Delivery of an executed counterpart by telecopy or other secure electronic format (.pdf) shall be as effective as an original.  This First Amendment shall be governed by the laws of the State of Illinois and shall become effective upon the Administrative Agent's receipt of counterparts hereof duly executed by the Required Lenders and each of the Loan Parties.

[SIGNATURE PAGES FOLLOW]

The parties hereto have caused this First Amendment to be executed as of November 2, 2010.

WELLS FARGO BANK, NATIONAL ASSOCIATION,

as Administrative Agent

By           /s/ Allison Newman                                                                

Name:           Allison Newman

Title:           Director

LENDERS:                                           WELLS FARGO BANK, NATIONAL ASSOCIATION,

as a Lender, Swing Line Lender and an L/C Issuer

By:           /s/ Allison Newman                                                      

Name:           Allison Newman

Title:           Director

BANK OF AMERICA, N.A.,

as a Lender and an L/C Issuer

By:           /s/ Carlos Morales                                                      

Name:           Carlos Morales

Title:           Vice President

JPMORGAN CHASE BANK, N.A.,

as a Lender and an L/C Issuer

By:           /s/ Helen D. Davis                                                      

Name:           Helen D. Davis

Title:           Authorized Officer

UNION BANK, N.A.,

as a Lender and an L/C Issuer

By:           /s/ Susan K. Johnson                                                                

Name:           Susan K. Johnson

Title:           Vice President

FIFTH THIRD BANK,

as a Lender

By:           /s/ Jennifer Raibley                                                      

Name:           Jennifer Raibley

Title:           Vice President

U.S. BANK NATIONAL ASSOCIATION,

as a Lender

By:           /s/ Shawn O’Hara                                                      

Name:           Shawn O’Hara

Title:           Managing Director

PNC BANK, NATIONAL ASSOCIATION,

as a Lender

By:           /s/ Chris Johnson                                                      

Name:           Chris Johnson

Title:           Assistant Vice President

REGIONS BANK,

as a Lender

By:           /s/ Eric Harvey                                                      

Name:           Eric Harvey

Title:           Vice President

OLD NATIONAL BANK,

as a Lender

By:           /s/ Wade Jenkins                                           

Name:           Wade Jenkins

Title:           Vice President

INTEGRA BANK N.A.,

as a Lender

By:           /s/ Chris E. Rutledge                                                      

Name:           Chris E. Rutledge

Title:           SVP

BORROWER: VECTREN CAPITAL CORP.,

as Borrower

By           /s/ Robert L. Goocher                                                                

Name:           Robert L. Goocher

Title:           Vice President, Treasurer and Asst. Secretary

GUARANTOR:                                                      VECTREN CORPORATION

By           /s/ Robert L. Goocher                                                                

Name:           Robert L. Goocher

Title:           Treasurer and Vice President of InvestorRelations

INDS01 SWT 1320091v1

EX-21.1

Exhibit  21.1

VECTREN CORPORATION

Subsidiaries

Wholly Owned Subsidiaries:

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

Less than Wholly Owned Subsidiaries:

Name of Entity	State of Incorporation/ Jurisdiction	Doing Business As
ProLiance Holdings, LLC	Indiana
Reliant Services, LLC	Indiana
Haddington Energy Partners, LP	Delaware
Haddington Energy Partners II, LP	Delaware

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement Nos. 333-175243, 333-163828, 333-135429, 333-118399, 333-61252, 333-33684, and 333-33608 on Forms S-8 and in Registration Statement No. 333-178101 on Form S-3ASR of our reports dated February 16, 2012, relating to the consolidated financial statements and consolidated financial statement schedule of Vectren Corporation and subsidiaries, and the effectiveness of Vectren Corporation and subsidiaries’ internal control over financial reporting, appearing in this Annual Report on Form 10-K of Vectren Corporation for the year ended December 31, 2011.

Indianapolis, Indiana

February 16, 2012

EX-31.1

Exhibit 31.1

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

CHIEF EXECUTIVE OFFICER CERTIFICATION

I, Carl L. Chapman, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: February 16, 2012

/s/ Carl L. Chapman

Carl L. Chapman

Chairman, President, and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

CHIEF FINANCIAL OFFICER CERTIFICATION

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

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

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

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

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

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

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

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

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

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

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

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

Date: February 16, 2012

/s/ Jerome A. Benkert, Jr.

Jerome A. Benkert, Jr.

Executive Vice President and Chief Financial Officer

EX-32

Exhibit 32

CERTIFICATION PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

CERTIFICATION

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

Signed this 16th day of February, 2012.

/s/ Jerome A. Benkert, Jr.	/s/ Carl L. Chapman
(Signature of Authorized Officer)	(Signature of Authorized Officer)
Jerome A. Benkert, Jr.	Carl L. Chapman
(Typed Name)	(Typed Name)
Executive Vice President and Chief Financial Officer	Chairman, President, and Chief Executive Officer
(Title)	(Title)

XML

Nonutility Real Estate & Other Legacy Holdings (Tables)

12 Months Ended

Dec. 31, 2011

Nonutility Real Estate Other Legacy Holdings [Abstract]

Investment by type of investment

Further separation of that 2011 investment by type of investment follows:

	December 31, 2011
			Value Included In
(In millions)	Carrying Value		Other Nonutility Investments		Investments in Unconsolidated Affiliates
Commercial real estate investments	$	8.0	$	8.0	$	-
Leveraged leases		18.5		18.5		-
Affordable housing projects		3.1		0.1		3.0
Haddington energy partnerships		3.4		-		3.4
Other investments		3.9		3.0		0.9
	$	36.9	$	29.6	$	7.3

XML

Regulatory Assets & Liabilities (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Regulatory Assets [Abstract]
Regulatory assets	$ 226.0	$ 189.4
Regulatory Assets [Abstract]
Weighted average recovery period of regulatory assets currently being recovered (in years)	17
Regulatory Liabilities [Abstract]
Regulatory liabilities	345.2	333.5
Asset Retirement Obligations and Other [Member]
Regulatory Liabilities [Abstract]
Regulatory liabilities	320.9	307.5
Future Amounts Recoverable From Ratepayers [Member]
Regulatory Assets [Abstract]
Regulatory assets	129.6	113.8
Amounts Deferred for Future Recovery [Member]
Regulatory Assets [Abstract]
Regulatory assets	24.1	2.8
Amounts Currently Recovered in Customer Rates [Member]
Regulatory Assets [Abstract]
Regulatory assets	72.3	72.8
Benefit Obligations [Member] | Future Amounts Recoverable From Ratepayers [Member]
Regulatory Assets [Abstract]
Regulatory assets	126.0	92.5
Deferred Income Tax Charges [Member] | Future Amounts Recoverable From Ratepayers [Member]
Regulatory Assets [Abstract]
Regulatory assets	1.3	19.2
Asset Retirement Obligations and Other [Member] | Future Amounts Recoverable From Ratepayers [Member]
Regulatory Assets [Abstract]
Regulatory assets	2.3	2.1
Cost Recovery Riders Other [Member] | Amounts Deferred for Future Recovery [Member]
Regulatory Assets [Abstract]
Regulatory assets	6.4	2.8
Unamortized Debt Issue Costs and Hedging Proceeds [Member] | Amounts Currently Recovered in Customer Rates [Member]
Regulatory Assets [Abstract]
Regulatory assets	34.3	35.7
Demand Side Management Programs [Member] | Amounts Currently Recovered in Customer Rates [Member]
Regulatory Assets [Abstract]
Regulatory assets	6.3	9.5
Indiana Authorized Trackers [Member] | Amounts Currently Recovered in Customer Rates [Member]
Regulatory Assets [Abstract]
Regulatory assets	24.3	17.3
Ohio Authorized Trackers [Member] | Amounts Currently Recovered in Customer Rates [Member]
Regulatory Assets [Abstract]
Regulatory assets	1.0	2.0
Premiums Paid to Reaquire Debt [Member] | Amounts Currently Recovered in Customer Rates [Member]
Regulatory Assets [Abstract]
Regulatory assets	3.3	3.8
Other Base Rate Recoveries [Member] | Amounts Currently Recovered in Customer Rates [Member]
Regulatory Assets [Abstract]
Regulatory assets	3.1	4.5
Deferred Coal Costs [Member] | Amounts Deferred for Future Recovery [Member]
Regulatory Assets [Abstract]
Regulatory assets	$ 17.7	$ 0

XML

Segment Reporting (Tables)

12 Months Ended

Dec. 31, 2011

Segment Reporting [Abstract]

Summary of business segment information

Information related to the Company's business segments is summarized as follows:

	Year Ended December 31,
(In millions)	2011			2010			2009
Revenues
Utility Group
Gas Utility Services	$	819.1		$	954.1		$	1,066.0
Electric Utility Services		635.9			608.0			528.6
Other Operations		43.9			44.5			42.8
Eliminations		(41.9	)		(42.9	)		(41.2	)
Total Utility Group		1,457.0			1,563.7			1,596.2
Nonutility Group
Infrastructure Services		421.3			235.6			202.0
Energy Services		161.8			146.9			121.3
Coal Mining		285.6			209.9			193.4
Energy Marketing		149.9			142.8			157.2
Total Nonutility Group		1,018.6			735.2			673.9
Eliminations		(150.4	)		(169.4	)		(181.2	)
Consolidated Revenues	$	2,325.2		$	2,129.5		$	2,088.9

Schedule of segment profitability measure

Profitability Measures - Net Income
Utility Group Net Income
Gas Utility Services	$	52.5		$	53.7		$	50.2
Electric Utility Services		65.0			60.9			48.3
Other Operations		5.4			9.3			8.9
Total Utility Group Net Income		122.9			123.9			107.4
Nonutility Group Net Income
Infrastructure Services		14.9			3.1			2.4
Energy Services		6.7			6.4			8.4
Coal Mining		16.6			11.9			13.4
Energy Marketing		(4.2	)		(4.2	)		4.1
Other Businesses		(10.2	)		(7.4	)		(2.5	)
Total Nonutility Group Net Income		23.8			9.8			25.8
Corporate & Other Net Loss		(5.1	)		-			(0.1	)
Consolidated Net Income	$	141.6		$	133.7		$	133.1

	Year Ended December 31,
(In millions)	2011			2010			2009
Amounts Included in Profitability Measures
Depreciation & Amortization
Utility Group
Gas Utility Services	$	84.3		$	80.7		$	76.9
Electric Utility Services		80.2			80.8			77.5
Other Operations		27.8			26.7			26.5
Total Utility Group		192.3			188.2			180.9
Nonutility Group
Infrastructure Services		14.9			8.8			8.3
Energy Services		1.5			1.2			1.2
Coal Mining		35.1			30.4			21.0
Energy Marketing		0.5			0.5			0.5
Total Nonutility Group		52.0			40.9			31.0
Consolidated Depreciation & Amortization	$	244.3		$	229.1		$	211.9
Interest Expense
Utility Group
Gas Utility Services	$	37.1		$	38.8		$	38.8
Electric Utility Services		36.4			36.4			34.8
Other Operations		6.8			6.2			5.6
Total Utility Group		80.3			81.4			79.2
Nonutility Group
Infrastructure Services		7.4			3.3			2.6
Energy Services		0.6			0.2			0.6
Coal Mining		11.3			10.1			8.1
Energy Marketing		6.4			8.5			8.3
Other Businesses		1.3			1.5			1.3
Total Nonutility Group		27.0			23.6			20.9
Corporate & Other		(0.8	)		(0.4	)		(0.1	)
Consolidated Interest Expense	$	106.5		$	104.6		$	100.0

Schedule of segment income taxes and capital expenditures

Income Taxes
Utility Group
Gas Utility Services	$	34.5		$	35.1		$	31.3
Electric Utility Services		45.3			40.8			27.4
Other Operations		3.1			1.2			0.5
Total Utility Group		82.9			77.1			59.2
Nonutility Group
Infrastructure Services		10.7			2.7			2.1
Energy Services		1.1			2.5			1.6
Coal Mining		3.9			1.9			4.1
Energy Marketing		(2.4	)		(2.7	)		0.3
Other Businesses		(7.0	)		(5.9	)		(2.2	)
Total Nonutility Group		6.3			(1.5	)		5.9
Corporate & Other		(2.8	)		(0.9	)		(1.0	)
Consolidated Income Taxes	$	86.4		$	74.7		$	64.1

	Year Ended December 31,
(In millions)	2011			2010			2009
Capital Expenditures
Utility Group
Gas Utility Services	$	113.5		$	88.7		$	121.1
Electric Utility Services		102.2			120.1			154.1
Other Operations		17.8			22.5			16.7
Non-cash costs & changes in accruals		(0.1	)		(6.2	)		10.8
Total Utility Group		233.4			225.1			302.7
Nonutility Group
Infrastructure Services		22.8			12.0			11.0
Energy Services		9.7			1.2			1.9
Coal Mining		55.1			38.7			126.8
Energy Marketing		0.3			0.2			0.6
Other Businesses, net of eliminations		-			-			(11.0	)
Total Nonutility Group		87.9			52.1			129.3
Consolidated Capital Expenditures	$	321.3		$	277.2		$	432.0

Schedule of segment assets

At December 31,
(In millions)		2011			2010			2009
Assets
Utility Group
Gas Utility Services	$	2,125.2		$	2,161.7		$	2,102.4
Electric Utility Services		1,656.5			1,666.5			1,592.4
Other Operations, net of eliminations		192.8			96.3			128.3
Total Utility Group		3,974.5			3,924.5			3,823.1
Nonutility Group
Infrastructure Services		295.0			174.6			141.4
Energy Services		81.2			67.4			54.5
Coal Mining		352.8			362.5			342.8
Energy Marketing		112.5			209.1			229.6
Other Businesses		39.6			57.1			65.7
Eliminations & Reclassifications		7.2			(2.2	)		2.0
Total Nonutility Group		888.3			868.5			836.0
Corporate & Other		727.3			706.2			715.9
Eliminations		(711.2	)		(735.0	)		(703.2	)
Consolidated Assets	$	4,878.9		$	4,764.2		$	4,671.8

XML

Rate & Regulatory Matters (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011
Vectren South Electric Base Rate Filing [Abstract]
Amount of revised rate increase filed in rebuttal to original rate increase to IURC	$ 28.6
Amount of infrastructure construction in the three years leading up to December 2009 rate filing	325.0
Rate of return included in rate increase (in hundredths)	7.29%
Dollar amount of the rate base included in rate increase	1,295.6
Amount of rate of return on equity included in rate base (in hundredths)	10.40%
VEDO Gas Rate Design [Abstract]
Percentage of residential and commercial base rate covered by customer service charge (in hundredths)	90.00%
Vectren South Electric Demand Side Management Program Filing [Abstract]
Number of years in initial demand side management program approved by the IURC (in years)	3
Maximum deferral of lost margin associated with small customer demand side programs	1.0
VEDO Continues the Process to Exit the Merchant Function [Abstract]
Length of contract for customers who purchase natural gas through state certified natural gas suppliers (in months)	12 Months
Number of auctions requirement related to the plan approved by the PUCO (in number of auctions)	2
Number of tranches of customers secured in first auction	1
Number of tranches of customers secured in second auction	2
Approximate Number Of Customers In Tranche	28,000
Vectren South Electric Dense Pack Filing [Abstract]
Expected capital investment to improve the efficiency of generating station	32.0
Number of years in capital improvement program (in years)	2
Amount of expected capital investment invested to date	$ 19.0
Expected increase in efficiency for generating station following improvement (in hundredths)	5.00%
Vectren South Electric Fuel Cost Reduction [Abstract]
Number of years for recovery of coal costs	6

XML

Acquisition of Minnesota Limited, Inc. (Details) (USD $)	3 Months Ended								12 Months Ended
	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Acquisition of Minnesota Limited, Inc. [Abstract]
Acquisition date									March 31, 2011
Purchase price allocation [Abstract]
Business acquisition, net of cash acquired									$ 83,400,000	$ 0	$ 0
Number of years goodwill is deductible (which does not amortize pursuant to FASB guidance) for computing current income tax expense (in years)									15
Transaction costs associated with the acquisition included in other operating expenses during the period									652,200,000	538,400,000	514,000,000
Nonutility									870,200,000	567,400,000	494,300,000
Net income (loss)	46,600,000	35,300,000	15,100,000	44,600,000	45,400,000	16,400,000	8,700,000	63,200,000	141,600,000	133,700,000	133,100,000
Minnesota Limited, Inc. [Member]
Purchase price allocation [Abstract]
Working capital assets	21,500,000								21,500,000
Working capital liabilities	(6,700,000)								(6,700,000)
Net Working Capital	14,800,000								14,800,000
Property, plant and equipment	34,400,000								34,400,000
Identifiable intangible assets	19,100,000								19,100,000
Goodwill	20,300,000								20,300,000
Net assets acquired	88,600,000								88,600,000
Debt obligation assumed	(5,200,000)								(5,200,000)
Business acquisition, net of cash acquired									83,400,000
Transaction costs associated with the acquisition	600,000								600,000
Transaction costs associated with the acquisition included in other operating expenses during the period									200,000
Lease Obligation									83,333
Number of years the company is obligated to lease acquiree's corporate headquarters	10								10
Nonutility									116,500,000
Net income (loss)									9,400,000
Business Acquisition, Pro Forma Revenue									2,346,300,000	2,239,700,000	2,210,000,000
Business Acquisition, Pro Forma Net Income (Loss)									$ 141,400,000	$ 134,600,000	$ 138,100,000
Business Acquisition, Pro Forma Earnings Per Share, Basic									$ 1.73	$ 1.66	$ 1.71
Business Acquisition, Pro Forma Earnings Per Share, Diluted									$ 1.73	$ 1.66	$ 1.70

XML

Share-Based Compensation & Deferred Compensation Arrangements (Tables)

12 Months Ended

Dec. 31, 2011

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Reconciliation of total cost of share-based awards to the after tax effect on net income

Following is a reconciliation of the total cost associated with share-based awards recognized in the Company's financial statements to its after tax effect on net income:

	Year ended December 31,
(In millions)	2011		2010		2009
Total cost of share-based compensation	$	5.8	$	4.9	$	4.6
Less capitalized cost		0.8		1.7		1.6
Total in other operating expense		5.0		3.2		3.0
Less income tax benefit in earnings		2.0		1.3		1.2
After tax effect of share-based compensation	$	3.0	$	1.9	$	1.8

Restricted stock units and shares outstanding

A summary of the status of the Company's restricted stock and restricted unit awards separated between those accounted for as liabilities and equity as of December 31, 2011, and changes during the year ended December 31, 2011, follows:

	Equity Awards
				Wtd. Avg.
				Grant Date		Liability Awards
	Shares			Fair value		Shares/Units			Fair value
Restricted awards at January 1, 2011		41,458		$	26.19		668,892
Granted		27,518			25.64		277,480
Vested		(7,226	)		28.63		(108,390	)
Forfeited		(7,737	)		28.61		(139,872	)
Restricted awards at December 31, 2011		54,013		$	25.22		698,110		$           30.23

Status of stock option awards and changes during the period

A summary of the status of the Company's stock option awards as of December 31, 2011, and changes during the year ended December 31, 2011, follows:

				Weighted average				Aggregate
						Remaining		Intrinsic
	Shares			Exercise		Contractual		Value
				Price		Term (years)		(In millions)
Outstanding at January 1, 2011		929,806		$	24.55
Exercised		(522,173	)	$	23.61
Outstanding at December 31, 2011		407,633		$	25.74		2.5	$	1.8
Exercisable at December 31, 2011		407,633		$	25.74		2.5	$	1.8

XML

SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

12 Months Ended

Dec. 31, 2011

SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES [Abstract]

SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

SCHEDULE II

Vectren Corporation and Subsidiaries

VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

Column A	Column B		Column C				Column D		Column E
			Additions
	Balance at		Charged		Charged		Deductions		Balance at
	Beginning		to		to Other		from		End of
Description	of Year		Expenses		Accounts		Reserves, Net		Year
(In millions)
VALUATION AND QUALIFYING ACCOUNTS:
Year 2011 - Accumulated provision for
uncollectible accounts	$	5.3	$	11.8	$	-	$	10.4	$	6.7
Year 2010 - Accumulated provision for
uncollectible accounts	$	5.2	$	16.8	$	-	$	16.7	$	5.3
Year 2009 - Accumulated provision for
uncollectible accounts	$	5.6	$	15.1	$	-	$	15.5	$	5.2
Year 2011 - Reserve for impaired
notes receivable	$	6.1	$	9.6	$	-	$	-	$	15.7
Year 2010 - Reserve for impaired
notes receivable	$	9.2	$	1.2	$	-	$	4.3	$	6.1
Year 2009 - Reserve for impaired
notes receivable	$	6.3	$	2.9	$	-	$	-	$	9.2
OTHER RESERVES:
Year 2011 - Restructuring costs	$	0.4	$	-	$	-	$	-	$	0.4
Year 2010 - Restructuring costs	$	0.5	$	-	$	-	$	0.1	$	0.4
Year 2009 - Restructuring costs	$	0.6	$	-	$	-	$	0.1	$	0.5

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Additional Balance Sheet & Operational Information (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Inventories [Abstract]
Gas in storage - at average cost	$ 0	$ 23.6
Gas in storage - at LIFO cost	31.8	26.2
Total Gas in storage	31.8	49.8
Materials and supplies	54.9	48.8
Coal and Oil for electric generation - at average cost	60.6	70.1
Nonutility Coal - at LIFO cost	13.0	16.2
Other	1.6	2.2
Total inventories	161.9	187.1
Amount by which cost of replacing inventories carried at LIFO cost exceeded carrying value	12.0	16.0
Prepayments and other current assets [Abstract]
Prepaid gas delivery service	42.4	40.7
Deferred income taxes	16.0	3.8
Prepaid taxes	5.1	31.5
Other prepayments and current assets	20.8	25.2
Total prepayments and other current assets	84.3	101.2
Investments in unconsolidated affiliates [Abstract]
Total investments in unconsolidated affiliates	92.9	135.2
Equity in earnings (loss) of unconsolidated affiliates [Abstract]
Total equity in earnings (losses) of unconsolidated affiliates	(32.0)	(8.6)	3.4
Other utility and corporate investments [Abstract]
Cash surrender value of life insurance policies	27.3	27.5
Municipal bond	3.9	4.1
Restricted cash	1.9	1.2
Other investments	1.3	1.3
Other utility and corporate investments	34.4	34.1
Segment Reporting Information [Line Items]
Goodwill	262.3	242.0
Accrued liabilities [Abstract]
Refunds to customers and customer deposits	56.4	54.8
Accrued taxes	33.5	40.9
Accrued interest	21.7	23.8
Accrued retirement and deferred compensation benefits	6.5	5.8
Accrued salaries and other	63.0	53.1
Total accrued liabilities	181.1	178.4
Asset Retirement Obligation [Roll Forward]
Accrued liabilities	181.1	178.4
Deferred credits and other liabilities	239.4	220.6
Other - net in the consolidated statement of income [Abstract]
AFUDC - borrowed funds	2.5	1.4	1.3
AFUDC - equity funds	0.2	0.3	0.7
Nonutility plant capitalized interest	2.1	2.1	6.0
Interest income, net	1.4	1.7	1.4
Other nonutility investment impairment charges	(9.9)	(4.7)	0
Cash surrender value of life insurance policies	0.1	1.9	4.1
All other income	0.1	2.1	0.2
Total other - net	(3.5)	4.8	13.7
Cash paid for [Abstract]
Interest	108.6	104.5	95.5
Income taxes	(9.0)	8.1	(12.2)
Accruals related to utility and nonutility plant purchases [Abstract]
Accruals related to utility and nonutility plant purchases	15.9	13.9
Asset Retirement Obligation Costs [Member]
Accrued liabilities [Abstract]
Total accrued liabilities	0.2	0.3
Asset Retirement Obligation [Roll Forward]
Asset retirement obligation, beginning balance	38.7	36.1
Accretion	2.5	2.1
Increases (decreases) in estimates, net of cash payments	2.5	0.5
Asset retirement obligation, ending balance	43.7	38.7
Accrued liabilities	0.2	0.3
Deferred credits and other liabilities	43.5	38.4
Utility Group [Member] | Gas Utility Services [Member]
Segment Reporting Information [Line Items]
Goodwill	205.0	205.0
Nonutility Group [Member]
Investments in unconsolidated affiliates [Abstract]
Total investments in unconsolidated affiliates	7.3
Nonutility Group [Member] | Infrastructure Services [Member]
Segment Reporting Information [Line Items]
Goodwill	55.2	34.9
Nonutility Group [Member] | Energy Services [Member]
Segment Reporting Information [Line Items]
Goodwill	2.1	2.1
ProLiance Holdings, LLC [Member]
Investments in unconsolidated affiliates [Abstract]
Total investments in unconsolidated affiliates	85.4	123.2
Equity in earnings (loss) of unconsolidated affiliates [Abstract]
Total equity in earnings (losses) of unconsolidated affiliates	(28.6)	(2.5)	3.6
Haddington Energy Partners, LP [Member]
Investments in unconsolidated affiliates [Abstract]
Total investments in unconsolidated affiliates	3.4	3.4
Equity in earnings (loss) of unconsolidated affiliates [Abstract]
Total equity in earnings (losses) of unconsolidated affiliates	0	(6.1)	0.9
Other Nonutility Partnerships and Corporations [Member]
Investments in unconsolidated affiliates [Abstract]
Total investments in unconsolidated affiliates	3.9	8.4
Other Utility Investments [Member]
Investments in unconsolidated affiliates [Abstract]
Total investments in unconsolidated affiliates	0.2	0.2
Other Unconsolidated Affiliates [Member]
Equity in earnings (loss) of unconsolidated affiliates [Abstract]
Total equity in earnings (losses) of unconsolidated affiliates	$ (3.4)	$ 0	$ (1.1)

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Investment in ProLiance Holdings, LLC (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
ProLiance Holdings, LLC [Abstract]
Equity method investment, profit and loss ownership percentage (in hundredths)	61.00%
Equity method investment, ownership percentage (in hundredths)	50.00%
Summarized balance sheet information:
Current assets	$ 381.9	$ 441.4
Noncurrent assets	56.1	59.1
Current liabilities	298.5	298.1
Noncurrent liabilities	0.7	0.4
Members' equity	161.5	208.9
Accumulated other comprehensive income (loss)	(26.0)	(10.8)
Noncontrolling interest	3.3	3.9
Investments in unconsolidated Affiliates [Line Items]
Investments in unconsolidated affiliates	92.9	135.2
Equity in earnings (losses) of unconsolidated affiliates	(32.0)	(8.6)	3.4
Equity method investment holding minority interest in equity method investment (in hundredths)	25.00%
Equity method investment minority interest in joint ventures	35.1	36.7
Impairment Charge Recorded By Investee Of Companys Equity Method Investments			132.0
Equity method investment unusual item gain or loss net of tax attributable to noncontrolling interest			11.9
Reduction to Equity in earnings of unconsolidated affiliates-gross			19.9
Income tax benefit due to gain or loss			8.0
Loss contingency, gross damages sought from a party that entered into a sub-lease agreement with a party that is an investment of an equity method investee.	56.7
Firm transportation and storage agreements due within one year of the balance sheet date	55.5
Firm transportation and storage agreements due in more than one and within two years of the balance sheet date	49.0
Firm transportation and storage agreements due in more than two and within three years of the balance sheet date	46.6
Firm transportation and storage agreements due in more than three and within four years of the balance sheet date	38.2
Firm transportation and storage agreements due in more than four and within five years of the balance sheet date	33.9
Firm transportation and storage agreements due after five years from the balance sheet date	247.9
Fixed payments for firm storage and transportation commitments	73.0	76.8	63.0
Purchases from ProLiance for resale and for injections into storage	378.7	437.7	533.4
Amounts owed to ProLiance for those purchases	36.8	59.6
ProLiance Holdings, LLC [Member]
Investments in unconsolidated Affiliates [Line Items]
Investments in unconsolidated affiliates	85.4	123.2
Equity in earnings (losses) of unconsolidated affiliates	(28.6)	(2.5)	3.6
Summarized Statement of Income [Member]
Summarized Statement of Income information [Abstract]
Revenues	1,410.5	1,497.0	1,654.9
Operating income (loss)	(44.5)	(3.1)	35.2
Charge related to Investment in Liberty Gas Storage	0	0	(32.7)
ProLiance's earnings (losses)	$ (47.3)	$ (3.7)	$ 4.5

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Fair Value Measurements (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Period to recover call premiums on reacquisition of long-term debt	15-year
Carrying value of notes receivable, inclusive of any accrued interest and net of impairment reserves	$ 2.1	$ 10.9
Error corrections and prior period adjustment, description		The fair value table in Note 18 of the financial statements in the 2010 Form 10-K excluded the estimated fair value of a long-term debt instrument. The chart above now includes the amount and reflects an increase in the estimated fair value of long-term debt of approximately $73.9 million. This change in the disclosed fair value of long-term debt had no effect on the carrying value of debt included in the consolidated balance sheet.
Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	1,622.3	1,715.9
Short-term borrowings	227.1	118.3
Cash and cash equivalents	8.6	10.4
Estimated Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	1,804.4	1,841.2
Short-term borrowings	227.1	118.3
Cash and cash equivalents	$ 8.6	$ 10.4

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Legislative Matters

12 Months Ended

Dec. 31, 2011

Legislative Matters Disclosure [Abstract]

Legislative Matters

18.   Legislative Matters

Pipeline Safety Law

On January 3, 2012 the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 was signed into law.  This new law, which reauthorizes federal pipeline safety programs through fiscal year 2015, provides for enhanced safety, reliability and environmental protection in the transportation of energy products by pipeline. The new law increases federal enforcement authority, grants the federal government expanded authority over pipeline safety, provides for new safety regulations and standards, and authorizes or requires the completion of several pipeline safety-related studies.  The DOT is required to promulgate a number of new regulatory requirements.  The direction of those regulations will be based on the results of the studies and reports required or authorized by the new law and may eventually lead to further regulatory or statutory requirements.

The Company continues to study the impact of the new law and potential new regulations associated with its implementation.  At this time, compliance costs and other effects associated with the increased pipeline safety regulations remain uncertain.  However, the new law is expected to result in further investment in pipeline inspections, and where necessary, additional modernization of pipeline infrastructure; and therefore, result in both increased levels of operating expenses and capital expenditures associated with the Company's natural gas distribution businesses.  Operating expenses associated with expanded compliance requirements may grow to approximately $9 million annually, with $6 million attributable to the Indiana operations.  The Company expects to seek recovery under Senate Bill 251 referenced below, or such costs may be recoverable through current tracking mechanisms.  Capital investments, driven by the pipeline safety regulations, associated with the Company's Indiana gas utilities are expected to be approximately $80 million over the next five years, which would likely qualify as federally mandated regulatory requirements.  In Ohio, capital investments are expected to be approximately $55 million over the next five years.  The Company expects to seek recovery of capital investments associated with complying with these federal mandates in accordance with Senate Bill 251 in Indiana and House Bill 95 in Ohio (referenced below).

Indiana House Bill 1004

In May 2011, House Bill 1004 was signed into law.  This legislation phases in over four years a two percent rate reduction to the Indiana Adjusted Gross Income Tax for corporations.  Pursuant to House Bill 1004, the tax rate will be lowered by one-half percent each year beginning on July 1, 2012, to the final rate of six and one-half percent effective July 1, 2015.  Pursuant to FASB guidance, the Company accounted for the effect of the change in tax law on its deferred taxes in the second quarter of 2011, the period of enactment.  The impact was not material to results of operations or financial condition as the decrease in Deferred tax liabilities was generally offset by a $17.1 million decrease in Regulatory assets.

Indiana Senate Bill 251

In April 2011, Senate Bill 251 was signed into law.  While the bill is broad in scope, it allows for cost recovery outside of a base rate proceeding for federal government mandated projects and provides for a voluntary clean energy portfolio standard. 

The law applies to both gas and electric utility operations and provides a framework to recover 80 percent of federally mandated costs through a periodic rate adjustment mechanism outside of a general rate case.  Such costs include construction, depreciation, operating and other costs.  The remaining 20 percent of those costs are to be deferred for recovery in the utility's next general rate case.  The Company is currently evaluating the impact this law may have on its operations, including applicability to expenditures associated with the integrity, safety, and reliable operation of natural gas pipelines and facilities; ash disposal; water regulations; and air pollution, including greenhouse gas emissions, among other federally mandated projects and potential projects. 

The legislation establishes a voluntary clean energy portfolio standard that provides incentives to electricity suppliers participating in the program.  The goal of the program is that by 2025, at least 10 percent of the total electricity obtained by the supplier to meet the energy needs of its Indiana retail customers will be provided by clean energy sources, as defined.  The financial incentives include an enhanced return on equity and tracking mechanisms to recover program costs.  In advance of a federal portfolio standard and Senate Bill 251, SIGECO received regulatory approval to purchase a 3 MW landfill gas generation facility from a related entity.  The facility was purchased in 2009 and is directly connected 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.  Before the impacts of efficiency measures, the Company currently stands at approximately 5 percent of its electricity being provided by clean energy sources due to the long-term wind contracts and landfill gas investments.  The Company continues to evaluate whether to participate in this voluntary program.

Ohio House Bill 95

In June 2011, Ohio House Bill 95 was signed into law.  The law adjusts, among other things, the manner in which gas utilities file for rate changes, including the implementation of base rate changes, alternative rate plans, and automatic rate adjustment mechanisms.  Outside of a base rate proceeding, the legislation permits a natural gas company to apply to implement a capital expenditure program for infrastructure expansion, upgrade, or replacement; installation, upgrade, or replacement of information technology systems; or any program necessary to comply with government regulation.  Once such application is approved, the legislation authorizes recovery or deferral of program costs, such as depreciation, property taxes, and carrying costs.  The Company is assessing the impact this legislation may have on its operations.  On February 3, 2012, the Company initiated a filing under House Bill 95.  This filing requests accounting authority to defer depreciation, post in service carrying costs and property taxes for its approximate $25 million 2012 capital expenditure program.  The capital expenditure program includes infrastructure expansion and improvements not covered by the Company's distribution replacement rider as well as expenditures necessary to comply with PUCO rules, regulations and orders.  A procedural schedule associated with the filing has not yet been set.

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Quarterly Financial Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2011

Quarterly Financial Data (Unaudited) [Abstract]

Summarized quarterly financial data

25.   Quarterly Financial Data (Unaudited)

Information in any one quarterly period is not indicative of annual results due to the seasonal variations common to the Company's utility operations.  Summarized quarterly financial data for 2011 and 2010 follows:

(In millions, except per share amounts)			Q1		Q2		Q3		Q4
2011
	Operating revenues	$	682.6	$	475.8	$	539.4	$	627.4
	Operating income		103.3		61.6		94.1		111.0
	Net income		44.6		15.1		35.3		46.6
	Earnings per share:
	Basic	$	0.55	$	0.19	$	0.43	$	0.56
	Diluted		0.55		0.18		0.43		0.56
2010
	Operating revenues	$	740.3	$	402.4	$	422.7	$	564.1
	Operating income		116.2		52.1		58.6		89.9
	Net income		63.2		8.7		16.4		45.4
	Earnings per share:
	Basic	$	0.78	$	0.11	$	0.20	$	0.56
	Diluted		0.78		0.11		0.20		0.55

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Retirement Plans & Other Postretirement Benefits (Tables)

12 Months Ended

Dec. 31, 2011

Retirement Plans and Other Postretirement Benefits [Abstract]

Summary of components of net periodic benefit cost

A summary of the components of net periodic benefit cost for the three years ended December 31, 2011 follows:

	Pension Benefits									Other Benefits
(In millions)	2011			2010			2009			2011			2010			2009
Service cost	$	6.9		$	6.3		$	6.3		$	0.5		$	0.5		$	0.5
Interest cost		15.9			15.9			15.8			4.3			4.6			4.4
Expected return on plan assets		(21.2	)		(18.4	)		(16.4	)		-			(0.4	)		(0.3	)
Amortization of prior service cost (benefit)		1.7			1.6			1.7			(0.8	)		(0.8	)		(0.8	)
Amortization of actuarial loss (gain)		3.8			3.2			2.2			0.6			0.5			0.4
Amortization of transitional obligation					-			-			1.1			1.2			1.1
Net periodic benefit cost	$	7.1		$	8.6		$	9.6		$	5.7		$	5.6		$	5.3

Schedule of assumptions used

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

	Pension Benefits									Other Benefits
	2011			2010			2009			2011			2010			2009
Discount rate		5.50	%		6.00	%		6.25	%		5.50	%		6.00	%		6.25	%
Rate of compensation increase		3.50	%		3.50	%		3.75	%		N/A			N/A			N/A
Expected return on plan assets		8.00	%		8.00	%		8.25	%		8.00	%		8.00	%		8.25	%
Expected increase in Consumer Price Index		N/A			N/A			N/A			3.00	%		3.00	%		3.50	%

The benefit obligation as of December 31, 2011 and 2010 was calculated using the following weighted average assumptions:

	Pension Benefits						Other Benefits
	2011			2010			2011			2010
Discount rate		4.82	%		5.50	%		4.78	%		5.50	%
Rate of compensation increase		3.50	%		3.50	%		N/A			N/A
Expected increase in Consumer Price Index		N/A			N/A			2.75	%		3.00	%

Schedule of changes in projected benefit obligations

A reconciliation of the Company's benefit obligations at December 31, 2011 and 2010 follows:

	Pension Benefits						Other Benefits
(In millions)	2011			2010			2011			2010
Benefit obligation, beginning of period	$	297.3		$	271.5		$	80.7		$	79.6
Service cost - benefits earned during the period		6.9			6.3			0.5			0.5
Interest cost on projected benefit obligation		15.9			15.9			4.3			4.6
Plan participants' contributions		-			-			1.9			1.7
Plan amendments		-			0.8			-			-
Actuarial loss (gain)		23.1			21.3			(0.5	)		1.2
Medicare subsidy receipts		-			-			1.0			0.5
Benefit payments		(14.0	)		(18.5	)		(8.2	)		(7.4	)
Benefit obligation, end of period	$	329.2		$	297.3		$	79.7		$	80.7

Schedule of changes in fair value of plan assets

A reconciliation of the Company's plan assets at December 31, 2011 and 2010 follows:

	Pension Benefits						Other Benefits
(In millions)	2011			2010			2011			2010
Plan assets at fair value, beginning of period	$	237.2		$	211.1		$	3.1		$	4.0
Actual return on plan assets		2.1			26.8			0.1			0.3
Employer contributions		35.7			17.8			3.1			4.5
Plan participants' contributions		-			-			1.9			1.7
Benefit payments		(14.0	)		(18.5	)		(8.2	)		(7.4	)
Fair value of plan assets, end of period	$	261.0		$	237.2		$	-		$	3.1

Fair values of pension and other retirement plan assets by category and fair value hierarchy

The fair values of the Company's pension and other retirement plan assets at December 31, 2011 and December 31, 2010 by asset category and by fair value hierarchy are as follows:

	As of December 31, 2011
(In millions)	Level 1		Level 2		Level 3		Total
Domestic equities & equity funds	$	54.7	$	66.5	$	-	$	121.2
International equities & equity funds		28.6		-		-		28.6
Domestic bonds & bond funds		38.2		39.1		-		77.3
Inflation protected security fund		-		11.8		-		11.8
Real estate, commodities & other		7.5		10.8		3.8		22.1
Total Plan Investments	$	129.0	$	128.2	$	3.8	$	261.0

	As of December 31, 2010
(In millions)	Level 1		Level 2		Level 3		Total
Domestic equities & equity funds	$	54.6	$	60.8	$	-	$	115.4
International equities & equity funds		29.7		-		-		29.7
Domestic bonds & bond funds		35.3		31.3		-		66.6
Inflation protected security fund		-		9.2		-		9.2
Real estate, commodities & other		6.6		9.1		3.7		19.4
Total Plan Investments	$	126.2	$	110.4	$	3.7	$	240.3

Schedule of effect of significant unobservable inputs, changes in plan assets

A roll forward of the fair value of the guaranteed annuity contract calculated using Level 3 valuation assumptions follows:

(In millions)	2011			2010
Fair value, beginning of year	$	3.7		$	3.6
Unrealized gains related to    investments still held at reporting date		0.2			0.2
Purchases, sales and settlements, net		(0.1	)		(0.1	)
Fair value, end of year	$	3.8		$	3.7

Schedule of net funded status of plans

The funded status of the plans as of December 31, 2011 and 2010 follows:

	Pension Benefits						Other Benefits
(In millions)	2011			2010			2011			2010
Qualified Plans
Benefit obligation, end of period	$	(314.7	)	$	(285.5	)	$	(79.7	)	$	(80.7	)
Fair value of plan assets, end of period		261.0			237.2			-			3.1
Funded Status of Qualified Plans, end of period		(53.7	)		(48.3	)		(79.7	)		(77.6	)
Benefit obligation of SERP Plan, end of period		(14.5	)		(11.8	)		-			-
Total funded status, end of period	$	(68.2	)	$	(60.1	)	$	(79.7	)	$	(77.6	)
Accrued liabilities	$	0.7		$	0.7		$	5.1		$	4.6
Deferred credits & other liabilities

Schedule of net periodic benefit cost not yet recognized

Following is a roll forward of prior service cost, actuarial gains and losses, and transition obligations.

(In millions)	Pensions						Other Benefits
	Prior Service Cost			Net Gain or Loss			Prior Service Cost			Net Gain or Loss			Transition Obligation
Balance January 1, 2009	$	9.5		$	90.9		$	(3.7	)	$	3.5		$	6.2
Amounts arising during the period		0.1			(20.2	)		0.1			6.6			(0.1	)
Reclassification to benefit costs		(1.7	)		(2.2	)		0.8			(0.4	)		(1.1	)
Balance December 31, 2009	$	7.9		$	68.5		$	(2.8	)	$	9.7		$	5.0
Amounts arising during the period		0.8			12.9			-			1.1			-
Reclassification to benefit costs		(1.6	)		(3.2	)		0.8			(0.5	)		(1.2	)
Balance December 31, 2010	$	7.1		$	78.2		$	(2.0	)	$	10.3		$	3.8
Amounts arising during the period		-			42.2			-			(0.6	)		-
Reclassification to benefit costs		(1.7	)		(3.8	)		0.8			(0.6	)		(1.1	)
Balance December 31, 2011	$	5.4		$	116.6		$	(1.2	)	$	9.1		$	2.7

Reconciliation of the amounts in Accumulated other comprehensive income (AOCI) and Regulatory assets related to retirement plan obligations

Following is a reconciliation of the amounts in Accumulated other comprehensive income (AOCI) and Regulatory assets related to retirement plan obligations at December 31, 2011 and 2010:

(In millions)	2011						2010
	Pensions			Other Benefits			Pensions			Other Benefits
Prior service cost	$	5.4		$	(1.2	)	$	7.1		$	(2.0	)
Unamortized actuarial gain/(loss)		116.6			9.1			78.2			10.3
Transition obligation		-			2.7			-			3.8
		122.0			10.6			85.3			12.1
Less: Regulatory asset deferral		(115.9	)		(10.1	)		(81.0	)		(11.5	)
AOCI before taxes	$	6.1		$	0.5		$	4.3		$	0.6

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SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Accumulated Provision for Uncollectible Accounts [Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
Balance, at beginning of year	$ 5.3	$ 5.2	$ 5.6
Additions charged to expenses	11.8	16.8	15.1
Additions charged to other accounts	0	0	0
Deductions from Reserves, Net	10.4	16.7	15.5
Balance, at end of period	6.7	5.3	5.2
Reserve for Impaired Notes Receivable [Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
Balance, at beginning of year	6.1	9.2	6.3
Additions charged to expenses	9.6	1.2	2.9
Additions charged to other accounts	0	0	0
Deductions from Reserves, Net	0	4.3	0
Balance, at end of period	15.7	6.1	9.2
Restructuring Costs [Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
Balance, at beginning of year	0.4	0.5	0.6
Additions charged to expenses	0	0	0
Additions charged to other accounts	0	0	0
Deductions from Reserves, Net	0	0.1	0.1
Balance, at end of period	$ 0.4	$ 0.4	$ 0.5

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Acquisition of Minnesota Limited, Inc. (Tables)

12 Months Ended

Dec. 31, 2011

Acquisition of Minnesota Limited, Inc. [Abstract]

Schedule of business acquisitions, by acquisition

The following table summarizes the allocation of the purchase price to the fair value of the assets acquired and liabilities assumed.

(In millions)
Working capital assets	$       21.5
Working capital liabilities	(6.7)
Net working capital	14.8
Property, plant & equipment	34.4
Identifiable intangible assets	19.1
Goodwill	20.3
Net assets acquired	88.6
Debt obligation assumed	(5.2)
Cash paid in acquisition, net of cash acquired	$       83.4

Business Acquisition, Pro Forma Information [Table Text Block]

The following table presents the Company's unaudited proforma results of operations for the twelve months ended December 31, 2011, 2010, and 2009 as if the acquisition had occurred on January 1, 2009.

	Year Ended December 31,
(In millions, except per share data)	2011		2010		2009
Total operating revenues	$	2,346.3	$	2,239.7	$	2,210.0
Net income	$	141.4	$	134.6	$	138.1
Basic earnings per share	$	1.73	$	1.66	$	1.71
Diluted earnings per share	$	1.73	$	1.66	$	1.70

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Summary of Significant Accounting Policies (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Summary of Significant Accounting Policies [Abstract]
Excise taxes and a portion of utility receipts taxes	$ 29.3	$ 33.8	$ 36.3
Number of operating segments in Utility group	3
Number of operating segments in Nonutility group	5

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Commitments and Contingencies (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Commitments [Abstract]
Future minimum operating lease payments due within one year of the balance sheet date	$ 4.7
Future minimum operating lease payments due within the second year of the balance sheet date	3.8
Future minimum operating lease payments due within the third year of the balance sheet date	2.5
Future minimum operating lease payments due within the fourth year of the balance sheet date	1.5
Future minimum operating lease payments due within the fifth year of the balance sheet date	1.1
Future minimum operating lease payments due within after the fifth year of the balance sheet date	4.3
Total lease expense	6.9	7.3	8.0
Guarantees for Other Unconsolidated Affiliates [Member]
Corporate Guarantees [Abstract]
Maximum exposure by parent company on guarantees.	3.0
Performance Guarantee [Member] | Guarantees for ESG [Member]
Corporate Guarantees [Abstract]
Maximum exposure by parent company on guarantees.	25.0
Performance Guarantees and Product Warranties [Abstract]
Number of surety bonds wholly owned subsidiary has outstanding in role as general contractor (in number of surety bonds)	78
Average face amount of surety bonds wholly owned subsidiary has outstanding	3.6
Maximum face amount of surety bond wholly owned subsidiary had outstanding	25.7
Percent of work completed on projects covered by open surety bonds (in hundredths)	60.00%
Timeframe when significant portion of performance guarantee commitments will be fulfilled	within one year
Performance Guarantee [Member] | Guarantees for Other Unconsolidated Affiliates [Member]
Corporate Guarantees [Abstract]
Maximum exposure by parent company on guarantees.	25.0
Performance Guarantee [Member] | Guarantees for Vectren Source [Member]
Corporate Guarantees [Abstract]
Maximum exposure by parent company on guarantees.	56.0
Other Guarantees Outstanding [Member] | Guarantees for ESG [Member]
Corporate Guarantees [Abstract]
Maximum exposure by parent company on guarantees.	27.0
Financial Standby Letter of Credit [Member] | Guarantees for Other Unconsolidated Affiliates [Member]
Corporate Guarantees [Abstract]
Maximum exposure by parent company on guarantees.	$ 20.0

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Retirement Plans & Other Postretirement Benefits (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Net periodic benefit costs [Abstract]
Portion of benefit costs capitalized as Utility plant		$ 3.9	$ 4.3	$ 4.5
Plan Assets [Roll Forward]
Plan assets at fair value, beginning of period [Roll Forward]		240.3
Fair value of plan assets, end of period		261.0	240.3
Target allocation percentages [Abstract]
Guaranteed Annuity Contract - estimate of undiscounted funds necessary to satisfy John Hancock's remaining obligation		3.4	3.1
Guaranteed Annuity Contract - percent of composite investment return, net of manger fees and other charges (in hundredths)		5.26%	5.37%
Fair value of plan assets		261.0	240.3
Qualified Plans
Fair value of plan assets, end of period		261.0	240.3
Payments expected to be made to SERP participants in the next fiscal year		0.7
Reconciliation of amounts in Accumulated other comprehensive income and Regulatory assets
Less: Regulatory asset deferral		226.0	189.4
Fair Value of guaranteed annuity contract [Roll Forward]
Fair value, beginning of year		3.7	3.6
Unrealized gains related to investments still held at reporting date		0.2	0.2
Purchases, sales and settlements, net		(0.1)	(0.1)
Multiemployer Benefit Plan [Abstract]
Expense for the Multiemployer Benefit plan		18.3	10.0	8.8
Number of unions the Company contributed to on behalf of employees		260
Average contributions to each union		less than $0.1 million
Largest union multiemployer plan contribution		1.1
Number of multiemployer plans to which the Company made contributions (in number of plans)		17
Defined Contribution Plan [Abstract]
Contributions to Defined Contribution Plan		6.2	6.6	4.6
Domestic equities and equity funds [Member]
Plan Assets [Roll Forward]
Fair value of plan assets, end of period		121.2	115.4
Target allocation percentages [Abstract]
Fair value of plan assets		121.2	115.4
Qualified Plans
Fair value of plan assets, end of period		121.2	115.4
International equities and equity funds [Member]
Plan Assets [Roll Forward]
Fair value of plan assets, end of period		28.6	29.7
Target allocation percentages [Abstract]
Fair value of plan assets		28.6	29.7
Qualified Plans
Fair value of plan assets, end of period		28.6	29.7
Domestic bonds and bond funds [Member]
Plan Assets [Roll Forward]
Fair value of plan assets, end of period		77.3	66.6
Target allocation percentages [Abstract]
Fair value of plan assets		77.3	66.6
Qualified Plans
Fair value of plan assets, end of period		77.3	66.6
Inflation protected security fund [Member]
Plan Assets [Roll Forward]
Fair value of plan assets, end of period		11.8	9.2
Target allocation percentages [Abstract]
Fair value of plan assets		11.8	9.2
Qualified Plans
Fair value of plan assets, end of period		11.8	9.2
Real estate, commodities and other [Member]
Plan Assets [Roll Forward]
Fair value of plan assets, end of period		22.1	19.4
Target allocation percentages [Abstract]
Fair value of plan assets		22.1	19.4
Qualified Plans
Fair value of plan assets, end of period		22.1	19.4
Fair Value, Inputs, Level 1 [Member]
Plan Assets [Roll Forward]
Fair value of plan assets, end of period		129.0	126.2
Target allocation percentages [Abstract]
Fair value of plan assets		129.0	126.2
Qualified Plans
Fair value of plan assets, end of period		129.0	126.2
Fair Value, Inputs, Level 1 [Member] | Domestic equities and equity funds [Member]
Plan Assets [Roll Forward]
Fair value of plan assets, end of period		54.7	54.6
Target allocation percentages [Abstract]
Fair value of plan assets		54.7	54.6
Qualified Plans
Fair value of plan assets, end of period		54.7	54.6
Fair Value, Inputs, Level 1 [Member] | International equities and equity funds [Member]
Plan Assets [Roll Forward]
Fair value of plan assets, end of period		28.6	29.7
Target allocation percentages [Abstract]
Fair value of plan assets		28.6	29.7
Qualified Plans
Fair value of plan assets, end of period		28.6	29.7
Fair Value, Inputs, Level 1 [Member] | Domestic bonds and bond funds [Member]
Plan Assets [Roll Forward]
Fair value of plan assets, end of period		38.2	35.3
Target allocation percentages [Abstract]
Fair value of plan assets		38.2	35.3
Qualified Plans
Fair value of plan assets, end of period		38.2	35.3
Fair Value, Inputs, Level 1 [Member] | Inflation protected security fund [Member]
Plan Assets [Roll Forward]
Fair value of plan assets, end of period		0	0
Target allocation percentages [Abstract]
Fair value of plan assets		0	0
Qualified Plans
Fair value of plan assets, end of period		0	0
Fair Value, Inputs, Level 1 [Member] | Real estate, commodities and other [Member]
Plan Assets [Roll Forward]
Fair value of plan assets, end of period		7.5	6.6
Target allocation percentages [Abstract]
Fair value of plan assets		7.5	6.6
Qualified Plans
Fair value of plan assets, end of period		7.5	6.6
Fair Value, Inputs, Level 2 [Member]
Target allocation percentages [Abstract]
Portion of Common Collective Trust Funds comprised of equity funds (in hundredths)		52.00%	55.00%
Portion of Common Collective Trust Funds comprised of fixed income funds (in hundredths)		40.00%	37.00%
Fair value of Common Collective Trust Funds		128.2	110.4
Maximum number of days restriction for exchange of shares in Common Collective Trust Funds (in days)		31
Fair Value, Inputs, Level 2 [Member] | Domestic equities and equity funds [Member]
Plan Assets [Roll Forward]
Fair value of plan assets, end of period		66.5	60.8
Target allocation percentages [Abstract]
Fair value of plan assets		66.5	60.8
Qualified Plans
Fair value of plan assets, end of period		66.5	60.8
Fair Value, Inputs, Level 2 [Member] | International equities and equity funds [Member]
Plan Assets [Roll Forward]
Fair value of plan assets, end of period		0	0
Target allocation percentages [Abstract]
Fair value of plan assets		0	0
Qualified Plans
Fair value of plan assets, end of period		0	0
Fair Value, Inputs, Level 2 [Member] | Domestic bonds and bond funds [Member]
Plan Assets [Roll Forward]
Fair value of plan assets, end of period		39.1	31.3
Target allocation percentages [Abstract]
Fair value of plan assets		39.1	31.3
Qualified Plans
Fair value of plan assets, end of period		39.1	31.3
Fair Value, Inputs, Level 2 [Member] | Inflation protected security fund [Member]
Plan Assets [Roll Forward]
Fair value of plan assets, end of period		11.8	9.2
Target allocation percentages [Abstract]
Fair value of plan assets		11.8	9.2
Qualified Plans
Fair value of plan assets, end of period		11.8	9.2
Fair Value, Inputs, Level 2 [Member] | Real estate, commodities and other [Member]
Plan Assets [Roll Forward]
Fair value of plan assets, end of period		10.8	9.1
Target allocation percentages [Abstract]
Fair value of plan assets		10.8	9.1
Qualified Plans
Fair value of plan assets, end of period		10.8	9.1
Fair Value, Inputs, Level 3 [Member]
Plan Assets [Roll Forward]
Fair value of plan assets, end of period		3.8	3.7
Target allocation percentages [Abstract]
Fair value of plan assets		3.8	3.7
Qualified Plans
Fair value of plan assets, end of period		3.8	3.7
Fair Value, Inputs, Level 3 [Member] | Domestic equities and equity funds [Member]
Plan Assets [Roll Forward]
Fair value of plan assets, end of period		0	0
Target allocation percentages [Abstract]
Fair value of plan assets		0	0
Qualified Plans
Fair value of plan assets, end of period		0	0
Fair Value, Inputs, Level 3 [Member] | International equities and equity funds [Member]
Plan Assets [Roll Forward]
Fair value of plan assets, end of period		0	0
Target allocation percentages [Abstract]
Fair value of plan assets		0	0
Qualified Plans
Fair value of plan assets, end of period		0	0
Fair Value, Inputs, Level 3 [Member] | Domestic bonds and bond funds [Member]
Plan Assets [Roll Forward]
Fair value of plan assets, end of period		0	0
Target allocation percentages [Abstract]
Fair value of plan assets		0	0
Qualified Plans
Fair value of plan assets, end of period		0	0
Fair Value, Inputs, Level 3 [Member] | Inflation protected security fund [Member]
Plan Assets [Roll Forward]
Fair value of plan assets, end of period		0	0
Target allocation percentages [Abstract]
Fair value of plan assets		0	0
Qualified Plans
Fair value of plan assets, end of period		0	0
Fair Value, Inputs, Level 3 [Member] | Real estate, commodities and other [Member]
Plan Assets [Roll Forward]
Fair value of plan assets, end of period		3.8	3.7
Target allocation percentages [Abstract]
Fair value of plan assets		3.8	3.7
Qualified Plans
Fair value of plan assets, end of period		3.8	3.7
Other Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Number of qualified defined benefit pension plans		3
Net periodic benefit costs [Abstract]
Service cost		6.9	6.3	6.3
Interest cost		15.9	15.9	15.8
Expected return on plan assets		(21.2)	(18.4)	(16.4)
Amortization of prior service cost (benefit)		1.7	1.6	1.7
Amortization of actuarial loss (gain)		3.8	3.2	2.2
Amortization of transitional obligation		0	0	0
Net periodic benefit cost		7.1	8.6	9.6
Discount rate (in hundredths)	4.82%	5.50%	6.00%	6.25%
Rate of compensation increase (in hundredths)		3.50%	3.50%	3.75%
Expected return on plan assets (in hundredths)		8.00%	8.00%	8.25%
Assumptions used to calculate benefit obligations [Abstract]
Discount rate (in hundredths)		4.82%	5.50%
Rate of compensation increase (in hundredths)		3.50%	3.50%
Benefit Obligation [Roll Forward]
Benefit obligation, beginning of period	329.2	297.3	271.5
Service cost - benefits earned during the period		6.9	6.3	6.3
Interest cost on projected benefit obligation		15.9	15.9	15.8
Plan participants' contributions		0	0
Plan amendments		0	0.8
Actuarial loss (gain)		23.1	21.3
Medicare subsidy receipts		0	0
Benefit payments		(14.0)	(18.5)
Benefit obligation, end of period		329.2	297.3	271.5
Accumulated benefit obligation for all defined benefit pension plans		310.9	280.5
Plan Assets [Roll Forward]
Plan assets at fair value, beginning of period [Roll Forward]	261.0	237.2	211.1
Actual return on plan assets		2.1	26.8
Employer contributions		35.7	17.8
Plan participants' contributions		0	0
Benefit payments		(14.0)	(18.5)
Fair value of plan assets, end of period		261.0	237.2	211.1
Target allocation percentages [Abstract]
Target percentage of investments in equity instruments (in hundredths)		60.00%
Target percentage of investments in debt instruments (in hundredths)		35.00%
Target percentage of investments in other investments, including real estate (in hundredths)		5.00%
Fair value of plan assets		261.0	237.2	211.1
Qualified Plans
Benefit obligation, end of period		(314.7)	(285.5)
Fair value of plan assets, end of period		261.0	237.2	211.1
Funded Status of Qualified Plans, end of period		(53.7)	(48.3)
Benefit obligation of SERP Plan, end of period		(14.5)	(11.8)
Total funded status, end of period		(68.2)	(60.1)
Accrued liabilities		0.7	0.7
Deferred credits and other liabilities		67.5	59.4
Contributions expected to be made to pension plan trusts in the next fiscal year		15.0
Estimated future benefit payments [Abstract]
Expected future benefit payments, year one		16.4
Expected future benefit payments, year two		17.3
Expected future benefit payments, year three		17.9
Expected future benefit payments, year four		18.7
Expected future benefit payments, year five		19.8
Expected future benefit payments, years six through ten		125.2
Prior service costs [Roll Forward]
Balance, beginning of year	5.4	7.1	7.9	9.5
Amounts arising during the period		0	0.8	0.1
Reclassification to benefit costs		(1.7)	(1.6)	(1.7)
Balance, end of year		5.4	7.1	7.9
Net gain or loss [Roll Forward]
Balance, beginning of year	116.6	78.2	68.5	90.9
Amounts arising during the period		42.2	12.9	(20.2)
Reclassification to benefit costs		(3.8)	(3.2)	(2.2)
Balance, end of year		116.6	78.2	68.5
Reconciliation of amounts in Accumulated other comprehensive income and Regulatory assets
Prior service cost		5.4	7.1	7.9
Unamortized actuarial gain/(loss)		116.6	78.2	68.5
Sub total		122.0	85.3
Less: Regulatory asset deferral		(115.9)	(81.0)
AOCI before taxes		6.1	4.3
Amounts that will be amortized from Accumulated Other Comprehensive Income (Loss) in next year [Abstract]
Prior service cost expected to be amortized in next year		1.6
Actuarial gain/loss expected to be amortized in next year		6.8
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Number of other postretirement benefit plans		3
Net periodic benefit costs [Abstract]
Service cost		0.5	0.5	0.5
Interest cost		4.3	4.6	4.4
Expected return on plan assets		0	(0.4)	(0.3)
Amortization of prior service cost (benefit)		(0.8)	(0.8)	(0.8)
Amortization of actuarial loss (gain)		0.6	0.5	0.4
Amortization of transitional obligation		1.1	1.2	1.1
Net periodic benefit cost		5.7	5.6	5.3
Discount rate (in hundredths)		5.50%	6.00%	6.25%
Expected return on plan assets (in hundredths)		8.00%	8.00%	8.25%
Expected increase in Consumer Price Index (in hundredths)		3.00%	3.00%	3.50%
Assumptions used to calculate benefit obligations [Abstract]
Discount rate (in hundredths)		4.78%	5.50%
Expected increase in Consumer Price Index (in hundredths)		2.75%	3.00%
Benefit Obligation [Roll Forward]
Benefit obligation, beginning of period		80.7	79.6
Service cost - benefits earned during the period		0.5	0.5	0.5
Interest cost on projected benefit obligation		4.3	4.6	4.4
Plan participants' contributions		1.9	1.7
Plan amendments		0	0
Actuarial loss (gain)		(0.5)	1.2
Medicare subsidy receipts		1.0	0.5
Benefit payments		(8.2)	(7.4)
Benefit obligation, end of period		79.7	80.7	79.6
Assumption of percentage increase in medical claims cost for next fiscal year (in hundredths)		8.00%
Ultimate trending increase of medical claims cost (in hundredths)		5.00%
Year that rate reaches ultimate trend rate		2018
Dollar impact of a one-percentage point change in assumed health care cost trend rates		2.5
Plan Assets [Roll Forward]
Plan assets at fair value, beginning of period [Roll Forward]		3.1	4.0
Actual return on plan assets		0.1	0.3
Employer contributions		3.1	4.5
Plan participants' contributions		1.9	1.7
Benefit payments		(8.2)	(7.4)
Fair value of plan assets, end of period		0	3.1	4.0
Target allocation percentages [Abstract]
Fair value of plan assets		0	3.1	4.0
Qualified Plans
Benefit obligation, end of period		(79.7)	(80.7)
Fair value of plan assets, end of period		0	3.1	4.0
Funded Status of Qualified Plans, end of period		(79.7)	(77.6)
Benefit obligation of SERP Plan, end of period		0	0
Total funded status, end of period		(79.7)	(77.6)
Accrued liabilities		5.1	4.6
Deferred credits and other liabilities		74.6	73.0
Other postretirement benefit payments to be made during the next fiscal year		5.1
Estimated future benefit payments [Abstract]
Expected future benefit payments, year one		7.5
Expected future benefit payments, year two		8.1
Expected future benefit payments, year three		8.7
Expected future benefit payments, year four		9.2
Expected future benefit payments, year five		9.8
Expected future benefit payments, years six through ten		58.1
Prior service costs [Roll Forward]
Balance, beginning of year		(2.0)	(2.8)	(3.7)
Amounts arising during the period		0	0	0.1
Reclassification to benefit costs		0.8	0.8	0.8
Balance, end of year		(1.2)	(2.0)	(2.8)
Net gain or loss [Roll Forward]
Balance, beginning of year		10.3	9.7	3.5
Amounts arising during the period		(0.6)	1.1	6.6
Reclassification to benefit costs		(0.6)	(0.5)	(0.4)
Balance, end of year		9.1	10.3	9.7
Transition obligation [Roll Forward]
Balance, beginning of year		3.8	5.0	6.2
Amounts arising during the period		0	0	(0.1)
Reclassification to benefit costs		(1.1)	(1.2)	(1.1)
Balance, end of year		2.7	3.8	5.0
Reconciliation of amounts in Accumulated other comprehensive income and Regulatory assets
Prior service cost		(1.2)	(2.0)	(2.8)
Unamortized actuarial gain/(loss)		9.1	10.3	9.7
Transition obligation		2.7	3.8	5.0
Sub total		10.6	12.1
Less: Regulatory asset deferral		(10.1)	(11.5)
AOCI before taxes		0.5	0.6
Amounts that will be amortized from Accumulated Other Comprehensive Income (Loss) in next year [Abstract]
Prior service cost expected to be amortized in next year		0.8
Actuarial gain/loss expected to be amortized in next year		0.5
Transition obligation expected to be amortized in next year		$ 1.1

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Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2011

Fair Value Measurements [Abstract]

Carrying value and estimated fair value of other financial instruments

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

	At December 31,
	2011				2010
(In millions)	Carrying Amount		Est. Fair Value		Carrying Amount		Est. Fair Value
Long-term debt	$	1,622.3	$	1,804.4	$	1,715.9	$	1,841.2
Short-term borrowings & notes payable		227.1		227.1		118.3		118.3
Cash & cash equivalents		8.6		8.6		10.4		10.4

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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2011

Summary of Significant Accounting Policies [Abstract]

Summary of Significant Accounting Policies

2.     Summary of Significant Accounting Policies

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

Principles of Consolidation

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

Subsequent Events Review

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

Cash & Cash Equivalents

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

Allowance for Uncollectible Accounts

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

Inventories

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

Property, Plant & Equipment

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

Utility Plant & Related Depreciation

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

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

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

Nonutility Plant & Related Depreciation

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

Impairment Reviews

Property, plant and equipment along with other long-lived assets are reviewed as facts and circumstances indicate that the carrying amount may be impaired.  This impairment review involves the comparison of an asset's (or group of assets') carrying value to the estimated future cash flows the asset (or asset group) is expected to generate over a remaining life.  If this evaluation were to conclude that the carrying value is impaired, an impairment charge would be recorded based on the difference between the carrying amount and its fair value (less costs to sell for assets to be disposed of by sale) as a charge to operations or discontinued operations.  There were no impairments related to property, plant and equipment during the periods presented.

Investments in Unconsolidated Affiliates

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

Goodwill

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

Regulation

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

Refundable or Recoverable Gas Costs & Cost of Fuel & Purchased Power

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

Regulatory Assets & Liabilities

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

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

Postretirement Obligations & Costs

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

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

Asset Retirement Obligations

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

Product Warranties, Performance Guarantees & Other Guarantees

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

While not significant at December 31, 2011 or 2010, the Company does recognize the fair value of an obligation at the inception of a guarantee in certain circumstances.  These circumstances would include executing certain indemnification agreements and guaranteeing operating lease residual values, the performance of a third party, or the indebtedness of a third party.

Energy Contracts & Derivatives

The Company will periodically execute derivative contracts in the normal course of operations while buying and selling commodities to be used in operations, optimizing its generation assets, and managing risk.  A derivative is recognized on the balance sheet as an asset or liability measured at its fair market value and the change in the derivative's fair market value is recognized currently in earnings unless specific hedge criteria are met.

When an energy contract that is a derivative is designated and documented as a normal purchase or normal sale (NPNS), it is exempted from mark-to-market accounting.  Most energy contracts executed by the Company are subject to the NPNS exclusion or are not considered derivatives.  Such energy contracts include Real Time and Day Ahead purchase and sale contracts with the MISO, natural gas purchases from ProLiance and others, and wind farm and other electric generating contracts.

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

Income Taxes

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

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

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

Revenues

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

MISO Transactions

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

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

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

Share-Based Compensation

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

Excise & Utility Receipts Taxes

Excise taxes and a portion of utility receipts taxes are included in rates charged to customers.  Accordingly, the Company records these taxes received as a component of operating revenues, which totaled $29.3 million in 2011, $33.8 million in 2010, and $36.3 million in 2009.  Expense associated with excise and utility receipts taxes are recorded as a component of Taxes other than income taxes.

Operating Segments

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

Fair Value Measurements

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

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

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

XML

Borrowing Arrangements (Details) (USD $)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Year end [Abstract]
Balance Outstanding, end of period	$ 227,100,000	$ 118,300,000
Long term debt [Abstract]
Total long term debt outstanding	1,524,200,000	1,718,200,000
Current maturities of long-term debt	(62,700,000)	(250,700,000)
Short-term borrowings expected to be refinanced	100,000,000	0
Debt subject to tender	0	(30,000,000)
Unamortized debt premium and discount - net	(1,900,000)	(2,300,000)
Long-term debt - net of current maturities and debt subject to tender	1,559,600,000	1,435,200,000
Long-term debt death put repayments	800,000	1,800,000	3,000,000
Maturities of long term debt [Abstract]
Debt maturing within 12 months following date of latest balance sheet	62,700,000
Debt maturing within two years following date of latest balance sheet	106,400,000
Debt maturing within three years following date of latest balance sheet	30,000,000
Debt maturing within four years following date of latest balance sheet	179,800,000
Debt maturing within five years following date of latest balance sheet	73,000,000
Debt maturing thereafter 5 years following date of the latest balance sheet	1,170,400,000
Covenants [Abstract]
Ratio of consolidated total debt to consolidated total capitalization, maximum ( in hundredths)	Not to exceed 65 percent
Fixed Rate Senior Unsecured Notes [Member] | Utility Holdings [Member]
Long term debt [Abstract]
Total long term debt outstanding	721,600,000	918,600,000
Proceeds from the sale of the notes, net of issuance costs	148,900,000
Debt guarantees [Abstract]
Long-term guarantees	722,000,000
Short-term debt guarantees	243,000,000
Fixed Rate Senior Unsecured Notes [Member] | Indiana Gas [Member]
Long term debt [Abstract]
Total long term debt outstanding	121,000,000	121,000,000
Fixed Rate Senior Unsecured Notes [Member] | Vectren Capital Corp. [Member]
Long term debt [Abstract]
Total long term debt outstanding	410,000,000	410,000,000
Proceeds from the sale of the notes, net of issuance costs		124,200,000	149,000,000
Amount of the proceeds that replaced the issuance of debt maturities due	48,000,000
Debt guarantees [Abstract]
Long-term guarantees	410,000,000
Short-term debt guarantees	84,000,000
Fixed Rate Senior Unsecured Notes [Member] | 2011, 6.625% [Member] | Utility Holdings [Member]
Long term debt [Abstract]
Total long term debt outstanding	0	250,000,000
Fixed Rate Senior Unsecured Notes [Member] | 2013, 5.25% [Member] | Utility Holdings [Member]
Long term debt [Abstract]
Total long term debt outstanding	100,000,000	100,000,000
Fixed Rate Senior Unsecured Notes [Member] | 2015, 5.45% [Member] | Utility Holdings [Member]
Long term debt [Abstract]
Total long term debt outstanding	75,000,000	75,000,000
Fixed Rate Senior Unsecured Notes [Member] | 2018, 5.75% [Member] | Utility Holdings [Member]
Long term debt [Abstract]
Total long term debt outstanding	100,000,000	100,000,000
Fixed Rate Senior Unsecured Notes [Member] | 2020, 6.28% [Member] | Utility Holdings [Member]
Long term debt [Abstract]
Total long term debt outstanding	100,000,000	100,000,000
Fixed rate stated percentage (in hundredths)	6.28%
Maturity date	Apr. 07, 2020
Debt Instrument Issuance Date	2009-04-07
Debt Issuance	100,000,000
Proceeds from the sale of the notes, net of issuance costs			99,500,000
Fixed Rate Senior Unsecured Notes [Member] | 2035, 6.10% [Member] | Utility Holdings [Member]
Long term debt [Abstract]
Total long term debt outstanding	75,000,000	75,000,000
Fixed Rate Senior Unsecured Notes [Member] | 2036, 5.95% [Member] | Utility Holdings [Member]
Long term debt [Abstract]
Total long term debt outstanding	0	96,700,000
Fixed rate stated percentage (in hundredths)	5.95%
Maturity date	Dec. 31, 2036
Call date	2011-10-21
Debt Issuance	96,200,000
Debt Instrument Put And Call Exercise Date			Nov. 21, 2011
Fixed Rate Senior Unsecured Notes [Member] | 2039, 6.25% [Member] | Utility Holdings [Member]
Long term debt [Abstract]
Total long term debt outstanding	121,600,000	121,900,000
Fixed Rate Senior Unsecured Notes [Member] | 2013, Series E, 6.69% [Member] | Indiana Gas [Member]
Long term debt [Abstract]
Total long term debt outstanding	5,000,000	5,000,000
Fixed Rate Senior Unsecured Notes [Member] | 2015, Series E, 7.15% [Member] | Indiana Gas [Member]
Long term debt [Abstract]
Total long term debt outstanding	5,000,000	5,000,000
Fixed Rate Senior Unsecured Notes [Member] | 2015, Series E1, 6.69% [Member] | Indiana Gas [Member]
Long term debt [Abstract]
Total long term debt outstanding	5,000,000	5,000,000
Fixed Rate Senior Unsecured Notes [Member] | 2015, Series E, 6.69% [Member] | Indiana Gas [Member]
Long term debt [Abstract]
Total long term debt outstanding	10,000,000	10,000,000
Fixed Rate Senior Unsecured Notes [Member] | 2025, Series E, 6.53% [Member] | Indiana Gas [Member]
Long term debt [Abstract]
Total long term debt outstanding	10,000,000	10,000,000
Fixed Rate Senior Unsecured Notes [Member] | 2027, Series E, 6.42% [Member] | Indiana Gas [Member]
Long term debt [Abstract]
Total long term debt outstanding	5,000,000	5,000,000
Fixed Rate Senior Unsecured Notes [Member] | 2027, Series E, 6.68% [Member] | Indiana Gas [Member]
Long term debt [Abstract]
Total long term debt outstanding	1,000,000	1,000,000
Fixed Rate Senior Unsecured Notes [Member] | 2027, Series F, 6.34% [Member] | Indiana Gas [Member]
Long term debt [Abstract]
Total long term debt outstanding	20,000,000	20,000,000
Fixed Rate Senior Unsecured Notes [Member] | 2028, Series F, 6.36% [Member] | Indiana Gas [Member]
Long term debt [Abstract]
Total long term debt outstanding	10,000,000	10,000,000
Fixed Rate Senior Unsecured Notes [Member] | 2028, Series F, 6.55% [Member] | Indiana Gas [Member]
Long term debt [Abstract]
Total long term debt outstanding	20,000,000	20,000,000
Fixed Rate Senior Unsecured Notes [Member] | 2029, Series G, 7.08% [Member] | Indiana Gas [Member]
Long term debt [Abstract]
Total long term debt outstanding	30,000,000	30,000,000
Fixed Rate Senior Unsecured Notes [Member] | 2010, 7.98% [Member] | Vectren Capital Corp. [Member]
Long term debt [Abstract]
Total long term debt outstanding			22,500,000
Fixed Rate Senior Unsecured Notes [Member] | 2012, 5.13% [Member] | Vectren Capital Corp. [Member]
Long term debt [Abstract]
Total long term debt outstanding	25,000,000	25,000,000
Fixed Rate Senior Unsecured Notes [Member] | 2012, 7.43% [Member] | Vectren Capital Corp. [Member]
Long term debt [Abstract]
Total long term debt outstanding	35,000,000	35,000,000
Fixed Rate Senior Unsecured Notes [Member] | 2014, 6.37% [Member] | Vectren Capital Corp. [Member]
Long term debt [Abstract]
Total long term debt outstanding	30,000,000	30,000,000
Fixed rate stated percentage (in hundredths)	6.37%
Maturity date	Dec. 31, 2014
Debt Instrument Issuance Date	2009-03-11
Debt Issuance	30,000,000
Fixed Rate Senior Unsecured Notes [Member] | 2015, 5.31% [Member] | Vectren Capital Corp. [Member]
Long term debt [Abstract]
Total long term debt outstanding	75,000,000	75,000,000
Fixed Rate Senior Unsecured Notes [Member] | 2016, 6.92% [Member] | Vectren Capital Corp. [Member]
Long term debt [Abstract]
Total long term debt outstanding	60,000,000	60,000,000
Fixed rate stated percentage (in hundredths)	6.92%
Maturity date	Dec. 31, 2016
Debt Instrument Issuance Date	2009-03-11
Debt Issuance	60,000,000
Fixed Rate Senior Unsecured Notes [Member] | 2017, 3.48% [Member] | Vectren Capital Corp. [Member]
Long term debt [Abstract]
Total long term debt outstanding	75,000,000	75,000,000
Fixed rate stated percentage (in hundredths)	3.48%
Maturity date	Dec. 31, 2017
Debt Instrument Issuance Date	2010-12-15
Debt Issuance	75,000,000
Fixed Rate Senior Unsecured Notes [Member] | 2019, 7.30% [Member] | Vectren Capital Corp. [Member]
Long term debt [Abstract]
Total long term debt outstanding	60,000,000	60,000,000
Fixed rate stated percentage (in hundredths)	7.30%
Maturity date	Dec. 31, 2019
Debt Instrument Issuance Date	2009-03-11
Debt Issuance	60,000,000
Fixed Rate Senior Unsecured Notes [Member] | 2025, 4.53% [Member] | Vectren Capital Corp. [Member]
Long term debt [Abstract]
Total long term debt outstanding	50,000,000	50,000,000
Fixed rate stated percentage (in hundredths)	4.53%
Maturity date	Dec. 31, 2025
Debt Instrument Issuance Date	2010-12-15
Debt Issuance	50,000,000
Fixed Rate Senior Unsecured Notes [Member] | 2021, 4.67 [Member] | Utility Holdings [Member]
Long term debt [Abstract]
Total long term debt outstanding	55,000,000	0
Fixed rate stated percentage (in hundredths)	4.67%
Maturity date	Nov. 30, 2021
Debt Instrument Issuance Date	2011-11-30
Debt Issuance	55,000,000
Fixed Rate Senior Unsecured Notes [Member] | 2026, 5.02% [Member] | Utility Holdings [Member]
Long term debt [Abstract]
Total long term debt outstanding	60,000,000	0
Fixed rate stated percentage (in hundredths)	5.02%
Maturity date	Nov. 30, 2026
Debt Instrument Issuance Date	2011-11-30
Debt Issuance	60,000,000
Fixed Rate Senior Unsecured Notes [Member] | 2041, 5.99% [Member] | Utility Holdings [Member]
Long term debt [Abstract]
Total long term debt outstanding	35,000,000	0
Fixed rate stated percentage (in hundredths)	5.99%
Maturity date	Dec. 02, 2041
Debt Instrument Issuance Date	2011-11-30
Debt Issuance	35,000,000
Fixed Rate Senior Unsecured Notes [Member] | Fixed Rate Senior Unsecured Notes 2042500 [Member] | Utility Holdings [Member]
Long term debt [Abstract]
Total long term debt outstanding	100,000,000
Fixed rate stated percentage (in hundredths)	5.00%
Maturity date	Feb. 03, 2042
Debt Instrument Issuance Date	2012-02-01
Debt Issuance	100,000,000
Proceeds from the sale of the notes, net of issuance costs	99,500,000
First Mortgage Bonds [Member] | SIGECO [Member]
Long term debt [Abstract]
Total long term debt outstanding	267,500,000	267,500,000
Debt Instrument Issuance Date	2009-03-26
Proceeds from the sale of the notes, net of issuance costs			40,600,000
Tax-exempt auction rate mode long-term debt remarketed			41,300,000
Future long term debt sinking fund fund requirements and maturities [Abstract]
Annual sinking fund requirement fixed percentage (in hundredths)	1.00%
Utility plant remaining unfunded under mortgage indenture	1,300,000,000
Gross utility plant balance subject to the mortgage indenture	2,700,000
First Mortgage Bonds [Member] | 2015, 1985 Pollution Control Series A, current adjustable rate 0.10%, tax exempt, 2011 weighted average: 0.19% | SIGECO [Member]
Long term debt [Abstract]
Total long term debt outstanding	9,800,000	9,800,000
First Mortgage Bonds [Member] | 2016, 1986 Series, 8.875% [Member] | SIGECO [Member]
Long term debt [Abstract]
Total long term debt outstanding	13,000,000	13,000,000
First Mortgage Bonds [Member] | 2020, 1998 Pollution Control Series B, 4.50%, tax exempt [Member] | SIGECO [Member]
Long term debt [Abstract]
Total long term debt outstanding	4,600,000	4,600,000
First Mortgage Bonds [Member] | 2023, 1993 Environmental Improvement Series B, 5.15%, tax exempt [Member] | SIGECO [Member]
Long term debt [Abstract]
Total long term debt outstanding	22,600,000	22,600,000
First Mortgage Bonds [Member] | 2024, 2000 Environmental Improvement Series A, 4.65%, tax exempt [Member] | SIGECO [Member]
Long term debt [Abstract]
Total long term debt outstanding	22,500,000	22,500,000
First Mortgage Bonds [Member] | 2025, 1998 Pollution Control Series A, current adjustable rate 0.08%, tax exempt, 2011 weighted average: 0.19% | SIGECO [Member]
Long term debt [Abstract]
Total long term debt outstanding	31,500,000	31,500,000
First Mortgage Bonds [Member] | 2029, 1999 Senior Notes, 6.72% [Member] | SIGECO [Member]
Long term debt [Abstract]
Total long term debt outstanding	80,000,000	80,000,000
First Mortgage Bonds [Member] | 2030, 1998 Pollution Control Series B, 5.00%, tax exempt [Member] | SIGECO [Member]
Long term debt [Abstract]
Total long term debt outstanding	22,000,000	22,000,000
First Mortgage Bonds [Member] | 2030, 1998 Pollution Control Series C, 5.35%, tax exempt [Member] | SIGECO [Member]
Long term debt [Abstract]
Total long term debt outstanding	22,200,000	22,200,000
First Mortgage Bonds [Member] | 2040, 2009 Environmental Improvement Series, 5.40%, tax exempt [Member] | SIGECO [Member]
Long term debt [Abstract]
Total long term debt outstanding	22,300,000	22,300,000
Fixed rate stated percentage (in hundredths)			5.40%
Maturity date			Dec. 31, 2040
Debt Instrument Issuance Date	2009-08-19
Debt Issuance			22,300,000
Proceeds from the sale of the notes, net of issuance costs			21,300,000
First Mortgage Bonds [Member] | 2041, 2007 Pollution Control Series, 5.45%, tax exempt [Member] | SIGECO [Member]
Long term debt [Abstract]
Total long term debt outstanding	17,000,000	17,000,000
Other Long Term Notes Payable [Member]
Long term debt [Abstract]
Total long term debt outstanding	4,100,000	1,100,000
Short Term Credit Facility [Member]
Short-term borrowings [Abstract]
Short-term borrowing capacity	600,000,000
Short term credit facilities expiration date	2016-12-31
Short Term Credit Facility [Member] | Utility Group [Member]
Short-term borrowings [Abstract]
Short-term borrowing capacity	350,000,000
Short term borrowings available	107,000,000
Year end [Abstract]
Balance Outstanding, end of period	242,800,000	47,000,000	16,400,000
Weighted Average Interest Rate, end of period (in hundredths)	0.57%	0.41%	0.25%
Annual Average [Abstract]
Balance Outstanding, annual average	39,600,000	14,000,000	29,200,000
Weighted Average Interest Rate, annual average (in hundredths)	0.48%	0.40%	1.28%
Maximum Month End Balance Outstanding	242,800,000	47,000,000	151,100,000
Short Term Credit Facility [Member] | Nonutility Group [Member]
Short-term borrowings [Abstract]
Short-term borrowing capacity	250,000,000
Short term borrowings available	166,000,000
Year end [Abstract]
Balance Outstanding, end of period	84,300,000	71,300,000	197,100,000
Weighted Average Interest Rate, end of period (in hundredths)	1.45%	2.01%	0.60%
Annual Average [Abstract]
Balance Outstanding, annual average	124,900,000	143,200,000	151,800,000
Weighted Average Interest Rate, annual average (in hundredths)	1.92%	0.93%	0.78%
Maximum Month End Balance Outstanding	$ 180,100,000	$ 174,600,000	$ 256,500,000

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Borrowing Arrangements (Tables)

12 Months Ended

Dec. 31, 2011

Borrowing Arrangements [Abstract]

Short term borrowing arrangements

Following is certain information regarding these short-term borrowing arrangements.

	Utility Group Borrowings									Nonutility Group Borrowings
(In millions)	2011			2010			2009			2011			2010			2009
Year End
Balance Outstanding	$	242.8		$	47.0		$	16.4		$	84.3		$	71.3		$	197.1
Weighted Average Interest Rate		0.57	%		0.41	%		0.25	%		1.45	%		2.01	%		0.60	%
Annual Average
Balance Outstanding	$	39.6		$	14.0		$	29.2		$	124.9		$	143.2		$	151.8
Weighted Average Interest Rate		0.48	%		0.40	%		1.28	%		1.92	%		0.93	%		0.78	%
Maximum Month End Balance Outstanding	$	242.8		$	47.0		$	151.1		$	180.1		$	174.6		$	256.5

Long term senior unsecured obligations and first mortgage bonds outstanding by subsidiary

Long-term senior unsecured obligations and first mortgage bonds outstanding by subsidiary follow:

			At December 31,
(In millions)			2011	2010
Utility Holdings
	Fixed Rate Senior Unsecured Notes
		2011, 6.625%	$                 -	$        250.0
		2013, 5.25%	100.0	100.0
		2015, 5.45%	75.0	75.0
		2018, 5.75%	100.0	100.0
		2020, 6.28%	100.0	100.0
		2021, 4.67%	55.0	-
		2026, 5.02%	60.0	-
		2035, 6.10%	75.0	75.0
		2036, 5.95%	-	96.7
		2039, 6.25%	121.6	121.9
		2041, 5.99%	35.0	-
		Total Utility Holdings	721.6	918.6
Indiana Gas
	Fixed Rate Senior Unsecured Notes
		2013, Series E, 6.69%	5.0	5.0
		2015, Series E, 7.15%	5.0	5.0
		2015, Series E, 6.69%	5.0	5.0
		2015, Series E, 6.69%	10.0	10.0
		2025, Series E, 6.53%	10.0	10.0
		2027, Series E, 6.42%	5.0	5.0
		2027, Series E, 6.68%	1.0	1.0
		2027, Series F, 6.34%	20.0	20.0
		2028, Series F, 6.36%	10.0	10.0
		2028, Series F, 6.55%	20.0	20.0
		2029, Series G, 7.08%	30.0	30.0
		Total Indiana Gas	121.0	121.0
SIGECO
	First Mortgage Bonds
		2015, 1985 Pollution Control Series A, current adjustable rate 0.10%, tax exempt,
		2011 weighted average: 0.19%	9.8	9.8
		2016, 1986 Series, 8.875%	13.0	13.0
		2020, 1998 Pollution Control Series B, 4.50%, tax exempt	4.6	4.6
		2023, 1993 Environmental Improvement Series B, 5.15%, tax exempt	22.6	22.6
		2024, 2000 Environmental Improvement Series A, 4.65%, tax exempt	22.5	22.5
		2025, 1998 Pollution Control Series A, current adjustable rate 0.08%, tax exempt,
		2011 weighted average: 0.19%	31.5	31.5
		2029, 1999 Senior Notes, 6.72%	80.0	80.0
		2030, 1998 Pollution Control Series B, 5.00%, tax exempt	22.0	22.0
		2030, 1998 Pollution Control Series C, 5.35%, tax exempt	22.2	22.2
		2040, 2009 Environmental Improvement Series, 5.40%, tax exempt	22.3	22.3
		2041, 2007 Pollution Control Series, 5.45%, tax exempt	17.0	17.0
		Total SIGECO	267.5	267.5

(In millions)			2011	2010
Vectren Capital Corp.
	Fixed Rate Senior Unsecured Notes
		2012, 5.13%	25.0	25.0
		2012, 7.43%	35.0	35.0
		2014, 6.37%	30.0	30.0
		2015, 5.31%	75.0	75.0
		2016, 6.92%	60.0	60.0
		2017, 3.48%	75.0	75.0
		2019, 7.30%	60.0	60.0
		2025, 4.53%	50.0	50.0
		Total Vectren Capital Corp.	410.0	410.0
Other Long-Term Notes Payable			4.1	1.1
Total long-term debt outstanding			1,524.2	1,718.2
	Current maturities of long-term debt		(62.7)	(250.7)
	Short-term borrowings refinanced in 2012		100.0	-
	Debt subject to tender		-	(30.0)
	Unamortized debt premium & discount - net		(1.9)	(2.3)
		Total long-term debt-net	$       1,559.6	$    1,435.2

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Segment Reporting

12 Months Ended

Dec. 31, 2011

Segment Reporting [Abstract]

Segment Reporting

22.   Segment Reporting

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

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

The Nonutility Group is comprised of five operating segments:  Infrastructure Services, Energy Services, Coal Mining, Energy Marketing, and Other Businesses.

Corporate and Other includes unallocated corporate expenses such as advertising and charitable contributions, among other activities, that benefit the Company's other operating segments.  Net income is the measure of profitability used by management for all operations.  The acquisition of Minnesota Limited was completed on March 31, 2011 (See Note 5) and is included in the Infrastructure Services nonutility operating segment.  Information related to the Company's business segments is summarized as follows:

	Year Ended December 31,
(In millions)	2011			2010			2009
Revenues
Utility Group
Gas Utility Services	$	819.1		$	954.1		$	1,066.0
Electric Utility Services		635.9			608.0			528.6
Other Operations		43.9			44.5			42.8
Eliminations		(41.9	)		(42.9	)		(41.2	)
Total Utility Group		1,457.0			1,563.7			1,596.2
Nonutility Group
Infrastructure Services		421.3			235.6			202.0
Energy Services		161.8			146.9			121.3
Coal Mining		285.6			209.9			193.4
Energy Marketing		149.9			142.8			157.2
Total Nonutility Group		1,018.6			735.2			673.9
Eliminations		(150.4	)		(169.4	)		(181.2	)
Consolidated Revenues	$	2,325.2		$	2,129.5		$	2,088.9
Profitability Measures - Net Income
Utility Group Net Income
Gas Utility Services	$	52.5		$	53.7		$	50.2
Electric Utility Services		65.0			60.9			48.3
Other Operations		5.4			9.3			8.9
Total Utility Group Net Income		122.9			123.9			107.4
Nonutility Group Net Income
Infrastructure Services		14.9			3.1			2.4
Energy Services		6.7			6.4			8.4
Coal Mining		16.6			11.9			13.4
Energy Marketing		(4.2	)		(4.2	)		4.1
Other Businesses		(10.2	)		(7.4	)		(2.5	)
Total Nonutility Group Net Income		23.8			9.8			25.8
Corporate & Other Net Loss		(5.1	)		-			(0.1	)
Consolidated Net Income	$	141.6		$	133.7		$	133.1

-101-

	Year Ended December 31,
(In millions)	2011			2010			2009
Amounts Included in Profitability Measures
Depreciation & Amortization
Utility Group
Gas Utility Services	$	84.3		$	80.7		$	76.9
Electric Utility Services		80.2			80.8			77.5
Other Operations		27.8			26.7			26.5
Total Utility Group		192.3			188.2			180.9
Nonutility Group
Infrastructure Services		14.9			8.8			8.3
Energy Services		1.5			1.2			1.2
Coal Mining		35.1			30.4			21.0
Energy Marketing		0.5			0.5			0.5
Total Nonutility Group		52.0			40.9			31.0
Consolidated Depreciation & Amortization	$	244.3		$	229.1		$	211.9
Interest Expense
Utility Group
Gas Utility Services	$	37.1		$	38.8		$	38.8
Electric Utility Services		36.4			36.4			34.8
Other Operations		6.8			6.2			5.6
Total Utility Group		80.3			81.4			79.2
Nonutility Group
Infrastructure Services		7.4			3.3			2.6
Energy Services		0.6			0.2			0.6
Coal Mining		11.3			10.1			8.1
Energy Marketing		6.4			8.5			8.3
Other Businesses		1.3			1.5			1.3
Total Nonutility Group		27.0			23.6			20.9
Corporate & Other		(0.8	)		(0.4	)		(0.1	)
Consolidated Interest Expense	$	106.5		$	104.6		$	100.0
Income Taxes
Utility Group
Gas Utility Services	$	34.5		$	35.1		$	31.3
Electric Utility Services		45.3			40.8			27.4
Other Operations		3.1			1.2			0.5
Total Utility Group		82.9			77.1			59.2
Nonutility Group
Infrastructure Services		10.7			2.7			2.1
Energy Services		1.1			2.5			1.6
Coal Mining		3.9			1.9			4.1
Energy Marketing		(2.4	)		(2.7	)		0.3
Other Businesses		(7.0	)		(5.9	)		(2.2	)
Total Nonutility Group		6.3			(1.5	)		5.9
Corporate & Other		(2.8	)		(0.9	)		(1.0	)
Consolidated Income Taxes	$	86.4		$	74.7		$	64.1

-102-

	Year Ended December 31,
(In millions)	2011			2010			2009
Capital Expenditures
Utility Group
Gas Utility Services	$	113.5		$	88.7		$	121.1
Electric Utility Services		102.2			120.1			154.1
Other Operations		17.8			22.5			16.7
Non-cash costs & changes in accruals		(0.1	)		(6.2	)		10.8
Total Utility Group		233.4			225.1			302.7
Nonutility Group
Infrastructure Services		22.8			12.0			11.0
Energy Services		9.7			1.2			1.9
Coal Mining		55.1			38.7			126.8
Energy Marketing		0.3			0.2			0.6
Other Businesses, net of eliminations		-			-			(11.0	)
Total Nonutility Group		87.9			52.1			129.3
Consolidated Capital Expenditures	$	321.3		$	277.2		$	432.0
	At December 31,
(In millions)		2011			2010			2009
Assets
Utility Group
Gas Utility Services	$	2,125.2		$	2,161.7		$	2,102.4
Electric Utility Services		1,656.5			1,666.5			1,592.4
Other Operations, net of eliminations		192.8			96.3			128.3
Total Utility Group		3,974.5			3,924.5			3,823.1
Nonutility Group
Infrastructure Services		295.0			174.6			141.4
Energy Services		81.2			67.4			54.5
Coal Mining		352.8			362.5			342.8
Energy Marketing		112.5			209.1			229.6
Other Businesses		39.6			57.1			65.7
Eliminations & Reclassifications		7.2			(2.2	)		2.0
Total Nonutility Group		888.3			868.5			836.0
Corporate & Other		727.3			706.2			715.9
Eliminations		(711.2	)		(735.0	)		(703.2	)
Consolidated Assets	$	4,878.9		$	4,764.2		$	4,671.8

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Fair Value Measurements

12 Months Ended

Dec. 31, 2011

Fair Value Measurements [Abstract]

Fair Value Measurements

21.   Fair Value Measurements

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

	At December 31,
	2011				2010
(In millions)	Carrying Amount		Est. Fair Value		Carrying Amount		Est. Fair Value
Long-term debt	$	1,622.3	$	1,804.4	$	1,715.9	$	1,841.2
Short-term borrowings & notes payable		227.1		227.1		118.3		118.3
Cash & cash equivalents		8.6		8.6		10.4		10.4

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

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

Under current regulatory treatment, call premiums on reacquisition of long-term debt are generally recovered in customer rates over the life of the refunding issue or over a 15-year period.  Accordingly, any reacquisition would not be expected to have a material effect on the Company's results of operations.

Because of the customized nature of notes receivable investments and lack of a readily available market, it is not practical to estimate the fair value of these financial instruments at specific dates without considerable effort and cost.  At December 31, 2011 and 2010, the fair value for these financial instruments was not estimated.  The carrying value of notes receivable, inclusive of any accrued interest and net of impairment reserves, was approximately $2.1 million and $10.9 million December 31, 2011 and 2010.

The fair value table in Note 18 of the financial statements in the 2010 Form 10-K excluded the estimated fair value of a long-term debt instrument.  The chart above now includes the amount and reflects an increase in the estimated fair value of long-term debt of approximately $73.9 million.  This change in the disclosed fair value of long-term debt had no effect on the carrying value of debt included in the consolidated balance sheet.

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Sale of Retail Gas Marketing Operations (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011
Sale of Retail Gas Marketing Operations [Abstract]
Gain (loss) on disposal	$ 25.4

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Earnings Per Share (Tables)

12 Months Ended

Dec. 31, 2011

Earnings Per Share [Abstract]

Basic and dilutive earnings per share calculation

The following table illustrates the basic and dilutive EPS calculations for the three years ended December 31, 2011:

	Year Ended December 31,
(In millions, except per share data)	2011		2010		2009
Numerator:
Numerator for basic EPS	$	141.6	$	133.6	$	132.9
Add back earnings attributable to participating securities		-		0.1		0.2
Reported net income (Numerator for Diluted EPS)	$	141.6	$	133.7	$	133.1
Denominator:
Weighted average common shares outstanding (Basic EPS)		81.8		81.2		80.7
Conversion of share based compensation arrangements		-		0.1		0.3
Adjusted weighted average shares outstanding and
assumed conversions outstanding (Diluted EPS)		81.8		81.3		81.0
Basic earnings per share	$	1.73	$	1.65	$	1.65
Diluted earnings per share	$	1.73	$	1.64	$	1.64

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Additional Balance Sheet & Operational Information

12 Months Ended

Dec. 31, 2011

Additional Balance Sheet and Operational Information [Abstract]

Additional Balance Sheet and Operational Information

23.   Additional Balance Sheet & Operational Information

Inventories consist of the following:

	At December 31,
(In millions)	2011		2010
Gas in storage - at LIFO cost	$	31.8	$	26.2
Gas in storage - at average cost		-		23.6
Total Gas in storage		31.8		49.8
Coal & Oil for electric generation - at average cost		60.6		70.1
Materials & supplies		54.9		48.8
Nonutility Coal - at LIFO cost		13.0		16.2
Other		1.6		2.2
Total inventories	$	161.9	$	187.1

Based on the average cost of gas purchased and coal produced during December, the cost of replacing inventories carried at LIFO cost exceeded that carrying value at December 31, 2011, and 2010, by approximately $12 million and $16 million, respectively.

Prepayments & other current assets in the Consolidated Balance Sheets consist of the following:

	At December 31,
(In millions)	2011		2010
Prepaid gas delivery service	$	42.4	$	40.7
Deferred income taxes		16.0		3.8
Prepaid taxes		5.1		31.5
Other prepayments & current assets		20.8		25.2
Total prepayments & other current assets	$	84.3	$	101.2

Investments in unconsolidated affiliates consist of the following:

	At December 31,
(In millions)	2011		2010
ProLiance Holdings, LLC	$	85.4	$	123.2
Haddington Energy Partnerships		3.4		3.4
Other non-utility partnerships & corporations		3.9		8.4
Other utility investments		0.2		0.2
Total investments in unconsolidated affiliates	$	92.9	$	135.2

Other utility & corporate Investments in the Consolidated Balance Sheets consist of the following:

	At December 31,
(In millions)	2011		2010
Cash surrender value of life insurance policies	$	27.3	$	27.5
Municipal bond		3.9		4.1
Restricted cash		1.9		1.2
Other investments		1.3		1.3
Other utility & corporate investments	$	34.4	$	34.1

Goodwill by operating segment follows:

	At December 31,
(In millions)	2011		2010
Utility Group
Gas Utility Services	$	205.0	$	205.0
Nonutility Group
Infrastructure Services		55.2		34.9
Energy Services		2.1		2.1
Consolidated goodwill	$	262.3	$	242.0

Accrued liabilities in the Consolidated Balance Sheets consist of the following:

	At December 31,
(In millions)	2011		2010
Refunds to customers & customer deposits	$	56.4	$	54.8
Accrued taxes		33.5		40.9
Accrued interest		21.7		23.8
Accrued retirement		6.5		5.8
Accrued salaries & other		63.0		53.1
Total accrued liabilities	$	181.1	$	178.4

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

(In millions)	2011		2010
Asset retirement obligation, January 1	$	38.7	$	36.1
Accretion		2.5		2.1
Increases in estimates, net of cash payments		2.5		0.5
Asset retirement obligation, December 31		43.7		38.7
Accrued liabilities	$	0.2	$	0.3
Deferred credits & other liabilities	$	43.5	$	38.4

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

	Year Ended December 31,
(In millions)	2011			2010			2009
ProLiance Holdings, LLC	$	(28.6	)	$	(2.5	)	$	3.6
Haddington Energy Partners, LP		-			(6.1	)		0.9
Other		(3.4	)		-			(1.1	)
Total equity in earnings (losses) of unconsolidated affiliates	$	(32.0	)	$	(8.6	)	$	3.4

Other income (expense) - net in the Consolidated Statements of Income consists of the following:

	Year Ended December 31,
(In millions)	2011			2010			2009
AFUDC - borrowed funds	$	2.5		$	1.4		$	1.3
AFUDC - equity funds		0.2			0.3			0.7
Nonutility plant capitalized interest		2.1			2.1			6.0
Interest income, net		1.4			1.7			1.4
Other nonutility investment impairment charges		(9.9	)		(4.7	)		-
Cash surrender value of life insurance policies		0.1			1.9			4.1
All other income		0.1			2.1			0.2
Total other income (expense) - net	$	(3.5	)	$	4.8		$	13.7

Supplemental Cash Flow Information:

	Year Ended December 31,
(In millions)	2011			2010		2009
Cash paid (received) for:
Interest	$	108.6		$	104.5	$	95.5
Income taxes		(9.0	)		8.1		(12.2	)

As of December 31, 2011 and 2010, the Company has accruals related to utility and nonutility plant purchases totaling approximately $15.9 million and $13.9 million, respectively.

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Impact of Recently Issued Accounting Guidance

12 Months Ended

Dec. 31, 2011

Impact of Recently Issued Accounting Principles [Abstract]

Recently Issued Accounting Standards

24.   Impact of Recently Issued Accounting Guidance

Other Comprehensive Income (OCI)

In June 2011, the FASB issued new accounting guidance regarding the presentation of comprehensive income within financial statements.  The new guidance will require entities to report components of comprehensive income in either (1) a continuous statement of comprehensive income or (2) two separate but consecutive statements.  Under the two-statement approach, the first statement would include components of net income, which is consistent with the income statement format used today, and the second statement would include components of OCI.  The guidance does not change the items that must be reported in OCI.  The new guidance is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011 and retrospective application is required.  The Company will adopt this guidance for its quarterly reporting period ending March 31, 2012.  The adoption of this guidance will have no material impacts to the Company's financial statements.

Goodwill Testing

In September 2011, the FASB issued new accounting guidance regarding testing goodwill for impairment.  The new guidance will allow the Company an option to first assess qualitative factors to determine whether it is necessary to perform the two-step quantitative goodwill impairment test.  Using the new guidance, the Company no longer would be required to calculate the fair value of a reporting unit unless the Company determines, based on that qualitative assessment, that it is more likely than not that its fair value is less than its carrying amount.  The new guidance is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011.  The adoption of this guidance will have no material impact to the Company's financial statements.

Multiemployer Pension Plan Disclosures

In September 2011, the FASB issued new accounting guidance that requires enhanced disclosures regarding an employer's participation in multiemployer pension plans.  For plans that are individually significant, these enhanced disclosures include the legal name of the plan, the plan's Employer Identification Number, the employer's contributions made to the plan, the expiration date(s) of the collective-bargaining agreement(s) requiring contributions to the plan, the most recently available certified zone status provided by the plan, and several other disclosures.  The Company participates in several multiemployer pension plans and has adopted this guidance for the Company's 2011 financial statements as required.

Fair Value Measurement and Disclosure

In May 2011, the FASB issued accounting guidance to improve the comparability of fair value measurements presented and disclosed in financial statements prepared in accordance with U.S. GAAP and International Financial Reporting Standards (IFRS). The amendments are not intended to change the application of the current fair value requirements, but to clarify the application of existing requirements. The guidance does change particular principles or requirements for measuring fair value or disclosing information about fair value measurements. To improve consistency, language has been changed to ensure that U.S. GAAP and IFRS fair value measurement and disclosure requirements are described in the same way. The guidance will be effective for interim and annual periods beginning after December 15, 2011. The Company will adopt this guidance for its quarterly reporting period ending March 31, 2012.  We do not expect the adoption of this guidance to have a material impact on our financial position, results of operations or cash flows.

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Organization and Nature of Operations

12 Months Ended

Dec. 31, 2011

Organization and Nature of Operations [Abstract]

Organization and Nature of Operations

1.     Organization and Nature of Operations

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

Indiana Gas provides energy delivery services to approximately 563,000 natural gas customers located in central and southern Indiana.  SIGECO provides energy delivery services to approximately 141,000 electric customers and approximately 110,000 gas customers located near Evansville in southwestern Indiana.  SIGECO also owns and operates electric generation assets to serve its electric customers and optimizes those assets in the wholesale power market.  Indiana Gas and SIGECO generally do business as Vectren Energy Delivery of Indiana.  VEDO provides energy delivery services to over 310,000 natural gas customers located near Dayton in west central Ohio.

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

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Quarterly Financial Data (Unaudited)

12 Months Ended

Dec. 31, 2011

Quarterly Financial Data (Unaudited) [Abstract]

Quarterly Financial Data (Unaudited)

25.   Quarterly Financial Data (Unaudited)

Information in any one quarterly period is not indicative of annual results due to the seasonal variations common to the Company's utility operations.  Summarized quarterly financial data for 2011 and 2010 follows:

(In millions, except per share amounts)			Q1		Q2		Q3		Q4
2011
	Operating revenues	$	682.6	$	475.8	$	539.4	$	627.4
	Operating income		103.3		61.6		94.1		111.0
	Net income		44.6		15.1		35.3		46.6
	Earnings per share:
	Basic	$	0.55	$	0.19	$	0.43	$	0.56
	Diluted		0.55		0.18		0.43		0.56
2010
	Operating revenues	$	740.3	$	402.4	$	422.7	$	564.1
	Operating income		116.2		52.1		58.6		89.9
	Net income		63.2		8.7		16.4		45.4
	Earnings per share:
	Basic	$	0.78	$	0.11	$	0.20	$	0.56
	Diluted		0.78		0.11		0.20		0.55

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Intangible Assets (Tables)

12 Months Ended

Dec. 31, 2011

Intangible Assets [Abstract]

Intangible Assets

Intangible assets, which are included in Other assets, consist of the following:

(In millions)	At December 31,
	2011				2010
	Amortizing		Non-amortizing		Amortizing		Non-amortizing
Customer-related assets	$	20.6	$	-	$	7.4	$	-
Market-related assets		3.6		7.0		-		7.0
Intangible assets, net	$	24.2	$	7.0	$	7.4	$	7.0

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Utility & Nonutility Plant (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Utility & Nonutility Plant
Original Cost	$ 4,979.9	$ 4,791.7
Cost of Non-Utility plant, net of depreciation and amortization	550.8	488.3
Utility Group [Member] | Gas Utility Plant [Member]
Utility & Nonutility Plant
Original Cost	2,516.8	2,410.2
Depreciation Rates as a Percent of Original Cost (in hundredths)	3.50%	3.60%
Utility Group [Member] | Electric Utility Plant [Member]
Utility & Nonutility Plant
Original Cost	2,316.8	2,258.6
Depreciation Rates as a Percent of Original Cost (in hundredths)	3.30%	3.40%
Utility Group [Member] | Common Utility Plant [Member]
Utility & Nonutility Plant
Original Cost	51.6	49.7
Depreciation Rates as a Percent of Original Cost (in hundredths)	2.90%	3.10%
Utility Group [Member] | Construction Work in Progress [Member]
Utility & Nonutility Plant
Original Cost	94.7	73.2
Depreciation Rates as a Percent of Original Cost (in hundredths)	0.00%	0.00%
Utility Group [Member] | Warrick Power Plant [Member]
Utility & Nonutility Plant
Size of Unit 4 Warrick Power Plant (in megawatts)	300
Southern Indiana Gas And Electric Company's Share Of Cost Of Unit 4	182.6
Southern Indiana Gas And Electric Company's Share Of Accumulated Depreciation Of Unit 4	70.3
Nonutility Group [Member]
Utility & Nonutility Plant
Nonutility plant accumulated depreciation and amortization	418.5	385.5
Capitalized interest on nonutility plant construction projects	2.1	2.1	6.0
Nonutility Group [Member] | Coal Mine Development Costs and Equipment [Member]
Utility & Nonutility Plant
Cost of Non-Utility plant, net of depreciation and amortization	222.0	196.9
Nonutility Group [Member] | Computer Hardware and Software [Member]
Utility & Nonutility Plant
Cost of Non-Utility plant, net of depreciation and amortization	101.9	114.5
Nonutility Group [Member] | Land and Buildings [Member]
Utility & Nonutility Plant
Cost of Non-Utility plant, net of depreciation and amortization	112.0	112.8
Nonutility Group [Member] | Vehicles and Equipment [Member]
Utility & Nonutility Plant
Cost of Non-Utility plant, net of depreciation and amortization	92.5	46.9
Nonutility Group [Member] | All Other [Member]
Utility & Nonutility Plant
Cost of Non-Utility plant, net of depreciation and amortization	$ 22.4	$ 17.2

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Segment Reporting (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Segment Reporting [Abstract]
Number of reporting segments	3								3
Segment Reporting Information [Line Items]
Revenues	$ 627.4	$ 539.4	$ 475.8	$ 682.6	$ 564.1	$ 422.7	$ 402.4	$ 740.3	$ 2,325.2	$ 2,129.5	$ 2,088.9
Net income (loss)	46.6	35.3	15.1	44.6	45.4	16.4	8.7	63.2	141.6	133.7	133.1
Amounts Included in Profitability Measures [Abstract]
Depreciation and Amortization									244.3	229.1	211.9
Interest Expense									106.5	104.6	100.0
Income Taxes									86.4	74.7	64.1
Capital Expenditures									321.3	277.2	432.0
Assets	4,878.9				4,764.2				4,878.9	4,764.2	4,671.8
Number of operating segments in the Nonutility Group	5								5
Portion of Indiana that is provided natural gas distribution and transportation services by the Gas Utility Services segment	67.00%								67.00%
Utility Group [Member]
Segment Reporting Information [Line Items]
Revenues									1,457.0	1,563.7	1,596.2
Net income (loss)									122.9	123.9	107.4
Amounts Included in Profitability Measures [Abstract]
Depreciation and Amortization									192.3	188.2	180.9
Interest Expense									80.3	81.4	79.2
Income Taxes									82.9	77.1	59.2
Capital Expenditures									233.4	225.1	302.7
Assets	3,974.5				3,924.5				3,974.5	3,924.5	3,823.1
Utility Group [Member] | Gas Utility Services [Member]
Segment Reporting Information [Line Items]
Revenues									819.1	954.1	1,066.0
Net income (loss)									52.5	53.7	50.2
Amounts Included in Profitability Measures [Abstract]
Depreciation and Amortization									84.3	80.7	76.9
Interest Expense									37.1	38.8	38.8
Income Taxes									34.5	35.1	31.3
Capital Expenditures									113.5	88.7	121.1
Assets	2,125.2				2,161.7				2,125.2	2,161.7	2,102.4
Utility Group [Member] | Electric Utility Services [Member]
Segment Reporting Information [Line Items]
Revenues									635.9	608.0	528.6
Net income (loss)									65.0	60.9	48.3
Amounts Included in Profitability Measures [Abstract]
Depreciation and Amortization									80.2	80.8	77.5
Interest Expense									36.4	36.4	34.8
Income Taxes									45.3	40.8	27.4
Capital Expenditures									102.2	120.1	154.1
Assets	1,656.5				1,666.5				1,656.5	1,666.5	1,592.4
Utility Group [Member] | Other Operations [Member]
Segment Reporting Information [Line Items]
Revenues									43.9	44.5	42.8
Net income (loss)									5.4	9.3	8.9
Amounts Included in Profitability Measures [Abstract]
Depreciation and Amortization									27.8	26.7	26.5
Interest Expense									6.8	6.2	5.6
Income Taxes									3.1	1.2	0.5
Capital Expenditures									17.8	22.5	16.7
Assets	192.8				96.3				192.8	96.3	128.3
Utility Group [Member] | Intersegment Elimination [Member]
Segment Reporting Information [Line Items]
Revenues									(41.9)	(42.9)	(41.2)
Utility Group [Member] | Non-Cash Cost and Change in Accruals [Member]
Amounts Included in Profitability Measures [Abstract]
Capital Expenditures									(0.1)	(6.2)	10.8
Nonutility Group [Member]
Segment Reporting Information [Line Items]
Revenues									1,018.6	735.2	673.9
Net income (loss)									23.8	9.8	25.8
Amounts Included in Profitability Measures [Abstract]
Depreciation and Amortization									52.0	40.9	31.0
Interest Expense									27.0	23.6	20.9
Income Taxes									6.3	(1.5)	5.9
Capital Expenditures									87.9	52.1	129.3
Assets	888.3				868.5				888.3	868.5	836.0
Nonutility Group [Member] | Intersegment Elimination [Member]
Amounts Included in Profitability Measures [Abstract]
Assets	7.2				(2.2)				7.2	(2.2)	2.0
Nonutility Group [Member] | Infrastructure Services [Member]
Segment Reporting Information [Line Items]
Revenues									421.3	235.6	202.0
Net income (loss)									14.9	3.1	2.4
Amounts Included in Profitability Measures [Abstract]
Depreciation and Amortization									14.9	8.8	8.3
Interest Expense									7.4	3.3	2.6
Income Taxes									10.7	2.7	2.1
Capital Expenditures									22.8	12.0	11.0
Assets	295.0				174.6				295.0	174.6	141.4
Nonutility Group [Member] | Energy Services [Member]
Segment Reporting Information [Line Items]
Revenues									161.8	146.9	121.3
Net income (loss)									6.7	6.4	8.4
Amounts Included in Profitability Measures [Abstract]
Depreciation and Amortization									1.5	1.2	1.2
Interest Expense									0.6	0.2	0.6
Income Taxes									1.1	2.5	1.6
Capital Expenditures									9.7	1.2	1.9
Assets	81.2				67.4				81.2	67.4	54.5
Nonutility Group [Member] | Coal Mining [Member]
Segment Reporting Information [Line Items]
Revenues									285.6	209.9	193.4
Net income (loss)									16.6	11.9	13.4
Amounts Included in Profitability Measures [Abstract]
Depreciation and Amortization									35.1	30.4	21.0
Interest Expense									11.3	10.1	8.1
Income Taxes									3.9	1.9	4.1
Capital Expenditures									55.1	38.7	126.8
Assets	352.8				362.5				352.8	362.5	342.8
Nonutility Group [Member] | Energy Marketing [Member]
Segment Reporting Information [Line Items]
Revenues									149.9	142.8	157.2
Net income (loss)									(4.2)	(4.2)	4.1
Amounts Included in Profitability Measures [Abstract]
Depreciation and Amortization									0.5	0.5	0.5
Interest Expense									6.4	8.5	8.3
Income Taxes									(2.4)	(2.7)	0.3
Capital Expenditures									0.3	0.2	0.6
Assets	112.5				209.1				112.5	209.1	229.6
Nonutility Group [Member] | Other Businesses [Member]
Segment Reporting Information [Line Items]
Net income (loss)									(10.2)	(7.4)	(2.5)
Amounts Included in Profitability Measures [Abstract]
Interest Expense									1.3	1.5	1.3
Income Taxes									(7.0)	(5.9)	(2.2)
Capital Expenditures									0	0	(11.0)
Assets	39.6				57.1				39.6	57.1	65.7
Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues									(150.4)	(169.4)	(181.2)
Amounts Included in Profitability Measures [Abstract]
Assets	(711.2)				(735.0)				(711.2)	(735.0)	(703.2)
Corporate and Other Group [Member]
Segment Reporting Information [Line Items]
Net income (loss)									(5.1)	0	(0.1)
Amounts Included in Profitability Measures [Abstract]
Interest Expense									(0.8)	(0.4)	(0.1)
Income Taxes									(2.8)	(0.9)	(1.0)
Assets	$ 727.3				$ 706.2				$ 727.3	$ 706.2	$ 715.9

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Income Statement (USD $) In Millions, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
OPERATING REVENUES
Gas utility	$ 819.1	$ 954.1	$ 1,066.0
Electric utility	635.9	608.0	528.6
Nonutility	870.2	567.4	494.3
Total operating revenues	2,325.2	2,129.5	2,088.9
OPERATING EXPENSES
Cost of gas sold	375.4	504.7	618.1
Cost of fuel and purchased power	240.4	235.0	194.3
Cost of nonutility revenues	385.3	243.3	207.5
Other operating	652.2	538.4	514.0
Depreciation and amortization	244.3	229.1	211.9
Taxes other than income taxes	57.6	62.2	63.0
Total operating expenses	1,955.2	1,812.7	1,808.8
OPERATING INCOME	370.0	316.8	280.1
OTHER INCOME (EXPENSE)
Equity in earnings (losses) of unconsolidated affiliates	(32.0)	(8.6)	3.4
Other income (expense) - net	(3.5)	4.8	13.7
Total other income (expense)	(35.5)	(3.8)	17.1
Interest expense	106.5	104.6	100.0
INCOME BEFORE INCOME TAXES	228.0	208.4	197.2
Income taxes	86.4	74.7	64.1
Net income	$ 141.6	$ 133.7	$ 133.1
AVERAGE COMMON SHARES OUTSTANDING (in shares)	81.8	81.2	80.7
DILUTED COMMON SHARES OUTSTANDING (in shares)	81.8	81.3	81.0
EARNINGS PER SHARE OF COMMON STOCK:
BASIC (in dollars per share)	$ 1.73	$ 1.65	$ 1.65
DILUTED (in dollars per share)	$ 1.73	$ 1.64	$ 1.64

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Accumulated Other Comprehensive Income (Tables)

12 Months Ended

Dec. 31, 2011

Accumulated Other Comprehensive Income [Abstract]

Components and changes in accumulated other comprehensive income

A summary of the components of and changes in Accumulated other comprehensive income for the past three years follows:

	2009									2010						2011
	Beginning			Changes			End			Changes			End			Changes			End
	of Year			During			of Year			During			of Year			During			of Year
(In millions)	Balance			Year			Balance			Year			Balance			Year			Balance
Unconsolidated affiliates	$	(29.0	)	$	21.9		$	(7.1	)	$	0.5		$	(6.6	)	$	(9.3	)	$	(15.9	)
Pension & other benefit costs		(5.3	)		0.9			(4.4	)		(0.5	)		(4.9	)		(1.7	)		(6.6	)
Cash flow hedges		0.1			-			0.1			3.9			4.0			(3.9	)		0.1
Deferred income taxes		13.9			(9.3	)		4.6			(1.5	)		3.1			6.0			9.1
Accumulated other comprehensive income (loss)	$	(20.3	)	$	13.5		$	(6.8	)	$	2.4		$	(4.4	)	$	(8.9	)	$	(13.3	)

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Statement of Shareholders' Equity (USD $) In Millions, unless otherwise specified	Total	Common Stock [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Income (Loss) [Member]
Balance at beginning of period at Dec. 31, 2008	$ 1,351.6	$ 659.1	$ 712.8	$ (20.3)
Balance at beginning of period (in shares) at Dec. 31, 2008		81.0
Comprehensive income:
Net income	133.1		133.1
Pension/OPEB funded status adjustment - net of $0.7, $0.2 and $0.4 million in tax	0.5			0.5
Cash flow hedges:
Comprehensive income of unconsolidated affiliates - net of $3.8, $0.2 and $8.9 million in tax	13.0			13.0
Total comprehensive income	146.6
Common stock:
Issuance: option exercises and dividend reinvestment plan	5.8	5.8
Issuance: option exercises and dividend reinvestment plan (in shares)		0.3
Dividends ($1.385, $1.365 and $1.345 per share)	(108.6)		(108.6)
Other	1.8	1.9	(0.1)
Other (in shares)		(0.2)
Balance at end of period at Dec. 31, 2009	1,397.2	666.8	737.2	(6.8)
Balance at end of period (in shares) at Dec. 31, 2009		81.1
Comprehensive income:
Net income	133.7		133.7
Pension/OPEB funded status adjustment - net of $0.7, $0.2 and $0.4 million in tax	(0.3)			(0.3)
Cash flow hedges:
unrealized gains (losses) - net of $1.5, $1.5 and $0.0 million in tax	2.5			2.5
reclassifications to net income- net of tax	(0.1)			(0.1)
Comprehensive income of unconsolidated affiliates - net of $3.8, $0.2 and $8.9 million in tax	0.3			0.3
Total comprehensive income	136.1
Common stock:
Issuance: option exercises and dividend reinvestment plan	14.0	14.0
Issuance: option exercises and dividend reinvestment plan (in shares)		0.6
Dividends ($1.385, $1.365 and $1.345 per share)	(110.8)		(110.8)
Other	2.4	2.6	(0.2)
Balance at end of period at Dec. 31, 2010	1,438.9	683.4	759.9	(4.4)
Balance at end of period (in shares) at Dec. 31, 2010	81.7	81.7
Comprehensive income:
Net income	141.6		141.6
Pension/OPEB funded status adjustment - net of $0.7, $0.2 and $0.4 million in tax	(1.0)			(1.0)
Cash flow hedges:
unrealized gains (losses) - net of $1.5, $1.5 and $0.0 million in tax	(2.1)			(2.1)
reclassifications to net income- net of tax	(0.3)			(0.3)
Comprehensive income of unconsolidated affiliates - net of $3.8, $0.2 and $8.9 million in tax	(5.5)			(5.5)
Total comprehensive income	132.7
Common stock:
Issuance: option exercises and dividend reinvestment plan	7.9	7.9
Issuance: option exercises and dividend reinvestment plan (in shares)		0.2
Dividends ($1.385, $1.365 and $1.345 per share)	(113.2)		(113.2)
Other	(0.8)	1.3	(2.1)
Balance at end of period at Dec. 31, 2011	$ 1,465.5	$ 692.6	$ 786.2	$ (13.3)
Balance at end of period (in shares) at Dec. 31, 2011	81.9	81.9

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Intangible Assets (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Schedule of intangible assets, excluding goodwill [Line Items]
Amortizing	$ 24.2	$ 7.4
Non-amortizing	7.0	7.0
Weighted average remaining life for amortizing customer-related assets and all amortizing intangibles (in years)	14
Amortization expense	2.3	0.6	0.6
Amortization expense - year one	2.6
Amortization expense - year two	2.3
Amortization expense - year three	2.3
Amortization expense - year four	2.2
Amortization expense - year five	1.6
Customer Related Assets [Member]
Schedule of intangible assets, excluding goodwill [Line Items]
Amortizing	20.6	7.4
Non-amortizing	0	0
Accumulated amortization	5.1	3.4
Market Related Assets [Member]
Schedule of intangible assets, excluding goodwill [Line Items]
Amortizing	3.6	0
Non-amortizing	7.0	7.0
Accumulated amortization	$ 0.9	$ 0.3

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Utility & Nonutility Plant (Tables)

12 Months Ended

Dec. 31, 2011

Utility and Nonutility Plant [Abstract]

Cost of Utility Plant, together with depreciation rates expressed as a percentage of original costs

The original cost of Utility Plant, together with depreciation rates expressed as a percentage of original cost, follows:

	At December 31,
(In millions)	2011					2010
	Original Cost		Depreciation Rates as a Percent of  Original Cost			Original Cost		Depreciation Rates as a Percent of  Original Cost
Gas utility plant	$	2,516.8		3.5	%	$	2,410.2		3.6	%
Electric utility plant		2,316.8		3.3	%		2,258.6		3.4	%
Common utility plant		51.6		2.9	%		49.7		3.1	%
Construction work in progress		94.7		-			73.2		-
Total original cost	$	4,979.9				$	4,791.7

Nonutility Plant, Net of Depreciation and Amortization

Nonutility plant, net of accumulated depreciation and amortization follows:

	At December 31,
(In millions)	2011		2010
Coal mine development costs & equipment	$	222.0	$	196.9
Computer hardware & software		101.9		114.5
Land & buildings		112.0		112.8
Vehicles & equipment		92.5		46.9
All other		22.4		17.2
Nonutility plant - net	$	550.8	$	488.3

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Accumulated Other Comprehensive Income (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Accumulated other comprehensive income (loss), net of income taxes [Line Items]
Balance, beginning of period	$ (4.4)	$ (6.8)	$ (20.3)
Changes during period	(8.9)	2.4	13.5
Balance, end of period	(13.3)	(4.4)	(6.8)
Unconsolidated Affiliates [Member]
Accumulated other comprehensive income (loss), net of income taxes [Line Items]
Balance, beginning of period	(6.6)	(7.1)	(29.0)
Changes during period	(9.3)	0.5	21.9
Balance, end of period	(15.9)	(6.6)	(7.1)
Pension and Other Benefit Costs [Member]
Accumulated other comprehensive income (loss), net of income taxes [Line Items]
Balance, beginning of period	(4.9)	(4.4)	(5.3)
Changes during period	(1.7)	(0.5)	0.9
Balance, end of period	(6.6)	(4.9)	(4.4)
Cash Flow Hedges [Member]
Accumulated other comprehensive income (loss), net of income taxes [Line Items]
Balance, beginning of period	4.0	0.1	0.1
Changes during period	(3.9)	3.9	0
Balance, end of period	0.1	4.0	0.1
Deferred Income Taxes [Member]
Accumulated other comprehensive income (loss), net of income taxes [Line Items]
Balance, beginning of period	3.1	4.6	13.9
Changes during period	6.0	(1.5)	(9.3)
Balance, end of period	$ 9.1	$ 3.1	$ 4.6

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Accumulated Other Comprehensive Income

12 Months Ended

Dec. 31, 2011

Accumulated Other Comprehensive Income [Abstract]

Accumulated Other Comprehensive Income

15.   Accumulated Other Comprehensive Income

A summary of the components of and changes in Accumulated other comprehensive income for the past three years follows:

	2009									2010						2011
	Beginning			Changes			End			Changes			End			Changes			End
	of Year			During			of Year			During			of Year			During			of Year
(In millions)	Balance			Year			Balance			Year			Balance			Year			Balance
Unconsolidated affiliates	$	(29.0	)	$	21.9		$	(7.1	)	$	0.5		$	(6.6	)	$	(9.3	)	$	(15.9	)
Pension & other benefit costs		(5.3	)		0.9			(4.4	)		(0.5	)		(4.9	)		(1.7	)		(6.6	)
Cash flow hedges		0.1			-			0.1			3.9			4.0			(3.9	)		0.1
Deferred income taxes		13.9			(9.3	)		4.6			(1.5	)		3.1			6.0			9.1
Accumulated other comprehensive income (loss)	$	(20.3	)	$	13.5		$	(6.8	)	$	2.4		$	(4.4	)	$	(8.9	)	$	(13.3	)

Accumulated other comprehensive income arising from unconsolidated affiliates is primarily the Company's portion of ProLiance Holdings, LLC's accumulated comprehensive income related to use of cash flow hedges.  (See Note 7 for more information on ProLiance.)

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Regulatory Assets & Liabilities (Tables)

12 Months Ended

Dec. 31, 2011

Regulatory Assets and Liabilities [Abstract]

Schedule of Regulatory Assets

Regulatory assets consist of the following:

	At December 31,
(In millions)	2011		2010
Future amounts recoverable from ratepayers related to:
Benefit obligations (See Note 11)	$	126.0	$	92.5
Deferred Income taxes (See Notes 10 & 18)		1.3		19.2
Asset retirement obligations & other		2.3		2.1
		129.6		113.8
Amounts deferred for future recovery related to:
Deferred coal costs (See Note 20)		17.7		-
Cost recovery riders & other		6.4		2.8
		24.1		2.8
Amounts currently recovered in customer rates related to:
Unamortized debt issue costs & hedging proceeds		34.3		35.7
Demand side management programs		6.3		9.5
Indiana authorized trackers		24.3		17.3
Ohio authorized trackers		1.0		2.0
Premiums paid to reacquire debt		3.3		3.8
Other base rate recoveries		3.1		4.5
		72.3		72.8
Total regulatory assets	$	226.0	$	189.4

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2011

Commitments and Contingencies [Abstract]

Commitments and Contingencies

17.   Commitments & Contingencies

Commitments

Future minimum lease payments required under operating leases that have initial or remaining noncancelable lease terms in excess of one year during the five years following 2011 and thereafter (in millions) are $4.7 in 2012, $3.8 in 2013, $2.5 in 2014, $1.5 in 2015, $1.1 in 2016, and $4.3 thereafter.  Total lease expense (in millions) was $6.9 in 2011, $7.3 in 2010, and $8.0 in 2009.

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

Corporate Guarantees

The Company issues parent level 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, 2011, parent level guarantees support a maximum of $25 million of ESG's performance contracting commitments and warranty obligations and $27 million of other project guarantees.  The broader scope of ESG's performance contracting obligations, including those not guaranteed by the parent company, are described below.  In addition, the parent company has approximately $25 million of other guarantees outstanding supporting other consolidated subsidiary operations, of which $20 million represent letters of credit supporting other nonutility operations.  Guarantees issued and outstanding on behalf of unconsolidated affiliates approximated $3 million at December 31, 2011.  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.

As a result of the sale of Vectren Source on December 31, 2011, the Company has $56 million of outstanding guarantees related to this formerly wholly owned subsidiary that will remain in effect for up to 90 days after the closing.  The buyer's parent will hold the Company harmless if any amounts are required to be paid pursuant to these guarantees and, within the 90 day period, the buyer is required to provide its own guarantees in substitution for the Company guarantees.

Performance Guarantees & Product Warranties

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

Specific to ESG, in its role as a general contractor in the performance contracting industry, at December 31, 2011, there are 78 open surety bonds supporting future performance.  The average face amount of these obligations is $3.6 million, and the largest obligation has a face amount of $25.7 million.  The maximum exposure of these obligations is less than these amounts for several factors, including the level of work already completed.  At December 31, 2011, approximately 60 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.  The Company has no significant accruals for these warranty obligations as of December 31, 2011.

Legal & Regulatory Proceedings

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

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Legislative Matters (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011
Pipeline Safety Law [Member]
Legislative Matters [Line Items]
Estimated amount of operating expenses that could accumulate associated with expanded compliance requirements	$ 9.0
Pipeline Safety Law [Member] | Indiana [Member]
Legislative Matters [Line Items]
Estimated amount of operating expenses that could accumulate associated with expanded compliance requirements	6.0
Capital expenditures driven by the legislation	80.0
Period over which capital expenditures would accumulate (in years)	5
Pipeline Safety Law [Member] | Ohio [Member]
Legislative Matters [Line Items]
Capital expenditures driven by the legislation	55.0
Period over which capital expenditures would accumulate (in years)	5
Indiana House Bill 1004 [Member]
Legislative Matters [Line Items]
Description of legislation	This legislation phases in over four years a two percent rate reduction to the Indiana Adjusted Gross Income Tax for corporations. Pursuant to House Bill 1004, the tax rate will be lowered by one-half percent each year beginning on July 1, 2012, to the final rate of six and one-half percent effective July 1, 2015.
Decrease In Regulatory Asset, Deferred Tax Liabilities	17.1
Indiana Senate Bill 251 [Member]
Legislative Matters [Line Items]
Description of legislation	The legislation establishes a voluntary clean energy portfolio standard that provides incentives to electricity suppliers participating in the program.
Description of the goal of legislation	The law applies to both gas and electric utility operations and provides a framework to recover 80 percent of federally mandated costs through a periodic rate adjustment mechanism outside of a general rate case. Such costs include construction, depreciation, operating and other costs. The remaining 20 percent of those costs are to be deferred for recovery in the utility's next general rate case. The goal of the program is that by 2025, at least 10 percent of the total electricity obtained by the supplier to meet the energy needs of its Indiana retail customers will be provided by clean energy sources, as defined.
Indiana Senate Bill 251 [Abstract]
Power generation capacity for acquired landfill gas generations facility (in megawatts)	3
Long term contract for purchase of electric power generated by wind energy (in megawatts)	50
Purchased electric power generated by wind energy (in megawatts)	30
Percentage of total electricity obtained by the supplier to meet the energy needs of its retail customers provided by clean energy sources (in hundredths)	5.00%
Ohio House Bill 95 [Member]
Legislative Matters [Line Items]
Cost Of Defered Capital Expenditure Program	$ 25.0

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Statement of Shareholders' Equity (Parenthetical) (USD $) In Millions, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Comprehensive income:
Pension/OPEB funded status adjustment - taxes	$ 0.7	$ 0.2	$ 0.4
Unrealized gains (losses) - taxes	1.5	1.5	0
Comprehensive income of unconsolidated affiliates - taxes	$ 3.8	$ 0.2	$ 8.9
Common stock
Dividends (in dollars per share)	$ 1.385	$ 1.365	$ 1.345

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Balance Sheet (USD $) In Millions, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Current Assets
Cash and cash equivalents	$ 8.6	$ 10.4
Accounts receivable - less reserves of $6.7 and $5.3, respectively	221.3	176.6
Accrued unbilled revenues	121.5	162.0
Inventories	161.9	187.1
Recoverable fuel and natural gas costs	12.4	7.9
Prepayments and other current assets	84.3	101.2
Total current assets	610.0	645.2
Utility Plant
Original cost	4,979.9	4,791.7
Less: accumulated depreciation and amortization	1,947.3	1,836.3
Net utility plant	3,032.6	2,955.4
Investments in unconsolidated affiliates	92.9	135.2
Other utility and corporate investments	34.4	34.1
Other nonutility investments	29.6	40.9
Nonutility plant - net	550.8	488.3
Goodwill - net	262.3	242.0
Regulatory assets	226.0	189.4
Other assets	40.3	33.7
TOTAL ASSETS	4,878.9	4,764.2
Current Liabilities
Accounts payable	185.8	183.7
Accounts payable to affiliated companies	36.8	59.6
Accrued liabilities	181.1	178.4
Short-term borrowings	227.1	118.3
Current maturities of long-term debt	62.7	250.7
Long-term debt subject to tender	0	30.0
Total current liabilities	693.5	820.7
Long-term Debt - Net of Current Maturities and Debt Subject to Tender	1,559.6	1,435.2
Deferred Income Taxes and Other Liabilities
Deferred income taxes	575.7	515.3
Regulatory liabilities	345.2	333.5
Deferred credits and other liabilities	239.4	220.6
Total deferred credits and other liabilities	1,160.3	1,069.4
Commitments and Contingencies (Notes 7, 17-20)
Common Shareholders' Equity
Common stock (no par value) - issued and outstanding 81.9 and 81.7, respectively	692.6	683.4
Retained earnings	786.2	759.9
Accumulated other comprehensive income/(loss)	(13.3)	(4.4)
Total common shareholders' equity	1,465.5	1,438.9
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$ 4,878.9	$ 4,764.2

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Income Taxes

12 Months Ended

Dec. 31, 2011

Income Taxes [Abstract]

Income Taxes

10.   Income Taxes

A reconciliation of the federal statutory rate to the effective income tax rate follows:

	Year Ended December 31,
	2011		2010		2009
Statutory rate:	35.0	%	35.0	%	35.0	%
State & local taxes-net of federal benefit	4.2		3.8		2.3
Amortization of investment tax credit	(0.3	)	(0.4	)	(0.5	)
Depletion	(1.9	)	(2.0	)	(2.0	)
Other tax credits	(0.2	)	(0.2	)	(0.2	)
Adjustment of income tax accruals and all other-net	1.1		(0.4	)	(2.1	)
Effective tax rate	37.9	%	35.8	%	32.5	%

Significant components of the net deferred tax liability follow:

	At December 31,
(In millions)	2011			2010
Noncurrent deferred tax liabilities (assets):
Depreciation & cost recovery timing differences	$	625.5		$	565.7
Leveraged leases		13.8			14.2
Regulatory assets recoverable through future rates		25.1			20.1
Other comprehensive income		(10.2	)		(4.2	)
Alternative minimum tax carryforward		(35.1	)		(48.6	)
Employee benefit obligations		(9.4	)		(18.9	)
Net operating loss & other carryforwards		(6.7	)		(3.8	)
Regulatory liabilities to be settled through future rates		(17.2	)		(4.8	)
Impairments		(11.4	)		(4.4	)
Other - net		1.3			-
Net noncurrent deferred tax liability		575.7			515.3
Current deferred tax (assets)/liabilities:
Deferred fuel costs-net		6.0			2.4
Demand side management programs		0.7			2.5
Alternative minimum tax carryforward		(15.6	)		(0.8	)
Other - net		(7.1	)		(7.9	)
Net current deferred tax asset		(16.0	)		(3.8	)
Net deferred tax liability	$	559.7		$	511.5

At December 31, 2011 and 2010, investment tax credits totaling $4.3 million and $5.0 million, respectively, are included in Deferred credits & other liabilities.  At December 31, 2011, the Company has alternative minimum tax carryforwards which do not expire.  In addition, the Company has $6.7 million in net operating loss and general business credit carryforwards, which will expire in 5 to 20 years.

The components of income tax expense and utilization of investment tax credits follow:

	Year Ended December 31,
(In millions)	2011			2010			2009
Current:
Federal	$	4.4		$	(0.8	)	$	(21.4	)
State		10.3			6.2			0.6
Total current taxes		14.7			5.4			(20.8	)
Deferred:
Federal		66.0			65.6			78.7
State		6.4			4.5			7.3
Total deferred taxes		72.4			70.1			86.0
Amortization of investment tax credits		(0.7	)		(0.8	)		(1.1	)
Total income tax expense	$	86.4		$	74.7		$	64.1

Uncertain Tax Positions

Following is a roll forward of unrecognized tax benefits for the three years ended December 31, 2011:

(In millions)	2011			2010			2009
Unrecognized tax benefits at January 1	$	13.3		$	11.5		$	2.2
Gross increases - tax positions in prior periods		3.3			1.6			1.1
Gross decreases - tax positions in prior periods		(4.5	)		(0.3	)		(1.8	)
Gross increases - current period tax positions		0.6			1.0			9.0
Settlements		(0.3	)		-			(0.1	)
Lapse of statute of limitations		-			(0.5	)		1.1
Unrecognized tax benefits at December 31	$	12.4		$	13.3		$	11.5

Of the change in unrecognized tax benefits during 2011, 2010, and 2009, almost none impacted the effective rate.  The amount of unrecognized tax benefits, which if recognized, that would impact the effective tax rate was $0.7 million at December 31, 2011, $0.7 million at December 31, 2010 and $0.5 million at December 31, 2009.  As of December 31, 2011, the unrecognized tax benefit relates to tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility.  Because of the impact of deferred tax accounting, other than interest and penalties, the disallowance of the shorter deductibility period would not affect the annual effective tax rate but would accelerate the payment of cash to the taxing authority. Thus, it is not expected that any changes to these tax positions would have a significant impact on earnings.

The Company recognized expense related to interest and penalties totaling approximately $0.4 million in 2011, $0.3 million in 2010, and $0.2 million in 2009.  The Company had approximately $1.3 million and $0.9 million for the payment of interest and penalties accrued as of December 31, 2011 and 2010, respectively.

The net liability on the Consolidated Balance Sheet for unrecognized tax benefits inclusive of interest, penalties and net of secondary impacts which are a component of the Deferred income taxes and are benefits, totaled $10.1 million and $9.8 million, respectively, at December 31, 2011 and 2010.

The Company and/or certain of its subsidiaries file income tax returns in the U.S. federal jurisdiction and various states.  The Internal Revenue Service (IRS) has concluded examinations of the Company's U.S. federal income tax returns for tax years through December 31, 2005.  Tax years 2006 and 2008 are currently under IRS examination.  The primary focus of the IRS examination is certain repairs and maintenance deductions, an area of particular focus by the IRS throughout the utility industry.  The Company received Notices of Assessment from the IRS related to these deductions.  The Company responded to the assessments in January 2012 and continues to follow industry activities in this area.  However, in the event the IRS assessments related to these deductions are upheld, any impact is not expected to be material to the Company's results of operations or financial condition.  Further, the Company does not expect any changes to this liability for unrecognized income tax benefits within the next 12 months that would significantly impact the Company's results of operations or financial condition.  The State of Indiana, the Company's primary state tax jurisdiction, has conducted examinations of state income tax returns for tax years through December 31, 2007.  The statutes of limitations for assessment of federal income tax have expired with respect to tax years through 2005 and through 2007 for Indiana income tax.

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Document And Entity Information (USD $)	12 Months Ended
	Dec. 31, 2011	Jan. 31, 2012	Jun. 30, 2011
Entity Registrant Name	VECTREN CORP
Entity Central Index Key	0001096385
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	No
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$ 2,270,509,262
Entity Common Stock, Shares Outstanding		81,934,781
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	FY
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2011

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Retirement Plans & Other Postretirement Benefits

12 Months Ended

Dec. 31, 2011

Retirement Plans and Other Postretirement Benefits [Abstract]

Retirement Plans and Other Postretirement Benefits

11.   Retirement Plans & Other Postretirement Benefits

At December 31, 2011, the Company maintains three qualified defined benefit pension plans, a nonqualified supplemental executive retirement plan (SERP), and three other postretirement benefit plans.  The defined benefit pension and other postretirement benefit plans, which cover eligible full-time regular employees, are primarily noncontributory.  The postretirement health care and life insurance plans are a combination of self-insured and fully insured plans.  The qualified pension plans and the SERP are aggregated under the heading "Pension Benefits."  Other postretirement benefit plans are aggregated under the heading "Other Benefits."

Net Periodic Benefit Costs

A summary of the components of net periodic benefit cost for the three years ended December 31, 2011 follows:

	Pension Benefits									Other Benefits
(In millions)	2011			2010			2009			2011			2010			2009
Service cost	$	6.9		$	6.3		$	6.3		$	0.5		$	0.5		$	0.5
Interest cost		15.9			15.9			15.8			4.3			4.6			4.4
Expected return on plan assets		(21.2	)		(18.4	)		(16.4	)		-			(0.4	)		(0.3	)
Amortization of prior service cost (benefit)		1.7			1.6			1.7			(0.8	)		(0.8	)		(0.8	)
Amortization of actuarial loss (gain)		3.8			3.2			2.2			0.6			0.5			0.4
Amortization of transitional obligation					-			-			1.1			1.2			1.1
Net periodic benefit cost	$	7.1		$	8.6		$	9.6		$	5.7		$	5.6		$	5.3

A portion of benefit costs are capitalized as Utility plant.  Costs capitalized in 2011, 2010, and 2009 are estimated at $3.9 million, $4.3 million, and $4.5 million, respectively.

The Company lowered the discount rate used to measure periodic cost from 6.0 percent in 2010 to 5.50 percent in 2011 due to lower benchmark interest rates that approximate the expected duration of the Company's benefit obligations.  For fiscal year 2012, the weighted average discount rate will be 4.82 percent for the defined benefit pension plans.  Over the periods presented other assumptions have also declined reflecting the lower interest rate environment.

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

	Pension Benefits									Other Benefits
	2011			2010			2009			2011			2010			2009
Discount rate		5.50	%		6.00	%		6.25	%		5.50	%		6.00	%		6.25	%
Rate of compensation increase		3.50	%		3.50	%		3.75	%		N/A			N/A			N/A
Expected return on plan assets		8.00	%		8.00	%		8.25	%		8.00	%		8.00	%		8.25	%
Expected increase in Consumer Price Index		N/A			N/A			N/A			3.00	%		3.00	%		3.50	%

Health care cost trend rate assumptions do not have a material effect on the service and interest cost components of benefit costs.  The Company's plans limit its exposure to increases in health care costs to annual changes in the Consumer Price Index (CPI).  Any increase in health care costs in excess of the CPI increase is the responsibility of the plan participants.

Benefit Obligations

A reconciliation of the Company's benefit obligations at December 31, 2011 and 2010 follows:

	Pension Benefits						Other Benefits
(In millions)	2011			2010			2011			2010
Benefit obligation, beginning of period	$	297.3		$	271.5		$	80.7		$	79.6
Service cost - benefits earned during the period		6.9			6.3			0.5			0.5
Interest cost on projected benefit obligation		15.9			15.9			4.3			4.6
Plan participants' contributions		-			-			1.9			1.7
Plan amendments		-			0.8			-			-
Actuarial loss (gain)		23.1			21.3			(0.5	)		1.2
Medicare subsidy receipts		-			-			1.0			0.5
Benefit payments		(14.0	)		(18.5	)		(8.2	)		(7.4	)
Benefit obligation, end of period	$	329.2		$	297.3		$	79.7		$	80.7

The accumulated benefit obligation for all defined benefit pension plans was $310.9 and $280.5 million at December 31, 2011 and 2010, respectively.

The benefit obligation as of December 31, 2011 and 2010 was calculated using the following weighted average assumptions:

	Pension Benefits						Other Benefits
	2011			2010			2011			2010
Discount rate		4.82	%		5.50	%		4.78	%		5.50	%
Rate of compensation increase		3.50	%		3.50	%		N/A			N/A
Expected increase in Consumer Price Index		N/A			N/A			2.75	%		3.00	%

To calculate the 2011 ending postretirement benefit obligation, medical claims costs in 2012 were assumed to be 8 percent higher than those incurred in 2011.  That trend was assumed to reach its ultimate trending increase of 5 percent by 2018 and remain level thereafter.  A one-percentage point change in assumed health care cost trend rates would have changed the benefit obligation by approximately $2.5 million.

Plan Assets

A reconciliation of the Company's plan assets at December 31, 2011 and 2010 follows:

	Pension Benefits						Other Benefits
(In millions)	2011			2010			2011			2010
Plan assets at fair value, beginning of period	$	237.2		$	211.1		$	3.1		$	4.0
Actual return on plan assets		2.1			26.8			0.1			0.3
Employer contributions		35.7			17.8			3.1			4.5
Plan participants' contributions		-			-			1.9			1.7
Benefit payments		(14.0	)		(18.5	)		(8.2	)		(7.4	)
Fair value of plan assets, end of period	$	261.0		$	237.2		$	-		$	3.1

The Company's overall investment strategy for its retirement plan trusts is to maintain investments in a diversified portfolio, comprised of primarily equity and fixed income investments, which are further diversified among various asset classes.  The diversification is designed to minimize the risk of large losses while maximizing total return within reasonable and prudent levels of risk.  The investment objectives specify a targeted investment allocation for the pension plans of 60 percent equities, 35 percent debt, and 5 percent for other investments, including real estate.  Both the equity and debt securities have a blend of domestic and international exposures.  Objectives do not target a specific return by asset class.  The portfolios' return is monitored in total.  Following is a description of the valuation methodologies used for trust assets measured at fair value.

Mutual Funds

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

Common Collective Trust Funds (CTF's)

The Company's plans have investments in trust funds similar to mutual funds in that they are created by pooling of funds from investors into a common trust and such funds are managed by a third party investment manager.  These trust funds typically give investors a wider range of investment options through this pooling of funds than that generally available to investors on an individual basis.  However, unlike mutual funds, these trusts are not publicly traded in an active market.  The fair values of these trusts are derived from Level 2 market inputs based on a daily calculated unit value as determined by the issuer.  This daily calculated value is based on the fair market value of the underlying investments.  These funds are primarily comprised of investments in equity and fixed income securities which represent approximately 52 percent and 40 percent, respectively, of their fair value as of December 31, 2011 and approximately 55 percent and 37 percent, respectively, as of December 31, 2010.  Equity securities within these funds are primarily valued using quoted market prices as these instruments have active markets.  From time to time, less liquid equity securities are valued using Level 2 inputs, such as bid prices or a closing price, as determined in good faith by the investment manager.  Fixed income securities are valued at the last available bid prices quoted by an independent pricing service.  When valuations are not readily available, fixed income securities are valued using primarily other Level 2 inputs as determined in good faith by the investment manager.

The fair value of these funds totals $128.2 million at December 31, 2011 and $110.4 million at December 31, 2010.  In relation to these investments, there are no unfunded commitments.  Also, the Plan can exchange shares with minimal restrictions.  However, in certain events, a restriction of up to 31 days may exist.

Guaranteed Annuity Contract

One of the Company's pension plans is party to a group annuity contract with John Hancock Life Insurance Company.  At December 31, 2011 and 2010, the estimate of undiscounted funds necessary to satisfy John Hancock's remaining obligation was $3.4 million and $3.1 million, respectively.  If funds retained by John Hancock are not sufficient to satisfy retirement payments due these retirees, the shortfall must be funded by the Company. The composite investment return, net of manager fees and other charges for the years ended December 31, 2011 and 2010 was 5.26 percent and 5.37 percent, respectively.  The Company values this illiquid investment using long-term interest rate and mortality assumptions, among others, and is therefore considered a Level 3 investment.  There is no unfunded commitment related to this investment.

The fair values of the Company's pension and other retirement plan assets at December 31, 2011 and December 31, 2010 by asset category and by fair value hierarchy are as follows:

	As of December 31, 2011
(In millions)	Level 1		Level 2		Level 3		Total
Domestic equities & equity funds	$	54.7	$	66.5	$	-	$	121.2
International equities & equity funds		28.6		-		-		28.6
Domestic bonds & bond funds		38.2		39.1		-		77.3
Inflation protected security fund		-		11.8		-		11.8
Real estate, commodities & other		7.5		10.8		3.8		22.1
Total Plan Investments	$	129.0	$	128.2	$	3.8	$	261.0

	As of December 31, 2010
(In millions)	Level 1		Level 2		Level 3		Total
Domestic equities & equity funds	$	54.6	$	60.8	$	-	$	115.4
International equities & equity funds		29.7		-		-		29.7
Domestic bonds & bond funds		35.3		31.3		-		66.6
Inflation protected security fund		-		9.2		-		9.2
Real estate, commodities & other		6.6		9.1		3.7		19.4
Total Plan Investments	$	126.2	$	110.4	$	3.7	$	240.3

A roll forward of the fair value of the guaranteed annuity contract calculated using Level 3 valuation assumptions follows:

(In millions)	2011			2010
Fair value, beginning of year	$	3.7		$	3.6
Unrealized gains related to    investments still held at reporting date		0.2			0.2
Purchases, sales and settlements, net		(0.1	)		(0.1	)
Fair value, end of year	$	3.8		$	3.7

Funded Status

The funded status of the plans as of December 31, 2011 and 2010 follows:

	Pension Benefits						Other Benefits
(In millions)	2011			2010			2011			2010
Qualified Plans
Benefit obligation, end of period	$	(314.7	)	$	(285.5	)	$	(79.7	)	$	(80.7	)
Fair value of plan assets, end of period		261.0			237.2			-			3.1
Funded Status of Qualified Plans, end of period		(53.7	)		(48.3	)		(79.7	)		(77.6	)
Benefit obligation of SERP Plan, end of period		(14.5	)		(11.8	)		-			-
Total funded status, end of period	$	(68.2	)	$	(60.1	)	$	(79.7	)	$	(77.6	)
Accrued liabilities	$	0.7		$	0.7		$	5.1		$	4.6
Deferred credits & other liabilities	$	67.5		$	59.4		$	74.6		$	73.0

Expected Cash Flows

In 2012, the Company expects to make contributions of approximately $15 million to its pension plan trusts.  In addition, the Company expects to make payments totaling approximately $0.7 million directly to SERP participants and approximately $5.1 million directly to those participating in other postretirement plans.

Estimated retiree pension benefit payments, including the SERP, projected to be required during the years following 2011 (in millions) are approximately $16.4 in 2012, $17.3 in 2013 $17.9 in 2014, $18.7 in 2015, $19.8 in 2016 and $125.2 in years 2017-2021.  Expected benefit payments projected to be required for postretirement benefits during the years following 2011 (in millions) are approximately $7.5 in 2012, $8.1 in 2013, $8.7 in 2014, $9.2 in 2015, and $9.8 in 2016 and $58.1 in years 2017-2021.

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

Following is a roll forward of prior service cost, actuarial gains and losses, and transition obligations.

(In millions)	Pensions						Other Benefits
	Prior Service Cost			Net Gain or Loss			Prior Service Cost			Net Gain or Loss			Transition Obligation
Balance January 1, 2009	$	9.5		$	90.9		$	(3.7	)	$	3.5		$	6.2
Amounts arising during the period		0.1			(20.2	)		0.1			6.6			(0.1	)
Reclassification to benefit costs		(1.7	)		(2.2	)		0.8			(0.4	)		(1.1	)
Balance December 31, 2009	$	7.9		$	68.5		$	(2.8	)	$	9.7		$	5.0
Amounts arising during the period		0.8			12.9			-			1.1			-
Reclassification to benefit costs		(1.6	)		(3.2	)		0.8			(0.5	)		(1.2	)
Balance December 31, 2010	$	7.1		$	78.2		$	(2.0	)	$	10.3		$	3.8
Amounts arising during the period		-			42.2			-			(0.6	)		-
Reclassification to benefit costs		(1.7	)		(3.8	)		0.8			(0.6	)		(1.1	)
Balance December 31, 2011	$	5.4		$	116.6		$	(1.2	)	$	9.1		$	2.7

Following is a reconciliation of the amounts in Accumulated other comprehensive income (AOCI) and Regulatory assets related to retirement plan obligations at December 31, 2011 and 2010:

(In millions)	2011						2010
	Pensions			Other Benefits			Pensions			Other Benefits
Prior service cost	$	5.4		$	(1.2	)	$	7.1		$	(2.0	)
Unamortized actuarial gain/(loss)		116.6			9.1			78.2			10.3
Transition obligation		-			2.7			-			3.8
		122.0			10.6			85.3			12.1
Less: Regulatory asset deferral		(115.9	)		(10.1	)		(81.0	)		(11.5	)
AOCI before taxes	$	6.1		$	0.5		$	4.3		$	0.6

Related to pension plans, $1.6 million of prior service cost and $6.8 million of actuarial gain/loss is expected to be amortized to cost in 2012.  Related to other benefits, $1.1 million of the transition obligation and $0.5 million of actuarial gain/loss is expected to be amortized to periodic cost in 2012, and $0.8 million of prior service cost is expected to reduce cost in 2012.

Multiemployer Benefit Plan

The Company, through its Infrastructure Services operating segment, participates in several industry wide multiemployer pension plans for its union employees which provide for monthly benefits based on length of service. Expense is recognized as payments are accrued for work performed or when withdrawal liabilities are probable and estimable.  Expense associated with multiemployer plans was $18.3 million for the year ended December 31, 2011 and includes results from Minnesota Limited and a small withdrawal liability from one plan.  Expense in 2010 and 2009 was $10.0 million and $8.8 million, respectively.  During 2011, the Company made contributions on behalf of employees that participate in over 260 unions.  The average contribution to each union was less than $0.1 million, and the largest contribution was $1.1 million.  Multiple unions can contribute to a single multiemployer plan.  The Company identified contributions to at least 17 plans in 2011 and total contributions to each plan were not significant.

Defined Contribution Plan

The Company also has defined contribution retirement savings plans that are qualified under sections 401(a) and 401(k) of the Internal Revenue Code and include an option to invest in Vectren common stock, among other alternatives.  During 2011, 2010 and 2009, the Company made contributions to these plans of $6.2 million, $6.6 million, and $4.6 million, respectively.

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Balance Sheet (Parenthetical) (USD $) In Millions, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Current Assets
Reserves	$ 6.7	$ 5.3
Common Shareholders' Equity
Common Stock No Par Value
Common stock Shares, Issued (in shares)	81.9	81.7
Common stock, Shares Outstanding (in shares)	81.9	81.7

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Acquisition of Minnesota Limited, Inc.

12 Months Ended

Dec. 31, 2011

Acquisition of Minnesota Limited, Inc. [Abstract]

Acquisition of Minnesota Limited, Inc.

5.     Acquisition of Minnesota Limited, Inc.

On March 31, 2011, the Company, through its wholly owned subsidiary Vectren Infrastructure Services Company, Inc., purchased Minnesota Limited, Inc., excluding certain assets.  Minnesota Limited is a specialty contractor focusing on transmission pipeline construction and maintenance; pump station, compressor station, terminal and refinery construction; gas distribution; and hydrostatic testing.  Minnesota Limited is headquartered in Big Lake, Minnesota and the majority of its customers are generally located in the northern Midwest region.

Along with the Company's wholly owned subsidiary, Miller Pipeline LLC, Minnesota Limited is included in the Company's nonutility Infrastructure Services operating segment.  This acquisition positions the Company for anticipated growth in demand for gas transmission construction resulting from the need to transport new sources of natural gas and oil found in shale formations and the need to upgrade the nation's aging pipelines.

The Company accounted for the cash acquisition in accordance with FASB authoritative guidance for business combinations, which requires the Company to recognize the assets acquired and the liabilities assumed, measured at their fair values as of the date of acquisition.  The following table summarizes the allocation of the purchase price to the fair value of the assets acquired and liabilities assumed.

(In millions)
Working capital assets	$       21.5
Working capital liabilities	(6.7)
Net working capital	14.8
Property, plant & equipment	34.4
Identifiable intangible assets	19.1
Goodwill	20.3
Net assets acquired	88.6
Debt obligation assumed	(5.2)
Cash paid in acquisition, net of cash acquired	$       83.4

The purchase price and its allocation remain preliminary and could change in subsequent periods.  Any subsequent material changes to the purchase price and its allocation will be adjusted pursuant to FASB guidance. Since the initial purchase price allocation was disclosed only minor adjustments have been made.  The final purchase price and the allocation are dependent on final reconciliations of working capital and other items.

Level 3 market inputs, such as discounted cash flows, revenue growth rates, royalty rates, and dealer and auction values of used equipment, were used to derive the preliminary fair values of the identifiable intangible assets and property plant and equipment.  Identifiable intangible assets include back log, long-term customer relationships, and trade name.  The Company intends to use the acquired assets for an extended period and is amortizing them on a straight-line basis over their estimated useful lives.  Goodwill arising from the purchase represents intangible value the Company expects to realize over time.  This value includes but is not limited to: 1) expected synergies from more efficient utilization of equipment and human resources within the combined entities; 2) the experience and size of the acquired work force; and 3) the reputation of the current Minnesota Limited management team.  The goodwill, which does not amortize pursuant to FASB guidance, is deductible over a 15 year period for purposes of computing current income tax expense.

Transaction costs associated with the acquisition and expensed by the Company totaled approximately $0.6 million, of which $0.2 million are included in Other operating expenses during the twelve months ended December 31, 2011 and the remainder was expensed in 2010.  For the period from April 1, 2011 through December 31, 2011, Minnesota Limited contributed approximately $116.5 million and $9.4 million to the Company's revenue and net income, respectively.

The following table presents the Company's unaudited proforma results of operations for the twelve months ended December 31, 2011, 2010, and 2009 as if the acquisition had occurred on January 1, 2009.

	Year Ended December 31,
(In millions, except per share data)	2011		2010		2009
Total operating revenues	$	2,346.3	$	2,239.7	$	2,210.0
Net income	$	141.4	$	134.6	$	138.1
Basic earnings per share	$	1.73	$	1.66	$	1.71
Diluted earnings per share	$	1.73	$	1.66	$	1.70

In addition to the incremental revenues and expenses recorded by Minnesota Limited during this period, the proforma financial data for all periods presented contain several adjustments including the following: recording the additional amortization expense from the identifiable intangible assets; adjusting the estimated tax provision of the proforma combined results; and adjusting for the issuance of short-term debt to facilitate the acquisition.  The Company prepared the proforma financial information for the combined entities for comparative purposes only, and it may not be indicative of what actual results would have been if the acquisition had taken place on the proforma date, or of future results.

Concurrent with the purchase agreement, the Company executed a lease arrangement at fair value for the Minnesota Limited corporate headquarters, which is owned by a member of the Minnesota Limited management team and certain family members.  The lease obligates the Company to pay approximately $83,333 per month for 10 years along with certain executory costs for taxes and other operating expenses.  Pursuant to FASB guidance, the Company accounts for the obligation as an operating lease, expensing the lease payments and executory costs as incurred.

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Regulatory Assets & Liabilities

12 Months Ended

Dec. 31, 2011

Regulatory Assets and Liabilities [Abstract]

Regulatory Assets and Liabilities

4.     Regulatory Assets & Liabilities

Regulatory Assets

Regulatory assets consist of the following:

	At December 31,
(In millions)	2011		2010
Future amounts recoverable from ratepayers related to:
Benefit obligations (See Note 11)	$	126.0	$	92.5
Deferred Income taxes (See Notes 10 & 18)		1.3		19.2
Asset retirement obligations & other		2.3		2.1
		129.6		113.8
Amounts deferred for future recovery related to:
Deferred coal costs (See Note 20)		17.7		-
Cost recovery riders & other		6.4		2.8
		24.1		2.8
Amounts currently recovered in customer rates related to:
Unamortized debt issue costs & hedging proceeds		34.3		35.7
Demand side management programs		6.3		9.5
Indiana authorized trackers		24.3		17.3
Ohio authorized trackers		1.0		2.0
Premiums paid to reacquire debt		3.3		3.8
Other base rate recoveries		3.1		4.5
		72.3		72.8
Total regulatory assets	$	226.0	$	189.4

Of the $72.3 million currently being recovered in customer rates, $6.3 million that is associated with demand side management programs is earning a return.  The weighted average recovery period of regulatory assets currently being recovered is 17 years.  The Company has rate orders for all deferred costs not yet in rates and therefore believes that future recovery is probable.

Assets arising from benefit obligations represent the funded status of retirement plans less amounts previously recognized in the statement of income.  The Company records a Regulatory asset for that portion related to its rate regulated utilities. If the cost is ultimately recognized as a periodic cost, it will be recovered through rates charged to customers.  See Note 11.

Regulatory Liabilities

At December 31, 2011 and 2010, the Company has approximately $345.2 million and $333.5 million, respectively, in Regulatory liabilities.  Of these amounts, $320.9 million and $307.5 million relate to cost of removal obligations.  The remaining amounts primarily relate to timing differences associated with asset retirement obligations and deferred financing costs.

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Share-Based Compensation & Deferred Compensation Arrangements

12 Months Ended

Dec. 31, 2011

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Share-Based Compensation and Deferred Compensation Arrangements

16.   Share-Based Compensation & Deferred Compensation Arrangements

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

Following is a reconciliation of the total cost associated with share-based awards recognized in the Company's financial statements to its after tax effect on net income:

	Year ended December 31,
(In millions)	2011		2010		2009
Total cost of share-based compensation	$	5.8	$	4.9	$	4.6
Less capitalized cost		0.8		1.7		1.6
Total in other operating expense		5.0		3.2		3.0
Less income tax benefit in earnings		2.0		1.3		1.2
After tax effect of share-based compensation	$	3.0	$	1.9	$	1.8

Restricted Stock & Restricted Stock Unit Plans

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

A summary of the status of the Company's restricted stock and restricted unit awards separated between those accounted for as liabilities and equity as of December 31, 2011, and changes during the year ended December 31, 2011, follows:

	Equity Awards
				Wtd. Avg.
				Grant Date		Liability Awards
	Shares			Fair value		Shares/Units			Fair value
Restricted awards at January 1, 2011		41,458		$	26.19		668,892
Granted		27,518			25.64		277,480
Vested		(7,226	)		28.63		(108,390	)
Forfeited		(7,737	)		28.61		(139,872	)
Restricted awards at December 31, 2011		54,013		$	25.22		698,110		$           30.23

As of December 31, 2011, there was $7.6 million of total unrecognized compensation cost related to restricted stock awards.  That cost is expected to be recognized over a weighted-average period of 1.6 years.  The total fair value of shares vested for liability awards during the years ended December 31, 2011, 2010, and 2009, was $3.0 million, $5.0 million, and $2.8 million, respectively.  The total fair value of equity awards vesting during the year ended December 31, 2011, 2010, and 2009 was $0.2 million, $0.2 million, $0.1 million, respectively.

Stock Option Plans

In the past, option awards were granted to executives and other key employees with an exercise price equal to the market price of the Company's stock at the date of grant; those option awards generally required 3 years of continuous service and have 10-year contractual terms.  These awards generally vested on a pro-rata basis over 3 years.  The last option grant occurred in 2005, and the Company does not intend to issue options in the future.  All compensation cost has been recognized.  A summary of the status of the Company's stock option awards as of December 31, 2011, and changes during the year ended December 31, 2011, follows:

				Weighted average				Aggregate
						Remaining		Intrinsic
	Shares			Exercise		Contractual		Value
				Price		Term (years)		(In millions)
Outstanding at January 1, 2011		929,806		$	24.55
Exercised		(522,173	)	$	23.61
Outstanding at December 31, 2011		407,633		$	25.74		2.5	$	1.8
Exercisable at December 31, 2011		407,633		$	25.74		2.5	$	1.8

The total intrinsic value of options exercised during the year ended December 31, 2011 and 2010 was $2.4 million and $1.3 million, respectively.  The actual tax benefit realized for tax deductions from option exercises was approximately $1.0 million and $0.5 million in 2011 and 2010, respectively.

The Company periodically issues new shares and also from time to time repurchases shares to satisfy share option exercises.  During the year ended December 31, 2011 and 2010, the Company received cash upon exercise of stock options totaling approximately $12.3 million and $9.5 million, respectively.  During these periods, the Company repurchased shares totaling approximately $12.8 million and $1.2 million respectively.  During the year ended December 31, 2009, stock option activity was insignificant.

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

Deferred Compensation Plans

The Company has nonqualified deferred compensation plans, which permit eligible executives and non-employee directors to defer portions of their compensation and vested restricted stock or units.  A record keeping account is established for each participant, and the participant chooses from a variety of measurement funds for the deemed investment of their accounts.  The measurement funds are similar to the funds in the Company's defined contribution plan and include an investment in phantom stock units of the Company.  The account balance fluctuates with the investment returns on those funds.  At December 31, 2011 and 2010, the liability associated with these plans totaled $21.1 million and $19.1 million, respectively.  Other than $0.7 million and $0.5 million which are classified in Accrued liabilities at December 31, 2011 and 2010, respectively, the liability is included in Deferred credits & other liabilities.  The impact of these plans on Other operating expenses was expense of $2.1 million in 2011, $2.3 million in 2010 and income of $0.8 million in 2009.  The amount recorded in earnings related to the investment activities in Vectren phantom stock associated with these plans during the years ended December 31, 2011, 2010, and 2009, was a cost of $1.7 million, a cost of $1.6 million and a benefit of $1.5 million, respectively.

The Company has certain investments currently funded primarily through corporate-owned life insurance policies.  These investments, which are consolidated, are available to pay deferred compensation benefits.  These investments are also subject to the claims of the Company's creditors.  The cash surrender value of these policies included in Other corporate & utility investments on the Consolidated Balance Sheets were $27.3 million and $27.5 million at December 31, 2011 and 2010, respectively.  Earnings from those investments, which are recorded in Other-net, were earnings $0.1 million in 2011, $1.9 million in 2010, and $4.1 million in 2009. 

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Borrowing Arrangements

12 Months Ended

Dec. 31, 2011

Borrowing Arrangements [Abstract]

Borrowing Arrangements

12.   Borrowing Arrangements

Long-Term Debt

Long-term senior unsecured obligations and first mortgage bonds outstanding by subsidiary follow:

			At December 31,
(In millions)			2011	2010
Utility Holdings
	Fixed Rate Senior Unsecured Notes
		2011, 6.625%	$                 -	$        250.0
		2013, 5.25%	100.0	100.0
		2015, 5.45%	75.0	75.0
		2018, 5.75%	100.0	100.0
		2020, 6.28%	100.0	100.0
		2021, 4.67%	55.0	-
		2026, 5.02%	60.0	-
		2035, 6.10%	75.0	75.0
		2036, 5.95%	-	96.7
		2039, 6.25%	121.6	121.9
		2041, 5.99%	35.0	-
		Total Utility Holdings	721.6	918.6
Indiana Gas
	Fixed Rate Senior Unsecured Notes
		2013, Series E, 6.69%	5.0	5.0
		2015, Series E, 7.15%	5.0	5.0
		2015, Series E, 6.69%	5.0	5.0
		2015, Series E, 6.69%	10.0	10.0
		2025, Series E, 6.53%	10.0	10.0
		2027, Series E, 6.42%	5.0	5.0
		2027, Series E, 6.68%	1.0	1.0
		2027, Series F, 6.34%	20.0	20.0
		2028, Series F, 6.36%	10.0	10.0
		2028, Series F, 6.55%	20.0	20.0
		2029, Series G, 7.08%	30.0	30.0
		Total Indiana Gas	121.0	121.0
SIGECO
	First Mortgage Bonds
		2015, 1985 Pollution Control Series A, current adjustable rate 0.10%, tax exempt,
		2011 weighted average: 0.19%	9.8	9.8
		2016, 1986 Series, 8.875%	13.0	13.0
		2020, 1998 Pollution Control Series B, 4.50%, tax exempt	4.6	4.6
		2023, 1993 Environmental Improvement Series B, 5.15%, tax exempt	22.6	22.6
		2024, 2000 Environmental Improvement Series A, 4.65%, tax exempt	22.5	22.5
		2025, 1998 Pollution Control Series A, current adjustable rate 0.08%, tax exempt,
		2011 weighted average: 0.19%	31.5	31.5
		2029, 1999 Senior Notes, 6.72%	80.0	80.0
		2030, 1998 Pollution Control Series B, 5.00%, tax exempt	22.0	22.0
		2030, 1998 Pollution Control Series C, 5.35%, tax exempt	22.2	22.2
		2040, 2009 Environmental Improvement Series, 5.40%, tax exempt	22.3	22.3
		2041, 2007 Pollution Control Series, 5.45%, tax exempt	17.0	17.0
		Total SIGECO	267.5	267.5

(In millions)			2011	2010
Vectren Capital Corp.
	Fixed Rate Senior Unsecured Notes
		2012, 5.13%	25.0	25.0
		2012, 7.43%	35.0	35.0
		2014, 6.37%	30.0	30.0
		2015, 5.31%	75.0	75.0
		2016, 6.92%	60.0	60.0
		2017, 3.48%	75.0	75.0
		2019, 7.30%	60.0	60.0
		2025, 4.53%	50.0	50.0
		Total Vectren Capital Corp.	410.0	410.0
Other Long-Term Notes Payable			4.1	1.1
Total long-term debt outstanding			1,524.2	1,718.2
	Current maturities of long-term debt		(62.7)	(250.7)
	Short-term borrowings refinanced in 2012		100.0	-
	Debt subject to tender		-	(30.0)
	Unamortized debt premium & discount - net		(1.9)	(2.3)
		Total long-term debt-net	$       1,559.6	$    1,435.2

Utility Holdings 2012 Debt Issuance

On February 1, 2012, Utility Holdings issued $100 million of senior unsecured notes at an interest rate of 5.00 percent per annum and with a maturity date of February 3, 2042.  The notes were sold to various institutional investors pursuant to a private placement note purchase agreement executed in November 2011 with a delayed draw feature.  These senior notes are unsecured and jointly and severally guaranteed by Utility Holdings' regulated utility subsidiaries, SIGECO, Indiana Gas, and VEDO.  The proceeds from the sale of the notes, net of issuance costs, totaled approximately $99.5 million.  These notes have no sinking fund requirements and interest payments are due semi-annually.  These notes contain customary representations, warranties and covenants, including a leverage covenant consistent with leverage covenants contained in other Utility Holdings' borrowing arrangements.As of December 31, 2011, the Company has reclassified $100 million of short-term borrowings as long-term debt to reflect those borrowings were refinanced with the proceeds received.

Utility Holdings 2011 Debt Issuance

On November 30, 2011, Utility Holdings closed a financing under a private placement note purchase agreement pursuant to which various institutional investors purchased the following tranches of notes:  (i) $55 million of 4.67 percent Senior Guaranteed Notes, due November 30, 2021, (ii) $60 million of 5.02 percent Senior Guaranteed Notes, due November 30, 2026, and (iii) $35 million of 5.99 percent Senior Guaranteed Notes, due December 2, 2041.  These senior notes are unsecured and jointly and severally guaranteed by Utility Holdings' regulated utility subsidiaries, SIGECO, Indiana Gas, and VEDO.  The proceeds from the sale of the notes, net of issuance costs, totaled approximately $148.9 million.  These notes have no sinking fund requirements and interest payments are due semi-annually.  These notes contain customary representations, warranties and covenants, including a leverage covenant consistent with leverage covenants contained in other Utility Holdings' borrowing arrangements.

Vectren Capital Corp. 2010 Debt Issuance

On December 15, 2010, the Company and Vectren Capital closed a financing under a private placement note purchase agreement pursuant to which various institutional investors agreed to purchase the following tranches of notes from Vectren Capital:  (i) $75 million 3.48 percent Senior Notes, Series A due 2017, and (ii) $50 million 4.53 percent Senior Notes, Series B due 2025.  These Senior Notes are unconditionally guaranteed by Vectren.  The proceeds from the issuance replaced $48 million debt maturities due in December 2010 and provided long-term financing for some nonutility investments originally financed with short-term borrowings.  These notes have no sinking fund requirements and interest payments are due semi-annually.  The proceeds from the sale of the notes, net of issuance costs, totaled approximately $124.2 million.  These notes contain customary representations, warranties and covenants, including a leverage covenant consistent with leverage covenants contained in other Vectren Capital borrowing arrangements.

Vectren Capital Corp. 2009 Debt Issuance

On March 11, 2009, Vectren and Vectren Capital closed a financing under a private placement Note Purchase Agreement (the "2009 Note Purchase Agreement") pursuant to which various institutional investors purchased the following tranches of notes from Vectren Capital: (i) $30 million in 6.37 percent senior notes, Series A due 2014, (ii) $60 million in 6.92 percent senior notes, Series B due 2016 and (iii) $60 million in 7.30 percent senior notes, Series C due 2019. These senior notes are unconditionally guaranteed by Vectren, the parent of Vectren Capital.  These notes have no sinking fund requirements and interest payments are due semi-annually.  The proceeds from the sale of the notes, net of issuance costs, totaled approximately $149.0 million.  The 2009 Note Purchase Agreement contains customary representations, warranties and covenants, including a leverage covenant consistent with leverage covenants contained in other Vectren Capital borrowing arrangements.  On March 11, 2009, Vectren and Vectren Capital also entered into a first amendment with respect to prior note purchase agreements for the remaining outstanding Vectren Capital debt, other than the $22.5 million series due in 2010, to conform the covenants in certain respects to those contained in the 2009 Note Purchase Agreement.

Utility Holdings 2009 Debt Issuance

On April 7, 2009, Utility Holdings closed a financing under a private placement note purchase agreement pursuant to which institutional investors purchased from Utility Holdings $100 million in 6.28 percent senior unsecured notes due April 7, 2020 (2020 Notes).  The 2020 Notes are guaranteed by Utility Holdings' three utilities:  SIGECO, Indiana Gas, and VEDO.  These guarantees are full and unconditional and joint and several.  The proceeds from the sale of the 2020 Notes, net of issuance costs, totaled approximately $99.5 million.  The 2020 Notes have no sinking fund requirements and interest payments are due semi-annually.  The 2020 Notes contain customary representations, warranties and covenants, including a leverage covenant consistent with leverage covenants contained in other Utility Holdings' borrowing arrangements.

SIGECO 2009 Debt Issuance

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

Auction Rate Securities

On March 26, 2009, SIGECO remarketed the remaining $41.3 million of its auction rate securities obligations, receiving proceeds, net of issuance costs of approximately $40.6 million.  The remarketed notes have a variable rate interest rate which is reset weekly and are supported by a standby letter of credit.  The notes are collateralized by SIGECO's utility plant, and $9.8 million are due in 2015 and $31.5 million are due in 2025.

Long-Term Debt Puts & Calls

Certain long-term debt issues contain put and call provisions that can be exercised on various dates before maturity.  Certain instruments can be put to the Company upon the death of the holder (death puts).  During 2011, 2010, and 2009, the Company repaid approximately $0.8 million, $1.8 million, and $3.0 million, respectively, related to death puts.

On October 21, 2011, the Company notified holders of Utility Holdings $96.2 million 5.95 percent senior notes due 2036, of its intent to call those notes.  This call option was exercised at par on November 21, 2011.

Future Long-Term Debt Sinking Fund Requirements and Maturities

The annual sinking fund requirement of SIGECO's first mortgage bonds is 1 percent of the greatest amount of bonds outstanding under the Mortgage Indenture.  This requirement may be satisfied by certification to the Trustee of unfunded property additions in the prescribed amount as provided in the Mortgage Indenture.  SIGECO intends to meet the 2011 sinking fund requirement by this means and, accordingly, the sinking fund requirement for 2011 is excluded from Current liabilities in the Consolidated Balance Sheets.  At December 31, 2011, $1.3 billion of SIGECO's utility plant remained unfunded under SIGECO's Mortgage Indenture.  SIGECO's gross utility plant balance subject to the Mortgage Indenture approximated $2.7 billion at December 31, 2011.

Consolidated maturities of long-term debt during the five years following 2011 (in millions) are $62.7 in 2012, $106.4 in 2013, $30.0 in 2014, $179.8 in 2015, $73.0 in 2016, and $1,170.4 thereafter.

Debt Guarantees

Vectren Corporation guarantees Vectren Capital's long-term and short-term debt, which totaled $410 million and $84 million, respectively, at December 31, 2011.  Utility Holdings' currently outstanding long-term and short-term debt is jointly and severally guaranteed by Indiana Gas, SIGECO, and VEDO.  Utility Holdings' long-term debt, including current maturities, and short-term debt outstanding at December 31, 2011, totaled $722 million and $243 million, respectively.

Covenants

Both long-term and short-term borrowing arrangements contain customary default provisions; restrictions on liens, sale-leaseback transactions, mergers or consolidations, and sales of assets; and restrictions on leverage and interest coverage, among other restrictions.  Multiple debt agreements contain a covenant that the ratio of consolidated total debt to consolidated total capitalization will not exceed 65 percent.  As of December 31, 2011, the Company was in compliance with all debt covenants.

Short-Term Borrowings

At December 31, 2011, the Company has $600 million of short-term borrowing capacity, including $350 million for the Utility Group and $250 million for the wholly owned Nonutility Group and corporate operations.  As reduced by borrowings currently outstanding, approximately $107 million was available for the Utility Group operations and approximately $166 million was available for the wholly owned Nonutility Group and corporate operations.  This short-term borrowing facility was amended effective November 10, 2011 to extend its maturity date from 2013 to 2016 at current market rates.  The $350 million of capacity remains unchanged.  The Company has historically funded the short-term borrowing needs of Utility Holdings' operations through the commercial paper market and expects to use the Utility Holdings short-term borrowing facility in instances where the commercial paper market is not efficient. 

Following is certain information regarding these short-term borrowing arrangements.

	Utility Group Borrowings									Nonutility Group Borrowings
(In millions)	2011			2010			2009			2011			2010			2009
Year End
Balance Outstanding	$	242.8		$	47.0		$	16.4		$	84.3		$	71.3		$	197.1
Weighted Average Interest Rate		0.57	%		0.41	%		0.25	%		1.45	%		2.01	%		0.60	%
Annual Average
Balance Outstanding	$	39.6		$	14.0		$	29.2		$	124.9		$	143.2		$	151.8
Weighted Average Interest Rate		0.48	%		0.40	%		1.28	%		1.92	%		0.93	%		0.78	%
Maximum Month End Balance Outstanding	$	242.8		$	47.0		$	151.1		$	180.1		$	174.6		$	256.5

Throughout 2011, 2010, and most of 2009, the Company has placed commercial paper without any significant issues and only had to borrow from its backup credit facility in early 2009 on a limited basis.  As noted above, $100 million of the outstanding borrowings are presented as long-term at December 31, 2011.

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Nonutility Real Estate & Other Legacy Holdings

12 Months Ended

Dec. 31, 2011

Nonutility Real Estate Other Legacy Holdings [Abstract]

Nonutility Real Estate and Other Legacy Holdings

8.     Nonutility Real Estate & Other Legacy Holdings

Within the Nonutility business segment, there are legacy investments involved in energy-related infrastructure and services, real estate, leveraged leases, and other ventures.  As of December 31, 2011 and 2010, total remaining legacy investments included in the Other Businesses portfolio total $36.9 million and $52.7 million, respectively.  Further separation of that 2011 investment by type of investment follows:

	December 31, 2011
			Value Included In
(In millions)	Carrying Value		Other Nonutility Investments		Investments in Unconsolidated Affiliates
Commercial real estate investments	$	8.0	$	8.0	$	-
Leveraged leases		18.5		18.5		-
Affordable housing projects		3.1		0.1		3.0
Haddington energy partnerships		3.4		-		3.4
Other investments		3.9		3.0		0.9
	$	36.9	$	29.6	$	7.3

Net of deferred taxes related to these leveraged leases, the net investment at December 31, 2011 was $23.1 million. 

Commercial Real Estate Charge

During the fourth quarter of 2011, the Company obtained new evidence confirming further weakness in markets where the Company holds legacy real estate investments.  The Company holds real estate investments such as an office building, affordable housing projects, and second mortgages. The evaluation of the evidence resulted in a $15.4 million charge in 2011. Of the $15.4 million charge, $8.8 million is reflected in Other-net, $3.6 million is reflected in Equity in earnings/losses of unconsolidated affiliates, and $3.0 million is reflected in Other operating expenses.

Leveraged Leases

The Company is a lessor in leveraged lease agreements under which real estate or equipment is leased to third parties.  The total equipment and facilities cost was approximately $45.2 million at December 31, 2011.  The cost of the equipment and facilities was partially financed by non-recourse debt provided by lenders who have been granted an assignment of rentals due under the leases and a security interest in the leased property, which they accepted as their sole remedy in the event of default by the lessee.  Such debt amounted to approximately $39.8 million at December 31, 2011.  Subsequent to year end on January 3, 2012 the Company divested of one leveraged lease with a book value of approximately $5.2 million, and net of deferred taxes a net book value of $2.7 million at December 31, 2011, at a small gain.

Notes Receivable

At December 31, 2011 and 2010, notes receivable totaled $2.1 million and $10.9 million, respectively, and reflect the impairment charges discussed above.  These amounts are inclusive of accrued interest and net of reserves totaling $15.7 million and $6.1 million, respectively.  As of December 31, 2011, the Company is recognizing interest on the cash basis for substantially the entire note portfolio.  Such interest income has been insignificant during the past three years.  Second mortgages serve as collateral for notes associated with the commercial real estate investments.

Haddington Energy Partnerships

The Company has an approximate 40 percent ownership interest in Haddington Energy Partners, LP (Haddington I) and Haddington Energy Partners II, LP (Haddington II).  As of December 31, 2011, these Haddington ventures have interests in two remaining mid-stream energy related investments.  Both Haddington ventures are investment companies accounted for using the equity method of accounting.  During 2010, the Company recorded its share of the decline in fair value and also impaired a note receivable associated with Haddington's investment in a liquefied natural gas facility.  In total, the charge was approximately $6.5 million, of which, $6.1 million is reflected in Equity in earnings (losses) of unconsolidated affiliates and $0.4 million is reflected in Other income-net,for the twelve months ended December 31, 2010.  At December 31, 2011, the Company's remaining $3.4 million investment in the Haddington ventures is related to payments to be received associated with the sale of a compressed air storage facility sold in 2009.  The Company has no further commitments to invest in either Haddington I or II.  

The following is summarized financial information as to the results of operations of Haddington.  For the year ended December 31, 2011, operating results were insignificant.  For the year ended December 31, 2010, revenues, operating loss, and net loss were (in millions) zero, $(0.3), and $(18.1), respectively.  For the year ended December 31, 2009, revenues, operating loss, and net income were (in millions) zero, $(0.4), and $7.9, respectively.

Variable Interest Entities

Some of these legacy nonutility investments are partnership-like structures involved in activities surrounding multifamily housing and office properties and are variable interest entities.  The Company is either a limited partner or a subordinated lender and does not consolidate any of these entities.  The Company's exposure to loss is limited to its investment which as of December 31, 2011, and 2010, totaled $3.0 million and $7.0 million, respectively, recorded in Investments in unconsolidated affiliates, and $0.1 million and $9.0 million, respectively, recorded in Other nonutility investments.

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Income Taxes (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Reconciliation of the federal statutory rate to the effective income tax rate [Abstract]
Statutory rate: (in hundredths)	35.00%	35.00%	35.00%
State and local taxes-net of federal benefit (in hundredths)	4.20%	3.80%	2.30%
Amortization of investment tax credit (in hundredths)	(0.30%)	(0.40%)	(0.50%)
Depletion (in hundredths)	(1.90%)	(2.00%)	(2.00%)
Other tax credits (in hundredths)	(0.20%)	(0.20%)	(0.20%)
Adjustment of income tax accruals and all other-net (in hundredths)	1.10%	(0.40%)	(2.10%)
Effective tax rate (in hundredths)	37.90%	35.80%	32.50%
Noncurrent deferred tax liabilities (assets) [Abstract]
Depreciation and cost recovery timing differences	$ 625.5	$ 565.7
Leveraged leases	13.8	14.2
Regulatory assets recoverable through future rates	25.1	20.1
Other comprehensive income	(10.2)	(4.2)
Alternative minimum tax carryforward - long term	(35.1)	(48.6)
Employee benefit obligations	(9.4)	(18.9)
Net operating loss and other carryforwards	(6.7)	(3.8)
Regulatory liabilities to be settled through future rates	(17.2)	(4.8)
Impairments	(11.4)	(4.4)
Other - net	1.3	0
Deferred Tax Liabilities, Noncurrent	575.7	515.3
Deferred Tax (Assets) Liabilities Current [Abstract]
Deferred fuel costs-net	6.0	2.4
Demand side management programs	0.7	2.5
Alternative Minimum Tax Carryforward - Short Term	(15.6)	(0.8)
Other - net	(7.1)	(7.9)
Net current deferred tax asset	(16.0)	(3.8)
Net deferred tax liability	559.7	511.5
Investment tax credits	4.3	5.0
Remaining life of NOL's and business credit carryforwards (in years)	5 to 20 years
Current: [Abstract]
Federal	4.4	(0.8)	(21.4)
State	10.3	6.2	0.6
Total current taxes	14.7	5.4	(20.8)
Deferred: [Abstract]
Federal	66.0	65.6	78.7
State	6.4	4.5	7.3
Total deferred taxes	72.4	70.1	86.0
Amortization of investment tax credits	(0.7)	(0.8)	(1.1)
Total income tax expense	86.4	74.7	64.1
Uncertain tax positions [Roll Forward]
Unrecognized tax benefits at beginning of period	13.3	11.5	2.2
Gross increases - tax positions in prior periods	3.3	1.6	1.1
Gross decreases - tax positions in prior periods	(4.5)	(0.3)	(1.8)
Gross increases - current period tax positions	0.6	1.0	9.0
Settlements	(0.3)	0	(0.1)
Lapse of statute of limitations	0	(0.5)	1.1
Unrecognized tax benefits at end of period	12.4	13.3	11.5
Uncertain tax positions [Abstract]
Amount of unrecognized tax benefits, which if recognized, that would impact the effective tax rate	0.7	0.7	0.5
Interest and penalties	0.4	0.3	0.2
Payment of interest and penalties accrued	1.3	0.9
Net liability for unrecognized tax benefits inclusive of interest, penalties and net of secondary impacts which are a component of the deferred income taxes and are benefits	$ 10.1	$ 9.8

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Sale of Retail Gas Marketing Operations

12 Months Ended

Dec. 31, 2011

Sale of Retail Gas Marketing Operations [Abstract]

Sale of Retail Gas Marketing Operations

6.     Sale of Retail Gas Marketing Operations

On December 31, 2011, the Company sold its retail gas marketing operations performed through Vectren Source receiving cash proceeds of approximately $84.3 million, including, and subject to a final determination of, working capital.  The sale, net of transaction costs, resulted in a pretax gain of approximately $25.4 million, which is included in Other operating expenses in the Consolidated Statements of Income. VEDO continues doing business with Vectren Source.  Vectren Source sells natural gas directly to customers in VEDO's service territory, and VEDO purchases receivables and natural gas from Vectren Source.  Vectren Source is a component of the Energy Marketing operating segment.

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Investment in ProLiance Holdings, LLC

12 Months Ended

Dec. 31, 2011

ProLiance Holdings, LLC [Abstract]

Investment in ProLiance Holdings, LLC

7.     Investment in ProLiance Holdings, LLC

ProLiance Holdings, LLC (ProLiance), a nonutility energy marketing affiliate of Vectren and Citizens Energy Group (Citizens), provides services to a broad range of municipalities, utilities, industrial operations, schools, and healthcare institutions located throughout the Midwest and Southeast United States.  ProLiance's customers include Vectren's Indiana utilities and nonutility gas supply operations as well as Citizens' utilities.  ProLiance's primary businesses include gas marketing, gas portfolio optimization, and other portfolio and energy management services.  Consistent with its ownership percentage, Vectren is allocated 61 percent of ProLiance's profits and losses; however, governance and voting rights remain at 50 percent for each member; and therefore, the Company accounts for its investment in ProLiance using the equity method of accounting.  The Company, including its former retail gas supply operations, contracted for a substantial portion of its natural gas purchases through ProLiance in 2011, 2010, and 2009.

Summarized Financial Information

	Year Ended December 31,
(In millions)	2011			2010			2009
Summarized Statement of Income information:
Revenues	$	1,410.5		$	1,497.0		$	1,654.9
Operating income (loss)		(44.5	)		(3.1	)		35.2
Charge related to Investment in Liberty Gas Storage		-			-			(32.7	)
ProLiance's earnings (losses)		(47.3	)		(3.7	)		4.5

	As of December 31,
(In millions)	2011			2010
Summarized balance sheet information:
Current assets	$	381.9		$	441.4
Noncurrent assets		56.1			59.1
Current liabilities		298.5			298.1
Noncurrent liabilities		0.7			0.4
Members' equity		161.5			208.9
Accumulated other comprehensive income (loss)		(26.0	)		(10.8	)
Noncontrolling interest		3.3			3.9

Vectren records its 61 percent share of ProLiance's results in Equity in earnings (losses) of unconsolidated affiliates.  Interest expense and income taxes associated with the investment are recorded separately within the statements of income in those line items.  As of December 31, 2011 and 2010, the Company's investment balance is $85.4 million and $123.2 million, respectively. The amounts recorded to Equity in earnings (losses) of unconsolidated affiliates related to ProLiance's operations totaled a pre-tax loss of $28.6 million and $2.5 million for the twelve months ended December 31, 2011 and 2010, respectively, and pre-tax income of $3.6 million for the twelve months ended December 31, 2009.  Lower natural gas prices, which have resulted in narrowed summer/winter spreads and locational margins, have negatively impacted ProLiance's results. 

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 site, and an additional capacity of at least 17 Bcf at the South site.  The South site also has the potential for further expansion.  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. 

In late 2008, the project at the North site was halted due to subsurface and well-completion problems, resulting in Liberty recording a $132 million impairment charge related to the North site in 2009.  ProLiance recorded its share of the charge in 2009 totaling $33 million; the Company recorded its share of the charge in 2009 totaling $11.9 million after tax.  In the Consolidated Statement of Income for the year ended December 31, 2009, the charge is an approximate $19.9 million reduction to Equity in earnings of unconsolidated affiliates and an income tax benefit reflected in Income taxes of approximately $8.0 million.  ProLiance's ability to meet the needs of its customers has not been, nor does it expect it to be, impacted.  Approximately 12 Bcf of the storage at the South site, which comprises three of the four FERC certified caverns, is fully completed and tested.  As a result of the issues encountered at the North site, Liberty requested and the FERC approved the separation of the North site from the South site.  As of December 31, 2011 and December 31, 2010, ProLiance's investment in Liberty approximated $35.1 million and $36.7 million, respectively.

Liberty received a Demand for Arbitration from Williams Midstream Natural Gas Liquids, Inc. ("Williams") on February 8, 2011 related to a Sublease Agreement ("Sublease") between Liberty and Williams at the North site.  Williams alleges that Liberty was negligent in its attempt to convert certain salt caverns to natural gas storage and thereby damaged the caverns.  Williams alleges damages of $56.7 million.  Liberty believes that it has complied with all of its obligations to Williams, including properly terminating the Sublease.  Liberty intends to vigorously defend itself and has asserted counterclaims substantially in excess of the amounts asserted by Williams. 

Firm Transportation and Storage Commitments

ProLiance has various firm transportation and storage agreements with only minimal support from Vectren or Citizens. (See Note 17 regarding corporate guarantees.)  Under these agreements, ProLiance must make specified minimum payments which extend through 2029.  At December 31, 2011, the estimated aggregated amounts of such required future payments were $55.5 million, $49.0 million, $46.6 million, $38.2 million, $33.9 million, and $247.9 million for 2012, 2013, 2014, 2015, 2016, and thereafter, respectively.  During 2011, 2010, and 2009, fixed payments under these agreements were $73.0 million, $76.8 million, and $63.0 million, respectively.  ProLiance also made variable payments under these agreements in 2011, 2010, and 2009. Variable payments include storage injection and withdrawal charges, and commodity transportation charges.

Transactions with ProLiance

Purchases from ProLiance for resale and for injections into storage for the years ended December 31, 2011, 2010, and 2009, totaled $378.7 million, $437.7 million, and $533.4 million, respectively.  Amounts owed to ProLiance at December 31, 2011, and 2010, for those purchases were $36.8 million and $59.6 million, respectively, and are included in Accounts payable to affiliated companies in the Consolidated Balance Sheets.  Vectren received regulatory approval on April 25, 2006, from the IURC for ProLiance to provide natural gas supply services to the Company's Indiana utilities through March 2011.  On March 17, 2011, an order was received from the IURC providing for ProLiance's continued provision of gas supply services to the Company's Indiana utilities and Citizens Energy Group through March 2016.  Amounts charged by ProLiance for gas supply services are established by supply agreements with each utility.

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Intangible Assets

12 Months Ended

Dec. 31, 2011

Intangible Assets [Abstract]

Intangible Assets

9.     Intangible Assets

Intangible assets, which are included in Other assets, consist of the following:

(In millions)	At December 31,
	2011				2010
	Amortizing		Non-amortizing		Amortizing		Non-amortizing
Customer-related assets	$	20.6	$	-	$	7.4	$	-
Market-related assets		3.6		7.0		-		7.0
Intangible assets, net	$	24.2	$	7.0	$	7.4	$	7.0

As of December 31, 2011, the weighted average remaining life for amortizing customer-related assets and all amortizing intangibles is 14 years.  These amortizing intangible assets have no significant residual values.  Intangible assets are presented net of accumulated amortization totaling $5.1 million for customer-related assets and $0.9 million for market-related assets at December 31, 2011 and $3.4 million for customer-related assets and $0.3 million for market-related assets at December 31, 2010.  Annual amortization associated with intangible assets totaled $2.3 million in 2011 and $0.6 million in 2010 and 2009.  Amortization should approximate $2.6 million, $2.3 million, $2.3 million, $2.2 million, and $1.6 million in 2012, 2013, 2014, 2015, and 2016, respectively. Intangible assets are primarily in the Nonutility Group.

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Earnings Per Share (Details) (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Numerator:
Numerator for basic earnings per share									$ 141.6	$ 133.6	$ 132.9
Earnings attributable to participating securities									0	0.1	0.2
Reported net income (Numerator for diluted earnings per share)									$ 141.6	$ 133.7	$ 133.1
Denominator:
Weighted average common shares outstanding (Basic earnings per share) (in shares)									81,800,000	81,200,000	80,700,000
Additional shares included in the calculation of diluted EPS as a result of the potentially dilutive effect of share based payment arrangements using the treasury stock and contingent share method (in shares)									0	100,000	300,000
Adjusted weighted average shares outstanding and assumed conversions outstanding (Diluted earnings per share) (in shares)									81,800,000	81,300,000	81,000,000
Basic earnings per share (in dollars per share)	$ 0.56	$ 0.43	$ 0.19	$ 0.55	$ 0.56	$ 0.20	$ 0.11	$ 0.78	$ 1.73	$ 1.65	$ 1.65
Diluted earnings per share (in dollars per share)	$ 0.56	$ 0.43	$ 0.18	$ 0.55	$ 0.55	$ 0.20	$ 0.11	$ 0.78	$ 1.73	$ 1.64	$ 1.64
Antidilutive securities excluded from computation of diluted earnings per share (in shares)									0	308,800	837,100
Stock options, exercise prices range , lower range limit (in dollars per share)										$ 24.90	$ 23.19
Stock options, exercise prices range , upper range limit (in dollars per share)										$ 27.15	$ 27.15

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Share-Based Compensation & Deferred Compensation Arrangements (Details) (USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Total cost of share-based compensation	$ 5.8	$ 4.9	$ 4.6
Less capitalized cost	0.8	1.7	1.6
Total in other operating expense	5.0	3.2	3.0
Less income tax benefit in earnings	2.0	1.3	1.2
After tax effect of share-based compensation	3.0	1.9	1.8
Deferred Compensation Plans [Abstract]
Liability associated with deferred compensation plans	21.1	19.1
Portion of liability classified in Accrued liabilities	0.7	0.5
Impact of deferred compensation plans on Other operating expenses	2.1	2.3	0.8
Amount recorded in earnings related to the investment activities in phantom stock associated with deferred compensation plans	1.7	1.6	(1.5)
Cash surrender value of life insurance policies	27.3	27.5
Earnings from investments in corporate-owned life insurance policies	0.1	1.9	4.1
Restricted Stock and Restricted Stock Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period for performance-based awards to executives and key non-officer employees (in years)	4
Vesting period for time-vested awards to non-officer employees (in years)	3
Vesting period for awards to non-employee directors (in years)	1
Performance Measurement Time Frame For Grants To Executives And Key Nonofficer Emplyees In Years	3
Share Based Payment Award Equity Instruments Other Than Options [Roll Forward]
Restricted awards at beginning of period (in shares)	668,892
Granted (in shares)	277,480
Vested (in shares)	(108,390)
Forfeited (in shares)	(139,872)
Restricted awards at end of period (in shares)	698,110
Weighted average grant date fair value at end of period (in dollars per share)	$ 30.23
Restricted Stock [Member]
Share Based Payment Award Equity Instruments Other Than Options [Roll Forward]
Restricted awards at beginning of period (in shares)	41,458
Granted (in shares)	27,518
Vested (in shares)	(7,226)
Forfeited (in shares)	(7,737)
Restricted awards at end of period (in shares)	54,013	41,458
Weighted average grant date fair value at beginning of period (in dollars per share)	$ 26.19
Weighted average grant date fair value of shares granted during period (in dollars per share)	$ 25.64
Weighted average grant date fair value of shares vested during period (in dollars per share)	$ 28.63
Weighted average grant date fair value of shares forfeited during period (in dollars per share)	$ 28.61
Weighted average grant date fair value at end of period (in dollars per share)	$ 25.22	$ 26.19
Total unrecognized compensation cost related to restricted stock awards	7.6
Weighted-average life of unrecognized compensation cost (in years)	1.6
Total fair value of liability awards vested	3.0	5.0	2.8
Total fair value of equity awards vested	0.2	0.2	0.1
Stock Options [Member]
Share Based Payment Award Equity Instruments Other Than Options [Roll Forward]
Length of continuous service required for option awards (in years)	3
Option awards term (in years)	10
Vesting period of option awards (in years)	3
Share Based Payment Award Options Outstanding [Roll Forward]
Outstanding at beginning of period (in shares)	929,806
Exercised (in shares)	(522,173)
Outstanding at end of period (in shares)	407,633	929,806
Exercisable at end of period (in shares)	407,633
Weighted average exercise price at beginning of period (in dollars per share)	$ 24.55
Weighted average exercise price of options exercised (in dollars per share)	$ 23.61
Weighted average exercise price at end of period (in dollars per share)	$ 25.74	$ 24.55
Weighted average exercise price of exercisable shares at end of period (in dollars per share)	$ 25.74
Remaining contractual term at end of period (in years)	2.5
Remaining contractual term of exercisable shares at end of period (in years)	2.5
Outstanding at end of period	1.8
Exercisable at end of period	1.8
Intrinsic value of options exercised	2.4	1.3
Tax benefit realized for tax deductions from option exercises	1.0	0.5
Cash received upon exercise of stock options	12.3	9.5
Stock repurchased during period	$ 12.8	$ 1.2

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Common Shareholder's Equity (Details) In Millions, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Authorized, reserved common and preferred shares [Abstract]
Common stock, shares authorized for issue (in shares)	480.0	480.0
Preferred stock , shares authorized for issue (in shares)	20.0	20.0
Number of shares reserved for issuance under share-based compensation plans, benefit plans, and dividend reinvestment plan (in shares)	6.8	5.5
Authorized shares of preferred stock available for issuance (in shares)	20.0	20.0
Authorized shares of common stock available for issuance (in shares)	391.3	392.8

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2011

Summary of Significant Accounting Policies [Abstract]

Principles of Consolidation

Principles of Consolidation

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

Subsequent Events Review

Subsequent Events Review

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

Cash and Cash Equivalents

Cash & Cash Equivalents

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

Allowance for Uncollectible Accounts

Allowance for Uncollectible Accounts

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

Inventories

Inventories

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

Property, Plant and Equipment

Property, Plant & Equipment

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

Utility Plant & Related Depreciation

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

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

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

Nonutility Plant & Related Depreciation

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

Impairment Reviews

Property, plant and equipment along with other long-lived assets are reviewed as facts and circumstances indicate that the carrying amount may be impaired.  This impairment review involves the comparison of an asset's (or group of assets') carrying value to the estimated future cash flows the asset (or asset group) is expected to generate over a remaining life.  If this evaluation were to conclude that the carrying value is impaired, an impairment charge would be recorded based on the difference between the carrying amount and its fair value (less costs to sell for assets to be disposed of by sale) as a charge to operations or discontinued operations.  There were no impairments related to property, plant and equipment during the periods presented.

Investments in Unconsolidated Affiliates

Investments in Unconsolidated Affiliates

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

Goodwill

Goodwill

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

Regulation

Regulation

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

Refundable or Recoverable Gas Costs & Cost of Fuel & Purchased Power

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

Regulatory Assets & Liabilities

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

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

Postretirement Obligations and Costs

Postretirement Obligations & Costs

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

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

Asset Retirement Obligations

Asset Retirement Obligations

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

Product Warranties, Performance Guarantees and Other Guarantees

Product Warranties, Performance Guarantees & Other Guarantees

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

While not significant at December 31, 2011 or 2010, the Company does recognize the fair value of an obligation at the inception of a guarantee in certain circumstances.  These circumstances would include executing certain indemnification agreements and guaranteeing operating lease residual values, the performance of a third party, or the indebtedness of a third party.

Energy Contracts and Derivatives

Energy Contracts & Derivatives

The Company will periodically execute derivative contracts in the normal course of operations while buying and selling commodities to be used in operations, optimizing its generation assets, and managing risk.  A derivative is recognized on the balance sheet as an asset or liability measured at its fair market value and the change in the derivative's fair market value is recognized currently in earnings unless specific hedge criteria are met.

When an energy contract that is a derivative is designated and documented as a normal purchase or normal sale (NPNS), it is exempted from mark-to-market accounting.  Most energy contracts executed by the Company are subject to the NPNS exclusion or are not considered derivatives.  Such energy contracts include Real Time and Day Ahead purchase and sale contracts with the MISO, natural gas purchases from ProLiance and others, and wind farm and other electric generating contracts.

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

Income Taxes

Income Taxes

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

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

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

Revenues

Revenues

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

MISO Transactions

MISO Transactions

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

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

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

Share-Based Compensation

Share-Based Compensation

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

Excise and Utility Receipts Taxes

Excise & Utility Receipts Taxes

Excise taxes and a portion of utility receipts taxes are included in rates charged to customers.  Accordingly, the Company records these taxes received as a component of operating revenues, which totaled $29.3 million in 2011, $33.8 million in 2010, and $36.3 million in 2009.  Expense associated with excise and utility receipts taxes are recorded as a component of Taxes other than income taxes.

Operating Segments

Operating Segments

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

Fair Value Measurements

Fair Value Measurements

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

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

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

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Organization and Nature of Operations (Details)	12 Months Ended
	Dec. 31, 2011
Organization and Nature of Operations [Abstract]
Number of public utility subsidiaries owned by wholly owned subsidiary, Vectren Utility Holdings, Inc. (in number of subsidiaries)	3
Estimated number of natural gas customers located in central and southern Indiana serviced by Indiana Gas Company (in number of customers)	563,000
Estimated number of electric customers located near Evansville in southwestern Indiana serviced by Southern Indiana Gas and Electric Company (in number of customers)	141,000
Estimated number of natural gas customers located near Evansville in southwestern Indiana serviced by Southern Indiana Gas and Electric Company (in number of customers)	110,000
Estimated number of natural gas customers located near Dayton in west central Ohio serviced by the Ohio operations (in number of customers)	310,000

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Earnings Per Share

12 Months Ended

Dec. 31, 2011

Earnings Per Share [Abstract]

Earnings Per Share

14.   Earnings Per Share

The Company uses the two class method to calculate earnings per share (EPS).  The two class method is an earnings allocation formula that treats a participating security as having rights to earnings that otherwise would have been available to common shareholders.  Under the two class method, earnings for a period are allocated between common shareholders and participating security holders based on their respective rights to receive dividends as if all undistributed book earnings for the period were distributed.  Basic EPS is computed by dividing net income attributable to only the common shareholders by the weighted-average number of common shares outstanding for the period.  Diluted EPS includes the impact of stock options and other equity based instruments to the extent the effect is dilutive.

The following table illustrates the basic and dilutive EPS calculations for the three years ended December 31, 2011:

	Year Ended December 31,
(In millions, except per share data)	2011		2010		2009
Numerator:
Numerator for basic EPS	$	141.6	$	133.6	$	132.9
Add back earnings attributable to participating securities		-		0.1		0.2
Reported net income (Numerator for Diluted EPS)	$	141.6	$	133.7	$	133.1
Denominator:
Weighted average common shares outstanding (Basic EPS)		81.8		81.2		80.7
Conversion of share based compensation arrangements		-		0.1		0.3
Adjusted weighted average shares outstanding and
assumed conversions outstanding (Diluted EPS)		81.8		81.3		81.0
Basic earnings per share	$	1.73	$	1.65	$	1.65
Diluted earnings per share	$	1.73	$	1.64	$	1.64

For the year ended December 31, 2011, there were no antidilutive options outstanding.  For the years ended December 31, 2010 and 2009, options to purchase 308,800 and 837,100, respectively, of additional shares of the Company's common stock were outstanding, but were not included in the computation of diluted EPS because their effect would be antidilutive.  The exercise prices for these options ranged from $24.90 to $27.15 and $23.19 to $27.15 for the years ended December 31, 2010 and 2009, respectively.

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Environmental Matters

12 Months Ended

Dec. 31, 2011

Environmental Matters Disclosure [Abstract]

Environmental Matters

19.   Environmental Matters

Air Quality

Cross-State Air Pollution Rule (Formerly Clean Air Interstate Rule (CAIR))

On July 7, 2011, EPA finalized the Cross-State Air Pollution Rule (CSAPR).  CSPAR is the EPA's response to the US Court of Appeals for the District of Columbia's (the Court) remand of the Clean Air Interstate Rule (CAIR). CAIR was originally established in 2005 as an allowance cap and trade program that required reductions from coal-burning power plants for NOx emissions beginning January 1, 2009 and SO2 emissions beginning January 1, 2010, with a second phase of reductions in 2015.

In an effort to address the Court's finding that CAIR did not adequately ensure attainment of pollutants in certain downwind states due to unlimited trading of SO2and NOx allowances, CSPAR reduces the ability of facilities to meet emission reduction targets through allowance trading.  Like CAIR, CSPAR sets individual state caps for SO2and NOx emissions.  However, unlike CAIR in which states allocated allowances through state implementation plans, CSPAR allowances were allocated to individual units directly through the federal rule.  As finalized, CSAPR requires a 71 percent reduction of SO2 emissions compared to 2005 national levels and a 52 percent reduction of NOx emissions compared to 2005 national levels and that such reductions are to be achieved with initial step reductions beginning January 1, 2012, with final compliance to be achieved in 2014.  Multiple administrative and judicial challenges have been filed, including requests to stay CSPAR's implementation.

On December 30, 2011, the Court granted a stay of CSPAR and ordered expedited briefing schedules be submitted by January 18, 2012, that would allow for completion of briefing and a hearing in April 2012.  Two primary issues are before the Court for review:  (1) EPA's use of air modeling data (as opposed to exclusive reliance on actual monitoring data) to support state contribution levels, and (2) EPA's allocation of allowances directly through a federal implementation plan as opposed to setting state caps and providing states the opportunity to submit individual state implementation plans.  In addition, there are initiatives in the Congress that, if adopted, would suspend CSPAR's implementation.

Utility Hazardous Air Pollutants (HAPs) Rule

On December 21, 2011, the EPA finalized the Utility HAPs rule.  The HAPs Rule is the EPA's response to the US Court of Appeals for the District of Columbia vacating the Clean Air Mercury Rule (CAMR) in 2008.  CAMR was originally established in 2005 as a nation-wide mercury emission allowance cap and trade system which sought to reduce utility emissions of mercury starting in 2010.

The HAPs rule sets emission limits for hazardous air pollutants for existing and new coal-fired power plants and identifies the following broad categories of hazardous air pollutants:  mercury, non-mercury hazardous air pollutants (primarily arsenic, chromium, cobalt, and selenium) and acid gases (hydrogen cyanide, hydrogen chloride, and hydrogen fluoride).  The rule imposes mercury emission limits for two sub-categories of coal, and proposed surrogate limits for non-mercury and acid gas hazardous air pollutants. The EPA did not grant blanket compliance extensions, but asserted that states have broad authority to grant one year extensions for individual units where potential reliability impacts have been demonstrated.  Reductions are to be achieved within three years of publication of the final rule in the Federal register (early 2015).  Initiatives to suspend CSPAR's implementation by the Congress also apply to the implementation of the HAPs Rule.

Conclusions Regarding Air Regulations

To comply with Indiana's implementation plan of the Clean Air Act, and other federal air quality standards, the Company obtained authority from the IURC to invest in clean coal technology.  Using this authorization, the Company invested approximately $411 million starting in 2001 with the last equipment being placed into service on January 1, 2010.  The pollution control equipment included Selective Catalytic Reduction (SCR) systems, fabric filters, and an SO2 scrubber at its generating facility that is jointly owned with ALCOA (the Company's portion is 150 MW).  SCR technology is the most effective method of reducing NOx emissions where high removal efficiencies are required and fabric filters control particulate matter emissions.  The unamortized portion of the $411 million clean coal technology investment was included in rate base for purposes of determining SIGECO's new electric base rates approved in the latest base rate order obtained April 27, 2011.  SIGECO's coal fired generating fleet is 100 percent scrubbed for SO2 and 90 percent controlled for NOx. 

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

The Company is currently reviewing the sufficiency of its existing pollution control equipment in relation to the requirements described in CSPAR and the Utility HAPs Rule.  Based upon an initial review of the final rules, including minor revisions made to CSPAR in October 2011, the Company believes that it will be able to meet these requirements with its existing suite of pollution control equipment and the anticipated allotment of new emission allowances.  However, it is possible some minor modifications to the control equipment and additional operating expenses could be required.  The Company believes that such additional costs, if necessary, would be recoverable under Indiana Senate Bill 251 referenced above.

Water

Section 316(b) of the Clean Water Act requires that generating facilities use the "best technology available" to minimize adverse environmental impacts in a body of water.  More specifically, Section 316(b) is concerned with impingement and entrainment of aquatic species in once-through cooling water intake structures used at electric generating facilities.  In April 2009, the U.S. Supreme Court affirmed that the EPA could, but was not required to, consider costs and benefits in making the evaluation as to the best technology available for existing generating facilities.  The regulation was remanded back to the EPA for further consideration.  In March 2011, the EPA released its proposed Section 316(b) regulations.  The EPA did not mandate the retrofitting of cooling towers in the proposed regulation, but if finalized the regulation will leave it to the state to determine whether cooling towers should be required on a case by case basis.  A final rule is expected in 2012.  Depending on the final rule and on the Company's facts and circumstances, capital investments could be in the $40 million range if new infrastructure, such as new cooling water towers, is required.  Costs for compliance with these final regulations would likely qualify as federally mandated regulatory requirements under Indiana Senate Bill 251 referenced above.

Coal Ash Waste Disposal & Ash Ponds

In June 2010, the EPA issued proposed regulations affecting the management and disposal of coal combustion products, such as ash generated by the Company's coal-fired power plants.  The proposed rules more stringently regulate these byproducts and would likely increase the cost of operating or expanding existing ash ponds and the development of new ash ponds.  The alternatives include regulating coal combustion by-products that are not being beneficially reused as hazardous waste.  The EPA did not offer a preferred alternative, but took public comment on multiple alternative regulations.  Rules may not be finalized in 2012 given oversight hearings, congressional interest, and other factors.

At this time, the majority of the Company's ash is being beneficially reused.  However, the alternatives proposed would require some retrofitting or closure of existing ash ponds.  The Company estimates capital expenditures to comply could be as much as $30 million, and such expenditures could exceed $100 million if the most stringent of the alternatives is selected.  Annual compliance costs could increase slightly or be impacted by as much as $5 million.  Costs for compliance with these regulations would likely qualify as federally mandated regulatory requirements under Senate Bill 251 referenced above. 

Climate Change

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

Numerous competing federal legislative proposals have also been introduced in recent years that involve carbon, energy efficiency, and renewable energy.  Comprehensive energy legislation at the federal level continues to be debated, but there has been little progress to date.  The progression of regional initiatives throughout the United States has also slowed.

Impact of Legislative Actions & Other Initiatives is Unknown

If regulations are enacted by the EPA or other agencies or if legislation requiring reductions in CO2 and other greenhouse gases or legislation mandating a renewable energy portfolio standard is adopted, such regulation could substantially affect both the costs and operating characteristics of the Company's fossil fuel generating plants, nonutility coal mining operations, and natural gas distribution businesses.  At this time and in the absence of final legislation or rulemaking, compliance costs and other effects associated with reductions in greenhouse gas emissions or obtaining renewable energy sources remain uncertain.  The Company has gathered preliminary estimates of the costs to control greenhouse gas emissions.  A preliminary investigation demonstrated costs to comply would be significant, first with regard to operating expenses and later for capital expenditures as technology becomes available to control greenhouse gas emissions.  However, these compliance cost estimates are based on highly uncertain assumptions, including allowance prices if a cap and trade approach were employed, and energy efficiency targets.  Costs to purchase allowances that cap greenhouse gas emissions or expenditures made to control emissions should be considered a cost of providing electricity, and as such, the Company believes such costs and expenditures would be recoverable from customers through Senate Bill 251.  Customer rates may also be impacted should decisions be made to reduce the level of sales to municipal and other wholesale customers in order to meet emission targets.

Manufactured Gas Plants

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

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

The Company has accrued the estimated costs for further investigation, remediation, groundwater monitoring, and related costs for the sites.  While the total costs that may be incurred in connection with addressing these sites cannot be determined at this time, the Company has recorded cumulative costs that it reasonably expects to incur totaling approximately $41.6 million ($23.1 million at Indiana Gas and $18.5 million at SIGECO).  The estimated accrued costs are limited to the Company's share of the remediation efforts and are therefore net of exposures of other potentially responsible parties (PRP).

With respect to insurance coverage, Indiana Gas has received approximately $20.8 million from all known insurance carriers under insurance policies in effect when these plants were in operation.  SIGECO 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 another site subject to a lawsuit that has been settled.  In November 2011, the Court ruled on two motions for summary judgment, finding for SIGECO and against certain insurers on indemnification and defense obligations in the policies at issue.  SIGECO has settlement agreements with all known insurance carriers and has recorded approximately $15.1 million of expected insurance recoveries.

The costs the Company expects to incur are estimated by management using assumptions based on actual costs incurred, the timing of expected future payments, and inflation factors, among others.  While the Company's utilities have recorded all costs which they presently expect to incur in connection with activities at these sites, it is possible that future events may require 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, 2011 and 2010, respectively, approximately $6.5 million and $5.5 million of accrued, but not yet spent, costs are included in Other Liabilities related to both the Indiana Gas and SIGECO sites.

Jacobsville Superfund Site

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

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Additional Balance Sheet & Operational Information (Tables)

12 Months Ended

Dec. 31, 2011

Additional Balance Sheet and Operational Information [Abstract]

Summary of inventories

Inventories consist of the following:

	At December 31,
(In millions)	2011		2010
Gas in storage - at LIFO cost	$	31.8	$	26.2
Gas in storage - at average cost		-		23.6
Total Gas in storage		31.8		49.8
Coal & Oil for electric generation - at average cost		60.6		70.1
Materials & supplies		54.9		48.8
Nonutility Coal - at LIFO cost		13.0		16.2
Other		1.6		2.2
Total inventories	$	161.9	$	187.1

Summary of prepayments and other current assets

Prepayments & other current assets in the Consolidated Balance Sheets consist of the following:

	At December 31,
(In millions)	2011		2010
Prepaid gas delivery service	$	42.4	$	40.7
Deferred income taxes		16.0		3.8
Prepaid taxes		5.1		31.5
Other prepayments & current assets		20.8		25.2
Total prepayments & other current assets	$	84.3	$	101.2

Schedule of investments in unconsolidated affiliates

Investments in unconsolidated affiliates consist of the following:

	At December 31,
(In millions)	2011		2010
ProLiance Holdings, LLC	$	85.4	$	123.2
Haddington Energy Partnerships		3.4		3.4
Other non-utility partnerships & corporations		3.9		8.4
Other utility investments		0.2		0.2
Total investments in unconsolidated affiliates	$	92.9	$	135.2

Other utility and corporate investments in the consolidated balance sheets

Other utility & corporate Investments in the Consolidated Balance Sheets consist of the following:

	At December 31,
(In millions)	2011		2010
Cash surrender value of life insurance policies	$	27.3	$	27.5
Municipal bond		3.9		4.1
Restricted cash		1.9		1.2
Other investments		1.3		1.3
Other utility & corporate investments	$	34.4	$	34.1

Goodwill by operating segment

Goodwill by operating segment follows:

	At December 31,
(In millions)	2011		2010
Utility Group
Gas Utility Services	$	205.0	$	205.0
Nonutility Group
Infrastructure Services		55.2		34.9
Energy Services		2.1		2.1
Consolidated goodwill	$	262.3	$	242.0

Accrued Liabilities

Accrued liabilities in the Consolidated Balance Sheets consist of the following:

	At December 31,
(In millions)	2011		2010
Refunds to customers & customer deposits	$	56.4	$	54.8
Accrued taxes		33.5		40.9
Accrued interest		21.7		23.8
Accrued retirement		6.5		5.8
Accrued salaries & other		63.0		53.1
Total accrued liabilities	$	181.1	$	178.4

Asset retirement obligation

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

(In millions)	2011		2010
Asset retirement obligation, January 1	$	38.7	$	36.1
Accretion		2.5		2.1
Increases in estimates, net of cash payments		2.5		0.5
Asset retirement obligation, December 31		43.7		38.7
Accrued liabilities	$	0.2	$	0.3
Deferred credits & other liabilities	$	43.5	$	38.4

Equity in earnings (losses) of unconsolidated affiliates

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

	Year Ended December 31,
(In millions)	2011			2010			2009
ProLiance Holdings, LLC	$	(28.6	)	$	(2.5	)	$	3.6
Haddington Energy Partners, LP		-			(6.1	)		0.9
Other		(3.4	)		-			(1.1	)
Total equity in earnings (losses) of unconsolidated affiliates	$	(32.0	)	$	(8.6	)	$	3.4

Other, net in the consolidated statements of income

Other income (expense) - net in the Consolidated Statements of Income consists of the following:

	Year Ended December 31,
(In millions)	2011			2010			2009
AFUDC - borrowed funds	$	2.5		$	1.4		$	1.3
AFUDC - equity funds		0.2			0.3			0.7
Nonutility plant capitalized interest		2.1			2.1			6.0
Interest income, net		1.4			1.7			1.4
Other nonutility investment impairment charges		(9.9	)		(4.7	)		-
Cash surrender value of life insurance policies		0.1			1.9			4.1
All other income		0.1			2.1			0.2
Total other income (expense) - net	$	(3.5	)	$	4.8		$	13.7

Supplemental cash flow information

Supplemental Cash Flow Information:

	Year Ended December 31,
(In millions)	2011			2010		2009
Cash paid (received) for:
Interest	$	108.6		$	104.5	$	95.5
Income taxes		(9.0	)		8.1		(12.2	)

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2011

Income Taxes [Abstract]

Reconciliation of the federal statutory rate to the effective income tax rate

A reconciliation of the federal statutory rate to the effective income tax rate follows:

	Year Ended December 31,
	2011		2010		2009
Statutory rate:	35.0	%	35.0	%	35.0	%
State & local taxes-net of federal benefit	4.2		3.8		2.3
Amortization of investment tax credit	(0.3	)	(0.4	)	(0.5	)
Depletion	(1.9	)	(2.0	)	(2.0	)
Other tax credits	(0.2	)	(0.2	)	(0.2	)
Adjustment of income tax accruals and all other-net	1.1		(0.4	)	(2.1	)
Effective tax rate	37.9	%	35.8	%	32.5	%

Significant components of the net deferred tax liability (assets)

Significant components of the net deferred tax liability follow:

	At December 31,
(In millions)	2011			2010
Noncurrent deferred tax liabilities (assets):
Depreciation & cost recovery timing differences	$	625.5		$	565.7
Leveraged leases		13.8			14.2
Regulatory assets recoverable through future rates		25.1			20.1
Other comprehensive income		(10.2	)		(4.2	)
Alternative minimum tax carryforward		(35.1	)		(48.6	)
Employee benefit obligations		(9.4	)		(18.9	)
Net operating loss & other carryforwards		(6.7	)		(3.8	)
Regulatory liabilities to be settled through future rates		(17.2	)		(4.8	)
Impairments		(11.4	)		(4.4	)
Other - net		1.3			-
Net noncurrent deferred tax liability		575.7			515.3
Current deferred tax (assets)/liabilities:
Deferred fuel costs-net		6.0			2.4
Demand side management programs		0.7			2.5
Alternative minimum tax carryforward		(15.6	)		(0.8	)
Other - net		(7.1	)		(7.9	)
Net current deferred tax asset		(16.0	)		(3.8	)
Net deferred tax liability	$	559.7		$	511.5

Components of income tax expense and utilization of investment tax credits

The components of income tax expense and utilization of investment tax credits follow:

	Year Ended December 31,
(In millions)	2011			2010			2009
Current:
Federal	$	4.4		$	(0.8	)	$	(21.4	)
State		10.3			6.2			0.6
Total current taxes		14.7			5.4			(20.8	)
Deferred:
Federal		66.0			65.6			78.7
State		6.4			4.5			7.3
Total deferred taxes		72.4			70.1			86.0
Amortization of investment tax credits		(0.7	)		(0.8	)		(1.1	)
Total income tax expense	$	86.4		$	74.7		$	64.1

Roll forward of unrecognized tax benefits

Following is a roll forward of unrecognized tax benefits for the three years ended December 31, 2011:

(In millions)	2011			2010			2009
Unrecognized tax benefits at January 1	$	13.3		$	11.5		$	2.2
Gross increases - tax positions in prior periods		3.3			1.6			1.1
Gross decreases - tax positions in prior periods		(4.5	)		(0.3	)		(1.8	)
Gross increases - current period tax positions		0.6			1.0			9.0
Settlements		(0.3	)		-			(0.1	)
Lapse of statute of limitations		-			(0.5	)		1.1
Unrecognized tax benefits at December 31	$	12.4		$	13.3		$	11.5

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Statement of Cash Flows (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$ 141.6	$ 133.7	$ 133.1
Adjustments to reconcile net income to cash from operating activities:
Depreciation and amortization	244.3	229.1	211.9
Deferred income taxes and investment tax credits	71.7	69.3	84.9
Equity in (earnings) losses of unconsolidated affiliates	32.0	8.6	(3.4)
Provision for uncollectible accounts	11.8	16.8	15.1
Expense portion of pension and postretirement benefit cost	9.0	10.0	10.4
Gain on sale of business in 2011, net of other non-cash charges	(0.1)	15.9	13.3
Changes in working capital accounts:
Accounts receivable and accrued unbilled revenue	(17.5)	(48.3)	96.9
Inventories	(26.1)	(19.3)	(36.1)
Recoverable/refundable fuel and natural gas costs	(4.5)	(30.2)	21.3
Prepayments and other current assets	17.9	(23.5)	43.1
Accounts payable, including to affiliated companies	(21.2)	5.5	(85.8)
Accrued liabilities	6.4	10.2	4.0
Unconsolidated affiliate dividends	0.1	42.7	12.6
Employer contributions to pension and postretirement plans	(38.8)	(22.0)	(38.5)
Changes in noncurrent assets	0.3	(7.6)	0.2
Changes in noncurrent liabilities	(10.0)	(6.1)	(33.4)
Net cash flows from operating activities	416.9	384.8	449.6
Proceeds from:
Long-term debt, net of issuance costs	148.9	124.2	312.5
Dividend reinvestment plan and other common stock issuances	7.9	14.0	5.8
Requirements for:
Dividends on common stock	(113.2)	(110.8)	(108.6)
Retirement of long-term debt	(349.1)	(49.3)	(3.5)
Other financing activities	(2.3)	(0.2)	0
Net change in short-term borrowings	208.8	(95.2)	(306.0)
Net cash flows from financing activities	(99.0)	(117.3)	(99.8)
Proceeds from:
Sale of business	84.3	0	0
Unconsolidated affiliate distributions	0.5	0.5	4.6
Other collections	1.1	10.8	1.5
Requirements for:
Capital expenditures, excluding AFUDC equity	(321.3)	(277.2)	(432.0)
Business acquisition, net of cash acquired	(83.4)	0	0
Other investments	(0.9)	(3.1)	(5.2)
Net cash flows from investing activities	(319.7)	(269.0)	(431.1)
Net change in cash and cash equivalents	(1.8)	(1.5)	(81.3)
Cash and cash equivalents at beginning of period	10.4	11.9	93.2
Cash and cash equivalents at end of period	$ 8.6	$ 10.4	$ 11.9

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Utility & Nonutility Plant

12 Months Ended

Dec. 31, 2011

Utility and Nonutility Plant [Abstract]

Utility and Nonutility Plant

3.     Utility & Nonutility Plant

The original cost of Utility Plant, together with depreciation rates expressed as a percentage of original cost, follows:

	At December 31,
(In millions)	2011					2010
	Original Cost		Depreciation Rates as a Percent of  Original Cost			Original Cost		Depreciation Rates as a Percent of  Original Cost
Gas utility plant	$	2,516.8		3.5	%	$	2,410.2		3.6	%
Electric utility plant		2,316.8		3.3	%		2,258.6		3.4	%
Common utility plant		51.6		2.9	%		49.7		3.1	%
Construction work in progress		94.7		-			73.2		-
Total original cost	$	4,979.9				$	4,791.7

SIGECO and Alcoa Generating Corporation (AGC), a subsidiary of ALCOA, own the 300 MW Unit 4 at the Warrick Power Plant as tenants in common.  SIGECO's share of the cost of this unit at December 31, 2011, is $182.6 million with accumulated depreciation totaling $70.3 million.  AGC and SIGECO also share equally in the cost of operation and output of the unit.  SIGECO's share of operating costs is included in Other operating expenses in the Consolidated Statements of Income.

Nonutility plant, net of accumulated depreciation and amortization follows:

	At December 31,
(In millions)	2011		2010
Coal mine development costs & equipment	$	222.0	$	196.9
Computer hardware & software		101.9		114.5
Land & buildings		112.0		112.8
Vehicles & equipment		92.5		46.9
All other		22.4		17.2
Nonutility plant - net	$	550.8	$	488.3

Nonutility plant is presented net of accumulated depreciation and amortization totaling $418.5 million and $385.5 million as of December 31, 2011 and 2010, respectively.  For the years ended December 31, 2011, 2010, and 2009, the Company capitalized interest totaling $2.1 million, $2.1 million, and $6.0 million, respectively, on nonutility plant construction projects.

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Nonutility Real Estate & Other Legacy Holdings (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Investments by type [Abstract]
Other nonutility investments	$ 29.6	$ 40.9
Investments in Unconsolidated Affiliates	92.9	135.2
Haddington Energy Partnerships [Abstract]
Equity in earnings (losses) of unconsolidated affiliates	(32.0)	(8.6)	3.4
Other assets	40.3	33.7
Liabilities	1,160.3	1,069.4
Notes Receivable
Other nonutility investments identified above	29.6	40.9
Variable Interest Expense
Investments in Unconsolidated Affiliates	92.9	135.2
Other nonutility investments	29.6	40.9
Nonutility Group [Member]
Investments by type [Abstract]
Total carrying value by type of investment	36.9	52.7
Other nonutility investments	29.6
Investments in Unconsolidated Affiliates	7.3
Carrying value of legacy investments less deferred taxes of leveraged leases	23.1
Notes Receivable
Notes receivable	2.1	10.9
Accrued interest and reserves associated with notes receivable	15.7	6.1
Other nonutility investments identified above	29.6
Variable Interest Expense
Investments in Unconsolidated Affiliates	7.3
Other nonutility investments	29.6
Nonutility Group [Member] | Leveraged Leases Member
Investments by type [Abstract]
Total carrying value by type of investment	18.5
Other nonutility investments	18.5
Investments in Unconsolidated Affiliates	0
Leveraged Leases
Total equipment and facilities cost	45.2
Rentals due under the leases and a security interest in the leased property	39.8
Book value of divested leveraged lease	5.2
Net Book Value Of Deferred Taxes Of Divested Leveraged Lease	2.7
Notes Receivable
Other nonutility investments identified above	18.5
Variable Interest Expense
Investments in Unconsolidated Affiliates	0
Other nonutility investments	18.5
Nonutility Group [Member] | Commercial Real Estate Investments [Member]
Investments by type [Abstract]
Total carrying value by type of investment	8.0
Other nonutility investments	8.0
Investments in Unconsolidated Affiliates	0
Haddington Energy Partnerships [Abstract]
Equity in earnings (losses) of unconsolidated affiliates	3.6
Notes Receivable
Other nonutility investments identified above	8.0
Commercial real estate
Impairment charge	15.4
Amount of impairment charge included in Other-net	8.8
Other operating expenses	3.0
Variable Interest Expense
Investments in Unconsolidated Affiliates	0
Other nonutility investments	8.0
Nonutility Group [Member] | Affordable Housing Projects [Member]
Investments by type [Abstract]
Total carrying value by type of investment	3.1
Other nonutility investments	0.1
Investments in Unconsolidated Affiliates	3.0
Notes Receivable
Other nonutility investments identified above	0.1
Variable Interest Expense
Investments in Unconsolidated Affiliates	3.0
Other nonutility investments	0.1
Nonutility Group [Member] | Haddington Energy Partnerships [Member]
Investments by type [Abstract]
Total carrying value by type of investment	3.4
Other nonutility investments	0
Investments in Unconsolidated Affiliates	3.4
Haddington Energy Partnerships [Abstract]
Percentage of ownership interest in both Haddington Ventures (in hundredths)	40.00%
Number of remaining mid-stream energy related investments	2
Charge related to decline in fair value and note receivable impairment		6.5
Equity in earnings (losses) of unconsolidated affiliates		6.1
Amount charged to other income-net		0.4
Revenues		0	0
Operating income (loss)		(0.3)	(0.4)
Net income		(18.1)	7.9
Notes Receivable
Other nonutility investments identified above	0
Variable Interest Expense
Investments in Unconsolidated Affiliates	3.4
Other nonutility investments	0
Nonutility Group [Member] | Other Investments [Member]
Investments by type [Abstract]
Total carrying value by type of investment	3.9
Other nonutility investments	3.0
Investments in Unconsolidated Affiliates	0.9
Notes Receivable
Other nonutility investments identified above	3.0
Variable Interest Expense
Investments in Unconsolidated Affiliates	0.9
Other nonutility investments	3.0
Nonutility Group [Member] | Variable Interest Entities [Member]
Investments by type [Abstract]
Other nonutility investments	0.1	9.0
Investments in Unconsolidated Affiliates	3.0	7.0
Notes Receivable
Other nonutility investments identified above	0.1	9.0
Variable Interest Expense
Investments in Unconsolidated Affiliates	3.0	7.0
Other nonutility investments	$ 0.1	$ 9.0

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Environmental Matters (Details) (USD $)
In Millions, unless otherwise specified

12 Months Ended

Dec. 31, 2011

Dec. 31, 2010

Air Quality [Abstract]

Cost of most of the allowances granted to company for NOx and SO2 inventory usage

$ 0

SIGECO investment in Property, Plant and Equipment, Pollution control equipment

411.0

Property, Plant and Equipment, amount of investment in pollution control equipment included in rate base

411.0

Percentage of coal fired generating fleet currently being scrubbed for SO2 (in hundredths)

100.00%

Percentage of coal fired generating fleet currently controlled for NOx (in hundredths)

90.00%

Percentage reduction of SO2 per Cross-State Air Pollution Rule (in hundredths)

71.00%

Percentage reduction of NOx per Cross-State Air Pollution Rule (in hundredths)

52.00%

Climate Changes [Abstract]

Maximum level of greenhouse gas emissions that prompts requirement to obtain permit for facilities to construct new facility of significant modification to existing facility (in tons)

75,000

Coal Ash Waste Disposal and Ash Ponds [Abstract]

Estimated capital expenditures to comply with ash pond and coal ash disposal regulations

30.0

Potential estimated capital expenditures to comply with ash pond and coal ash disposal regulations with stringent alternative

100.0

Estimated annual compliance costs maximum with ash pond and coal ash disposal regulation

5.0

Clean Water Act [Abstract]

Estimated capital expenditures related to Clean Water Act

40.0

Jacobsville Superfund Site [Abstract]

EPA identified sources of historic lead

 The EPA has identified four sources of historic lead contamination.  These four sources shut down manufacturing operations years ago.  When drawing up the boundaries for the listing, the EPA included a 250 acre block of properties surrounding the Jacobsville neighborhood, including the Company's operations center.  

Manufactured Gas Plants

Site contingency, accrual, undiscounted amount

41.6

Remediation cost accrued and not yet spent a the end of the period

6.5

5.5

Indiana Gas [Member]

Manufactured Gas Plants

Number of sites identified with potential remedial responsibility for entity (in number of sites)

26

Site contingency, accrual, undiscounted amount

23.1

Environmental cost recognized, recover from insurance carriers credited to expense

20.8

SIGECO [Member]

Manufactured Gas Plants

Number of sites identified with potential remedial responsibility for entity (in number of sites)

5

Site contingency, accrual, undiscounted amount

18.5

Environmental cost recognized, recover from insurance carriers credited to expense

$ 15.1

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Rate & Regulatory Matters

12 Months Ended

Dec. 31, 2011

Rate and Regulatory Matters [Abstract]

Rate and Regulatory Matters

20.   Rate & Regulatory Matters

Vectren South Electric Base Rate Filing

On December 11, 2009, Vectren South filed a request with the IURC to adjust its base electric rates.  The requested increase in base rates addressed capital investments, a modified electric rate design that would facilitate a partnership between Vectren South and customers to pursue energy efficiency and conservation, and new energy efficiency programs to complement those currently offered for natural gas customers.  The IURC issued an order in the case on April 27, 2011.  The order provides for an approximate $28.6 million revenue increase to recover costs associated with approximately $325 million in system upgrades that were completed in the three years leading up to the December 2009 filing and modest increases in maintenance and operating expenses.  The approved revenue increase is based on rate base of $1,295.6 million, return on equity of 10.4 percent and an overall rate of return of 7.29 percent.  The new rates were effective May 3, 2011.  The IURC, in its order, denied the Company's request for implementation of the decoupled rate design, which is discussed further below.  Addressing issues raised in the case concerning coal supply contracts and related costs, the IURC found that current coal contracts remain effective and that a prospective review process of future procurement decisions would be initiated.

Coal Procurement Procedures

Vectren South submitted a request for proposal in April 2011 regarding coal purchases for a four year period beginning in 2012.  After negotiations with bidders, Vectren South has reached an agreement in principle for multi-year purchases with two suppliers, one of which is Vectren Fuels, Inc.  Consistent with the IURC direction in the electric rate case, a sub docket proceeding was established to review the Company's prospective coal procurement procedures, and the Company submitted evidence related to its recent request for proposal (RFP) and those coal procurement procedures to the IURC in September 2011.  In October 2011, the OUCC filed its testimony which, while suggesting enhancements to the process to be considered, does not challenge the results of the RFP and the resulting new contracts.  All hearings were completed in December 2011, and an order is expected in early 2012.

Vectren South Electric Fuel Cost Reduction

On December 5, 2011 within the quarterly Fuel Adjustment Clause (FAC) filing, Vectren South submitted a joint proposal with the OUCC to reduce its fuel costs by accelerating the impact of lower cost coal contracts to be effective after 2012.  In the spring of 2011, Vectren secured contracts for lower coal costs through a formal bidding process. This lower-priced coal is expected to start being delivered and used at Vectren's power plants by late 2012 to early 2013 and beyond. The agreement to accelerate savings into early 2012 means that the existing 2012 coal costs that are above the new, lower prices will be deferred to a regulatory asset and recovered over a six-year period without interest beginning in 2014.  This deferral also includes a reduction to the coal inventory balance at December 31, 2011 of approximately $17.7 million to reflect existing inventory at the new, lower price.  The IURC approved this proposal on January 25, 2012, with an impact to customer's rates effective February 1, 2012.

Vectren South Electric Demand Side Management Program Filing

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

On August 31, 2011 the IURC issued an order approving an initial three year DSM plan in the Vectren South service territory that complies with the IURC's energy saving targets.  Consistent with the Company's proposal, the order approved, among other items, the following: 1) recovery of costs associated with implementing the DSM Plan; 2) the recovery of a performance incentive mechanism based on measured savings related to certain DSM programs; 3) lost margin recovery associated with the implementation of DSM programs for large customers; and 4) deferral of lost margin up to $1 million in 2011 associated with small customer DSM programs for subsequent recovery under a tracking mechanism to be proposed by the Company.  This mechanism is an alternative to the electric decoupling proposal that was denied by the IURC in the order received April 27, 2011.  On January 26, 2012, the Company filed with the IURC a proposal for a small customer lost margin recovery mechanism within the existing Demand Side Management Adjustment (DSMA).  The proposal includes a request for recovery of the $1 million deferred in 2011, and a request for continued deferral of lost margins in 2012 until such point as these lost margins are included in DSMA rates.  The procedural schedule has not been set in this filing, but the Company expects an order in 2012.

Vectren South Electric Dense Pack Filing

On September 14, 2011, Vectren South filed a petition with the IURC seeking recovery of and return on the capital investment in dense pack technology to improve the efficiency of its A.B. Brown Generating Station.  This investment is expected to be approximately $32 million over the next two years, of which approximately $19 million has been invested to date.  This technology is expected to allow the A.B. Brown units to run at least 5 percent more efficient, thereby burning less fuel, and reducing fuel costs and emissions of pollutants.  Indiana statute provides for timely recovery of investments, with a return, in instances where the investment increases the efficiency of existing generating plants that are fueled by coal.  Several parties have intervened in the case and are requesting that the IURC deny recovery of these project costs outside of a base rate proceeding.The IURC will conduct a hearing in February 2012.

Vectren North Reporting Location Consolidation Proceeding

Vectren North implemented a reporting location consolidation plan in 2011 and closed certain locations throughout the North territory.  On May 26, 2011, the International Brotherhood of Electrical Workers Local 1393, United Steel Workers Locals 12213 and 7441 and others filed a formal complaint with the IURC claiming that the consolidation and simultaneous closing by Vectren North of select reporting locations endangers public safety and impairs Vectren North's ability to provide adequate, safe and reliable service.  These parties have asked the IURC to require Vectren North to reopen previously consolidated reporting locations and maintain and staff those locations.  A hearing in this case was held in February 2012, and the Company expects the IURC to act some time in 2012.

Vectren North & Vectren South Gas Decoupling Extension Filing

On April 14, 2011, the Company's Indiana based gas companies (Vectren North and Vectren South) filed with the IURC a joint settlement agreement with the OUCC on an extension of the offering of conservation programs and the supporting gas decoupling mechanism originally approved in December 2006.  On August 18, 2011, the IURC issued an order approving the settlement as filed, granting the extension of the current decoupling mechanism in place at both gas companies and recovery of new conservation program costs through December 2015.

VEDO Gas Rate Design

The rate design approved by the PUCO on January 7, 2009, and initially implemented on February 22, 2009, allowed for the phased movement toward a straight fixed variable rate design, which places substantially all of the fixed cost recovery in the monthly customer service charge.  This rate design mitigates most weather risk as well as the effects of declining usage, similar to the company's lost margin recovery mechanism in place in the Indiana natural gas service territories and the mechanism in place in Ohio prior to this rate order.  Since the straight fixed variable rate design was fully implemented in February 2010, nearly 90 percent of the combined residential and commercial base rate gas margins were recovered through the customer service charge.  As a result, some margin previously recovered during the peak delivery winter months, such as January and the first half of February 2010, is more ratably recognized throughout the year.

In addition in 2010, the Company began recognizing a return on and of investments made to replace distribution risers and bare steel and cast iron infrastructure per a PUCO order.

VEDO Continues the Process to Exit the Merchant Function

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

The second phase of the exit process began on April 1, 2010.  During this phase, the Company no longer sells natural gas directly to customers.  Rather, state-certified Competitive Retail Natural Gas Suppliers, that were successful bidders in a similar regulatory-approved auction, sell the gas commodity to specific customers for a 12-month period at auction-determined standard pricing.  The first auction was conducted on January 12, 2010, and the auction results were approved by the PUCO on January 13, 2010.  The plan approved by the PUCO required that the Company conduct at least two annual auctions during this phase.  As such, the Company conducted another auction on January 18, 2011 in advance of the second 12-month term which commenced on April 1, 2011.  The results of that auction were approved by the PUCO on January 19, 2011.Vectren Source, the Company's former wholly owned nonutility retail gas marketer, was a successful bidder in both auctions winning one tranche of customers in the first auction and two tranches of customers in the second auction.  Each tranche of customers equates to approximately 28,000 customers.  As per the terms of the plan approved by the PUCO, because no application for a full exit of the merchant function was neither sought nor approved by April 1, 2011, VEDO conducted a third retail auction on January 31, 2012 to address the 12-month term beginning April 1, 2012.  The results of that auction were approved by the PUCO on February 1, 2012.  Consistent with current practice, customers continue to receive a single bill for the commodity as well as the delivery component of natural gas service from VEDO.

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

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Quarterly Financial Data (Unaudited) (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Quarterly Financial Data (Unaudited) [Abstract]
Operating revenues	$ 627.4	$ 539.4	$ 475.8	$ 682.6	$ 564.1	$ 422.7	$ 402.4	$ 740.3	$ 2,325.2	$ 2,129.5	$ 2,088.9
Operating income	111.0	94.1	61.6	103.3	89.9	58.6	52.1	116.2	370.0	316.8	280.1
Net income	$ 46.6	$ 35.3	$ 15.1	$ 44.6	$ 45.4	$ 16.4	$ 8.7	$ 63.2	$ 141.6	$ 133.7	$ 133.1
Earnings per share [Abstract]
Basic	$ 0.56	$ 0.43	$ 0.19	$ 0.55	$ 0.56	$ 0.20	$ 0.11	$ 0.78	$ 1.73	$ 1.65	$ 1.65
Diluted	$ 0.56	$ 0.43	$ 0.18	$ 0.55	$ 0.55	$ 0.20	$ 0.11	$ 0.78	$ 1.73	$ 1.64	$ 1.64

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Investment in ProLiance Holdings, LLC (Tables)

12 Months Ended

Dec. 31, 2011

ProLiance Holdings, LLC [Abstract]

Summarized Financial Information

Summarized Financial Information

	Year Ended December 31,
(In millions)	2011			2010			2009
Summarized Statement of Income information:
Revenues	$	1,410.5		$	1,497.0		$	1,654.9
Operating income (loss)		(44.5	)		(3.1	)		35.2
Charge related to Investment in Liberty Gas Storage		-			-			(32.7	)
ProLiance's earnings (losses)		(47.3	)		(3.7	)		4.5

	As of December 31,
(In millions)	2011			2010
Summarized balance sheet information:
Current assets	$	381.9		$	441.4
Noncurrent assets		56.1			59.1
Current liabilities		298.5			298.1
Noncurrent liabilities		0.7			0.4
Members' equity		161.5			208.9
Accumulated other comprehensive income (loss)		(26.0	)		(10.8	)
Noncontrolling interest		3.3			3.9

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Common Shareholder's Equity

12 Months Ended

Dec. 31, 2011

Common Shareholder's Equity [Abstract]

Common Shareholder's Equity

13.   Common Shareholders' Equity

Authorized, Reserved Common and Preferred Shares

At December 31, 2011 and 2010, the Company was authorized to issue 480.0 million shares of common stock and 20.0 million shares of preferred stock.  Of the authorized common shares, approximately 6.8 million shares at December 31, 2011 and 5.5 million shares at December 31, 2010, were reserved by the board of directors for issuance through the Company's share-based compensation plans, benefit plans, and dividend reinvestment plan.  At December 31, 2011 and 2010, there were 391.3 million and 392.8 million, respectively, of authorized shares of common stock and all authorized shares of preferred stock, available for a variety of general corporate purposes, including future public offerings to raise additional capital and for facilitating acquisitions.