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, 2012

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.  Yes ý    No ¨

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes ý No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes ý No ¨

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

Non-accelerated filer ¨                                                                   Smaller reporting company ¨

(Do not check if a smaller

reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes ¨ No ý

The aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of June 30, 2012, was $2,415,396,451.

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	82,204,242	January 31, 2013
Class	Number of Shares	Date

Documents Incorporated by Reference

Certain information in the Company's definitive Proxy Statement for the 2013 Annual Meeting of Shareholders, 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

Table of Contents

Item Number		Page Number
Part I
1	Business	3
1A	Risk Factors	11
1B	Unresolved Staff Comments	19
2	Properties	19
3	Legal Proceedings	20
4	Mine Safety Disclosures	20
Part II
5	Market for the Company’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities	21
6	Selected Financial Data	21
7	Management's Discussion and Analysis of Results of Operations and Financial Condition	22
7A	Qualitative and Quantitative Disclosures About Market Risk	52
8	Financial Statements and Supplementary Data	54
9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	107
9A	Controls and Procedures, including Management’s Assessment of Internal Controls over Financial Reporting	107
9B	Other Information	107
Part III
10	Directors, Executive Officers and Corporate Governance	107
11	Executive Compensation	108
12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	108
13	Certain Relationships, Related Transactions and Director Independence	109
14	Principal Accountant Fees and Services	109
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 566,000 natural gas customers located in central and southern Indiana.  SIGECO provides energy delivery services to approximately 142,000 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 pipeline construction and repair services.  Energy Services provides performance contracting and renewable energy services.  Coal Mining owns coal 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 a leveraged lease, among other investments.  All of the above are collectively referred to as the Nonutility Group.  Pursuant to service contracts, the Nonutility Group provides the Company's regulated utilities 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, 2012, the Company had $5.1 billion in total assets, with $4.0 billion (80 percent) attributed to the Utility Group, and $1.0 billion (20 percent) attributed to the Nonutility Group.  Net income for the year ended December 31, 2012, was $159.0 million, or $1.94 per share of common stock, with net income of $138.0 million attributed to the Utility Group, $21.7 million attributed to the Nonutility Group, and a loss of $0.7 million attributed to Corporate and Other.  Net income for the year ended December 31, 2011, was $141.6 million, or $1.73 per share of common stock.  For further information regarding the activities and assets of operating segments within these Groups, refer to Note 21 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 its 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, 2012, the Company supplied natural gas service to approximately 997,400 Indiana and Ohio customers, including 911,300 residential, 84,400 commercial, and 1,700 industrial and other contract customers.  Average gas utility customers served were approximately 986,100 in 2012, 983,700 in 2011, and 982,100 in 2010.

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 and 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 196.0 MMDth for the year ended December 31, 2012.  Gas sold and transported to residential and commercial customers was 90.2 MMDth representing 46 percent of throughput.  Gas transported or sold to industrial and other contract customers was 105.8 MMDth representing 54 percent of throughput.  Rates for transporting gas generally provide for the same margins earned by selling gas under applicable sales tariffs. In 2012, natural gas began being transported to a natural gas fired power plant that was recently placed into service in the Vectren South service territory. Volumes were 6.3 MMDth in 2012 and are expected to increase in 2013. Volumes delivered to the new plant are based on a monthly fixed charge.

For the year ended December 31, 2012, gas utility revenues were approximately $738.1 million, of which residential customers accounted for 68 percent and commercial 23 percent. Industrial and other contract customers account for 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 three propane 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

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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 March 17, 2011, from the IURC for ProLiance to continue to provide natural gas supply services to the Company’s Indiana utilities and Citizens Energy Group's utilities through March 2016.  

Natural Gas Purchasing Activity in Ohio

On April 30, 2008, the PUCO issued an order which approved the first two phases of a three phase plan to exit the merchant function in the Company's Ohio service territory. As a result, substantially all of the Company's Ohio customers now purchase natural gas directly from retail gas marketers rather than from the Company.

The PUCO provided for an Exit Transition Cost rider, which allows the Company to recover costs associated with the first two phases of 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 as VEDO, for the most part, no longer purchases gas for resale.

Total Natural Gas Purchased Volumes

In 2012, Utility Holdings purchased 61.0 MMDth volumes of gas at an average cost of $4.47 per Dth, of which approximately 97 percent was purchased from ProLiance and 3 percent was purchased from third party providers.  The average cost of gas per Dth purchased for the previous four years was $5.30 in 2011, $5.99 in 2010, $5.97 in 2009, and $9.61 in 2008.

Electric Utility Services

At December 31, 2012, the Company supplied electric service to approximately 142,100 Indiana customers, including approximately 123,600 residential, 18,400 commercial, and 100 industrial and other customers.  Average electric utility customers served were approximately 141,700 in 2012, 141,400 in 2011, and 141,300 in 2010.

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, 2012, retail electricity sales totaled 5,464.8 GWh, resulting in revenues of approximately $553.9 million.  Residential customers accounted for 36 percent of 2012 revenues; commercial 27 percent; industrial 35 percent; and other 2 percent.  In addition, in 2012 the Company sold 336.7 GWh through wholesale activities principally to the MISO.  Wholesale revenues, including transmission-related revenue, totaled $41.0 million in 2012.

System Load

Total load for each of the years 2008 through 2012 at the time of the system summer peak, and the related reserve margin, is presented below in MW.

Date of summer peak load	7/24/2012		7/21/2011		8/4/2010		6/22/2009		7/21/2008
Total load at peak	1,259		1,220		1,275		1,143		1,167
Generating capability	1,298		1,298		1,298		1,295		1,295
Firm purchase supply	136		136		136		136		135
Interruptible contracts & direct load control	60		60		62		62		62
Total power supply capacity	1,494		1,494		1,496		1,493		1,492
Reserve margin at peak	19	%	22	%	17	%	31	%	28	%

The winter peak load for the 2011-2012 season of approximately 895 MW occurred on January 12, 2012.  The prior year winter peak load for the 2010-2011 season was approximately 943 MW, occurring on December 14, 2010.

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Generating Capability

Installed generating capacity as of December 31, 2012, 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 2012 was fueled by coal (97 percent), natural gas (3 percent), and landfill gas (less than 1 percent).  Oil was used only for testing of gas/oil-fired peaking units.  The Company generated approximately 4,998 GWh in 2012.  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 2.1 million tons were purchased for generating electricity during 2012, of which approximately 80 percent was supplied by Vectren Fuels from its mines.  This compares to 2.3 million tons and 2.2 million tons purchased in 2011 and 2010, respectively.  The utility’s coal inventory was approximately 1 million tons at December 31, 2012 and 2011.

Coal Purchases

The average cost of coal per ton purchased for the last five years was $68.65 in 2012, $75.04 in 2011, $70.47 in 2010, $64.28 in 2009, and $42.76 in 2008.  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 that began in 2012 at lower prices.

The Company received an order on January 25, 2012 to allow for the lower prices that began late in 2012 and beyond to be reflected in customer bills beginning in early 2012.  Because the cost of coal expensed in 2012 was 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 179 GWh from OVEC in 2012.

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 2012, the Company purchased approximately 78 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 2012.

MISO Related Activity

The Company is a member of the MISO, a FERC approved regional transmission organization.  The MISO serves the electric 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, where it bids its generation into the Day Ahead and Real Time markets and procures power for its retail customers at Locational Marginal Pricing

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(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 as purchased power in Cost of fuel & purchased power and net sales in a single hour are recorded in Electric utility revenues. During 2012, in hours when purchases from the MISO were in excess of generation sold to the MISO, the net purchases were 632 GWh. During 2012, in hours when sales to the MISO were in excess of purchases from the MISO, the net sales were 322 GWh.

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 expired on December 31, 2012. The Company has not replaced this contract.

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 671 MW during peak load periods.  This interchange capability varies from season to season and has been impacted in recent years as a result of ongoing initiatives to improve the transmission grid throughout the Midwest.  As an example, the 345 kV Vectren transmission project that was placed into service in December 2012 will result in the ability to simultaneously interchange an additional 100 MW.  The Company, as required as a member of the MISO, has turned over operational control of the interchange facilities and its own transmission assets to MISO.

Competition

The utility industry has undergone structural changes 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.  Substantially all of VEDO's customers receive gas from third-party suppliers and at December 31, 2012, approximately 138,000 customers in Vectren’s Ohio service territory select their supplier. In addition, VEDO’s service territory continues transition toward exiting the merchant function.  Margin earned for transporting natural gas to those customers, who have purchased natural gas from another supplier, is generally the same as that 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 pipeline 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, as well as other

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industries.  Infrastructure Services generated approximately $664 million in gross revenues for 2012, compared to $421 million in 2011 and $236 million in 2010.  Revenues in 2012 and 2011 have increased as a result of the acquisition of Minnesota Limited and increased demand for services provided by both Miller and Minnesota Limited.

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.  ESG’s customer base is located throughout the Midwest, Mid-Atlantic, Southern and Southwestern United States.  ESG generated revenues of approximately $118 million in 2012, compared to $162 million in 2011 and $147 million in 2010.  ESG’s backlog at December 31, 2012 was $77 million, compared to $82 million at December 31, 2011.

Coal Mining

The Coal Mining group owns coal mines and sells coal to the Company’s utility operations and to other third parties through its wholly owned subsidiary, Vectren Fuels, Inc.  The Company owns three underground mines (Prosperity, Oaktown 1, and Oaktown 2) and one reclaimed 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 operate the coal mines.  Coal mining generated approximately $236 million in revenues in 2012, compared to $286 million in 2011 and $210 million in 2010.

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 development of the second mine was substantially completed in 2012 but is not expected to begin production until demand for its coal increases. Reserves at the two mines are estimated at about 100 million tons of recoverable number-five coal at 11,200 BTU and less than 6-pound sulfur dioxide.  Once in full production, the two mines are capable of producing about 5 million tons of coal per year. 

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.  It is estimated approximately 25,000 acres of coal will be mined during the life of both mines.  Through December 31, 2012, approximately 1,425 acres of coal have been mined with approximately 23,575 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 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 $271 million, inclusive of advance royalty payments.  The remaining unamortized plant balance as of December 31, 2012 approximates $221 million, inclusive of $44 million in land and buildings, $174 million in mine development and equipment, and $3 million in advance royalty payments.  Reserves, absent expansion, are expected to be completely exhausted over the next 20 years.

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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 the Company's power supply operations and other third party utilities.  The mine opened in 2001, and the total plant and development costs to date are $200 million.  Through December 31, 2012, approximately 7,500 acres of coal have been mined with approximately 12,500 acres remaining. Reserves at December 31, 2012 approximate 28 million tons, not including possible nearby expansion opportunities.  The remaining unamortized plant balance as of December 31, 2012 approximates $77 million, inclusive of $7 million of land and buildings and $70 million of mine development and equipment.  Reserves, absent expansion, are expected to be exhausted by 2025.

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.  The mine opened in 1998 and as of December 31, 2012, no significant reserves remain, the mine is substantially reclaimed, and the remaining carrying amount is not significant.

Following is summarized data regarding coal mining operations:

	Prosperity	Oaktown Mine 1	Oaktown Mine 2	Cypress Creek	Totals
Type of Mining	Underground	Underground	Underground	Surface
Mining Technology	Room & Pillar	Room & Pillar	Room & Pillar	Truck & Shovel
Tons Mined (in thousands)
2012	2,072	2,755	—	—	4,827
2011	2,457	2,668	—	—	5,125
2010	2,685	995	—	91	3,771
County Located in Indiana	Pike	Knox	Knox	Warrick
Coal Reserves (thousands of tons)	28,343	60,109	38,795	—	127,247
Average Heat Content (BTU/lb.)	11,300	11,100	11,300	10,500
Average Sulfur Content (lbs./ton)	4.0	5.6	4.8	8.0

Mine Safety Information

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.  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, 2012, the Company paid approximately $0.7 million related to assessments issued to the mine operators.

On April 30, 2012, Five Star received a citation referred to as an “imminent danger” citation for high levels of methane near one of the roof bolting machines operating in the Prosperity Mine.  The machine was idled for approximately two hours while the

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methane levels were lowered by adjusting airflow near the equipment.  Other mining operations continued during this period.  No injuries or property damage resulted from the incident.

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; and Oaktown 2’s identification number is 1202418.  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 incidents at coal mines of other companies, a significant increase in the frequency and scope of MSHA inspections continues.  The MSHA recently proposed new regulations related to the level of allowable respirable dust and the utilization of proximity detection devices.  In addition, MSHA no longer has to wait for final orders of citations before placing a mine on a “pattern of violation” status, and the initial step of notifying mine operators and giving them time to reduce instances of violations has been eliminated.

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 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 contracted for approximately 97 percent of its natural gas purchases through ProLiance in 2012.

For the year ended December 31, 2012, ProLiance’s revenues, including sales to Vectren companies, were $1.0 billion, compared to $1.4 billion in 2011 and $1.5 billion in 2010.  Summarized financial data regarding ProLiance’s operations are included in Note 7 to the Consolidated Financial Statements included in Item 8.  At December 31, 2012, the ProLiance customer base was 2,012 customers, compared to 1,950 customers in 2011 and 1,789 customers in 2010.

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. On December 31, 2011, the Company sold Vectren Source for $84.3 million, excluding minor working capital adjustments. Gas sold by Vectren Source approximated 25.3 MMDth in 2011 and 21.0 MMDth in 2010.  Average customers served by Vectren Source were 254,000 in 2011 and 203,000 in 2010.  Vectren Source generated approximately $150 million in revenues for 2011, compared to $143 million in 2010.  

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 a leveraged lease, among other investments.  Investments at December 31, 2012, include two Haddington Energy Partnerships both approximately 40 percent owned; and wholly owned subsidiaries, Southern Indiana Properties, Inc. and Energy Realty, Inc.

Personnel

As of December 31, 2012, the Company and its consolidated subsidiaries had approximately 5,400 employees.  Of those employees, 700 are subject to collective bargaining arrangements negotiated by Utility Holdings and 3,000 are subject to collective bargaining arrangements negotiated by Infrastructure Services. The 20 percent increase in total employees, compared to the prior year, is attributable to the overall growth of Infrastructure Services.

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Utility Holdings

In December 2012, 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, 2012 and ends October 31, 2015. This labor agreement relates to employees of VEDO.

In September 2012, the Company reached a three year agreement with Local 135 of the Teamsters, Chauffeurs, Warehousemen, and Helpers Union, ending September 23, 2015. This labor agreement relates to employees of SIGECO.

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. This labor agreement relates to employees of Indiana Gas.

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. This labor agreement relates to employees of SIGECO.

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 in 2015 and 2016. The trade agreements through the PLCA expire at various times in 2014. 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.

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, production cutbacks, 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

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impact on utility industry spending for construction projects, demand for natural gas, electricity, 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 affiliate, ProLiance, will not experience adverse effects, which may be material.  These effects may include, but are not limited to, difficulties in accessing the short and long-term debt capital markets and the commercial paper market, increased borrowing costs associated with current short-term debt obligations, higher interest rates in future financings, and a smaller potential pool of investors and funding sources.  Finally, there is no assurance the Company will have access to the equity capital markets to obtain financing when necessary or desirable.

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

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

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

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

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

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 and steel finishing; aluminum smelting and recycling; 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,

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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.  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 of a normal temperature adjustment mechanism.  Additionally, the implementation of a straight fixed variable rate design mitigates most weather variations 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 generation, 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, the IURC, PUCO, and FERC 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 that may intervene in regulatory proceedings and affect regulatory outcomes.

Trends Toward Stricter Standards

With the trend toward stricter standards, greater regulation, more extensive permit requirements and an increase in the number and types of assets operated that are subject to regulation, the Company's investment in 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 considering revisions to regulations involving fly ash disposal, cooling tower intake facilities, waste water discharges, and greenhouse gases and continues to implement increasingly more stringent air quality standards.  

Pipeline Safety Considerations

Vectren monitors and maintains its natural gas distribution system to ensure that natural gas is delivered in a safe, efficient manner. Vectren's natural gas utilities are currently engaged in replacement programs in both Indiana and Ohio, the primary purpose of which is preventive maintenance and continual renewal and improvement.  The Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 (Pipeline Safety Law) was signed into law on January 3, 2012 and Vectren continues to study the impact of the Pipeline Safety Law and potential new regulations associated with its implementation.  While compliance costs remain uncertain, the Pipeline Safety Law is expected to result in further investment in pipeline inspections, and where necessary, additional investments in pipeline infrastructure; and therefore, result in both increased levels of operating expenses and capital expenditures associated with the Company's natural gas distribution businesses. 

Environmental Considerations

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 the storage, transportation, treatment, and disposal of hazardous substances and limit airborne emissions from electric generating facilities including particulate matter, sulfur dioxide (SO₂), nitrogen oxide (NOx), and mercury, among others.  Environmental legislation/regulation also requires that facilities, sites, and other properties associated

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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.  

Climate Change and Renewable Energy Considerations

While there have been a series of legislative 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, none have been finalized to date.  The US Supreme Court has determined that the EPA has the authority to regulate greenhouse gases as a pollutant under the Clean Air Act.  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.  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.  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. 

Increasing regulation and infrastructure replacement programs 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 and other infrastructure replacement activities 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.

Vectren's utilities' ability to obtain rate increases and to maintain current authorized rates of return depends in part 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, and in Ohio other capital investments, outside of a base rate proceeding. However, these activities may have at least a short-term adverse impact on the Company's cash flow and financial condition.

In addition, failure to comply with new laws and regulations may result in fines, penalties, or injunctive measures and may not be recoverable from customers and could result in a material adverse effect on the Company's financial condition and results of operations. 

Vectren's 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 injury to or 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’s regulated 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 electric 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 per year 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.

Volatility 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 volatility 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 increased 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 or regulations 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 infrastructure services operations could be adversely affected by a number of factors.

Infrastructure Services results are dependent on a number of factors.  The industry is competitive and many of the contracts are subject to a bidding process.  Should Infrastructure Services be unsuccessful in bidding contracts, results of operations could be impacted.  Infrastructure services enters into a variety of contracts, some of which are fixed price.  Through competitive bidding, the volume of contracted work could vary significantly from year to year. Further, to the extent there are unanticipated cost increases in completion of the contracted work, the profit margin realized on any single project could be reduced.  Additionally, Infrastructure Services contributes to several multi-employer pension plans under collective bargaining agreements with unions representing employees covered by those agreements.  A significant increase to the funding requirements could adversely impact financial condition, results of operations, and/or cash flows.  Changes in legislation and regulations impacting the industries in which the customers served by Infrastructure Services operate could impact operating results.  Other risks include, but are not limited to:  the effects of weather; failure to properly estimate the cost to construct projects; the ability to attract and retain qualified employees; cancellation of projects by customers and/or reductions in the scope of the projects; credit worthiness of customers; ability to obtain materials and equipment required to perform services from suppliers and manufacturers; and changing market conditions. 

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 be implemented 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 the Company's coal including impacts of fuel switching to alternative sources and coal specifications in terms of sulfur and mercury, among others; 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.

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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.

ProLiance relies on short-term borrowings and trade credit to meet its cash flow needs. ProLiance has borrowing capacity through a syndicated credit facility. The current facility expires in May 2014. Should ProLiance be unsuccessful in maintaining short-term borrowing capacity and trade credit in the future, ProLiance's results of operations and financial condition could be adversely impacted.

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 commodity derivative instruments in conjunction with energy marketing and procurement activities.  The Company may also periodically use interest rate derivative instruments to minimize the impact of interest rate fluctuations associated with anticipated debt issuances.

Regulations related to the use of derivatives that became law in 2010 under the Dodd-Frank Wall Street Reform and Consumer Protection Act continue to evolve and their ultimate application remains uncertain. Depending on the regulations adopted by the Commodities Futures Trading Commission (CFTC) and other agencies, the Company and ProLiance may be required to post additional collateral with dealer counterparties for commitments and interest rate, physical or financial commodity derivative transactions and report or otherwise disclose such activity to dealer counterparties or other agencies. The law provides for an

17

exception from these clearing and cash collateral requirements for commercial end-users. 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 regulations may also limit the pool of potential counterparties and/or the liquidity in the respective markets for such transactions.

Significant rule-making by numerous governmental agencies, particularly the CFTC, continues to evolve and has been subject to a number of extensions and delays. The Company and ProLiance continue to evaluate the impacts as these rulemakings and interpretations become available and whether these rulemakings and interpretations affirm that exemptions apply to the Company’s and ProLiance’s use of derivative instruments.

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

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

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

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

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, corporate reputation, 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.

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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 perday.  Indiana Gas also owns and operates three propane 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 12.5 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 13,100 miles of distribution and transmission mains, all of which are in Indiana except for pipeline facilities extending from points in northern Kentucky to points in southern Indiana so that gas may be transported to Indiana and sold or transported by Indiana Gas to ultimate customers in Indiana.

SIGECO owns and operates three active underground gas storage fields located in Indiana covering 6,100 acres of land with an estimated ready delivery from storage capability of 6.3 BCF of gas with maximum peak day delivery capabilities of 108,500 MCF per day.  In addition to its company owned storage delivery capabilities, SIGECO has contracted with ProLiance for 0.4 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.

During 2012, VEDO retired three propane plants, all of which were located in Ohio.  The plants were capable of storing 0.5 million gallons of propane, and the plants could manufacture for delivery 52,200 MCF of manufactured gas per day.  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, 2012, 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 1,014 circuit miles of 345Kv, 138Kv and 69Kv lines.  The transmission system also includes 37 substations with an installed capacity of 4,863 megavolt amperes (Mva).  The electric distribution system includes 4,301 pole miles of lower voltage overhead lines and 381 trench miles of conduit containing 2,098 miles of underground

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distribution cable.  The distribution system also includes 96 distribution substations with an installed capacity of 2,990 Mva and 54,000 distribution transformers with an installed capacity of 2,363 Mva.

SIGECO owns utility property outside of Indiana approximating 24 miles of 138Kv and 345Kv electric transmission lines, which are included in the 1,014 circuit miles discussed above, located in Kentucky and which interconnects with Louisville Gas and Electric Company's transmission system at Cloverport, Kentucky and with Big Rivers Electric Cooperative at Sebree, Kentucky.

Nonutility Properties

Subsidiaries other than the utility operations have no significant properties other than the ownership 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.”

ITEM 4.  MINE SAFETY DISCLOSURES

Not Applicable.

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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 2012 and 2011, 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
2012
	First Quarter	$0.350	$30.69	$28.21
	Second Quarter	0.350	30.17	28.03
	Third Quarter	0.350	30.75	27.78
	Fourth Quarter	0.355	30.25	27.46
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

On January 31, 2013 the board of directors declared a dividend of $0.355 per share, payable on March 1, 2013, to common shareholders of record on February 15, 2013.

As of January 31, 2013, there were 8,860 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; however, no such open market purchases were made during the quarter ended December 31, 2012.

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 53 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.

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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)	2012		2011		2010		2009		2008
Operating Data:
Operating revenues	$	2,232.8	$	2,325.2	$	2,129.5	$	2,088.9	$	2,484.7
Operating income	$	352.5	$	370.0	$	316.8	$	280.1	$	263.4
Net income	$	159.0	$	141.6	$	133.7	$	133.1	$	129.0
Average common shares outstanding	82.0		81.8		81.2		80.7		78.3
Fully diluted common shares outstanding	82.1		81.8		81.3		81.0		78.7
Basic earnings per share
on common stock	$	1.94	$	1.73	$	1.65	$	1.65	$	1.65
Diluted earnings per share
on common stock	$	1.94	$	1.73	$	1.64	$	1.64	$	1.63
Dividends per share on common stock	$	1.405	$	1.385	$	1.365	$	1.345	$	1.310
Balance Sheet Data:
Total assets	$	5,089.1	$	4,878.9	$	4,764.2	$	4,671.8	$	4,632.9
Long-term debt, net	$	1,553.4	$	1,559.6	$	1,435.2	$	1,540.5	$	1,247.9
Common shareholders' equity	$	1,526.1	$	1,465.5	$	1,438.9	$	1,397.2	$	1,351.6

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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, 2012, 2011, and 2010 follow:

	Year Ended December 31,
(In millions, except per share data)	2012			2011			2010
Net income	$	159.0		$	141.6		$	133.7
Attributed to:
Utility Group	$	138.0		$	122.9		$	123.9
Nonutility Group	21.7			23.8			9.8
Corporate & Other	(0.7		)	(5.1		)	—
Basic earnings per share	$	1.94		$	1.73		$	1.65
Attributed to:
Utility Group	$	1.68		$	1.50		$	1.53
Nonutility Group	0.26			0.29			0.12
Corporate & Other	—			(0.06		)	—

Utility Group

Gas utility services

The gas utility segment earned $60.0 million during the year ended December 31, 2012, compared to earnings of $52.5 million in 2011 and $53.7 million in 2010. The increased earnings in 2012 reflect revenues and the deferral for future recovery of some operating expenses from regulatory orders allowing for recovery of and accounting for infrastructure replacement activities in Ohio. Year-over-year, interest expense was also favorably impacted by financing transactions completed in late 2011 and early 2012. 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 earnings compared to 2010.

Electric utility services

The electric operations earned $68.0 million during 2012, compared to $65.0 million in 2011 and $60.9 million in 2010. Results in 2012 and 2011 were positively impacted by new electric base rates implemented on May 3, 2011. In addition, lower interest costs associated with refinancing activity favorably impacted results in 2012. These increased results in 2012 were somewhat offset by lower small customer margin from conservation initiatives net of lost margin recovery. The increased earnings in 2011 driven by the base rate increase, compared to 2010, were offset somewhat by summer weather that, while warmer than normal,

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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.  

Other utility operations

In 2012, earnings from other utility operations were $10.0 million, compared to $5.4 million in 2011 and $9.3 million in 2010.  Differences in the Utility Group's effective tax rate among the periods presented resulted in the lower earnings in 2011. The higher income tax rate in 2011 was driven by the revaluation of Utility Group deferred income taxes related to the fourth quarter 2011 sale of Vectren Source, a nonutility retail energy marketer, which resulted in a charge to Utility Group income taxes of approximately $2.8 million. 2011 also includes a $1.4 million unfavorable tax adjustment.

Nonutility Group

In 2012, Nonutility Group earnings were $21.7 million, compared to earnings of $23.8 million in 2011 and $9.8 million in 2010. Results over these periods were favorably impacted by the March 31, 2011 acquisition of Minnesota Limited and significantly higher demand for pipeline construction and repair. Weakness in coal prices in 2012 and lower natural gas prices over the last several years have negatively impacted results from the Company's commodity driven coal and wholesale gas marketing operations. However, losses incurred by energy marketer, ProLiance, narrowed in 2012 compared to 2011, due primarily to lower demand costs for pipeline storage and transportation. Nonutility Group results were impacted by a gain on the sale of retail natural gas marketer, Vectren Source, on December 31, 2011, totaling $15.2 million after tax. After tax charges related to legacy investments totaled $2.2 million, $9.2 million, and $6.9 million in 2012, 2011, and 2010, respectively.

Corporate & Other

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

Dividends

Dividends declared for the year ended December 31, 2012 were $1.405 per share, compared to $1.385 per share in 2011 and $1.365 per share in 2010.  In November 2012, the Company’s board of directors increased its quarterly dividend to $0.355 per share from $0.350 per share.  The increase marks the 53^rd 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.

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Detailed Discussion of Results of Operations

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

Results of Operations of the Utility Group

The Utility Group is comprised of Utility Holdings’ operations and consists of the Company’s regulated operations and other operations that provide information technology and other support services to those regulated operations.  Regulated operations consist of a natural gas distribution business that provides natural gas distribution and transportation services to nearly two-thirds of Indiana and to west central Ohio and an electric transmission and distribution business, which provides electric distribution services primarily to southwestern Indiana, and its 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, 2012, 2011, and 2010, follow:

	Year Ended December 31,
(In millions, except per share data)	2012		2011		2010
OPERATING REVENUES
Gas utility	$	738.1	$	819.1	$	954.1
Electric utility	594.9		635.9		608.0
Other	0.6		2.0		1.6
Total operating revenues	1,333.6		1,457.0		1,563.7
OPERATING EXPENSES
Cost of gas sold	301.3		375.4		504.7
Cost of fuel & purchased power	192.0		240.4		235.0
Other operating	310.1		313.1		299.2
Depreciation & amortization	190.0		192.3		188.2
Taxes other than income taxes	53.4		54.0		59.6
Total operating expenses	1,046.8		1,175.2		1,286.7
OPERATING INCOME	286.8		281.8		277.0
Other income - net	8.0		4.3		5.4
Interest expense	71.5		80.3		81.4
INCOME BEFORE INCOME TAXES	223.3		205.8		201.0
Income taxes	85.3		82.9		77.1
NET INCOME	$	138.0	$	122.9	$	123.9
CONTRIBUTION TO VECTREN BASIC EPS	$	1.68	$	1.50	$	1.53

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 six 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 with implementation in February 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 that have been authorized by these state commissions.  Outside of a full base rate proceeding, these approaches mitigate to some extent the impacts of investments in government-mandated and other infrastructure replacement projects, operating costs that are volatile, and changing consumption patterns.  In addition to timely gas and fuel cost recovery,

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approximately $36 million of the Utility Group’s approximate $310 million in Other operating expenses incurred during 2012 are subject to recovery mechanisms outside of base rates.  

Rate Design Strategies

Sales of natural gas and electricity to residential and commercial customers are largely 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 decoupling 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 for its residential customers.  This rate design, which was fully implemented in February 2010, mitigates approximately 90 percent 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 decoupling 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 actual experience, subject to caps that are 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. Since April 2010, the Company has not been the supplier of natural gas in its Ohio territory.

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.  The FAC earnings test had some impact on the Company’s 2012 operating results, as discussed below.  

In Indiana, gas pipeline integrity management operating 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 regional electric transmission assets not in base rates are also recovered by mechanisms outside of standard base rate recovery.  In Ohio, expenses such as uncollectible accounts expense, costs associated with exiting the merchant function, and costs associated with a distribution riser 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.

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 capital investment projects, outside of a base rate proceeding.  Utilization of these mechanisms will likely increase in the coming years.

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.

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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 earnings 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.

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)	2012		2011		2010
Gas utility revenues	$	738.1	$	819.1	$	954.1
Cost of gas sold	301.3		375.4		504.7
Total gas utility margin	$	436.8	$	443.7	$	449.4
Margin attributed to:
Residential & commercial customers	$	369.5	$	375.2	$	384.7
Industrial customers	56.7		56.4		52.2
Other	10.6		12.1		12.5
Sold & transported volumes in MMDth attributed to:
Residential & commercial customers	90.2		99.9		106.2
Industrial customers	105.8		97.0		90.8
Total sold & transported volumes	196.0		196.9		197.0

Gas utility margins were $436.8 million for year ended December 31, 2012, and compared to 2011, decreased $6.9 million.  The impact of low natural gas prices and mild weather on revenue taxes, late and reconnect fees, and volumetric pass through costs decreased gas utility margin $10.9 million in 2012 compared to 2011.  Returns generated on investments in infrastructure replacement in Ohio increased margins $2.9 million in 2012 compared to the prior year. Excluding the impact of regulatory initiatives and pass through costs, large customer margins increased $1.0 million on increasing volumes. With rate designs that substantially limit the impact of weather on margin, heating temperatures in 2012 that were 79 percent of normal in Indiana and 88 percent of normal in Ohio had a significant impact on small volumes sold, but only a slightly negative impact on margin, reducing margin $0.6 million year over year. Large customer volumes in 2012 compared to 2011 significantly increased due to natural gas transported to a natural gas fired power plant that was recently placed into service in the Vectren South service territory. Volumes delivered to this customer are based on a monthly fixed charge and began in 2010 when service was initiated.

For the year ended December 31, 2011, gas utility margins decreased $5.7 million compared to 2010.  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 infrastructure replacement in Ohio increased margins $2.2 million year over year.  Large customer margin, net of the impacts of regulatory initiatives and pass through costs, increased by $3.8 million due primarily to ethanol producers.

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.  Since the straight fixed variable rate design was fully implemented for residential base rates in February 2010, nearly 90 percent of the combined residential and commercial base rate gas margins were recovered through the customer service charge since that date.  Margin recognized in 2011 reflects the full implementation of the rate design which resulted in a decrease in margin in 2011 compared to 2010. In 2010, there was volumetric recovery during the peak delivery periods of January and February.

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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)	2012		2011		2010
Electric utility revenues	$	594.9	$	635.9	$	608.0
Cost of fuel & purchased power	192.0		240.4		235.0
Total electric utility margin	$	402.9	$	395.5	$	373.0
Margin attributed to:
Residential & commercial customers	$	258.5	$	255.8	$	241.2
Industrial customers	103.4		101.6		97.1
Municipals & other customers	8.9		8.5		8.5
Subtotal: Retail	$	370.8	$	365.9	$	346.8
Wholesale margin	32.1		29.6		26.2
Total electric utility margin	$	402.9	$	395.5	$	373.0
Electric volumes sold in GWh attributed to:
Residential & commercial customers	2,731.7		2,827.2		2,964.0
Industrial customers	2,710.5		2,744.8		2,630.3
Municipals & other	22.6		22.8		22.6
Total retail & firm wholesale volumes sold	5,464.8		5,594.8		5,616.9

Retail

Electric retail utility margins were $370.8 million for the year ended December 31, 2012 and, compared to 2011, increased by $4.9 million.  The impact year over year of new retail base rates that were effective May 3, 2011 was an increase in margin of approximately $10.0 million.  Offsetting a portion of the increase was a decline in small customer usage that lowered margin by $2.6 million in 2012 as a result of energy conservation, net of an approved lost margin recovery mechanism.  Weather also impacted margin and, compared to normal temperatures, increased results $2.7 million and $3.0 million, in 2012 and 2011, respectively.  Due in part to the favorable weather in both periods, the Company provided refunds to customers in 2012 totaling $2.6 million pursuant to the statutory earnings test.  Indiana regulation includes a statutory mechanism that can limit a utility's rolling twelve month net operating income to that authorized in its last general rate order, as adjusted for previous net operating income levels that were below authorized levels.  Should weather or other factors continue to increase net operating income in future periods, the full benefit of those favorable impacts on the Company's electric utility may continue to be limited by the statutory earnings test. Finally, though volumes sold to large customers during 2012 decreased, the impact on margin was small as certain large customers have rate structures that include both a daily peak usage component, as well as a volumetric component. 

In 2011, electric retail utility margins increased $19.1 million compared to 2010.  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 recovered in margin.  In 2010, management estimates that cooling weather 134 percent of normal increased margin compared to normal by $10.4 million.

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Margin from Wholesale Electric Activities

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 and also markets and sells its generating and transmission capacity to optimize the return on its owned assets.  Substantially all off-system sales are generated in the MISO Day Ahead and Real Time markets when sales into the MISO in a given hour are greater than amounts purchased for native load.  Further detail of MISO off-system margin and transmission system margin follows:

	Year Ended December 31,
(In millions)	2012		2011		2010
Transmission system margin	$	26.4	$	23.5	$	18.8
Off-system margin	5.7		6.1		7.4
Total wholesale margin	$	32.1	$	29.6	$	26.2

Transmission system margin associated with qualifying projects, including the reconciliation of recovery mechanisms, and other transmission system operations, totaled $26.4 million during 2012, compared to $23.5 million in 2011 and $18.8 million in 2010.  Increases are primarily due to increased investment in qualifying projects. To date, the Company has invested $155 million in qualifying projects. These projects include an interstate 345 Kv transmission line that connects Vectren’s A.B. Brown Generating Station to a generating station in Indiana owned by Duke Energy to the north and to a generating station in Kentucky owned by Big Rivers Electric Corporation to the south; a substation; and another transmission line. Once placed into service, these projects earn a FERC approved equity rate of return of 12.38 percent on the net plant balance, and operating expenses are also recovered. The 345 Kv project is the largest of these qualifying projects, with a cost of $107 million that earned the FERC approved equity rate of return while under construction. The last segment of that project was placed into service in December 2012.

For the year ended December 31, 2012, margin from off-system sales was $5.7 million, compared to $6.1 million in 2011 and $7.4 million in 2010.  The base rate changes implemented in May 2011 require that wholesale margin from off-system sales earned above or below $7.5 million per year 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 336.7 GWh in 2012, compared to 586.7 GWh in 2011, and 587.6 GWh in 2010. The lower volumes sold in 2012 from Vectren South's primarily coal-fired generation result from increased sales of power in MISO from gas-fired electric generation due to low natural gas prices and more wind generation.

Utility Group Operating Expenses

Other Operating

For the year ended December 31, 2012, Other operating expenses were $310.1 million, and compared to 2011, decreased $3.0 million.  Excluding pass through costs, expenses were essentially flat. Continuous improvement initiatives throughout the Utility Group are being implemented to limit growth in operating expenses over the coming years. The Company estimates that in 2012 these initiatives have resulted in sustainable savings of more than $7 million. Examples of the initiatives implemented in 2012 include improved processes that have allowed the Company to become more efficient in completing work and thereby reduce labor costs and recent amendments to postretirement medical plans that provide better access to benefits for retirees at lower costs to the Company.  These sustainable savings have aided in offsetting planned increases in energy delivery related operating expenses. 

For the year ended December 31, 2011, Other operating expenses increased $13.9 million compared to 2010.  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 expected energy delivery costs.

Depreciation & Amortization

For the year ended December 31, 2012, depreciation and amortization expense was $190.0 million, compared to $192.3 million in 2011 and $188.2 million in 2010. The periods presented reflect increased utility plant investments placed into service.

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However, in 2012 regulatory orders allowing for deferral of depreciation on capital investments previously placed into service were received that more than offset the impact of utility plant increases in 2012 and partially offset increases in 2011.

Taxes Other Than Income Taxes

Taxes other than income taxes decreased $0.6 million in 2012 compared to 2011 and decreased $5.6 million in 2011 compared to 2010. The decrease in 2012 was primarily due to lower usage taxes associated with lower gas and fuel costs. The decrease in 2011 is primarily attributable to lower Ohio excise and usage taxes associated with that territory’s process of exiting the merchant function.  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 $8.0 million in 2012, compared to $4.3 million in 2011 and $5.4 million in 2010. Results in 2012 include approximately $2.2 million of increased AFUDC compared to 2011. AFUDC in 2012 reflects the impact of recent regulatory orders related to the infrastructure replacement investments. In addition, results in 2012 and in 2010 reflect increased returns on assets that fund benefit plans compared to 2011.  

Interest Expense

For year ended December 31, 2012, interest expense was $71.5 million, compared to $80.3 million in 2011 and $81.4 million in 2010. The decreases among the years are 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 of 2011, 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.

Income Taxes

In 2012, Utility Group federal and state income taxes were $85.3 million, compared to $82.9 million in 2011 and $77.1 million in 2010.  Changes in income taxes are primarily driven by changes in pre-tax income. In addition, the effective income tax rate in 2011 was higher primarily due to the revaluation of Utility Group deferred income taxes from the fourth quarter sale of Vectren Source which resulted in a $2.8 million charge, and a $1.4 million unfavorable tax adjustment recognized earlier in that year.

Rate & Regulatory Matters

Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement

Vectren monitors and maintains its natural gas distribution system to ensure that natural gas is delivered in a safe and efficient manner. Vectren's natural gas utilities are currently engaged in replacement programs in both Indiana and Ohio, the primary purpose of which is preventive maintenance and continual renewal and operational improvement.  In 2011, 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 capital investment projects, outside of a base rate proceeding.  Utilization of these recovery mechanisms is discussed below.

Ohio Recovery and Deferral Mechanisms

The PUCO order approving the Company's 2009 base rate case in the Ohio service territory authorized a distribution replacement rider (DRR). The DRR's primary purpose is recovery of investments in utility plant and related operating expenses associated with replacing bare steel and cast iron pipelines and certain other infrastructure. This rider is updated annually for qualifying capital expenditures and allows for a return to be earned on those capital expenditures based upon the rate of return approved in the 2009 base rate case. In addition, deferral of depreciation and the ability to accrue debt-related post in service carrying costs is also allowed until the related capital expenditures are recovered through the DRR. To date, the Company has made capital investments under this rider totaling $80 million. During 2012, 2011, and 2010 gas operating revenues associated with the DRR were $6.5 million, $3.6 million, and $1.4 million, respectively. Other Income associated with the debt-related post in service carrying costs totaled $1.8 million, $2.0 million, and $0.9 million for 2012, 2011, and 2010, respectively. Regulatory assets associated with post in service carrying costs and depreciation deferrals were $6.5 million, $3.0 million, and $1.0 million at December 31, 2012, 2011, and 2010, respectively.

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In June 2011, Ohio House Bill 95 was signed into law. Outside of a base rate proceeding, this legislation permits a natural gas company to apply for recovery of much of its capital expenditure program. Once such application is approved, the legislation authorizes a deferral of costs, such as depreciation, property taxes, and debt-related carrying costs. On December 12, 2012, the PUCO issued an order approving the Company's initial application using this law. The order provides for the deferral of depreciation, debt-related post in service carrying costs, and property taxes for its $23.5 million capital expenditure program covering the fifteen month period ending December 31, 2012. Such capital expenditures include infrastructure expansion and improvements not covered by the DRR as well as expenditures necessary to comply with PUCO rules, regulations, orders, and system expansion to some new customers. The order also established a prospective bill impact evaluation on the cumulative deferrals, limiting the total deferrals at a level which would equal $1.50 per residential and general service customer per month. The order created a regulatory asset as of December 31, 2012 of $1.5 million, of which $0.9 million is Other Income related to the accrual of post in service carrying costs, and the remaining $0.6 million is the deferral of depreciation and property tax expense. The Company expects to make a future request for similar accounting authority on its capital expenditure program for the calendar year 2013.

Based on the deferral of costs and continuing recognition of debt-related post in service carrying costs using the 2009 capital structure, Regulatory assets associated with these infrastructure programs increased $5.0 million in 2012. Regulatory assets are expected to continue to increase in future periods as post in service carrying costs are recognized in the statement of income and operating costs are deferred. Historical relationships between rate base growth and depreciation expense and property taxes will also be impacted.

Indiana Recovery and Deferral Mechanisms

The Company's Indiana natural gas utilities received orders in 2008 and 2007 associated with the most recent base rate cases. These orders authorized the deferral of financial impacts associated with bare steel and cast iron replacement activities. The orders provide for the deferral of depreciation and post in service carrying costs on qualifying projects totaling $20 million annually at Vectren North and $3 million annually at Vectren South. For USGAAP accounting purposes only the debt-related post in service carrying costs are recognized in the Consolidated Statements of Income currently. Such deferral is limited by individual qualifying project to three years after being placed into service at Vectren South and four years after being placed into service at Vectren North. The debt-related post in service rate used to calculate the deferral is based on a current cost of funds. At December 31, 2012 and 2011, the Company has USGAAP regulatory assets totaling $8.5 million and $4.7 million, respectively, associated with the deferral of depreciation and debt-related post in service carrying cost activities.

In April 2011, Senate Bill 251 was signed into Indiana law. The law 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 a return on the federally mandated capital investment, along with recovery of depreciation and other operating costs associated with these mandates. The remaining 20 percent of those costs are to be deferred for future recovery in the utility's next general rate case. To date, the Company has not initiated a filing requesting authority to recover costs using the Senate Bill 251 approach and continues to study its applicability to expenditures associated with its natural gas distribution operations.

Pipeline Safety Law

On January 3, 2012, the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 (Pipeline Safety Law) was signed into law. The Pipeline Safety 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 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 over the next two years Those regulations may eventually lead to further regulatory or statutory requirements.

The Company continues to study the impact of the Pipeline Safety 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 law is expected to result in further investment in pipeline inspections, and where necessary, additional investments in 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

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expanded compliance requirements may grow by approximately $9 million annually, with $6 million attributable to the Indiana operations. Related to the Indiana operations, the Company expects to seek recovery under Senate Bill 251, or such costs may be recoverable through current tracking mechanisms. Capital investments, associated with the Pipeline Safety Law, are expected to be significant. 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 or other currently authorized recovery mechanisms, such as the Distribution Replacement Rider, in Ohio.

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 provided for a 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, provided for deferred accounting treatment related to the Company's estimated $32 million investment in dense pack technology, of which approximately $25.5 million has been invested as of December 31, 2012. In addition, the IURC 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 (RFP) in April 2011 regarding coal purchases for a four year period beginning in 2012. After negotiations with bidders, Vectren South 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 2011 RFP.  In March 2012, the IURC issued its order in the sub docket which concluded that Vectren South’s 2011 RFP process resulted in the lowest fuel cost reasonably possible.  In late 2012, Vectren South terminated its contract with one of the suppliers due to coal quality issues that were identified during test burns of the coal. In addition to coal purchased under these contracts, Vectren South has also contracted with Vectren Fuels, Inc. to purchase lower priced spot coal. This spot purchase was found to be reasonable in a recent FAC order. The IURC will continue to regularly monitor Vectren South’s procurement process in future fuel adjustment proceedings.

Delivery to Vectren's power plants of lower-priced contract coal from the April 2011 RFP process began during 2012. On December 5, 2011 within the quarterly FAC filing, Vectren South submitted a joint proposal with the OUCC to reduce its fuel costs billed to customers by accelerating into 2012 the impact of lower cost coal under these new term contracts effective after 2012. The cost difference will be deferred to a regulatory asset and recovered over a six-year period without interest beginning in 2014.  The IURC approved this proposal on January 25, 2012, with the reduction to customer’s rates effective February 1, 2012.  The deferred amount includes a reduction in the value of the coal inventory at December 31, 2011 of approximately $17.7 million to reflect existing coal inventory at the new, lower price.  Deferrals related to coal purchases in 2012 have totaled approximately $24.7 million, bringing the total deferred balance as of December 31, 2012, to the expected level of $42.4 million.

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 were 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.

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On August 31, 2011 the IURC issued an order approving an initial three year DSM plan in the Vectren South service territory that complied 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 $3 million in 2012 and $1 million in 2011 associated with small customer DSM programs for subsequent recovery under a tracking mechanism to be proposed by the Company.  On June 20, 2012, the IURC issued an order approving a small customer lost margin recovery mechanism, inclusive of all previous deferrals. This mechanism is an alternative to the electric decoupling proposal that was denied by the IURC in the Company's last base rate proceeding discussed earlier. 

Vectren North Pipeline Safety Investigation

On April 11, 2012, the IURC's pipeline safety division filed a complaint against Vectren North alleging several violations of safety regulations pertaining to damage that occurred at a residence in Vectren North's service territory during a pipeline replacement project. The Company negotiated a settlement with the IURC's pipeline safety division, agreeing to a fine and several modifications to the Company's operating policies. The amount of the fine was not material to the Company's financial results. The IURC approved the settlement but modified certain terms of the settlement and added a requirement that Company employees conduct inspections of pipeline excavations. The Company sought and was granted a request for rehearing on the sole issue related to the requirement to use Company employees to inspect excavations. The Company seeks further clarity on the scope of the requirement and the ability to also use contractors to perform certain inspections. A procedural schedule is expected to be established in late February 2013.

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 for residential base rates 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.

VEDO Continues the Process to Exit the Merchant Function

On April 30, 2008, the PUCO issued an order which approved the first two phases of a three phase plan to exit the merchant function in the Company's Ohio service territory.  As a result, substantially all of the Company's Ohio customers now purchase natural gas directly from retail gas marketers rather than from the Company. The PUCO provided for an Exit Transition Cost rider, which allows the Company to recover costs associated with the first two phases of 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 as VEDO, for the most part, no longer purchases gas for resale. VEDO’s gas costs in 2010 were $89.5 million, and were insignificant in 2012 and 2011. The decreases in gas costs were offset by similar decreases in revenues.

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Environmental Matters

The Company'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 the storage, transportation, treatment, and disposal of hazardous substances and limit airborne emissions from electric generating facilities including 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 the Company'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.

With the trend toward stricter standards, greater regulation, and more extensive permit requirements, the Company's investment in compliant infrastructure, and the associated operating costs have increased and are expected to increase in the future. Similar to the costs associated with federal mandates in the Pipeline Safety Law, Indiana Senate Bill 251 is also applicable to federal environmental mandates impacting Vectren South's electric operations. The Company is currently evaluating the impact Senate Bill 251 may have on its operations, including applicability to the stricter regulations the EPA is currently considering involving air quality, fly ash disposal, cooling tower intake facilities, waste water discharges, and greenhouse gases. These issues are further discussed below.

Air Quality

Clean Air Interstate Rule / Cross-State Air Pollution Rule

In July 2011, the EPA finalized the Cross-State Air Pollution Rule (CSAPR).  CSAPR was 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 SO₂ and NOx allowances, CSAPR reduced the ability of facilities to meet emission reduction targets through allowance trading.  Like CAIR, CSAPR set individual state caps for SO₂ and NOx emissions.  However, unlike CAIR in which states allocated allowances to generating units through state implementation plans, CSAPR allowances were allocated to individual units directly through the federal rule.  CSAPR reductions were to be achieved with initial step reductions beginning January 1, 2012, and final compliance to be achieved in 2014.  Multiple administrative and judicial challenges were filed. On December 30, 2011, the Court granted a stay of CSAPR and left CAIR in place pending its review. On August 21, 2012, the Court vacated CSAPR and directed the EPA to continue to administer CAIR. In October 2012, the EPA filed its request for a hearing before the full federal appeals court that struck down the CSAPR.  EPA's request for rehearing was denied by the Court on January 24, 2013. The Company remains in full compliance with CAIR (see additional information below "Conclusions Regarding Air Regulations").

Mercury and Air Toxics (MATS) Rule

On December 21, 2011, the EPA finalized the Utility MATS Rule.  The MATS 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 MATS 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 (April 2015).  Initiatives to suspend CSAPR’s implementation by the Congress also apply to the implementation of the MATS rule.  Multiple judicial challenges were filed and briefing is proceeding. The EPA also recently announced it will reconsider MATS requirements for new construction. Such

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requirements are more stringent than those for existing plants. Utilities planning new coal-fired generation had argued standards outlined in the MATS could not be attained even using the best available control technology.

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 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 the MATS Rule and the 2015 requirement imposed by CAIR.  Based upon an initial review, the Company believes that it will be able to meet these requirements with its existing suite of pollution control equipment.  However, it is possible some operational modifications to the control equipment will be required. Additional capital investments, operating expenses, and possibly the purchase of emission allowances may be required and could be significant depending on the required method of compliance with the requirements.  While the Company has not yet quantified what the additional costs may be associated with these efforts, because the compliance is required by government regulation the Company believes that such additional costs, if incurred, should be recoverable under Indiana Senate Bill 251 referenced above.

Notice of Violation Received

The Company received a notice of violation (NOV) from the EPA in November 2011 pertaining to its A.B. Brown power plant.  The NOV asserts that when the power plant was equipped with SCRs the correct permits were not obtained or the best available control technology to control incidental sulfuric acid mist was not installed.  Based on the Company’s understanding of the New Source Review reform in effect when the equipment was installed, it is the Company’s position that its SCR project was exempted from such requirements.  At this time the Company is reviewing the potential impact this NOV could have on capital expenditures and operating costs.  To the extent costs to comply increase, they should be recoverable under Indiana law.

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 2013.  Depending on the final rule and on the Company’s facts and circumstances, capital investments could approximate $40 million if new infrastructure, such as new cooling water towers, is required.  Costs for compliance with these final regulations should qualify as federally mandated regulatory requirements and be recovered under Indiana Senate Bill 251 referenced above.

Under the Clean Water Act, EPA sets technology-based guidelines for water discharges from new and existing facilities. EPA is currently in the process of revising the existing steam electric effluent limitation guidelines that set the technology-based water discharge limits for the electric power industry. EPA is focusing its rulemaking on wastewater generated primarily by pollution control equipment necessitated by the comprehensive air regulations. EPA is under an April 19, 2013 deadline to complete its rule proposal. It is not possible to estimate what potential costs may be required to meet these new water discharge limits,

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however costs for compliance with these regulations should qualify as federally mandated regulatory requirements and be recovered under 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 have not been finalized 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 modification to, 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 should qualify as federally mandated regulatory requirements and be recovered 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;

• Inclusion of incentives for investment in advanced clean coal technology and support for research and development; and

• A strategy supporting alternative energy technologies and biofuels and continued increase in the domestic supply of natural gas to reduce dependence on foreign oil.

The Company emits greenhouse gases (GHG) primarily from its fossil fuel electric generation plants.  The Company uses the 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)	2012	2011	2010	2009	2008
Direct CO2 Emissions (tons)	6,083	5,645	6,120	5,500	8,029

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.

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;

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• 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.  EPA's PSD and Title V permitting rules for GHG's were recently upheld by the US Court of Appeals for the District of Columbia. In 2012, the EPA proposed New Source Performance Standards for greenhouse gases for new electric generating facilities under Clean Air Act Section 111(b). While standards for new sources are not yet final, EPA has signaled its intent to propose New Source Performance Standards for greenhouse gases for existing electric generating units under Section 111(d), which would be applicable to the Company's existing units. The Company anticipates that these initial standards will focus on power plant efficiency and other coal fleet carbon intensity reduction measures. The Company believes that such additional costs, if necessary, should be recoverable under Indiana Senate Bill 251 referenced above.

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 should be recoverable from customers through Senate Bill 251. 

Senate Bill 251 also established 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 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.

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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 which are defined as clean energy in the legislation, the Company currently has approximately 5 percent of its electricity being provided by clean energy sources due to the long-term wind contracts and landfill gas investment. The Company continues to evaluate whether to participate in this voluntary program.

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.

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 plant 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 has incurred or reasonably expects to incur totaling approximately $41.7 million ($23.2 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.  Likewise, SIGECO has settlement agreements with all known insurance carriers and has received to date approximately $14 million of the expected $15 million in 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 remedial activities which are not presently foreseen and those costs may not be subject to PRP or insurance recovery.  As of December 31, 2012 and 2011, approximately $4.6 million and $6.5 million, respectively, of accrued, but not yet spent, costs are included in Other Liabilities related to both the Indiana Gas and SIGECO sites.

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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 pipeline construction and repair services.  Energy Services provides performance contracting and renewable energy services.  Coal Mining owns 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 a leveraged lease, among other investments.  Pursuant to service contracts, the Nonutility Group provides the Company’s regulated utilities natural gas supply services, coal, and infrastructure services.  Nonutility Group earnings for the years ended December 31, 2012, 2011, and 2010, follow:

	Year Ended December 31,
(In millions, except per share amounts)	2012			2011			2010
NET INCOME	$	21.7		$	23.8		$	9.8
CONTRIBUTION TO VECTREN BASIC EPS	$	0.26		$	0.29		$	0.12
NET INCOME (LOSS) ATTRIBUTED TO:
Infrastructure Services	$	40.5		$	14.9		$	3.1
Energy Services	5.7			6.7			6.4
Coal Mining	(3.5		)	16.6			11.9
Energy Marketing
Vectren Source	—			18.7			3.7
ProLiance	(17.6		)	(22.9		)	(7.9		)
Other Businesses	(3.4		)	(10.2		)	(7.4		)

Infrastructure Services

Infrastructure Services provides underground pipeline construction and repair services through wholly-owned subsidiaries Miller Pipeline (Miller) and Minnesota Limited, Inc. (Minnesota Limited) which was acquired on March 31, 2011.  Inclusive of holding company costs, earnings from Infrastructure Services' operations for the year ended December 31, 2012 were $40.5 million, compared to $14.9 million in 2011 and $3.1 million in 2010. The increases in earnings reflect increased demand across all infrastructure business areas. Results in 2012 were further favorably impacted by warm, dry weather resulting in favorable construction conditions.  For the nine months owned in 2011, Minnesota Limited contributed earnings of $9.4 million.  The remainder of the increase in 2011 compared to 2010, totaling $2.4 million, relates to Miller’s ongoing operations. Revenues in 2012 were $664 million, compared to revenues in 2011 of $442 million, including $21 million from Minnesota Limited prior to its acquisition. Infrastructure Services' revenues in 2010 totaled $236 million. Construction activity generally is expected to remain strong as utilities and pipeline operators replace their aging natural gas and oil pipeline infrastructure and due to the continued strong demand for shale gas and oil infrastructure. As an example, in the fourth quarter of 2012, Infrastructure Services was awarded a contract to construct an approximately 80 mile natural gas pipeline in the Bakken Shale area of North Dakota. It is expected this work will be completed by the end of the second quarter of 2013.

Acquisition of Minnesota Limited

On March 31, 2011, the Company purchased Minnesota Limited, excluding certain assets.  Minnesota Limited is a specialty contractor focusing on natural gas and oil transmission pipeline construction and maintenance; pump station, compressor station, terminal and refinery construction; 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.  The purchase price was approximately $83.4 million and included $14.8 million of net working capital, $34.4 million of property plant and equipment and $39.4 million of intangible assets, including goodwill.  

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 $5.7 million in 2012, compared to $6.7 million in 2011 and $6.4 million in 2010.

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Results in 2012 reflect reduced revenues, which indicate a slowing in demand for performance contracting projects due primarily to current budgetary constraints on municipal and school customers, and increased operating expenses associated with an increase in the sales force incurred throughout 2012 and 2011. The impact of energy efficiency building tax deductions from qualifying projects on 2012 earnings offset the reduced revenues and higher operating expenses, and resulted in earnings comparable to 2011. The increase in earnings in 2011 compared to 2010 reflects increased revenues. ESG continues to add to its employee base and footprint to position it for long-term growth in this sector as the national focus on energy conservation, renewable energy, and sustainability is expected to continue longer term, given the expected rise in power prices across the country as utilities increase rates to recover expected increased environmental expenditures and other federally mandated costs.

As of December 31, 2012, performance contracting backlog was $77 million, compared to $82 million at December 31, 2011 and $118 million at December 31, 2010. ESG placed three “build and own” anaerobic digester projects into service in 2012.  

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).  Results from Coal Mining, inclusive of holding company costs, were a loss of $3.5 million in 2012, compared to earnings of $16.6 million in 2011 and $11.9 million in 2010.  

Results were lower in 2012 due to lower tons sold and reduced pricing for customers associated with contracts that had price reopener clauses. Tons sold in 2012 were unfavorably impacted by the low cost of natural gas and mild winter weather. These factors significantly reduced the demand for Illinois Basin coal and led to a more than 10 percent reduction in volumes sold compared to 2011. Coal sales in 2012 were 4.5 million tons, compared to 5.2 million tons in 2011 and 3.7 million tons in 2010. During 2012, the Company reduced production in order to better match the lower demand. Production at these lower than optimal levels significantly increased the cost per ton mined at both the Oaktown and Prosperity mining complexes. At normal production levels, the Oaktown cost environment remains favorable; however, at Prosperity a thin coal seam and other unfavorable mining conditions continue to have a negative impact on production costs. Coal Mining revenues were $236 million in 2012, $286 million in 2011, and $210 million in 2010. The increase in revenues in 2011 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.

Vectren Fuels' expected production is approximately 5.5 million tons in 2013. Coal sales in 2013 are estimated at 5.6 million tons. The impact of continued reduced demand for coal generally, and its impact on price, is expected to result in a greater loss from Coal Mining operations in 2013 compared to 2012. The development of the second mine at the Company's Oaktown mining complex was substantially completed in 2012 but is not expected to begin production until demand for its coal increases. Longer term, the Company continues to believe that reduced coal volumes available from Central Appalachia due to increased regulation and the large number of scrubbers to be installed throughout the United States, including the Midwest, coupled with moderate increases in natural gas prices from the very low levels experienced in 2012, should drive stronger demand for Illinois Basin coal. Changes in market conditions or other circumstances could cause actual results to be materially different from these expectations.

Coal Reserves

As of December 31, 2012, management estimates the Company’s total Illinois Basin coal reserves to be approximately 127 million tons.  Of this amount, approximately 39 million tons are attributable to the second mine at the Company's Oaktown mining complex. Once this mine is in production, Vectren Fuels' three underground mines are capable of producing about 7.5 million tons of coal per year.

Energy Marketing

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

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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.  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.  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, 2012, EMS’ results related to the Company’s share of ProLiance’s losses, which include financing costs, income taxes, and other holding company costs, were a loss of $17.6 million, compared to a loss of $22.9 million in 2011 and a loss of $7.9 million in 2010. The smaller loss in 2012 primarily reflects the reduction in fixed demand costs for both storage and transportation contracts and lower general and administrative expenses. The $15.0 million increased loss in 2011 compared to 2010 reflects new natural gas sources from shale and greater transmission capacity, as well as lower industrial demand for natural gas in the Midwest compared to prior years.  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, and continue to be, reduced opportunities to optimize ProLiance’s firm transportation and storage capacity.  

Efforts to lower the cost of pipeline and storage demand costs continue. Through negotiations and by dropping some uneconomical contracts as they expire, ProLiance has lowered its pipeline transportation and storage costs to approximately $55 million for 2012, compared to $73 million in 2011 and $77 million in 2010. The projected annual demand costs in 2013 are expected to be approximately $42 million, or approximately $13 million lower than 2012. In addition to these reductions, opportunities exist to renegotiate or drop contracts with annual demand costs of approximately $9 million by the end of 2015. Changes in market conditions or other circumstances could cause actual demand costs to be materially different from this expectation. At December 31, 2012, ProLiance had approximately $124 million of members' equity on its balance sheet, no long-term debt outstanding, and borrowings to support working capital of $77 million on its $120 million credit facility, which became effective in May 2012 for a two year period.

For the year ended December 31, 2012, the amounts recorded to Equity in (losses) of unconsolidated affiliates related to ProLiance’s operations totaled a pre-tax loss of $22.7 million, compared to a loss of $28.6 million in 2011 and a loss of $2.5 million in 2010.

At the time of the sale of Vectren Source, the Company stated that its future emphasis in the Nonutility Group would be on growing its infrastructure and energy services businesses rather than its commodities businesses.  The Company continues to evaluate and assess strategic alternatives related to the investment in its energy marketing affiliate, ProLiance Holdings.  The Company believes the carrying value of its investment in ProLiance Holdings at December 31, 2012 is appropriate, based upon projections and other valuation data received from ProLiance. If the Company, however, proceeds with one of the strategic alternatives being evaluated, which could include a disposition of its investment in ProLiance Holdings or a disposition by ProLiance Holdings of one or more of its operating subsidiaries or their assets, the amount realized could be materially below the carrying value of the Company's investment of $73.9 million. In such event, the Company would record such loss as Equity in (losses) of unconsolidated affiliates.

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. 

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In late 2008, the project at the North site was halted due to subsurface and well-completion problems, which resulted in Liberty recording a $132 million impairment charge. The Company, through ProLiance, recorded its share of the charge in 2009. 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.  Approximately 12 Bcf of the storage at the South site, which comprises three of the four FERC certified caverns, is fully tested but additional work is required to connect the caverns to the pipeline system. ProLiance's investment in Liberty is approximately $35 million.

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.  As such, as of December 31, 2012, ProLiance has no material reserve recorded related to this matter and this litigation has not materially impacted ProLiance's results of operations or statement of financial position.

Vectren Source

Vectren Source, a former wholly owned subsidiary, provided 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, excluding minor working capital adjustments recorded in 2012.  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 the third party purchaser of Vectren Source.  This third party continues to sell natural gas directly to customers in VEDO’s service territory, and VEDO purchases receivables and natural gas from the third party.  Prior to the sale, Vectren Source earned $2.8 million in 2011, compared to $3.7 million in 2010.

Other Businesses

Within the Nonutility business segment, there are legacy investments involved in energy-related opportunities and services, real estate, a leveraged lease, and other ventures.  As of December 31, 2012, remaining legacy investments included in the Other Businesses portfolio total $28.7 million, of which $24.9 million are included in Other nonutility investments and $3.8 million are included in Investments in unconsolidated affiliates.  The investment is made up of the following: commercial real estate, $8.0 million; a leveraged lease, $13.8 million ($3.0 million net of related deferred taxes); and other investments, $6.9 million.  Net of the deferred taxes, the net investment associated with these legacy investments at December 31, 2012 was $17.9 million. 

Other Businesses losses were $3.4 million in 2012, compared to a loss of $10.2 million in 2011 and a loss of $7.4 million in 2010. Results in 2011 include charges totaling $9.2 million after tax associated with legacy real estate holdings.  Results in 2012 and 2010 reflect after tax charges of $2.2 million and $4.0 million, respectively, related to the carrying value of an energy-related investment originally made in 1999 by Haddington Energy Partners. In addition to the Haddington-related charges, results in 2010 include a $2.9 million after tax charge related to the reduction in value of a receivable recorded in 2002 related to a previously exited business.

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), which are accounted for using the equity method. Inclusive of pre tax charges recorded in 2012 of $3.4 million and in 2010 of $6.5 million associated with remaining investments, the Company's net carrying value is zero at December 31, 2012. As the Haddington operations are nearing completion, the approximate $30 million invested in these partnerships since inception in the early 2000's generated a return of 16 percent, exclusive of taxes and management fees. 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 2011, the FASB issued new accounting guidance regarding the presentation of comprehensive income within financial statements.  The new guidance requires 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 adopted this guidance, as amended for condensed quarterly reporting, for the quarterly reporting period ended March 31, 2012 by reporting comprehensive income as required.

Goodwill Testing

In September 2011, the FASB issued new accounting guidance regarding testing goodwill for impairment.  The new guidance allows 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 Company considered this option during its quarterly reporting period ended March 31, 2012 and concluded the continuation of the use of a quantitative approach is appropriate.

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 Company adopted this guidance for its quarterly reporting period ended March 31, 2012.  The adoption of this guidance did not have a material impact on our financial position, results of operations or cash flows.

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 footnotes to the consolidated financial statements describe the significant accounting policies and methods used in their preparation.  Certain estimates 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 related to 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, unbilled revenues, deferred income taxes, 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

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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 analysis.

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.  

Related to the Company owned coal mines, an undiscounted cash flow analysis was performed during 2012 supporting the carrying amount of each coal mine. However, should market conditions worsen, 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 21 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 substantially in excess of the carrying amount in each of the last three years and therefore resulted in no impairment.

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 2012 periodic benefit cost:  a discount rate of approximately 4.8 percent, an expected return on plan assets of 7.75 percent, a rate of compensation increase of 3.5 percent, and an inflation assumption of 2.75 percent.  Due to low interest rates, the discount rate is 70 basis points lower from the assumption used in 2011.  The rate of return and inflation rates were also lowered 25 basis points. To estimate 2013 costs, the discount rate, expected return on plan assets, rate of compensation increase, and inflation assumption were approximately 4.0 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

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approximately $13 million in 2013.  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. However, the impact of increases associated with a lower discount rate are partially offset by the impact of plan contributions and a plan amendment related to the postretirement medical plan.

Regulation

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

Financial Condition

Within Vectren’s consolidated group, Utility Holdings primarily funds the short-term and long-term financing needs of the Utility Group operations, and Vectren Capital Corp (Vectren Capital) funds short-term and long-term financing needs of the Nonutility Group and corporate operations.  Vectren Corporation guarantees Vectren Capital’s debt, but does not guarantee Utility Holdings’ debt.  Vectren Capital’s long-term debt and short-term obligations outstanding at December 31, 2012 approximated $450 million and $162 million, respectively.  Utility Holdings’ outstanding long-term and short-term borrowing arrangements are jointly and severally guaranteed by its wholly owned subsidiaries and regulated utilities Indiana Gas, SIGECO, and VEDO.  Utility Holdings’ long-term debt, including current maturities, and short-term obligations outstanding at December 31, 2012 approximated $821 million and $117 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, including current maturities, outstanding at December 31, 2012, was $387 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, 2012, 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 48 percent and 47 percent of long-term capitalization at December 31, 2012 and 2011, respectively.  Long-term capitalization includes long-term debt, including current maturities, 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, among other

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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, 2012, 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, and the Company believes it will have the ability to continue to do so.  Given the Company's intent to maintain a balanced long-term capitalization ratio, it anticipates funding future capital expenditures and dividends principally through internally generated funds, which have recently been enhanced by bonus depreciation legislation, and refinancing maturing debt using the capital markets.  However, the resources required for capital investment remain uncertain for a variety of factors including pending legislative and regulatory initiatives involving gas pipeline infrastructure replacement; coal mine safety; expanded EPA regulations for air, water, and fly ash; and growth of Infrastructure Services and Energy Services. These regulations may result in the need to raise additional capital in the coming years.  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 available liquidity.  The Company may also consider disposing of certain assets, investments, or businesses to enhance or accelerate internally generated cash flow. Specifically for 2013, the Company plans to access the capital markets to refinance debt maturities or debt that is callable.  The Company currently has firm commitments for a debt issuance totaling $125 million which is more fully described below. 

Long-term debt transactions completed in 2012, 2011, and 2010 include issuances by Vectren Capital totaling $225 million and issuances by Vectren Utility Holdings totaling $250 million.  These transactions are more fully described below.  (See Financing Cash Flow.)

Consolidated Short-Term Borrowing Arrangements

At December 31, 2012, 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 $233 million was available for the Utility Group operations and approximately $88 million was available for the wholly owned Nonutility Group and corporate operations.  Both Vectren Capital’s and Utility Holdings’ short-term credit facilities were renewed in November 2011 and are available through September 2016.  The maximum limit of both facilities remained unchanged.  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.  

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)	2012			2011			2010			2012			2011			2010
Year End
Balance Outstanding	$	116.7		$	242.8		$	47.0		$	162.1		$	84.3		$	71.3
Weighted Average Interest Rate	0.40		%	0.57		%	0.41		%	1.35		%	1.45		%	2.01		%
Annual Average
Balance Outstanding	$	77.6		$	39.6		$	14.0		$	151.5		$	124.9		$	143.2
Weighted Average Interest Rate	0.47		%	0.48		%	0.40		%	1.44		%	1.92		%	0.93		%
Maximum Month End Balance Outstanding	$	214.2		$	242.8		$	47.0		$	216.1		$	180.1		$	174.6

Throughout 2012, 2011, and 2010, Utility Holdings has placed commercial paper without any significant issues and did not borrow from its backup credit facility in any of these periods.

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ProLiance Short-Term Borrowing Arrangements

ProLiance, a nonutility energy marketing affiliate of the Company, has separate borrowing capacity available through a syndicated credit facility.  On May 18, 2012, ProLiance entered into a two year asset based credit facility with a total capacity of $120 million. The level of capacity is also subject to outstanding letters of credit and current inventory and receivable balances. As of December 31, 2012, approximately $77 million in borrowings were outstanding. The facility is not guaranteed by Vectren or Citizens.  

New Share Issues

The Company may periodically issue new common shares to satisfy the dividend reinvestment plan, stock option plan and other employee benefit plan requirements.  New issuances added additional liquidity of $7.2 million in 2012, $7.9 million in 2011, and $14.0 million in 2010.

Potential Uses of Liquidity

Pension & Postretirement Funding Obligations

As of December 31, 2012, assets related to the Company’s qualified pension plans were approximately 82 percent of the projected benefit obligation on a GAAP basis and 115 percent of the target liability for ERISA purposes.  Management currently estimates contributing approximately $10 million to qualified pension plans in 2013.

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, 2012, parent level guarantees support a maximum of $25 million of ESG’s performance contracting commitments and warranty obligations and $28 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 $24 million of other guarantees outstanding supporting other consolidated subsidiary operations, of which $18 million represent letters of credit supporting other nonutility operations.  Guarantees issued and outstanding on behalf of unconsolidated affiliates approximated $3 million at December 31, 2012.  These guarantees relate primarily to arrangements between ProLiance and various natural gas pipeline operators.  The Company has not been called upon to satisfy any obligations pursuant to these parental guarantees and has accrued no significant liabilities related to these guarantees.

Performance Guarantees & Product Warranties

In the normal course of business, 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, 2012, there are 62 open surety bonds supporting future performance.  The average face amount of these obligations is $5.2 million, and the largest obligation has a face amount of $57.3 million.  The maximum exposure from these obligations is limited by the level of work already completed and guarantees issued to ESG by various subcontractors. At December 31, 2012, approximately 56 percent of work was completed on projects with open surety bonds.  A significant portion of these open surety bonds will be released 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

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obligations as of December 31, 2012. In addition, ESG has an $8 million stand-alone letter of credit facility and as of December 31, 2012, $3.4 million was outstanding.

Planned Capital Expenditures & Investments

During 2012 capital expenditures and other investments approximated $370 million, of which approximately $250 million related to Utility Group expenditures.  This compares to 2011 where consolidated investments were approximately $320 million with $230 million attributed to the Utility Group and 2010 where consolidated investments were approximately $280 million with $230 million attributed to the Utility Group.  Planned Utility Group capital expenditures, including contractual purchase commitments, for the five-year period 2013 - 2017 are expected to total approximately (in millions):  $290, $330, $320, $310, and $310, respectively. This plan contains the best estimate of the resources required for known regulatory compliance; however, many environmental and pipeline safety standards are subject to change in the near term. Such changes could materially impact planned capital expenditures.

Planned Nonutility Group capital expenditures for mine development and recurring infrastructure investments, including contractual purchase commitments, for the five-year period 2013 - 2017 are expected to total (in millions):  $100, $90, $90, $90, and $100, respectively. 

Contractual Obligations

The following is a summary of contractual obligations at December 31, 2012:

(In millions)	Total		2013		2014		2015		2016		2017		Thereafter
Long-term debt (1)	$	1,659.8	$	106.4	$	30.0	$	279.8	$	73.0	$	75.0	$	1,095.6
Short-term debt	278.8		278.8		—		—		—		—		—
Long-term debt interest commitments	1,089.3		85.9		81.1		79.7		66.1		64.7		711.8
Nonutility commodity purchase commitments	1.4		1.4		—		—		—		—		—
Plant and nonutility plant purchase commitments	20.3		20.3		—		—		—		—		—
Operating leases	22.8		6.8		5.5		3.8		2.2		1.2		3.3
Total (2)	$	3,072.4	$	499.6	$	116.6	$	363.3	$	141.3	$	140.9	$	1,810.7

(1) The debt due in 2013 is comprised of debt issued by Vectren Utility Holdings totaling $100 million, $5 million issued by Indiana Gas, and $1.4 million associated with the Company’s nonutility operations. The Company expects that the majority of this debt maturing in 2013 will be refinanced using the long-term debt capital markets.

(2) The Company has other long-term liabilities that total approximately $214 million.  This amount is comprised of the following:  pension obligations $81 million; postretirement obligations $50 million; deferred compensation and share-based compensation obligations $32 million; asset retirement obligations $38 million; investment tax credits $4 million; environmental remediation obligations $5 million; and other obligations including unrecognized tax benefits totaling $4 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.

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Comparison of Historical Sources & Uses of Liquidity

Operating Cash Flow

The Company's primary source of liquidity to fund capital requirements has been cash generated from operations, which totaled $387.4 million in 2012, compared to $416.9 million in 2011 and $384.8 million in 2010.

The $29.5 million decrease in operating cash flow in 2012 compared to 2011 is primarily due to greater working capital needs to support growth in the Infrastructure Services segment and lower cash generated by the Coal Mining segment . The deferral for future recovery of certain coal costs pursuant to a regulatory order is the primary use of cash impacting the change in noncurrent assets. Increased earnings overall, along with lower contributions to employee benefit plans in 2012, somewhat offset these decreases.

In 2011, operating cash flows increased $32.1 million compared to 2010.  This increase was 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.

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, 50 percent for 2012, and continues at 50 percent for 2013.  A significant portion of the Company’s capital expenditures qualify for this bonus treatment.

Financing Cash Flow

Net cash flow required for financing activities was $19.6 million, $99.0 million, and $117.3 million for the years ending December 31, 2012, 2011, and 2010, respectively. Financing activity across all periods reflects the Company’s utilization of the long-term capital markets in the current low interest rate environment. Since 2010, the Company has refinanced at lower rates approximately $455 million of maturing or callable long-term debt. These lower rates began to favorably impact interest expense in the fourth quarter of 2011, and more noticeably decreased interest expense in 2012.  The Company’s operating cash flow funded approximately 80 percent of capital expenditures and dividends in 2012 and over 95 percent in 2011 and 2010.  Recently completed long-term financing transactions are more fully described below.

Vectren Capital Term Loan

On November 1, 2012, Vectren Capital entered into a $100 million three year term loan agreement. Loans under the term loan agreement bear interest at either a Eurodollar rate or base rate plus a fixed adder, as defined in the loan agreement. Interest periods are variable and may range from seven days to six months. The proceeds from this debt transaction were used to repay short-term borrowings outstanding under Vectren Capital's credit facility, some of which resulted from the 2012 maturity of Vectren Capital's $60 million fixed rate senior unsecured notes. The loan agreement is guaranteed by Vectren Corporation and includes customary representations, warranties and covenants, including a leverage covenant consistent with leverage covenants contained in other Vectren Capital borrowing arrangements. 

Utility Holdings 2012 Debt Transactions

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 had 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 were 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.

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On December 20, 2012, Utility Holdings entered into a private placement note purchase agreement pursuant to which institutional investors have agreed to purchase the following tranches of notes:  (i) $45,000,000 3.20% Senior Guaranteed Notes, due June 5, 2028 and (ii) $80,000,000 4.25% Senior Guaranteed Notes, due June 5, 2043.  The notes will be unconditionally guaranteed by Indiana Gas Company, Inc., Southern Indiana Gas and Electric Company and Vectren Energy Delivery of Ohio, Inc. Subject to the satisfaction of customary conditions precedent, this financing is scheduled to close on or about June 5, 2013. The proceeds received from the issuance of these notes will be used to refinance existing indebtedness that matures or is callable in 2013 and for general corporate purposes.

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 December 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 December 15, 2017, and (ii) $50 million 4.53 percent Senior Notes, Series B due December 15, 2025.  These Senior Notes are unconditionally guaranteed by Vectren.  The proceeds from the issuance replaced $48 million of 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.

Long-Term Debt Puts & Calls

Occasionally, the Company has executed debt agreements that contain put and call provisions that can be exercised on various dates before maturity.  As an example, certain of these issuances could be put to the Company upon the death of the holder (death puts) or at specific dates.  During 2012, the Company repaid an insignificant amount related to death puts. During 2011, and 2010, the Company repaid approximately $0.8 million and $1.8 million, respectively, related to death puts. On February 4, 2013, the Company notified holders of Utility Holdings $121.6 million 6.25 percent senior unsecured notes due 2039, which contained both a put and call provision, of its intent to call the debt at par on April 1, 2013. These notes are the only issue outstanding at December 31, 2012 with a put provision.

On November 21, 2011, the Company exercised a call option on Utility Holdings' $96.2 million5.95 percent senior notes due 2036.

Investing Cash Flow

Cash flow required for investing activities was $356.9 million in 2012, $319.7 million in 2011, and $269.0 million in 2010.  Capital expenditures are the primary component of investing activities and totaled $365.8 million in 2012, $321.3 million in 2011 and $277.2 million in 2010.  Utility Group capital expenditures increased approximately $13 million in 2012 compared to 2011 and is attributable to greater expenditures for bare/steel cast iron replacement and regional electric transmission projects. In addition, capital expenditures for nonutility equipment have increased approximately $32 million in 2012 compared to 2011, primarily due to growth in the Infrastructure Services segment. The increase in capital expenditures in 2011 compared to 2010 primarily reflects an approximate $36 million increase in nonutility projects including expenditures for the Oaktown coal mines,

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infrastructure services equipment, and renewable energy projects and 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.

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, tornadoes, terrorist acts, cyber attacks, 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 increased potential for 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 services, energy services, coal mining, and energy marketing strategies.

• Factors affecting infrastructure services, including the level of success in bidding contracts; fluctuations in volume of contracted work; unanticipated cost increases in completion of the contracted work; funding requirements associated with multi-employer pension plans; changes in legislation and regulations impacting the industries in which the customers

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served operate; the effects of weather; failure to properly estimate the cost to construct projects; the ability to attract and retain qualified employees; cancellation and/or reductions in the scope of projects by customers; credit worthiness of customers; ability to obtain materials and equipment required to perform services; and changing market conditions.

• Factors affecting coal mining operations and their cost structure, including MSHA guidelines and interpretations of those guidelines, as well as additional mine regulations and more frequent and broader inspections that could result from 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; coal quality, including its sulfur and mercury content; and the ability to access 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.

• 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, pipeline safety regulations, 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 executes derivative contracts in the normal course of operations while buying and selling commodities and occasionally when managing interest rate risk.

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 and coal prices have other effects on working capital requirements, interest costs, and some level of price-sensitivity in volumes sold or delivered. The Company recently began purchasing call options that are designed to cap gas costs on approximately 70 percent of peak winter delivery periods. Such contracts are generally short term in nature and

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are insignificant in terms of value and volume at December 31, 2012. However, it is possible that the utilization of these instruments may grow in the future.

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 generation into the MISO Day Ahead and Real-time markets.  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, 2012 and 2011.

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, 2012 or 2011.

Other Operations

Other commodity-related operations are exposed to commodity price risk associated with gasoline/diesel, coal, and natural gas through 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.

The Company, 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 sell positions is mitigated using stored inventory and, for ProLiance, offsetting forward purchase contracts.  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. Occasionally, the Company will hedge a portion of its gasoline requirements using financial instruments. However, during the years presented such utilization has not been significant.

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 2012 and 2011, the weighted average combined borrowings under these arrangements approximated $287 million and $206 million, respectively.  At December 31, 2012, combined borrowings under these arrangements were $420 million. As of 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. Based upon average borrowing rates under these facilities during the years ended December 31, 2012 and 2011, an increase of 100 basis points (one percentage point) in the rates would have increased interest expense by approximately $2.9 million in 2012 and $2.0 million in 2011.

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

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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, comprehensive 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, 2012.  Management certified this in its Sarbanes Oxley Section 302 certifications, which are attached as exhibits to this 2012 Form 10-K.

55

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, 2012 and 2011, and the related consolidated statements of income, comprehensive income, common shareholders’ equity and cash flows for each of the three years in the period ended December 31, 2012. 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, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, 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, 2012, 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 15, 2013 expressed an unqualified opinion on the Company’s internal control over financial reporting.

/s/ DELOITTE & TOUCHE LLP

Indianapolis, Indiana

February 15, 2013

56

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, 2012, 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, 2012, 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, 2012 of the Company and our report dated February 15, 2013 expressed an unqualified opinion on those financial statements and financial statement schedule.

/s/ DELOITTE & TOUCHE LLP

Indianapolis, Indiana

February 15, 2013

57

VECTREN CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(In millions)

	At December 31,
	2012		2011
ASSETS
Current Assets
Cash & cash equivalents	$	19.5	$	8.6
Accounts receivable - less reserves of $6.8 & $6.7, respectively	216.7		221.3
Accrued unbilled revenues	185.0		121.5
Inventories	158.6		161.9
Recoverable fuel & natural gas costs	25.3		12.4
Prepayments & other current assets	73.3		84.3
Total current assets	678.4		610.0
Utility Plant
Original cost	5,176.8		4,979.9
Less:  accumulated depreciation & amortization	2,057.2		1,947.3
Net utility plant	3,119.6		3,032.6
Investments in unconsolidated affiliates	78.1		92.9
Other utility & corporate investments	34.6		34.4
Other nonutility investments	24.9		29.6
Nonutility plant - net	598.0		550.8
Goodwill - net	262.3		262.3
Regulatory assets	252.7		226.0
Other assets	40.5		40.3
TOTAL ASSETS	$	5,089.1	$	4,878.9

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

58

VECTREN CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(In millions)

	At December 31,
	2012			2011
LIABILITIES & SHAREHOLDERS' EQUITY
Current Liabilities
Accounts payable	$	180.6		$	185.8
Accounts payable to affiliated companies	29.7			36.8
Accrued liabilities	198.8			181.1
Short-term borrowings	278.8			227.1
Current maturities of long-term debt	106.4			62.7
Total current liabilities	794.3			693.5
Long-term Debt - Net of Current Maturities	1,553.4			1,559.6
Deferred Income Taxes & Other Liabilities
Deferred income taxes	637.2			575.7
Regulatory liabilities	364.2			345.2
Deferred credits & other liabilities	213.9			239.4
Total deferred credits & other liabilities	1,215.3			1,160.3
Commitments & Contingencies (Notes 7, 17-19)
Common Shareholders' Equity
Common stock (no par value) – issued & outstanding           82.2 & 81.9 shares, respectively	700.5			692.6
Retained earnings	829.9			786.2
Accumulated other comprehensive (loss)	(4.3		)	(13.3		)
Total common shareholders' equity	1,526.1			1,465.5
TOTAL LIABILITIES & SHAREHOLDERS' EQUITY	$	5,089.1		$	4,878.9

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

59

VECTREN CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF INCOME

(In millions, except per share amounts)

	Year Ended December 31,
	2012			2011			2010
OPERATING REVENUES
Gas utility	$	738.1		$	819.1		$	954.1
Electric utility	594.9			635.9			608.0
Nonutility	899.8			870.2			567.4
Total operating revenues	2,232.8			2,325.2			2,129.5
OPERATING EXPENSES
Cost of gas sold	301.3			375.4			504.7
Cost of fuel & purchased power	192.0			240.4			235.0
Cost of nonutility revenues	295.1			385.3			243.3
Other operating	781.0			652.2			538.4
Depreciation & amortization	254.6			244.3			229.1
Taxes other than income taxes	56.3			57.6			62.2
Total operating expenses	1,880.3			1,955.2			1,812.7
OPERATING INCOME	352.5			370.0			316.8
OTHER INCOME (EXPENSE)
Equity in (losses) of unconsolidated affiliates	(23.3		)	(32.0		)	(8.6		)
Other income (expense) – net	8.3			(3.5		)	4.8
Total other income (expense)	(15.0		)	(35.5		)	(3.8		)
Interest expense	96.0			106.5			104.6
INCOME BEFORE INCOME TAXES	241.5			228.0			208.4
Income taxes	82.5			86.4			74.7
NET INCOME	$	159.0		$	141.6		$	133.7
AVERAGE COMMON SHARES OUTSTANDING	82.0			81.8			81.2
DILUTED COMMON SHARES OUTSTANDING	82.1			81.8			81.3
EARNINGS PER SHARE OF COMMON STOCK:
BASIC	$	1.94		$	1.73		$	1.65
DILUTED	$	1.94		$	1.73		$	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 COMPREHENSIVE INCOME

(In millions)

	Year Ended December 31,
	2012			2011			2010
NET INCOME	$	159.0		$	141.6		$	133.7
Accumulated other comprehensive income (AOCI) of unconsolidated affiliates
Net amount arising during the year before tax	11.3			(9.3		)	0.5
Income taxes	(4.6		)	3.8			(0.2		)
AOCI of unconsolidated affiliates, net of tax	6.7			(5.5		)	0.3
Pension & other benefits
Amounts arising during the year before tax	(3.3		)	(41.6		)	(14.8		)
Reclassifications to periodic cost before tax	7.1			6.4			5.7
Deferrals to regulatory assets	0.2			33.5			8.6
Income taxes	(1.6		)	0.7			0.2
Pension & other benefits costs, net of tax	2.4			(1.0		)	(0.3		)
Cash flow hedges
Unrealized gains & losses before tax	—			(3.6		)	4.0
Reclassifications to net income before tax	(0.1		)	(0.3		)	(0.1		)
Income taxes	—			1.5			(1.5		)
Cash flow hedges, net of tax	(0.1		)	(2.4		)	2.4
OTHER COMPREHENSIVE INCOME, NET OF TAX	9.0			(8.9		)	2.4
TOTAL COMPREHENSIVE INCOME	$	168.0		$	132.7		$	136.1

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,
	2012			2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	159.0		$	141.6		$	133.7
Adjustments to reconcile net income to cash from operating activities:
Depreciation & amortization	254.6			244.3			229.1
Deferred income taxes & investment tax credits	84.3			71.7			69.3
Equity in losses of unconsolidated affiliates	23.3			32.0			8.6
Provision for uncollectible accounts	8.2			11.8			16.8
Expense portion of pension & postretirement benefit cost	8.7			9.0			10.0
(Gain) on sale of business in 2011, net of other non-cash charges	9.8			(0.1		)	15.9
Changes in working capital accounts:
Accounts receivable & accrued unbilled revenues	(67.1		)	(17.5		)	(48.3		)
Inventories	3.3			(26.1		)	(19.3		)
Recoverable/refundable fuel & natural gas costs	(12.9		)	(4.5		)	(30.2		)
Prepayments & other current assets	(5.1		)	17.9			(23.5		)
Accounts payable, including to affiliated companies	(14.8		)	(21.2		)	5.5
Accrued liabilities	3.4			6.4			10.2
Unconsolidated affiliate dividends	0.1			0.1			42.7
Employer contributions to pension & postretirement plans	(20.5		)	(38.8		)	(22.0		)
Changes in noncurrent assets	(35.3		)	0.3			(7.6		)
Changes in noncurrent liabilities	(11.6		)	(10.0		)	(6.1		)
Net cash flows from operating activities	387.4			416.9			384.8
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from:
Long-term debt, net of issuance costs	199.5			148.9			124.2
Dividend reinvestment plan & other common stock issuances	7.2			7.9			14.0
Requirements for:
Dividends on common stock	(115.3		)	(113.2		)	(110.8		)
Retirement of long-term debt	(62.7		)	(349.1		)	(49.3		)
Other financing activities	—			(2.3		)	(0.2		)
Net change in short-term borrowings	(48.3		)	208.8			(95.2		)
Net cash flows from financing activities	(19.6		)	(99.0		)	(117.3		)
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from:
Sale of business	—			84.3			—
Unconsolidated affiliate distributions	0.2			0.5			0.5
Other collections	9.9			1.1			10.8
Requirements for:
Capital expenditures, excluding AFUDC equity	(365.8		)	(321.3		)	(277.2		)
Business acquisition, net of cash acquired	—			(83.4		)	—
Other investments	(1.2		)	(0.9		)	(3.1		)
Net cash flows from investing activities	(356.9		)	(319.7		)	(269.0		)
Net change in cash & cash equivalents	10.9			(1.8		)	(1.5		)
Cash & cash equivalents at beginning of period	8.6			10.4			11.9
Cash & cash equivalents at end of period	$	19.5		$	8.6		$	10.4

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
	Shares	Amount		Retained Earnings			Comprehensive Income (Loss)			Total
Balance at January 1, 2010	81.1	$	666.8	$	737.2		$	(6.8	)	$	1,397.2
Net income				133.7						133.7
Other comprehensive income							2.4			2.4
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
Net income				141.6						141.6
Other comprehensive income							(8.9		)	(8.9		)
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
Net income				159.0						159.0
Other comprehensive income							9.0			9.0
Common stock:
Issuance:  option exercises & dividend reinvestment plan	0.3	7.2								7.2
Dividends ($1.405 per share)				(115.3		)				(115.3		)
Other		0.7								0.7
Balance at December 31, 2012	82.2	$	700.5	$	829.9		$	(4.3	)	$	1,526.1

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

63

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 566,000 natural gas customers located in central and southern Indiana.  SIGECO provides energy delivery services to approximately 142,000 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 owns coal 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 a leveraged lease, among other investments.  All of the above are collectively referred to as the Nonutility Group.  Pursuant to service contracts, the Nonutility Group provides the Company's regulated utilities 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 of 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 (losses) of

65

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 segments 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.  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 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 postretirement 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

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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 balance sheet 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, 2012 or 2011, 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

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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) 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 recognized as products and services are delivered to customers.  Some nonutility revenues are recognized using the percentage of completion method.  The Company records revenues for services and goods delivered but not billed at the end of an accounting period in Accrued unbilled revenues. The goods and services delivered by the Company subject to unbilled revenue accruals include gas, electricity, and infrastructure services.

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.

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Share-Based Compensation

The Company grants share-based awards 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 share-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 $26.9 million in 2012, $29.3 million in 2011, and $33.8 million in 2010.  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 members of executive management led by the Chief Executive Officer.  The Company uses net income calculated in accordance with generally accepted accounting principles as its most relevant performance measure.  The Company has three operating segments within its Utility Group, five operating segments in its Nonutility Group, and a Corporate and Other segment.

Fair Value Measurements

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

Level 1	Inputs to the valuation methodology are unadjusted quoted prices for identical assets or liabilities in active markets that the 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)	2012				2011
	Original Cost		Depreciation Rates as a Percent of  Original Cost		Original Cost		Depreciation Rates as a Percent of  Original Cost
Gas utility plant	$	2,614.3	3.5	%	$	2,516.8	3.5	%
Electric utility plant	2,463.6		3.3	%	2,316.8		3.3	%
Common utility plant	52.0		3.0	%	51.6		2.9	%
Construction work in progress	46.9		—		94.7		—
Total original cost	$	5,176.8			$	4,979.9

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, 2012, is $185.9 million with accumulated depreciation totaling $78.9 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 operatingexpenses in the Consolidated Statements of Income.

Nonutility plant, net of accumulated depreciation and amortization follows:

	At December 31,
(In millions)	2012		2011
Coal mine development costs & equipment	$	241.9	$	222.0
Computer hardware & software	97.3		101.9
Land & buildings	120.4		112.0
Vehicles & equipment	119.8		92.5
All other	18.6		22.4
Nonutility plant - net	$	598.0	$	550.8

Nonutility plant is presented net of accumulated depreciation and amortization totaling $468.4 million and $418.5 million as of December 31, 2012 and 2011, respectively.  For the years ended December 31, 2012, 2011, and 2010, the Company capitalized interest totaling $1.8 million, $2.1 million, and $2.1 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)	2012			2011
Future amounts recoverable from ratepayers related to:
Benefit obligations (See Note 11)	$	126.2		$	126.0
Deferred income taxes (See Note 10)	(3.9		)	1.3
Asset retirement obligations & other	2.6			2.3
	124.9			129.6
Amounts deferred for future recovery related to:
Deferred coal costs (See Note 18)	42.4			17.7
Cost recovery riders & other	10.2			6.4
	52.6			24.1
Amounts currently recovered in customer rates related to:
Unamortized debt issue costs & hedging proceeds	32.6			34.3
Demand side management programs	4.4			6.3
Indiana authorized trackers	32.1			24.3
Ohio authorized trackers	1.5			1.0
Premiums paid to reacquire debt	2.7			3.3
Other base rate recoveries	1.9			3.1
	75.2			72.3
Total regulatory assets	$	252.7		$	226.0

Of the $75.2 million currently being recovered in customer rates, $4.4 million that is associated with demand side management programs is earning a return.  The weighted average recovery period of regulatory assets currently being recovered in base rates, which totals $41.6 million, is 18 years.  The remainder of the regulatory assets are being recovered timely through tracking mechanisms. 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, 2012 and 2011, the Company has approximately $364.2 million and $345.2 million, respectively, in Regulatory liabilities.  Of these amounts, $349.5 million and $320.9 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; 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.

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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

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 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 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 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 year ended December 31, 2011 and 2010 as if the acquisition had occurred on January 1, 2010.

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

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

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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.

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, excluding minor working capital adjustments.  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 the third party purchaser of Vectren Source.  This third party continues to sell natural gas directly to customers in VEDO’s service territory, and VEDO purchases receivables and natural gas from the third party.  Vectren Source was 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 former 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 2012, 2011, and 2010.

Summarized Financial Information

	Year Ended December 31,
(In millions)	2012			2011			2010
Summarized Statement of Income information:
Revenues	$	1,001.3		$	1,410.5		$	1,497.0
Operating loss	(34.8		)	(44.5		)	(3.1		)
ProLiance's losses	(38.3		)	(47.3		)	(3.7		)

	As of December 31,
(In millions)	2012			2011
Summarized balance sheet information:
Current assets	$	279.7		$	381.9
Noncurrent assets	55.6			56.1
Current liabilities	215.1			298.5
Noncurrent liabilities	0.3			0.7
Members' equity	124.3			161.5
Accumulated other comprehensive loss	(7.5		)	(26.0		)
Noncontrolling interest	3.1			3.3

Vectren records its 61 percent share of ProLiance’s results in Equity in (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, 2012 and 2011, the Company’s investment balance is $73.9 million and $85.4 million, respectively. The

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amounts recorded to Equity in (losses) of unconsolidated affiliates related to ProLiance’s operations totaled a pre-tax loss of $22.7 million, $28.6 million, and $2.5 million for the years ended December 31, 2012, 2011, and 2010, respectively.  Lower natural gas prices, which have resulted in narrowed summer/winter spreads and locational margins, have negatively impacted ProLiance’s results. 

The Company continues to evaluate and assess strategic alternatives related to the investment in its energy marketing affiliate, ProLiance Holdings.  The Company believes the carrying value of its investment in ProLiance Holdings at December 31, 2012 is appropriate, based upon projections and other valuation data received from ProLiance. If the Company, however, proceeds with one of the strategic alternatives being evaluated, which could include a disposition of its investment in ProLiance Holdings or a disposition by ProLiance Holdings of one or more of its operating subsidiaries or their assets, the amount realized could be materially below the carrying value of the Company's investment.

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, which resulted in Liberty recording a $132 million impairment charge. The Company, through ProLiance, recorded its share of the charge in 2009. 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.  Approximately 12 Bcf of the storage at the South site, which comprises three of the four FERC certified caverns, is fully tested but additional work is required to connect the caverns to the pipeline system.  ProLiance's investment in Liberty is approximately $35 million.

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.  As such, as of December 31, 2012, ProLiance has no material reserve recorded related to this matter and this litigation has not materially impacted ProLiance's results of operations or statement of financial position.

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 2031.  At December 31, 2012, the estimated aggregated amounts of such required future payments were $42.3 million, $40.7 million, $33.5 million, $29.6 million, $26.2 million, and $180.1 million for 2013, 2014, 2015, 2016, 2017, and thereafter, respectively.  During 2012, 2011, and 2010, fixed payments under these agreements were $54.5 million, $73.0 million, and $76.8 million, respectively.  ProLiance also made variable payments under these agreements in 2012, 2011, and 2010. 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, 2012, 2011, and 2010, totaled $274.5 million, $378.7 million, and $437.7 million, respectively.  Amounts owed to ProLiance at December 31, 2012, and 2011, for those purchases were $29.7 million and $36.8 million, respectively, and are included in Accounts payable to affiliated companies in the Consolidated Balance Sheets. Vectren received regulatory approval on March 17, 2011, from the IURC for ProLiance to continue to provide natural gas supply services to the Company’s Indiana utilities and Citizens Energy Group's utilities through March 2016.  Amounts charged by ProLiance for gas supply services are established by supply agreements with each utility.

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8. Nonutility Real Estate & Other Legacy Holdings

Within the nonutility group, there are legacy investments involved in energy-related infrastructure and services, real estate, a leveraged lease, and other ventures.  As of December 31, 2012 and 2011, total remaining legacy investments included in the Other Businesses portfolio total $28.7 million and $36.9 million, respectively.  Further separation of that 2012 investment by type of investment follows:

	December 31, 2012
			Value Included In
(In millions)	Carrying Value		Other Nonutility Investments		Investments in Unconsolidated Affiliates
Commercial real estate investments	$	8.0	$	8.0	$	—
Leveraged lease	13.8		13.8		—
Other investments	6.9		3.1		3.8
	$	28.7	$	24.9	$	3.8

Net of deferred taxes related to the leveraged lease, the net investment at December 31, 2012 was $17.9 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 and affordable housing projects. 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 (losses) of unconsolidated affiliates, and $3.0 million is reflected in Other operating expenses.

Leveraged Lease

At December 31, 2012, the Company has an investment in a leveraged lease.  The original cost for the leased facility was $27.5 million and was partially financed by non-recourse debt provided by lenders who were granted an assignment of rentals due and a security interest in the leased property, which they accepted as their sole remedy in the event of default by the lessee.  Such remaining debt was approximately $22.9 million at December 31, 2012.  The book value of this leverage lease is $3.0 million at December 31, 2012, net of related deferred taxes of $10.8 million.

Other Investments

Other investments totaled $6.9 million at December 31, 2012 and are comprised of investments in partnership-like structures involved in multifamily housing; a 40 percent ownership interest in Haddington Energy Partners LP and Haddington Energy Partners II, LP; and a receivable resulting from a jury verdict, and a minor asset from an exited generation project.  The investments involving multifamily housing are variable interest entities where the Company is a limited partner.  The Company's exposure to loss is limited to its investment, and the Company does not consolidate any of these entities.  Both the Haddington investment and the multifamily housing investments are accounted for using the equity method.  The carrying value of the Haddington investments is fully reserved at December 31, 2012.

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9. Intangible Assets

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

(In millions)	At December 31,
	2012				2011
	Amortizing		Non-amortizing		Amortizing		Non-amortizing
Customer-related assets	$	18.9	$	—	$	20.6	$	—
Market-related assets	2.7		7.0		3.6		7.0
Intangible assets, net	$	21.6	$	7.0	$	24.2	$	7.0

As of December 31, 2012, the weighted average remaining life for amortizing customer-related assets and all amortizing intangibles is 13 years.  These amortizing intangible assets have no significant residual values.  Intangible assets are presented net of accumulated amortization totaling $6.6 million for customer-related assets and $1.7 million for market-related assets at December 31, 2012 and $5.1 million for customer-related assets and $0.9 million for market-related assets at December 31, 2011.  Annual amortization associated with intangible assets totaled $2.6 million in 2012 and $2.3 million in 2011 and $0.6 million2010.  Amortization should approximate (in millions) $2.3, $2.3, $2.2, $1.6, and $1.4 in 2013, 2014, 2015, 2016, and 2017, respectively. Intangible assets are primarily in the Nonutility Group.

10. Income Taxes

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

	Year Ended December 31,
	2012		2011		2010
Statutory rate:	35.0	%	35.0	%	35.0	%
State & local taxes-net of federal benefit	4.0		4.2		3.8
Amortization of investment tax credit	(0.3	)	(0.3	)	(0.4	)
Depletion	(1.5	)	(1.9	)	(2.0	)
Energy efficiency building deductions	(3.0	)	(1.1	)	(0.5	)
Other tax credits	(0.1	)	(0.2	)	(0.2	)
Adjustment of income tax accruals and all other-net	0.1		2.2		0.1
Effective tax rate	34.2	%	37.9	%	35.8	%

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Significant components of the net deferred tax liability follow:

	At December 31,
(In millions)	2012			2011
Noncurrent deferred tax liabilities (assets):
Depreciation & cost recovery timing differences	$	681.6		$	625.5
Leveraged lease	10.8			13.8
Regulatory assets recoverable through future rates	23.5			25.1
Other comprehensive income	(4.0		)	(10.2		)
Alternative minimum tax carryforward	(44.1		)	(35.1		)
Employee benefit obligations	(2.1		)	(9.4		)
Net operating loss & other carryforwards	(11.7		)	(6.7		)
Regulatory liabilities to be settled through future rates	(18.3		)	(17.2		)
Impairments	(6.1		)	(11.4		)
Other – net	7.6			1.3
Net noncurrent deferred tax liability	637.2			575.7
Current deferred tax liabilities (assets):
Deferred fuel costs-net	25.7			6.0
Demand side management programs	2.7			0.7
Alternative minimum tax carryforward	(2.7		)	(15.6		)
Other – net	(10.8		)	(7.1		)
Net current deferred tax liability (asset)	14.9			(16.0		)
Net deferred tax liability	$	652.1		$	559.7

At December 31, 2012 and 2011, investment tax credits totaling $3.7 million and $4.3 million respectively, are included in Deferred credits & other liabilities.  At December 31, 2012, the Company has alternative minimum tax carryforwards which do not expire.  In addition, the Company has $11.7 million in net operating loss and general business credit carryforwards, which will expire in 5 to 20 years.

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 million decrease in Regulatory assets.

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

	Year Ended December 31,
(In millions)	2012			2011			2010
Current:
Federal	$	(8.2	)	$	4.4		$	(0.8	)
State	6.4			10.3			6.2
Total current taxes	(1.8		)	14.7			5.4
Deferred:
Federal	80.3			66.0			65.6
State	4.6			6.4			4.5
Total deferred taxes	84.9			72.4			70.1
Amortization of investment tax credits	(0.6		)	(0.7		)	(0.8		)
Total income tax expense	$	82.5		$	86.4		$	74.7

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Uncertain Tax Positions

Following is a roll forward of unrecognized tax benefits for the three years ended December 31, 2012:

(In millions)	2012			2011			2010
Unrecognized tax benefits at January 1	$	12.4		$	13.3		$	11.5
Gross increases - tax positions in prior periods	0.2			3.3			1.6
Gross decreases - tax positions in prior periods	(9.4		)	(4.5		)	(0.3		)
Gross increases - current period tax positions	1.9			0.6			1.0
Settlements	(0.3		)	(0.3		)	—
Lapse of statute of limitations	—			—			(0.5		)
Unrecognized tax benefits at December 31	$	4.8		$	12.4		$	13.3

Of the change in unrecognized tax benefits during 2012, 2011, and 2010, 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 each of December 31, 2012, 2011 and 2010.  As of December 31, 2012, the unrecognized tax benefit relates to tax positions for which the ultimate deductibility is more likely than not 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 income related to a reversal of interest expense previously accrued and net of penalties totaling $0.7 million in 2012 and recognized expense related to interest and penalties totaling approximately $0.4 million in 2011, and $0.3 million in 2010.  The Company had approximately $0.6 million and $1.3 million for the payment of interest and penalties accrued as of December 31, 2012 and 2011, 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 $3.2 million and $10.1 million, respectively, at December 31, 2012 and 2011.

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 have recently been examined by the IRS, and such examination resulted in no assessments but is in IRS Joint Committee review currently. The primary focus of the IRS examination was certain repairs and maintenance deductions, an area of particular focus by the IRS throughout the utility industry. In 2012, the IRS suspended all examinations related to this issue generally, resulting in the elimination of the audit risk in this area for the company through 2012.  To the extent IRS guidance changes in this area, any impact is not expected to be material to the Company's result 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 2008 for Indiana income tax.

11. Retirement Plans & Other Postretirement Benefits

At December 31, 2012, the Company maintains three qualified defined benefit pension plans, a nonqualified supplemental executive retirement plan (SERP), and a postretirement benefit plan.  The defined benefit pension plans and postretirement benefit plan, 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.”  The postretirement benefit plan is presented under the heading “Other Benefits.”

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Net Periodic Benefit Costs

A summary of the components of net periodic benefit cost for the three years ended December 31, 2012 follows:

	Pension Benefits									Other Benefits
(In millions)	2012			2011			2010			2012			2011			2010
Service cost	$	7.7		$	6.9		$	6.3		$	0.5		$	0.5		$	0.5
Interest cost	15.5			15.9			15.9			2.8			4.3			4.6
Expected return on plan assets	(21.2		)	(21.2		)	(18.4		)	—			—			(0.4		)
Amortization of prior service cost (benefit)	1.6			1.7			1.6			(2.5		)	(0.8		)	(0.8		)
Amortization of actuarial loss (gain)	6.8			3.8			3.2			0.7			0.6			0.5
Amortization of transitional obligation	—			—			—			0.5			1.1			1.2
Net periodic benefit cost	$	10.4		$	7.1		$	8.6		$	2.0		$	5.7		$	5.6

A portion of the net periodic benefit cost disclosed in the table above is capitalized as Utility plant.  Costs capitalized in 2012, 2011, and 2010 are estimated at $3.7 million, $3.9 million, and $4.3 million, respectively.

The Company lowered the discount rate used to measure periodic cost from 5.50 percent in 2011 to 4.82 percent in 2012 due to lower benchmark interest rates that approximate the expected duration of the Company’s benefit obligations.  For fiscal year 2013, the weighted average discount rate will be 4.03 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
	2012		2011		2010		2012		2011		2010
Discount rate	4.82	%	5.50	%	6.00	%	4.75	%	5.50	%	6.00	%
Rate of compensation increase	3.50	%	3.50	%	3.50	%	N/A		N/A		N/A
Expected return on plan assets	7.75	%	8.00	%	8.00	%	N/A		8.00	%	8.00	%
Expected increase in Consumer Price Index	N/A		N/A		N/A		2.75	%	3.00	%	3.00	%

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, 2012 and 2011 follows:

	Pension Benefits						Other Benefits
(In millions)	2012			2011			2012			2011
Benefit obligation, beginning of period	$	329.2		$	297.3		$	79.7		$	80.7
Service cost – benefits earned during the period	7.7			6.9			0.5			0.5
Interest cost on projected benefit obligation	15.5			15.9			2.8			4.3
Plan participants' contributions	—			—			1.6			1.9
Plan amendments	0.7			—			(26.6		)	—
Actuarial loss (gain)	39.0			23.1			2.8			(0.5		)
Medicare subsidy receipts	—			—			0.5			1.0
Benefit payments	(14.8		)	(14.0		)	(6.9		)	(8.2		)
Benefit obligation, end of period	$	377.3		$	329.2		$	54.4		$	79.7

The accumulated benefit obligation for all defined benefit pension plans was $354.5 million and $310.9 million at December 31, 2012 and 2011, respectively.

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Postretirement Benefit Change

Effective September 1, 2012, the Company no longer offers postretirement health coverage for participants 65 and older.  Rather, the Company provides a subsidy to plan participants to purchase health coverage through a private Medicare exchange.  This change in benefits provides a comparable benefit at a reduced cost made possible by current market pricing.  Since this change in benefits was a significant event pursuant to GAAP, the Company remeasured its postretirement benefit obligations as of June 1, 2012, consistent with the notification date to participants.  The change in benefits, net of the impacts associated with remeasuring the benefit obligations using a lower discount rate, resulted in a $23 million reduction in the postretirement liability.  Substantially all of the amount was recorded as a reduction to Regulatory Assets, as the Company's retirement costs primarily relate to its regulated utilities.  The discount rate used to remeasure the postretirement benefit obligation was 3.93 percent. 

The benefit obligation as of December 31, 2012 and 2011 was calculated using the following weighted average assumptions:

	Pension Benefits				Other Benefits
	2012		2011		2012		2011
Discount rate	4.03	%	4.82	%	3.91	%	4.78	%
Rate of compensation increase	3.50	%	3.50	%	N/A		N/A
Expected increase in Consumer Price Index	N/A		N/A		2.75	%	2.75	%

To calculate the 2012 ending postretirement benefit obligation, medical claims costs in 2013 were assumed to be 7.50 percent higher than those incurred in 2012.  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 $0.7 million.

Plan Assets

A reconciliation of the Company’s plan assets at December 31, 2012 and 2011 follows:

	Pension Benefits						Other Benefits
(In millions)	2012			2011			2012			2011
Plan assets at fair value, beginning of period	$	261.0		$	237.2		$	—		$	3.1
Actual return on plan assets	33.8			2.1			—			0.1
Employer contributions	15.7			35.7			5.3			3.1
Plan participants' contributions	—			—			1.6			1.9
Benefit payments	(14.8		)	(14.0		)	(6.9		)	(8.2		)
Fair value of plan assets, end of period	$	295.7		$	261.0		$	—		$	—

The Company’s overall investment strategy for its retirement plan trusts is to maintain investments in a diversified portfolio, comprised of primarily equity and fixed income investments, which are further diversified among various asset classes.  The diversification is designed to minimize the risk of large losses while maximizing total return within reasonable and prudent levels of risk.  The investment objectives specify a targeted investment allocation for the pension plans of 60 percent equities, 35 percent debt, and 5 percent for other investments, including real estate.  Both the equity and debt securities have a blend of domestic and international exposures.  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

80

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 53 percent and 38 percent, respectively, of their fair value as of December 31, 2012 and approximately 52 percent and 40 percent, respectively, as of December 31, 2011.  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 $145.0 million at December 31, 2012 and $128.2 million at December 31, 2011.  In relation to these investments, there are no unfunded commitments.  Also, the Plan can exchange shares with minimal restrictions. However, in certain events 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, 2012 and 2011, the estimate of undiscounted funds necessary to satisfy John Hancock’s remaining obligation was $3.6 million and $3.4 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, 2012 and 2011 was 5.17 percent and 5.26 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, 2012 and December 31, 2011 by asset category and by fair value hierarchy are as follows:

	As of December 31, 2012
(In millions)	Level 1		Level 2		Level 3		Total
Domestic equities & equity funds	$	62.8	$	77.6	$	—	$	140.4
International equities & equity funds	34.3		—		—		34.3
Domestic bonds & bond funds	41.7		42.3		—		84.0
Inflation protected security fund	—		12.6		—		12.6
Real estate, commodities & other	8.0		12.5		3.9		24.4
Total plan investments	$	146.8	$	145.0	$	3.9	$	295.7

	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

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

(In millions)	2012			2011
Fair value, beginning of year	$	3.8		$	3.7
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	$	3.9		$	3.8

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Funded Status

The funded status of the plans as of December 31, 2012 and 2011 follows:

	Pension Benefits						Other Benefits
(In millions)	2012			2011			2012			2011
Qualified Plans
Benefit obligation, end of period	$	(360.0	)	$	(314.7	)	$	(54.4	)	$	(79.7	)
Fair value of plan assets, end of period	295.7			261.0			—			—
Funded Status of Qualified Plans, end of period	(64.3		)	(53.7		)	(54.4		)	(79.7		)
Benefit obligation of SERP Plan, end of period	(17.3		)	(14.5		)	—			—
Total funded status, end of period	$	(81.6	)	$	(68.2	)	$	(54.4	)	$	(79.7	)
Accrued liabilities	$	1.0		$	0.7		$	4.5		$	5.1
Deferred credits & other liabilities	$	80.6		$	67.5		$	49.9		$	74.6

Expected Cash Flows

In 2013, the Company expects to make contributions of approximately $10 million to its pension plan trusts.  In addition, the Company expects to make payments totaling approximately $1.0 million directly to SERP participants and approximately $3.5 million directly to those participating in the postretirement plan.

Estimated retiree pension benefit payments, including the SERP, projected to be required during the years following 2012 are approximately (in millions) $23.8 in 2013, $24.1 in 2014, $23.9 in 2015, $25.8 in 2016, $35.0 in 2017, and $142.0 in years 2018-2022.  Expected benefit payments projected to be required for postretirement benefits during the years following 2012 (in millions) are approximately $4.5 in 2013, $4.7 in 2014, $4.8 in 2015, $5.0 in 2016, and $5.3 in 2017 and $30.8 in years 2018-2022.

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.

	Pensions						Other Benefits
(In millions)	Prior Service Cost			Net Gain or Loss			Prior Service Cost			Net Gain or Loss			Transition Obligation
Balance at January 1, 2010	$	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 at 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 at December 31, 2011	$	5.4		$	116.6		$	(1.2	)	$	9.1		$	2.7
Amounts arising during the period	0.7			26.4			(24.4		)	2.8			(2.2		)
Reclassification to benefit costs	(1.6		)	(6.8		)	2.5			(0.7		)	(0.5		)
Balance at December 31, 2012	$	4.5		$	136.2		$	(23.1	)	$	11.2		$	—

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Following is a reconciliation of the amounts in Accumulated other comprehensive income (AOCI) and Regulatory assets related to retirement plan obligations at December 31, 2012 and 2011.

(In millions)	2012						2011
	Pensions			Other Benefits			Pensions			Other Benefits
Prior service cost	$	4.5		$	(23.1	)	$	5.4		$	(1.2	)
Unamortized actuarial gain/(loss)	136.2			11.2			116.6			9.1
Transition obligation	—			—			—			2.7
	140.7			(11.9		)	122.0			10.6
Less: Regulatory asset deferral	(137.9		)	11.7			(115.9		)	(10.1		)
AOCI before taxes	$	2.8		$	(0.2	)	$	6.1		$	0.5

Related to pension plans, $1.4 million of prior service cost and $10.2 million of actuarial gain/loss is expected to be amortized to cost in 2013.  Related to other benefits, $0.8 million of actuarial gain/loss is expected to be amortized to periodic cost in 2013, and $3.2 million of prior service cost is expected to reduce cost in 2013.

Multi-employer Benefit Plan

The Company, through its Infrastructure Services operating segment, participates in several industry wide multi-employer pension plans for its union employees which provide for monthly benefits based on length of service. The risks of participating in multi-employer pension plans are different from the risks of participating in single-employer pension plans in the following respects: 1) assets contributed to the multi-employer plan by one employer may be used to provide benefits to employees of other participating employers, 2) if a participating employer stops contributing to the plan, the unfunded obligations of the plan allocable to such withdrawing employer may be borne by the remaining participating employers, and 3) if the Company stops participating in some of its multi-employer pension plans, the Company may be required to pay those plans an amount based on its allocable share of the underfunded status of the plan, referred to as a withdrawal liability.

Expense is recognized as payments are accrued for work performed or when withdrawal liabilities are probable and estimable.  Expense associated with multi-employer plans was $27.6 million, $18.3 million and $10.0 million for the years ended December 31, 2012, 2011, and 2010, respectively. The increase in expense is due primarily to the increase in work performed. During 2012, the Company, through its Infrastructure Services operating segment, made contributions to these multi-employer plans on behalf of employees that participate in approximately 370 local unions.  Contracts with these unions are negotiated with trade agreements through two primary contractor associations. These trade agreements have varying expiration dates ranging from 2014 through 2016. The average contribution related to these local unions was less than $0.1 million, and the largest contribution was $3.6 million.  Multiple unions can contribute to a single multi-employer plan.  The Company made contributions to at least 41 plans in 2012, four of which are considered significant plans based on, among other things, the amount of the contributions, the number of employees participating in the plan, and the funded status of the plan. Further, of the 41 plans identified, there are four plans that are less than 65 percent funded (i.e. red zone status) and two plans where the Company's contributions represent more than 5 percent of the total contributions received by the plan; however, none of these plans are significant to the Company.

The Company's participation in the significant plans is outlined in the following table. The Employer Identification Number (EIN) / Pension Plan Number column provides the Employer Identification Number ("EIN") and three digit pension plan numbers. The most recent Pension Protection Act Zone Status available in 2012 and 2011 is for the plan year end at January 31, 2012 and 2011 for the Central Pension Fund, December 31, 2011 and 2010 for the Pipeline Industry Benefit Fund, May 31, 2011 and 2010 for the Indiana Laborers Pension Fund, and December 31, 2011 and 2010 for the Minnesota Laborers Pension Fund, respectively. Generally, plans in the red zone are less than 65 percent funded, plans in the yellow zone are less than 80 percent funded and plans in the green zone are at least 80 percent funded. The FIP/RP Status Pending / Implemented column indicates plans for which a funding improvement plan ("FIP") or rehabilitation plan ("RP") is either pending or has been implemented. The multi-employer contributions listed in the table below are the Company's multi-employer contributions made in 2012, 2011, and 2010.

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(In millions)
		Pension Protection Act Zone Status			Multi-Employer Contributions
Pension Fund	EIN/Pension Plan Number	2012	2011	FIP/RP Status Pending/Implemented	2012	2011	2010	Surcharge Imposed
Central Pension Fund	36-6052390-001	Green	Green	No	$4.0	$2.3	$1.1	No
Pipeline Industry Benefit Fund	73-0742835-001	Green	Green	No	3.9	1.0	0.7	No
Indiana Laborers Pension Fund (1)	35-6027150-001	Yellow	Yellow	Implemented	3.2	1.6	1.4	No
Minnesota Laborers Pension Fund	41-6159599-001	Green	Green	No	2.0	0.7	—	No
Other					14.5	12.7	6.8
Total Contributions					$27.6	$18.3	$10.0

(1) Federal law requires pension plans in endangered status to adopt a funding improvement plan aimed at restoring the financial health of the plan. Since this plan became endangered as of June 1, 2008, a funding improvement plan was previously set in place to begin June 1, 2009. The funding improvement plan requires that the plan's funded percentage improve at least one-third of the way to 100 percent over a 10-year period. The target for this plan under the law is a funded percentage of 78 percent by 2019. The plan must also meet the federal minimum funding requirements during this 10-year period. Based on the plan's most current actuarial projections, the plan is on track to meet or exceed these benchmarks.

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 2012, 2011 and 2010, the Company made contributions to these plans of $6.7 million, $6.2 million, and $6.6 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)	2012		2011
Utility Holdings
Fixed Rate Senior Unsecured Notes
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		55.0
2026, 5.02%	60.0		60.0
2035, 6.10%	75.0		75.0
2039, 6.25%	121.6		121.6
2041, 5.99%	35.0		35.0
2042, 5.00%	100.0		—
Total Utility Holdings	821.6		721.6
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 0.15%, tax exempt,
2012 weighted average: 0.17%	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 0.15%, tax exempt,
2012 weighted average: 0.16%	31.5		31.5
2029, 1999 Series, 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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	At December 31,
(In millions)	2012			2011
Vectren Capital Corp.
Fixed Rate Senior Unsecured Notes
2012, 5.13%	—			25.0
2012, 7.43%	—			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
Variable Rate Term Loan
2015, current adjustable rate 1.22%	100.0			—
Total Vectren Capital Corp.	450.0			410.0
Other Long-Term Notes Payable	1.4			4.1
Total long-term debt outstanding	1,661.5			1,524.2
Current maturities of long-term debt	(106.4		)	(62.7		)
Short-term borrowings refinanced in 2012	—			100.0
Unamortized debt premium & discount - net	(1.7		)	(1.9		)
Total long-term debt-net	$	1,553.4		$	1,559.6

Vectren Capital 2012 Term Loan

On November 1, 2012, Vectren Capital entered into a $100 millionthree year term loan agreement. Loans under the term loan agreement bear interest at either a Eurodollar rate or base rate plus a fixed adder, as defined in the loan agreement. Interest periods are variable and may range from seven days to six months. The proceeds from this debt transaction were used to repay short-term borrowings outstanding under Vectren Capital's credit facility. The loan agreement is guaranteed by Vectren Corporation and includes customary representations, warranties and covenants, including a leverage covenant consistent with leverage covenants contained in other Vectren Capital borrowing arrangements. 

Utility Holdings 2012 Debt Transactions

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.

On December 20, 2012, Utility Holdings entered into a private placement note purchase agreement pursuant to which institutional investors have agreed to purchase the following tranches of notes:  (i) $45 million3.20 percent Senior Guaranteed Notes, due June 5, 2028 and (ii) $80 million4.25 percent Senior Guaranteed Notes, due June 5, 2043.  The notes will be unconditionally guaranteed by Indiana Gas Company, Inc., Southern Indiana Gas and Electric Company and Vectren Energy Delivery of Ohio, Inc. Subject to the satisfaction of customary conditions precedent, this financing is scheduled to close on or about June 5, 2013. The proceeds received from the issuance of these notes will be used to refinance existing indebtedness that matures or is callable in 2013 and for general corporate purposes.

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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 $149 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 million3.48 percent Senior Notes, Series A due December 15, 2017, and (ii) $50 million4.53 percent Senior Notes, Series B due December 15, 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 million.  These notes contain customary representations, warranties and covenants, including a leverage covenant consistent with leverage covenants contained in other Vectren Capital borrowing arrangements.

Long-Term Debt Puts & Calls

Certain long-term debt issues contain put and call provisions that can be exercised on various dates before maturity.  As an example, certain instruments can be put to the Company upon the death of the holder (death puts) or at specific dates.  During 2012, the Company repaid an insignificant amount related to death puts. During 2011 and 2010, the Company repaid approximately $0.8 million and $1.8 million, respectively, related to death puts. On February 4, 2013, the Company notified holders of Utility Holdings $121.6 million6.25 percent senior unsecured notes due 2039, which contained both a put and call provision, of its intent to call the debt at par on April 1, 2013. These notes are the only issue outstanding at December 31, 2012 with a put provision.

On October 21, 2011, the Company notified holders of Utility Holdings $96.2 million5.95 percent senior notes due 2036, of its intent to call those notes.  This call option was exercised at par on November 21, 2011.

Letters of Credit Supporting Long-Term Debt

As of December 31, 2012, 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, 2012.

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 2012 sinking fund requirement by this means and, accordingly, the sinking fund requirement for 2012 is excluded from Current liabilities in the Consolidated Balance Sheets.  At December 31, 2012, $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 $2.8 billion at December 31, 2012.

Consolidated maturities of long-term debt during the five years following 2012 (in millions) are $106.4 in 2013, $30.0 in 2014, $279.8 in 2015, $73.0 in 2016, $75.0 in 2017, and $1,095.6 thereafter.

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Debt Guarantees

Vectren Corporation guarantees Vectren Capital’s long-term and short-term debt, which totaled $450 million and $162 million, respectively, at December 31, 2012.  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, 2012, totaled $821 million and $117 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, 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, 2012, the Company was in compliance with all debt covenants.

Short-Term Borrowings

At December 31, 2012, 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 $233 million was available for the Utility Group operations and approximately $88 million was available for the wholly owned Nonutility Group and corporate operations.  Both Vectren Capital’s and Utility Holdings’ short-term credit facilities were renewed in November 2011 and are available through September 2016.  The maximum limit of both facilities remained unchanged.  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.  

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

	Utility Group Borrowings									Nonutility Group Borrowings
(In millions)	2012			2011			2010			2012			2011			2010
Year End
Balance Outstanding	$	116.7		$	242.8		$	47.0		$	162.1		$	84.3		$	71.3
Weighted Average Interest Rate	0.40		%	0.57		%	0.41		%	1.35		%	1.45		%	2.01		%
Annual Average
Balance Outstanding	$	77.6		$	39.6		$	14.0		$	151.5		$	124.9		$	143.2
Weighted Average Interest Rate	0.47		%	0.48		%	0.40		%	1.44		%	1.92		%	0.93		%
Maximum Month End Balance Outstanding	$	214.2		$	242.8		$	47.0		$	216.1		$	180.1		$	174.6

Throughout 2012, 2011, and 2010, the Company has placed commercial paper without any significant issues and did not borrow from Utility Holdings' backup credit facility in any of the periods presented.

13.  Common Shareholders’ Equity

Authorized, Reserved Common and Preferred Shares

At December 31, 2012 and 2011, the Company was authorized to issue 480 million shares of common stock and 20 million shares of preferred stock.  Of the authorized common shares, approximately 6.5 million shares at December 31, 2012 and 6.8 million shares at December 31, 2011, were reserved by the board of directors for issuance through the Company’s share-based compensation plans, benefit plans, and dividend reinvestment plan.  At both December 31, 2012 and 2011, there were 391.3 million 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. Participating securities have declined over time as share based awards to employess that can be settled in shares and that participate in dividends have vested and replaced with awards where dividends are subject to forfeiture.

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, 2012:

	Year Ended December 31,
(In millions, except per share data)	2012		2011		2010
Numerator:
Numerator for basic EPS	$	159.0	$	141.6	$	133.6
Add back earnings attributable to participating securities	—		—		0.1
Reported net income (Numerator for Diluted EPS)	$	159.0	$	141.6	$	133.7
Denominator:
Weighted average common shares outstanding (Basic EPS)	82.0		81.8		81.2
Conversion of share based compensation arrangements	0.1		0.0		0.1
Adjusted weighted average shares outstanding and
assumed conversions outstanding (Diluted EPS)	82.1		81.8		81.3
Basic earnings per share	$	1.94	$	1.73	$	1.65
Diluted earnings per share	$	1.94	$	1.73	$	1.64

For the year ended December 31, 2012 and 2011 there were no antidilutive options outstanding.  For the year ended December 31, 2010, options to purchase 308,800 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 price for these options ranged from $24.90 to $27.15 for the year ended December 31, 2010.

15. Accumulated Other Comprehensive Income

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

	2010									2011						2012
	Beginning of Year			Changes During			End of Year			Changes During			End of Year			Changes During			End of Year
(In millions)	Balance			Year			Balance			Year			Balance			Year			Balance
Unconsolidated affiliates	$	(7.1	)	$	0.5		$	(6.6	)	$	(9.3	)	$	(15.9	)	$	11.3		$	(4.6	)
Pension & other benefit costs	(4.4		)	(0.5		)	(4.9		)	(1.7		)	(6.6		)	4.0			(2.6		)
Cash flow hedges	0.1			3.9			4.0			(3.9		)	0.1			(0.1		)	—
Deferred income taxes	4.6			(1.5		)	3.1			6.0			9.1			(6.2		)	2.9
Accumulated other comprehensive income (loss)	$	(6.8	)	$	2.4		$	(4.4	)	$	(8.9	)	$	(13.3	)	$	9.0		$	(4.3	)

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 share-based compensation programs to encourage Company officers, 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 has in the past issued stock options and both performance-based and time-based awards.  All share-based compensation programs are shareholder approved.  Currently, awards issued to officers of the Company, which comprise a substantial majority of the awards issued, are performance-based, are settled in cash, and dividends that accrue are also subject to performance measures. In addition, the Company maintains a deferred compensation plan for executives and non-employee directors where participants can invest earned compensation and vested share-based awards in phantom Company stock units, among other options.  Certain vesting grants 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)	2012		2011		2010
Total cost of share-based compensation	$	6.3	$	5.8	$	4.9
Less capitalized cost	1.2		0.8		1.7
Total in other operating expense	5.1		5.0		3.2
Less income tax benefit in earnings	2.1		2.0		1.3
After tax effect of share-based compensation	$	3.0	$	3.0	$	1.9

Performance Based Awards & Other Awards

The vesting of awards issued to Company officers and other key non-officer employees is contingent upon meeting a total return and/or return on equity performance objectives.  Grants to Company officers 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 have also been time-vested awards that vest ratably over a three year period.  In addition non-employee directors receive a portion of their fees in share based awards.  These awards to non-employee directors are not performance based and generally vest over one year.  Because Company officers and non-employee directors have the choice of settling awards in 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 awards separated between those accounted for as liabilities and equity as of December 31, 2012, and changes during the year ended December 31, 2012, follows:

	Equity Awards
		Wtd. Avg.
		Grant Date		Liability Awards
	Shares	Fair value		Shares/Units	Fair value
Awards at January 1, 2012	54,013	$	25.22	698,110
Granted	35,458	29.82		250,211
Vested	(2,635)	24.76		(149,374)
Forfeited	(16,343)	25.12		(170,137)
Awards at December 31, 2012	70,493	$	27.45	628,810	$	29.40

As of December 31, 2012, there was $8.1 million of total unrecognized compensation cost associated with outstanding grants.  That cost is expected to be recognized over a weighted-average period of 1.9 years.  The total fair value of shares vested for liability awards during the years ended December 31, 2012, 2011, and 2010, was $4.4 million, $3.0 million, and $5.0 million,

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respectively.  The total fair value of equity awards vesting during the year ended December 31, 2012, 2011, and 2010 was $0.1 million, $0.2 million, $0.2 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, 2012, and changes during the year ended December 31, 2012, follows:

		Weighted average			Aggregate
	Shares	Exercise Price		Remaining Contractual Term (years)	Intrinsic Value (In millions)
Outstanding at January 1, 2012	407,633	$	25.74
Exercised	(21,068)	$	23.18
Outstanding at December 31, 2012	386,565	$	25.88	1.6	$	1.4
Exercisable at December 31, 2012	386,565	$	25.88	1.6	$	1.4

The total intrinsic value of options exercised during the year ended December 31, 2012 , 2011, and 2010 was $0.1 million, $2.4 million, and $1.3 million respectively.  The actual tax benefit realized for tax deductions from option exercises was approximately $0.1 million , $1.0 million, and $0.5 million in 2012 , 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, 2012 , 2011, and 2010 the Company received cash upon exercise of stock options totaling approximately $0.3 million , $12.3 million, and $9.5 million respectively.  During these periods, the Company repurchased shares totaling approximately $0.1 million , $12.8 million, and $1.2 million respectively.  

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 share-based compensation.  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, 2012 and 2011, the liability associated with these plans totaled $22.9 million and $21.1 million, respectively.  Other than $1.3 million and $0.7 million which are classified in Accrued liabilities at December 31, 2012 and 2011, respectively, the liability is included in Deferred credits & other liabilities.  The impact of these plans on Other operating expenses was expense of $1.7 million in 2012, $2.1 million in 2011 and $2.3 million in 2010.  The amount recorded in earnings related to the investment activities in Vectren phantom stock associated with these plans during the years ended December 31, 2012, 2011, and 2010, was a cost of $0.6 million, $1.7 million and $1.6 million, respectively.

The Company has certain investments currently funded primarily through corporate-owned life insurance policies.  These investments, which are consolidated, are available to pay deferred compensation benefits.  These investments are also subject to the claims of the Company's creditors.  The cash surrender value of these policies included in Other corporate & utility investments on the Consolidated Balance Sheets were $29.1 million and $27.3 million at December 31, 2012 and 2011, respectively.  Earnings from those investments, which are recorded in Other-net, were earnings of $1.8 million in 2012, $0.1 million in 2011, and $1.9 million in 2010. 

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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 2012 and thereafter (in millions) are $6.8 in 2013, $5.5 in 2014, $3.8 in 2015, $2.2 in 2016, $1.2 in 2017, and $3.3 thereafter.  Total lease expense (in millions) was $8.5 in 2012, $6.9 in 2011, and $7.3 in 2010.

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, 2012, parent level guarantees support a maximum of $25 million of ESG’s performance contracting commitments and warranty obligations and $28 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 $24 million of other guarantees outstanding supporting other consolidated subsidiary operations, of which $18 million represent letters of credit supporting other nonutility operations.  Guarantees issued and outstanding on behalf of unconsolidated affiliates approximated $3 million at December 31, 2012.  These guarantees relate primarily to arrangements between ProLiance and various natural gas pipeline operators.  The Company has not been called upon to satisfy any obligations pursuant to these parental guarantees and has accrued no significant liabilities related to these guarantees.

Performance Guarantees & Product Warranties

In the normal course of business, 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, 2012, there are 62 open surety bonds supporting future performance.  The average face amount of these obligations is $5.2 million, and the largest obligation has a face amount of $57.3 million.  The maximum exposure from these obligations is limited by the level of work already completed and guarantees issued to ESG by various subcontractors. At December 31, 2012, approximately 56 percent of work was completed on projects with open surety bonds.  A significant portion of these open surety bonds will be released 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, 2012. In addition, ESG has an $8 million stand-alone letter of credit facility and as of December 31, 2012, $3.4 million was outstanding.

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. Rate & Regulatory Matters

Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement

Vectren monitors and maintains its natural gas distribution system to ensure that natural gas is delivered in a safe and efficient manner. Vectren's natural gas utilities are currently engaged in replacement programs in both Indiana and Ohio, the primary purpose of which is preventive maintenance and continual renewal and operational improvement.  In 2011, 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 capital investment projects, outside of a base rate proceeding.  Utilization of these recovery mechanisms is discussed below.

Ohio Recovery and Deferral Mechanisms

The PUCO order approving the Company's 2009 base rate case in the Ohio service territory authorized a distribution replacement rider (DRR). The DRR's primary purpose is recovery of investments in utility plant and related operating expenses associated with replacing bare steel and cast iron pipelines and certain other infrastructure. This rider is updated annually for qualifying capital expenditures and allows for a return to be earned on those capital expenditures based upon the rate of return approved in the 2009 base rate case. In addition, deferral of depreciation and the ability to accrue debt-related post in service carrying costs is also allowed until the related capital expenditures are recovered through the DRR. To date, the Company has made capital investments under this rider totaling $80 million. During 2012, 2011, and 2010 gas operating revenues associated with the DRR were $6.5 million, $3.6 million, and $1.4 million, respectively. Other Income associated with the debt-related post in service carrying costs totaled $1.8 million, $2.0 million, and $0.9 million for 2012, 2011, and 2010, respectively. Regulatory assets associated with post in service carrying costs and depreciation deferrals were $6.5 million, $3.0 million, and $1.0 million at December 31, 2012, 2011, and 2010, respectively.

In June 2011, Ohio House Bill 95 was signed into law. Outside of a base rate proceeding, this legislation permits a natural gas company to apply for recovery of much of its capital expenditure program. Once such application is approved, the legislation authorizes a deferral of costs, such as depreciation, property taxes, and debt-related carrying costs. On December 12, 2012, the PUCO issued an order approving the Company's initial application using this law. The order provides for the deferral of depreciation, debt-related post in service carrying costs, and property taxes for its $23.5 million capital expenditure program covering the fifteen month period ending December 31, 2012. Such capital expenditures include infrastructure expansion and improvements not covered by the DRR as well as expenditures necessary to comply with PUCO rules, regulations, orders, and system expansion to some new customers. The order also established a prospective bill impact evaluation on the cumulative deferrals, limiting the total deferrals at a level which would equal $1.50 per residential and general service customer per month. The order created a regulatory asset as of December 31, 2012 of $1.5 million, of which $0.9 million is Other Income related to the accrual of post in service carrying costs, and the remaining $0.6 million is the deferral of depreciation and property tax expense. The Company expects to make a future request for similar accounting authority on its capital expenditure program for the calendar year 2013.

Indiana Recovery and Deferral Mechanisms

The Company's Indiana natural gas utilities received orders in 2008 and 2007 associated with the most recent base rate cases. These orders authorized the deferral of financial impacts associated with bare steel and cast iron replacement activities. The orders provide for the deferral of depreciation and post in service carrying costs on qualifying projects totaling $20 million annually at Vectren North and $3 million annually at Vectren South. For USGAAP accounting purposes only the debt-related post in service carrying costs are recognized in the Consolidated Statements of Income currently. Such deferral is limited by individual qualifying project to three years after being placed into service at Vectren South and four years after being placed into service at Vectren North. The debt-related post in service rate used to calculate the deferral is based on a current cost of funds. At December 31, 2012 and 2011, the Company has USGAAP regulatory assets totaling $8.5 million and $4.7 million, respectively, associated with the deferral of depreciation and debt-related post in service carrying cost activities.

In April 2011, Senate Bill 251 was signed into Indiana law. The law 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 a return on the federally mandated capital investment, along with recovery of depreciation and other operating costs associated with these mandates. The remaining 20 percent of those costs are to be deferred for future recovery in the utility's next general rate case.

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To date, the Company has not initiated a filing requesting authority to recover costs using the Senate Bill 251 approach and continues to study its applicability to expenditures associated with its natural gas distribution operations.

Pipeline Safety Law

On January 3, 2012, the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 (Pipeline Safety Law) was signed into law. The Pipeline Safety 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 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 over the next two years Those regulations may eventually lead to further regulatory or statutory requirements.

The Company continues to study the impact of the Pipeline Safety 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 law is expected to result in further investment in pipeline inspections, and where necessary, additional investments in 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 by approximately $9 million annually, with $6 million attributable to the Indiana operations. Related to the Indiana operations, the Company expects to seek recovery under Senate Bill 251, or such costs may be recoverable through current tracking mechanisms. Capital investments, associated with the Pipeline Safety Law, are expected to be significant. 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 or other currently authorized recovery mechanisms, such as the Distribution Replacement Rider, in Ohio.

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 provided for a 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, provided for deferred accounting treatment related to the Company's estimated $32 million investment in dense pack technology, of which approximately $25.5 million has been invested as of December 31, 2012. In addition, the IURC 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 (RFP) in April 2011 regarding coal purchases for a four year period beginning in 2012. After negotiations with bidders, Vectren South 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 2011 RFP.  In March 2012, the IURC issued its order in the sub docket which concluded that Vectren South’s 2011 RFP process resulted in the lowest fuel cost reasonably possible.  In late 2012, Vectren South terminated its contract with one of the suppliers due to coal quality issues that were identified during test burns of the coal. In addition to coal purchased under these contracts, Vectren South has also contracted with Vectren Fuels, Inc. to purchase lower priced spot coal. This spot purchase was found to be reasonable in a recent FAC order. The IURC will continue to regularly monitor Vectren South’s procurement process in future fuel adjustment proceedings.

Delivery to Vectren's power plants of lower-priced contract coal from the April 2011 RFP process began during 2012. On December 5, 2011 within the quarterly FAC filing, Vectren South submitted a joint proposal with the OUCC to reduce its fuel

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costs billed to customers by accelerating into 2012 the impact of lower cost coal under these new term contracts effective after 2012. The cost difference will be deferred to a regulatory asset and recovered over a six-year period without interest beginning in 2014.  The IURC approved this proposal on January 25, 2012, with the reduction to customer’s rates effective February 1, 2012.  The deferred amount includes a reduction in the value of the coal inventory at December 31, 2011 of approximately $17.7 million to reflect existing coal inventory at the new, lower price.  Deferrals related to coal purchases in 2012 have totaled approximately $24.7 million, bringing the total deferred balance as of December 31, 2012, to the expected level of $42.4 million.

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 were 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 complied 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 $3 million in 2012 and $1 million in 2011 associated with small customer DSM programs for subsequent recovery under a tracking mechanism to be proposed by the Company.  On June 20, 2012, the IURC issued an order approving a small customer lost margin recovery mechanism, inclusive of all previous deferrals. This mechanism is an alternative to the electric decoupling proposal that was denied by the IURC in the Company's last base rate proceeding discussed earlier. 

Vectren North Pipeline Safety Investigation

On April 11, 2012, the IURC's pipeline safety division filed a complaint against Vectren North alleging several violations of safety regulations pertaining to damage that occurred at a residence in Vectren North's service territory during a pipeline replacement project. The Company negotiated a settlement with the IURC's pipeline safety division, agreeing to a fine and several modifications to the Company's operating policies. The amount of the fine was not material to the Company's financial results. The IURC approved the settlement but modified certain terms of the settlement and added a requirement that Company employees conduct inspections of pipeline excavations. The Company sought and was granted a request for rehearing on the sole issue related to the requirement to use Company employees to inspect excavations. The Company seeks further clarity on the scope of the requirement and the ability to also use contractors to perform certain inspections. A procedural schedule is expected to be established in late February 2013.

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 for residential base rates in February 2010, nearly 90 percent of the combined residential and commercial base rate gas margins were recovered

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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.

VEDO Continues the Process to Exit the Merchant Function

On April 30, 2008, the PUCO issued an order which approved the first two phases of a three phase plan to exit the merchant function in the Company's Ohio service territory. As a result, substantially all of the Company's Ohio customers now purchase natural gas directly from retail gas marketers rather than from the Company. The PUCO provided for an Exit Transition Cost rider, which allows the Company to recover costs associated with the first two phases of 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 as VEDO, for the most part, no longer purchases gas for resale.

19.  Environmental Matters

Indiana Senate Bill 251 is also applicable to federal environmental mandates impacting Vectren South's electric operations. The Company is currently evaluating the impact Senate Bill 251 may have on its operations, including applicability to the stricter regulations the EPA is currently considering involving air quality, fly ash disposal, cooling tower intake facilities, waste water discharges, and greenhouse gases. These issues are further discussed below.

Air Quality

Clean Air Interstate Rule / Cross-State Air Pollution Rule

In July 2011, the EPA finalized the Cross-State Air Pollution Rule (CSAPR).  CSAPR was 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 SO₂ and NOx allowances, CSAPR reduced the ability of facilities to meet emission reduction targets through allowance trading.  Like CAIR, CSAPR set individual state caps for SO₂ and NOx emissions.  However, unlike CAIR in which states allocated allowances to generating units through state implementation plans, CSAPR allowances were allocated to individual units directly through the federal rule.  CSAPR reductions were to be achieved with initial step reductions beginning January 1, 2012, and final compliance to be achieved in 2014.  Multiple administrative and judicial challenges were filed. On December 30, 2011, the Court granted a stay of CSAPR and left CAIR in place pending its review. On August 21, 2012, the Court vacated CSAPR and directed the EPA to continue to administer CAIR. In October 2012, the EPA filed its request for a hearing before the full federal appeals court that struck down the CSAPR.  EPA's request for rehearing was denied by the Court on January 24, 2013. The Company remains in full compliance with CAIR (see additional information below "Conclusions Regarding Air Regulations").

Mercury and Air Toxics (MATS) Rule

On December 21, 2011, the EPA finalized the Utility MATS Rule.  The MATS 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 MATS 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 (April 2015).  Initiatives to suspend CSAPR’s implementation by the Congress also apply to the implementation of the MATS rule.  Multiple judicial challenges were filed and briefing is proceeding. The EPA also recently announced it will reconsider MATS requirements for new construction. Such

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requirements are more stringent than those for existing plants. Utilities planning new coal-fired generation had argued standards outlined in the MATS could not be attained even using the best available control technology.

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 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 the MATS Rule and the 2015 requirement imposed by CAIR.  Based upon an initial review, the Company believes that it will be able to meet these requirements with its existing suite of pollution control equipment.  However, it is possible some operational modifications to the control equipment will be required. Additional capital investments, operating expenses, and possibly the purchase of emission allowances may be required and could be significant depending on the required method of compliance with the requirements.  While the Company has not yet quantified what the additional costs may be associated with these efforts, because the compliance is required by government regulation the Company believes that such additional costs, if incurred, should be recoverable under Indiana Senate Bill 251 referenced above.

Notice of Violation Received

The Company received a notice of violation (NOV) from the EPA in November 2011 pertaining to its A.B. Brown power plant.  The NOV asserts that when the power plant was equipped with SCRs the correct permits were not obtained or the best available control technology to control incidental sulfuric acid mist was not installed.  Based on the Company’s understanding of the New Source Review reform in effect when the equipment was installed, it is the Company’s position that its SCR project was exempted from such requirements.  At this time the Company is reviewing the potential impact this NOV could have on capital expenditures and operating costs.  To the extent costs to comply increase, they should be recoverable under Indiana law.

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 2013.  Depending on the final rule and on the Company’s facts and circumstances, capital investments could approximate $40 million if new infrastructure, such as new cooling water towers, is required.  Costs for compliance with these final regulations should qualify as federally mandated regulatory requirements and be recovered under Indiana Senate Bill 251 referenced above.

Under the Clean Water Act, EPA sets technology-based guidelines for water discharges from new and existing facilities. EPA is currently in the process of revising the existing steam electric effluent limitation guidelines that set the technology-based water discharge limits for the electric power industry. EPA is focusing its rulemaking on wastewater generated primarily by pollution control equipment necessitated by the comprehensive air regulations. EPA is under an April 19, 2013 deadline to complete its rule proposal. It is not possible to estimate what potential costs may be required to meet these new water discharge limits,

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however costs for compliance with these regulations should qualify as federally mandated regulatory requirements and be recovered under 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 have not been finalized 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 modification to, 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 should qualify as federally mandated regulatory requirements and be recovered 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.  EPA's PSD and Title V permitting rules for GHG's were recently upheld by the US Court of Appeals for the District of Columbia. In 2012, the EPA proposed New Source Performance Standards for greenhouse gases for new electric generating facilities under Clean Air Act Section 111(b). While standards for new sources are not yet final, EPA has signaled its intent to propose New Source Performance Standards for greenhouse gases for existing electric generating units under Section 111(d), which would be applicable to the Company's existing units. The Company anticipates that these initial standards will focus on power plant efficiency and other coal fleet carbon intensity reduction measures. The Company believes that such additional costs, if necessary, should be recoverable under Indiana Senate Bill 251 referenced above.

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

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be considered a cost of providing electricity, and as such, the Company believes such costs and expenditures should be recoverable from customers through Senate Bill 251. 

Senate Bill 251 also established 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 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 which are defined as clean energy in the legislation, the Company currently has approximately 5 percent of its electricity being provided by clean energy sources due to the long-term wind contracts and landfill gas investment. The Company continues to evaluate whether to participate in this voluntary program.

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.

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 plant 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 has incurred or reasonably expects to incur totaling approximately $41.7 million ($23.2 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.  Likewise, SIGECO has settlement agreements with all known insurance carriers and has received to date approximately $14 million of the expected $15 million in 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 remedial activities which are not presently foreseen and those costs may not be subject to PRP or insurance recovery.  As of December 31, 2012 and 2011, approximately $4.6 million and $6.5 million, respectively, of accrued, but not yet spent, costs are included in Other Liabilities related to both the Indiana Gas and SIGECO sites.

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20.  Fair Value Measurements

The carrying values and estimated fair values using primarily Level 2 assumptions of the Company's other financial instruments follow:

	At December 31,
	2012				2011
(In millions)	Carrying Amount		Est. Fair Value		Carrying Amount		Est. Fair Value
Long-term debt	$	1,659.8	$	1,873.3	$	1,622.3	$	1,804.4
Short-term borrowings & notes payable	278.8		278.8		227.1		227.1
Cash & cash equivalents	19.5		19.5		8.6		8.6

For the balance sheets presented, the Company had no material assets or liabilities marked to fair value.

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 certain other 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, 2012 and 2011, the fair value for these financial instruments was not estimated.  The carrying value of these investments was approximately $2.1 million at both December 31, 2012 and 2011.

21. 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.  The sale of Vectren Source was completed on December 31, 2011 (See

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Note 6) and the results of Vectren Source's operations are included in the Energy Marketing operating segment in 2011 and 2010. Information related to the Company’s business segments is summarized as follows:

	Year Ended December 31,
(In millions)	2012			2011			2010
Revenues
Utility Group
Gas Utility Services	$	738.1		$	819.1		$	954.1
Electric Utility Services	594.9			635.9			608.0
Other Operations	40.1			43.9			44.5
Eliminations	(39.5		)	(41.9		)	(42.9		)
Total Utility Group	1,333.6			1,457.0			1,563.7
Nonutility Group
Infrastructure Services	663.6			421.3			235.6
Energy Services	117.7			161.8			146.9
Coal Mining	235.8			285.6			209.9
Energy Marketing	—			149.9			142.8
Other Businesses	0.5			—			—
Total Nonutility Group	1,017.6			1,018.6			735.2
Eliminations	(118.4		)	(150.4		)	(169.4		)
Consolidated Revenues	$	2,232.8		$	2,325.2		$	2,129.5
Profitability Measures - Net Income
Utility Group Net Income
Gas Utility Services	$	60.0		$	52.5		$	53.7
Electric Utility Services	68.0			65.0			60.9
Other Operations	10.0			5.4			9.3
Total Utility Group Net Income	138.0			122.9			123.9
Nonutility Group Net Income (Loss)
Infrastructure Services	40.5			14.9			3.1
Energy Services	5.7			6.7			6.4
Coal Mining	(3.5		)	16.6			11.9
Energy Marketing	(17.6		)	(4.2		)	(4.2		)
Other Businesses	(3.4		)	(10.2		)	(7.4		)
Total Nonutility Group Net Income	21.7			23.8			9.8
Corporate & Other Net Loss	(0.7		)	(5.1		)	—
Consolidated Net Income	$	159.0		$	141.6		$	133.7

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	Year Ended December 31,
(In millions)	2012			2011			2010
Amounts Included in Profitability Measures
Depreciation & Amortization
Utility Group
Gas Utility Services	$	85.4		$	84.3		$	80.7
Electric Utility Services	81.3			80.2			80.8
Other Operations	23.3			27.8			26.7
Total Utility Group	190.0			192.3			188.2
Nonutility Group
Infrastructure Services	20.7			14.9			8.8
Energy Services	1.9			1.5			1.2
Coal Mining	41.8			35.1			30.4
Energy Marketing	—			0.5			0.5
Other Businesses	0.2			—			—
Total Nonutility Group	64.6			52.0			40.9
Consolidated Depreciation & Amortization	$	254.6		$	244.3		$	229.1
Interest Expense
Utility Group
Gas Utility Services	$	31.8		$	37.1		$	38.8
Electric Utility Services	33.8			36.4			36.4
Other Operations	5.9			6.8			6.2
Total Utility Group	71.5			80.3			81.4
Nonutility Group
Infrastructure Services	7.5			7.4			3.3
Energy Services	0.4			0.6			0.2
Coal Mining	11.5			11.3			10.1
Energy Marketing	4.8			6.4			8.5
Other Businesses	0.7			1.3			1.5
Total Nonutility Group	24.9			27.0			23.6
Corporate & Other	(0.4		)	(0.8		)	(0.4		)
Consolidated Interest Expense	$	96.0		$	106.5		$	104.6
Income Taxes
Utility Group
Gas Utility Services	$	39.1		$	34.5		$	35.1
Electric Utility Services	46.4			45.3			40.8
Other Operations	(0.2		)	3.1			1.2
Total Utility Group	85.3			82.9			77.1
Nonutility Group
Infrastructure Services	29.6			10.7			2.7
Energy Services	(9.0		)	1.1			2.5
Coal Mining	(8.6		)	3.9			1.9
Energy Marketing	(11.7		)	(2.4		)	(2.7		)
Other Businesses	(2.0		)	(7.0		)	(5.9		)
Total Nonutility Group	(1.7		)	6.3			(1.5		)
Corporate & Other	(1.1		)	(2.8		)	(0.9		)
Consolidated Income Taxes	$	82.5		$	86.4		$	74.7

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	Year Ended December 31,
(In millions)	2012			2011			2010
Capital Expenditures
Utility Group
Gas Utility Services	$	128.8		$	113.5		$	88.7
Electric Utility Services	108.8			102.2			120.1
Other Operations	16.2			17.8			22.5
Non-cash costs & changes in accruals	(7.8		)	(0.1		)	(6.2		)
Total Utility Group	246.0			233.4			225.1
Nonutility Group
Infrastructure Services	53.7			22.8			12.0
Energy Services	2.3			9.7			1.2
Coal Mining	63.8			55.1			38.7
Energy Marketing	—			0.3			0.2
Total Nonutility Group	119.8			87.9			52.1
Consolidated Capital Expenditures	$	365.8		$	321.3		$	277.2
	At December 31,
(In millions)	2012			2011			2010
Assets
Utility Group
Gas Utility Services	$	2,173.5		$	2,125.2		$	2,161.7
Electric Utility Services	1,705.1			1,656.5			1,666.5
Other Operations, net of eliminations	168.2			192.8			96.3
Total Utility Group	4,046.8			3,974.5			3,924.5
Nonutility Group
Infrastructure Services	420.0			295.0			174.6
Energy Services	69.7			81.2			67.4
Coal Mining	380.0			352.8			362.5
Energy Marketing	73.9			112.5			209.1
Other Businesses, net of eliminations and reclassifications	37.1			46.8			54.9
Total Nonutility Group	980.7			888.3			868.5
Corporate & Other	785.6			727.3			706.2
Eliminations	(724.0		)	(711.2		)	(735.0		)
Consolidated Assets	$	5,089.1		$	4,878.9		$	4,764.2

22.  Additional Balance Sheet & Operational Information

Inventories consist of the following:

	At December 31,
(In millions)	2012		2011
Gas in storage – at LIFO cost	$	22.4	$	31.8
Coal & oil for electric generation - at average cost	52.0		60.6
Materials & supplies	57.6		54.9
Nonutility coal - at LIFO cost	25.4		13.0
Other	1.2		1.6
Total inventories	$	158.6	$	161.9

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, 2012, and 2011, by approximately $12.7 million and $12.0 million, respectively.

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Prepayments & other current assets consist of the following:

	At December 31,
(In millions)	2012		2011
Prepaid gas delivery service	$	28.5	$	42.4
Deferred income taxes	—		16.0
Prepaid taxes	26.4		5.1
Other prepayments & current assets	18.4		20.8
Total prepayments & other current assets	$	73.3	$	84.3

Investments in unconsolidated affiliates consist of the following:

	At December 31,
(In millions)	2012		2011
ProLiance Holdings, LLC	$	73.9	$	85.4
Other nonutility partnerships & corporations	4.0		7.3
Other utility investments	0.2		0.2
Total investments in unconsolidated affiliates	$	78.1	$	92.9

Other utility & corporate investments consist of the following:

	At December 31,
(In millions)	2012		2011
Cash surrender value of life insurance policies	$	29.1	$	27.3
Municipal bond	3.6		3.9
Restricted cash & other investments	1.9		3.2
Other utility & corporate investments	$	34.6	$	34.4

Goodwill by operating segment follows:

	At December 31,
(In millions)	2012		2011
Utility Group
Gas Utility Services	$	205.0	$	205.0
Nonutility Group
Infrastructure Services	55.2		55.2
Energy Services	2.1		2.1
Consolidated goodwill	$	262.3	$	262.3

Accrued liabilities consist of the following:

	At December 31,
(In millions)	2012		2011
Refunds to customers & customer deposits	$	53.1	$	56.4
Accrued taxes	34.4		33.5
Accrued interest	23.1		21.7
Deferred compensation & post-retirement benefits	6.8		6.5
Deferred income taxes	14.9		—
Accrued salaries & other	66.5		63.0
Total accrued liabilities	$	198.8	$	181.1

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Asset retirement obligations roll forward as follows:

(In millions)	2012			2011
Asset retirement obligation, January 1	$	43.7		$	38.7
Accretion	2.7			2.5
Changes in estimates, net of cash payments	(8.7		)	2.5
Asset retirement obligation, December 31	37.7			43.7
Accrued liabilities	$	—		$	0.2
Deferred credits & other liabilities	$	37.7		$	43.5

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

	Year Ended December 31,
(In millions)	2012			2011			2010
ProLiance Holdings, LLC	$	(22.7	)	$	(28.6	)	$	(2.5	)
Haddington Energy Partners, LP	(0.7		)	—			(6.1		)
Other	0.1			(3.4		)	—
Total equity in (losses) of unconsolidated affiliates	$	(23.3	)	$	(32.0	)	$	(8.6	)

Other income (expense) – net consists of the following:

	Year Ended December 31,
(In millions)	2012			2011			2010
AFUDC – borrowed funds	$	4.6		$	2.5		$	1.4
AFUDC – equity funds	0.4			0.2			0.3
Nonutility plant capitalized interest	1.8			2.1			2.1
Interest income, net	1.1			1.4			1.7
Other nonutility investment impairment charges	(2.7		)	(9.9		)	(4.7		)
Cash surrender value of life insurance policies	1.8			0.1			1.9
All other income	1.3			0.1			2.1
Total other income (expense) – net	$	8.3		$	(3.5	)	$	4.8

Supplemental Cash Flow Information:

	Year Ended December 31,
(In millions)	2012		2011			2010
Cash paid (received) for:
Interest	$	94.6	$	108.6		$	104.5
Income taxes	21.8		(9.0		)	8.1

As of December 31, 2012 and 2011, the Company has accruals related to utility and nonutility plant purchases totaling approximately $11.1 million and $15.9 million, respectively.

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23. Impact of Recently Issued Accounting Guidance

Other Comprehensive Income (OCI)

In 2011, the FASB issued new accounting guidance regarding the presentation of comprehensive income within financial statements.  The new guidance requires 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 adopted this guidance, as amended for condensed quarterly reporting, for the quarterly reporting period ended March 31, 2012 by reporting comprehensive income as required.

Goodwill Testing

In September 2011, the FASB issued new accounting guidance regarding testing goodwill for impairment.  The new guidance allows 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 Company considered this option during its quarterly reporting period ended March 31, 2012 and concluded the continuation of the use of a quantitative approach is appropriate.

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 Company adopted this guidance for its quarterly reporting period ended March 31, 2012.  The adoption of this guidance did not have a material impact on our financial position, results of operations or cash flows.

24. 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 2012 and 2011 follows:

(In millions, except per share amounts)		Q1		Q2		Q3		Q4
2012
	Operating revenues	$	604.6	$	470.6	$	513.5	$	644.1
	Operating income	109.9		70.2		81.6		90.8
	Net income	51.3		25.6		39.3		42.8
	Earnings per share:
	Basic	$	0.63	$	0.31	$	0.48	$	0.52
	Diluted	0.62		0.31		0.48		0.52
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

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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, 2012, 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, 2012, 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, 2012, 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, 2012.

The effectiveness of internal control over financial reporting as of December 31, 2012, 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 2013 Annual Meeting of Shareholders, 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; the charters for each committee of the Board of Directors; its Corporate Code of Conduct that covers the Company’s officers and employees; and its Board Code of Ethics and Code of Conduct that

107

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 acknowledgements 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.

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 2013 Annual Meeting of Shareholders, 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 2013 Annual Meeting of Shareholders, 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, 2012, 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	386,565	(1)	$	25.88	(1)	3,598,059	(2)
Equity compensation plans not approved
by security holders	—		—			—
Total	386,565		$	25.88		3,598,059

(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, 2013, 261,220 performance-based and time-based units were issued to management by the Compensation and Benefits Committee of the Board of Directors.  In addition, participants forfeited 48,244 performance awards measured during the three year performance period ending December 31, 2012 which do not vest until December 31, 2013.  These issuances and forfeitures 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.

108

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 2013 Annual Meeting of Shareholders, 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 2013 Annual Meeting of Shareholders, which will be filed with the Securities and Exchange Commission pursuant to Regulation 14A, within 120 days after the end of the fiscal year.

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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 reports 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, 2012, 2011, and 2010, the Company’s Schedule II -- Valuation and Qualifying Accounts Consolidated Financial Statement Schedules is presented herein.  The report of Deloitte & Touche LLP on the schedule may be found in Item 8.  All other schedules are omitted as the required information is inapplicable or the information is presented in the Consolidated Financial Statements or related notes in Item 8.

SCHEDULE II

Vectren Corporation and Subsidiaries

VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

Column A	Column B		Column C				Column D		Column E
			Additions
	Balance at		Charged		Charged		Deductions		Balance at
	Beginning		to		to Other		from		End of
Description	of Year		Expenses		Accounts		Reserves, Net		Year
(In millions)
VALUATION AND QUALIFYING ACCOUNTS:
Year 2012 – Accumulated provision for
uncollectible accounts	$	6.7	$	8.2	$	—	$	8.1	$	6.8
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 2012 – Reserve for impaired
notes receivable	$	15.7	$	0.5	$	—	$	15.6	$	0.6
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
OTHER RESERVES:
Year 2012 – Restructuring costs	$	0.4	$	—	$	—	$	0.1	$	0.3
Year 2011 – Restructuring costs	$	0.4	$	—	$	—	$	—	$	0.4
Year 2010 – Restructuring costs	$	0.5	$	—	$	—	$	0.1	$	0.4

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List of Exhibits

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

Vectren Corporation

Form 10-K

Attached Exhibits

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

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

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

Exhibit Number	Document
10.1	Amendment Number One to Vectren Corporation Specimen Change in Control Agreement
10.2	Vectren Corporation At Risk Compensation Plan specimen unit award agreement for officers, effective January 1, 2013
10.3	Gas Sales and Portfolio Administration Agreement between Indiana Gas Company, Inc. and ProLiance Energy, LLC, effective April 1, 2012
10.4	Gas Sales and Portfolio Administration Agreement between Southern Indiana Gas and Electric Company and ProLiance Energy, LLC, effective April 1, 2012
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

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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 September 5, 2012.  (Filed and designated in Current Report on Form 8-K filed October 1, 2012, 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)

4.2 Indenture dated February 1, 1991, between Indiana Gas and U.S. Bank Trust National Association (formerly known as First Trust National Association, which was formerly known as Bank of America Illinois, which was formerly known 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.)

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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)

4.10 Note Purchase Agreement, dated December 20, 2012, 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 December 21, 2012 File No. 1-15467, as Exhibit 4.1)

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.)

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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 performance award 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 performance award unit 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 At Risk Compensation Plan specimen unit award agreement for officers, effective January 31, 2013. (Filed herewith as Exhibit 10.2)

10.13 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.

10.14 Amendment number one to Vectren Corporation specimen change in control agreement dated December 31, 2012.  (Filed herewith, as Exhibit 10.1)  

10.15 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.  

10.16 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.)

10.17 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.)

10.18 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.)

10.19 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.)

114

10.20 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)

10.21 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.

10.22 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.

10.23 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.

10.24 Gas Sales and Portfolio Administration Agreement between Indiana Gas Company, Inc. and ProLiance Energy, LLC, effective April 1, 2012.  (Filed herewith as Exhibit 10.3)

10.25 Gas Sales and Portfolio Administration Agreement between Southern Indiana Gas and Electric Company and ProLiance Energy, LLC, effective April 1, 2012.  (Filed herewith as Exhibit 10.4)

10.26 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.)

10.27 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)

10.28 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)

10.29 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)

10.30 First Amendment to Credit Agreement, dated September 30, 2010, among Vectren Capital Corp., and each of the financial institutions named therein.  (Filed and designated in Form 10-K, for the year ended December 31, 2011, File No. 1-15467, as Exhibit 10.1)

10.31 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)

10.32 Vectren Capital Three Year Term Loan Agreement, dated November 1, 2012  (Filed and designated in Form 10-Q, for the period ended September 30, 2012, File No. 1-15467, as Exhibit 10.1)

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.)

115

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.)

101Interactive Data File

101.INS  XBRL Instance Document (Filed herewith.)

101.SCH  XBRL Taxonomy Extension Schema (Filed herewith.)

101.CAL   XBRL Taxonomy Extension Calculation Linkbase (Filed herewith.)

101.DEF   XBRL Taxonomy Extension Definition Linkbase (Filed herewith.)

101.LAB   XBRL Taxonomy Extension Labels Linkbase (Filed herewith.)

101.PRE   XBRL Taxonomy Extension Presentation Linkbase (Filed herewith.)

116

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 15, 2013  /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 15, 2013
Carl L. Chapman	(Principal Executive Officer)
/s/ Jerome A. Benkert, Jr.	Executive Vice President and Chief Financial Officer	February 15, 2013
Jerome A. Benkert, Jr.	(Principal Financial Officer)
/s/ M. Susan Hardwick	Vice President, Controller and Assistant Treasurer	February 15, 2013
M. Susan Hardwick	(Principal Accounting Officer)
/s/ James H. DeGraffenreidt	Director	February 15, 2013
James H. DeGraffenreidt
/s/ Niel C. Ellerbrook	Director	February 15, 2013
Niel C. Ellerbrook
/s/ John D. Engelbrecht	Director	February 15, 2013
John D. Engelbrecht
/s/ Anton H. George	Director	February 15, 2013
Anton H. George
/s/ Martin C. Jischke	Director	February 15, 2013
Martin C. Jischke

117

/s/ Robert G. Jones	Director	February 15, 2013
Robert G. Jones
/s/ J. Timothy McGinley	Director	February 15, 2013
J. Timothy McGinley
/s/ R. Daniel Sadlier	Director	February 15, 2013
R. Daniel Sadlier
/s/ Michael L. Smith	Director	February 15, 2013
Michael L. Smith
/s/ Jean L. Wojtowicz	Director	February 15, 2013
Jean L. Wojtowicz

118

EX-10.1

Exhibit 10.1

AMENDMENT NUMBER ONE

TO THE VECTREN CORPORATION

CHANGE IN CONTROL AGREEMENT

This Amendment Number One to the Vectren Corporation Change in Control Agreement (this “Amendment”) is entered into to be effective as of December 31, 2012 (the “Effective Date”) between Vectren Corporation (the “Company”) and __________ (the “Executive”).

WHEREAS, the Company and the Executive are parties to the Vectren Corporation Change in Control Agreement dated as of December 31, 2011 (the “Original Agreement”); and

WHEREAS, the Company and the Executive desire to amend the Original Agreement.

NOW, THEREFORE, for good and valuable consideration, the receipt and sufficiency of which is hereby acknowledged, the parties agree as follows:

1.The introduction paragraph of Section 2(a) of the Original Agreement is hereby amended and restated to read as follows:

“The Company shall pay, or cause the appropriate Affiliate to pay, to the Executive in a lump sum in cash sixty calendar days after the Date of Termination the aggregate of the amounts set forth in clauses (i) and (ii) below:”

2.This Amendment is to be effective on the Effective Date. Except as specifically amended herein, all other terms and conditions contained in the Original Agreement shall remain unchanged and shall continue in full force and effect.

3.This Amendment may be executed in one or more counterparts, each of which when taken together shall be deemed one original Amendment.

IN WITNESS WHEREOF, the Executive has hereunto set the Executive's hand and the Company has caused these presents to be executed in its name on its behalf, all as of the day and year first above written.

_________________, the Executive

Vectren Corporation

By:

An Authorized Representative

EX-10.2

Exhibit 10.2

VECTREN CORPORATION

AT RISK COMPENSATION PLAN

STOCK UNIT AWARDS

AWARD AGREEMENT

(OFFICER)

Name of Grantee:No. of Units:

Date of Grant: January 1, 2013

__________ (“Grantee”) is hereby granted on January 1, 2013 (the “Grant Date”) under Section 7.3 of the Vectren Corporation At Risk Compensation Plan (the “Plan”) a grant of _____ Stock Unit Awards on the following terms and conditions:

1.Restriction.

(A) Value of the Stock Unit Award. Subject to approval by the Compensation and Benefits committee (Committee) of the Board of Directors (Board) of Vectren Corporation (Company), as of the date of the lifting of the restrictions or no later than sixty days after that date or if subject to 1.(C)(ii) no later than two and one half months after the end of the performance period, the Grantee shall be paid, for each Stock Unit Award, in cash, the value of one share of Common Stock determined by calculating the average of the closing price of the Common Stock on the New York Stock Exchange for the three consecutive trading days immediately preceding December 25, 2016, or if the lifting of restrictions occurs prior to December 25, 2016, the Fair Market Value of one share of Common Stock on the date the restrictions lapse; provided, however, if the restrictions are being lifted as of December 31, 2016, and the Grantee is not then in compliance with the share ownership guidelines established by the Company's Board, at that time the value of each Stock Unit Award shall be paid to the Grantee in one unrestricted share of the Company's common stock. The determination of compliance will be made by valuing the Grantee's ownership interest by averaging the high and low prices of a share of the Company's common stock during the preceding month of November and comparing the resulting amount of ownership interest against the then applicable share ownership guideline.

(B) Restricted Period. Except as otherwise provided pursuant to or in accordance with the terms and provisions of this Agreement or the Plan, the Stock Unit Awards shall not be sold, exchanged, assigned, transferred or permitted to be transferred, voluntarily, involuntarily, or by operation of law, delivered, encumbered, discounted, pledged, hypothecated, or otherwise disposed of during the “Restricted Period,” which shall, with respect to each Stock Unit Award commence on the Grant Date and, except as otherwise provided in this Agreement or the Plan, end on December 31, 2016.

(i) Final Measurement of the Stock Unit Award. Except as provided in this Agreement or the Plan, including Section 7.4(b)(i) and Article X, the lifting of the transferability restrictions and the forfeitability provisions shall be dependent on (1) the shareholder value performance (as measured by total shareholder return or TSR) of the underlying Stock during the TSR Measuring Period (January 1, 2013 through December 31, 2015), (2) the earned return on equity (ROE) of Vectren Corporation (Company) for the twelve months ended December 31, 2015 (the ROE Measuring Period) relative to the performance metrics established by the Compensation and Benefits committee (Committee), and (3) the continued employment of the Grantee until December 31, 2016.

(a) Total Shareholder Return. Fifty percent of the final amount of the Stock Unit Award shall be determined based upon the Company's TSR performance relative to the TSR of the companies within the peer group established by the Committee and determined in accordance with the rules established by the Committee, all of which are incorporated

herein by reference. In addition to the information that is incorporated herein by reference, the TSR performance conditions will operate in the following manner. For the TSR Measuring Period, the shareholder value performance of the Company shall be compared with the shareholder value performance of the group of comparable companies designated by the Committee. TSR performance shall be determined separately for Company and for each company included as part of the group of comparable companies by dividing:

(1) the difference between

(A)the sum of (A) the average for each peer group company of the monthly averages of the highest and lowest trading price of the common stock of such company for the last twelve (12) months of the TSR Measuring Period, and (B) any dividends, cash or stock, paid per share with respect to such company's common stock during the TSR Measuring Period, and

(B)the average for each peer group company of the monthly averages of the highest and lowest trading price of the common stock of such company for the twelve (12) months immediately preceding the TSR Measuring Period,

by

(2) (B) above; provided, however, that if during the period in which shareholder value performance is determined, Company or any of the comparable companies incurs a change in its outstanding shares because of a stock dividend, stock split, merger, consolidation, stock rights plan or exchange of shares or other similar corporate change, the Committee shall appropriately modify the above shareholder value performance determination to reflect such change in capitalization.

Pursuant to the TSR Performance Schedule applicable to this Grant and established by the Committee, depending on how Company performs in relationship to the group of comparable companies with respect to its TSR performance, fifty percent of the Stock Unit Award will be subject to adjustment at the end of the TSR Measuring Period.

(b) Earned Return on Equity. Fifty percent of the final amount of the Stock Unit Award shall be determined based upon the Company's earned ROE for the twelve months ended December 31, 2015 relative to the metrics established by the Committee and determined in accordance with the rules established by the Committee, all of which are incorporated herein by reference.

(ii) Lifting of Restrictions. The restrictions applicable to the Stock Unit Awards held by the Grantee at the end of the TSR and ROE Measuring Periods (after the completion of the adjustments in the number of Stock Unit Awards by reason of the computations called for by the (A) the TSR Performance Schedule, and (B) the ROE metrics) (January 1, 2013 through December 31, 2015 is the “Performance Period”) shall be lifted in whole as of December 31, 2016; provided, however, that except as provided in the Plan, which directs, under certain conditions, that the restrictions shall be lifted earlier: (a) the restrictions shall be lifted on December 31, 2016 only if the Grantee is still employed by a Participating Company on that date, and, subject to the terms of this Agreement and the Plan, (b) if the Grantee ceases to be employed by a Participating Company before the restrictions lapse on any Stock Unit Awards held by him or her, the Stock Unit Awards still subject to restrictions shall be immediately forfeited.

(iii) Continued Service As A Director. If the Grantee (a) whose employment is terminated with a Participating Company for any reason and (b) who is a director of Company immediately prior to the Grantee's termination of employment continues to serve Company as a director following the Grantee's termination of employment, the Committee shall have the complete and sole discretion to deem the Grantee's employment with the Participating Company as continuing for

purposes of this grant of Stock Unit Awards for all or a portion of the period in which the Grantee continuously serves as a member of the Board.

(C) Disability, Death or Retirement. In the event of the Grantee's death, Disability, or Retirement the following shall apply:

(i) If such event occurs after the end of the Performance Period but before the end of the Restriction Period, the restrictions on the Stock Unit Awards shall be immediately removed;

(ii) In the event of the Grantee's Disability or Retirement before the Performance Period has ended, the restrictions on the Stock Unit Awards shall be removed upon (a) expiration of the Performance Period, and (b) certification by the Committee of the Company's performance under the Total Shareholder Return and Return on Equity metrics applicable to this Grant. The number of Stock Unit Awards the Grantee shall be entitled to, if any, shall equal (i) the number of Stock Unit Awards, if any, the Grantee would otherwise be entitled to had the individual been an active Participant at the end of the Performance Period (i.e., as adjusted or forfeited based on the Performance Criteria) multiplied by (ii) the portion of Performance Period the Grantee was an active Participant hereunder;

(iii) In the event of the Grantee's death before the Performance Period has ended, the restrictions on the Stock Unit Awards shall be removed upon the Grantee's date of death, and the number of Stock Unit Awards the Grantee shall be entitled to, if any, shall equal the number of Stock Unit Awards contingently granted hereunder without any further adjustment; and

(iv) Notwithstanding the terms of the Plan and any other provision of this Agreement, in the event of the Grantee's Disability or Retirement prior to the end of the Performance Period, the Committee may, but shall not be obligated to, permit the Grantee to receive the number of Stock Unit Awards, if any, that the Grantee would otherwise be entitled to had the Grantee been an active employee at the end of the Performance Period (as adjusted or forfeited based on the Performance Criteria) without any reduction for the time the Grantee was not an active employee during the Performance Period.

2. Capitalization Changes. Prior to the lifting of restrictions, in the event of a change in the Company's outstanding shares by reason of a stock dividend, stock split, merger, consolidation, stock rights plan or exchange of shares or other similar corporate change, the Committee shall make appropriate adjustments in the number of Stock Unit Awards granted hereunder.

3. Dividends. Each time a dividend is paid on the Company's common stock, the amount of the dividend, multiplied by the number of Stock Unit Awards set forth herein, as adjusted by the receipt of additional Stock Unit Awards under this paragraph, shall be divided by the closing price of the Company's common stock on the dividend payment date and such resulting number shall be added to the number of Stock Unit Awards granted to the Grantee under this Agreement.

4. Investment Representation. By executing this Agreement, Grantee represents that the Stock Unit Award is being held in good faith for investment purposes only and not with a view to, or for sale in connection with, any distribution thereof, and that any Stock Unit Award Grantee or Grantee's legal representatives acquire pursuant to this award will be acquired by them in good faith for investment purposes and not with a view to, or for sale in connection with, any distribution thereof.

5. Clawback Policy. By executing this Agreement and receiving the Grant provided for hereunder Grantee acknowledges that under the Dodd Frank Act Wall Street Reform and Consumer Protection Act (“Act”) Company will be obligated to adopt a clawback policy that may require, under certain circumstances, the recoupment of compensation previously paid to designated individuals, including equity based compensation. Grantee further acknowledges that at the time of this Grant there is uncertainty regarding the form of such a required clawback policy and until the federal government provides further guidance in this area Company is not able to adopt its final policy under the Act. Grantee hereby agrees that during the pendency of this Grant if and when Company's required clawback policy is finalized, to the extent that policy is determined to apply to this Grant, which determination shall be made by the Committee, in their reasonable judgment, at the time the required policy is finalized by the Committee, the provisions of that policy shall be incorporated herein by

reference and this Grant shall be subject to that policy as if it was in effect as of the date hereof. Grantee further acknowledges that pending the finalization of that policy, this grant shall be subject to any interim policy that may be effective during the pendency hereof including the policy adopted on March 2, 2011, as the same may be amended from time to time.

6. Continued Employment. Nothing in this Agreement shall restrict the right of Vectren Corporation or its affiliates to terminate Grantee's employment or status as a consultant at any time with or without cause.

7. The Plan. This grant is subject to all the terms, provisions and conditions of the Plan, which is incorporated herein by reference, including the defined terms not otherwise defined herein, and to such regulations as may from time to time be adopted by the Committee. In the event of any conflict between the provisions of the Plan and the provisions of this Agreement, the terms, conditions and provisions of the Plan shall control, and this Agreement shall be deemed to be modified accordingly.

9. Withholding. Vectren shall withhold all applicable taxes required by law from all amounts paid in satisfaction of the award.

10. Notices. All notices by the Grantee or his or her assigns to Vectren shall be addressed to Vectren Corporation, One Vectren Square, Evansville, Indiana 47708, Attention: Corporate Secretary, or such other address as Vectren may, from time to time, specify. All notices by Vectren to the Grantee shall be addressed to the Grantee at their current work location at Vectren or, if they are no longer employed by Vectren, at the address on file for the Grantee with the Human Resources department of Vectren.

VECTREN CORPORATION

By:_________________________________

Its: A Duly Authorized Signatory on behalf of the Compensation and Benefits Committee

Accepted as of the date first above written

______________________________________ Grantee

EX-10.3

EXHIBIT 10.3

Gas Sales And Portfolio Administration Agreement

APPENDICES INDEX

Buyer's Primary Delivery Points        A

Buyer’s Maximum Quantities        B

“Reserved for Future Use”            C

Supplier Reservation Costs        D

Commodity Purchases-Gas Cost

Incentive Mechanism            E

Notices                    F

Invoice/Payment Data            G

Demand Cost Charges            H

Diversion of Entitlements            I

Portfolio Services                J - M

1

IGC-Appendix A

Gas Sales And Portfolio Administration Agreement    Revised Page No. 1

April 1, 2012

APPENDIX A - Buyer’s Primary Delivery Points

North/East System

Delivery Points

2509 Dana 2510 Danville 2515 Elwood 2516 Fairmount 2530 Noblesville 2531 North Salem 2535 Richmond    2538 Tipton    2576 Huntington 2597 Crawfordsville 2605 Upland 2684 Unionport 2751 Montpelier 2754 Sheridan 2757 Bloomingdale 2772 Newport 2780 Lebanon 2795 Anderson 2796 Zionsville 2812 Carpentersville 2822 Fowlerton 2823 Richmond 5233 Anderson 121N Rural 5530 Cent. Ind. Rurals 5531 West of Zionsville 5532 North of Zionsville 5534 East of King 5864 King 010530010 East Hancock School 010530030 Hope 010530070 Dunkirk 032150100 Muncie 037045550 ANR Storage Facilities ANRNNS NN Service Injection Points PEPL IND GAS-INJ CGCU Points of Interconnection  with Citizens Gas & Coke Utility

2

        Cause # 43963

IGC-Appendix A

Gas Sales And Portfolio Administration Agreement    Revised Page No. 2

April 1, 2012

APPENDIX A - Buyer’s Primary Delivery Points

Central System

Delivery Points

14411 Bedford 14412 Bedford 14431 Columbus 14432 Columbus 14433 Columbus 14461 Bargersville 14463 Bargersville 14481 Mitchell 14482 Mitchell 14491 Needmore 14492 Needmore 14493 Needmore 14501 Seymour 14511 Waynesville 14512 Waynesville 14521 Rural (Mitchell) 14522 Rural (Martinsville) 14531 Crane 14533 Crane 18531 Rural Ind. 037047100 West Shelbyville 44590 Vectren Indiana CGCU Points of Interconnection with Citizens Gas & Coke Utility 70018 TETCO Seymour

Terre Haute System

Delivery Points

14523 Rural (Terre Haute) 14531 Crane 14533 Crane 18421 Sand Cut 18422 Sand Cut 18423 Sand Cut 18424 Sand Cut 18451 Clinton 18452 Clinton 18461 Hercules Clinton 18462 Hercules Clinton 18491 Terre Haute-2 18492 Terre Haute-2 18511 Terre Haute-4 18521 Stuckey Rd. 18522 Stuckey Rd. 18523 Stuckey Rd. 18541 Terre Haute-6 18542 Terre Haute-6 18571 Magaret (Terre Haute) 18573 Magaret (Terre Haute)

South System

Delivery Point

17031    Locust, KY    17032    Locust, KY

17041    Moorefield, In.     17042    Moorefield, In.

17251    Crestwood, KY    17252    Crestwood, KY

Greensburg System

Delivery Point

70017        Greensburg

70940        Westport

TETCO        TETCO Storage Facilities

3

Cause # 43963

IGC-Appendix A

Gas Sales And Portfolio Administration Agreement    Revised Page No. 3

April 1, 2012

Amendment

Seller and Buyer agree that this Appendix A may be amended as provided in this Agreement, which amendment ultimately will be memorialized in a revised Appendix A.

PROLIANCE ENERGY, LLC.            INDIANA GAS COMPANY, INC.

By: /s/ David C. Pentzien _________________        By: /s/ Jerrold L. Ulrey        

David C. Pentzien    Jerrold L. Ulrey        

Its: Vice President of Sales & Marketing        Its: Vice President, Regulatory Affairs and Fuels

4

IGC-Appendix B

Gas Sales And Portfolio Administration Agreement    Revised Page No. 1

April 1, 2012

APPENDIX B - Buyer’s Maximum Quantities

Maximum Daily Quantities (in Dth)

Central/

MonthNorth/EastTerre HauteSouthWestport

April    194,115    80,016    31,094    750

May        184,115    39,058    14,221    750

June    184,115    39,058    14,221    750

July    184,115    39,058    14,221    750

August    184,115    39,058    14,221    750

September    184,115    39,058    14,221    750

October    194,115     92,255    36,228    750

November    419,115    115,087    53,887    750

December    419,115    175,087    53,887    750

January    419,115    175,087    53,887    750

February    419,115    175,087    53,887    750

March    419,115    115,087    53,887    750

Amendment

Seller and Buyer agree that this Appendix B may be amended as provided in this Agreement, which amendment ultimately will be memorialized in a revised Appendix B.

PROLIANCE ENERGY, LLC.            INDIANA GAS COMPANY, INC.

By: _/s/ David C. Pentzien ________________        By: /s/ Jerrold L. Ulrey    

David C. Pentzien    Jerrold L. Ulrey    

Its: Vice President of Sales & Marketing        Its: Vice President, Regulatory Affairs and Fuels

5

IGC-Appendix D

Gas Sales and Portfolio Administration Agreement    Revised Page No. 1

April 1, 2012

APPENDIX D - Supplier Reservation Costs

Supplier Reservation Costs

April 1, 2012 through October 31, 2012

I.    Reserved Commodity Quantities

a. Monthly Base load Reserved Quantity (Dth/Day)

System

Month	PEPL	ANR	North/East	Central/Terre Haute/South Texas Gas	TETCO Greensburg
November, 2011	103,559	0	103,559	22,489	159
December, 2011	153,187	0	153,187	37,402	267
January, 2012	153,187	0	153,187	39,357	267
February, 2012	133,904	0	133,904	34,841	267
March, 2012	97,451	0	97,451	25,276	214
April, 2012	83,191	—	83,191	10,402	100
May, 2012	80,509	—	80,509	10,068	50
June, 2012	83,191	0	83,191	10,402	50
July, 2012	75,670	0	75,670	10,068	50
August, 2012	75,670	0	75,670	10,068	50
September, 2012	78,191	0	78,191	10,402	50
October, 2012	75,670	0	75,670	10,068	100

Buyer and Seller agree that some portion of the quantities identified as Monthly Baseload Reserved Quantities may be provided at fixed, collared, or hedged prices mutually agreed upon pursuant to the GCIM.

6

IGC-Appendix D

Gas Sales and Portfolio Administration Agreement              Revised Page No. 2

April 1, 2012

APPENDIX D - Supplier Reservation Costs

b. Daily Swing Reserved Quantity (Dth/Day)

System

Month	PEPL	ANR	North/East	Texas Gas	MGT	Central/Terre Haute/South	TETCOGreensburg
November, 2011	135,231	33,416	168,647	57,585	5,051	62,636	636
December, 2011	85,603	33,416	119,019	42,594	5,051	47,645	534
January, 2012	75,603	33,416	109,019	40,719	5,051	45,770	534
February, 2012	104,886	33,416	138,302	45,230	5,051	50,281	534
March, 2012	141,339	33,416	174,755	54,800	5,051	59,851	588
April, 2012	71,924	0	71,924	37,877	5,051	42,928	650
May, 2012	74,606	0	74,606	38,211	5,051	43,262	700
June, 2012	71,924	0	71,924	37,877	5,051	42,928	700
July, 2012	79,445	0	79,445	38,211	5,051	43,262	700
August, 2012	79,445	0	79,445	38,211	5,051	43,262	700
September, 2012	76,924	0	76,924	37,877	5,051	42,928	700
October, 2012	79,445	0	79,445	38,211	5,051	43,262	650

Buyer and Seller agree that some portion of the quantities identified as Daily Swing Reserved Quantities may be provided at fixed, collared, or hedged prices mutually agreed upon pursuant to the GCIM.

II.    Applicable Reservation Rates ($/Dth/Day)

System	Winter Months (Nov.-Mar.)			Summer Months (Apr.-Oct.)
	Monthly Index ReservedQuantity	Daily Index ReservedQuantity	Monthly Index ReservedQuantity		Daily Index ReservedQuantity
North/East	$0.0005	$0.0046	$.0000		$.0000
Central/Terre Haute/South	$0.0012	$0.0031	$.0000		$.0000
Greensburg	$0.0025	$0.0025	$.0000		$.0000

7

IGC-Appendix D

Gas Sales and Portfolio Administration Agreement              Revised Page No. 3

April 1, 2012

APPENDIX D - Supplier Reservation Costs

Amendment

Seller and Buyer agree that this Appendix D may be amended from time to time by mutual agreement of the Parties, which ultimately will be memorialized in a revised Appendix D.

PROLIANCE ENERGY, LLC.            INDIANA GAS COMPANY, INC.

By: _/s/ David C. Pentzien ________________        By: /s/ Jerrold L. Ulrey        

David C. Pentzien    Jerrold L. Ulrey        

Its: Vice President of Marketing & Sales        Its: Vice President, Regulatory Affairs and Fuels

8

IGC-Appendix E

Gas Sales And Portfolio Administration Agreement    Revised Page No. 1

April 1, 2012

APPENDIX E –Commodity Purchases – Gas Cost Incentive Mechanism

The commodity purchased by Buyer shall be provided in accordance with the Commission approved Gas Cost Incentive Mechanism described in Appendix E of the Settlement. All record keeping and reporting shall be performed in a manner consistent with the terms of the GCIM. Seller agrees and acknowledges the reasonableness of the Gas purchases made shall be subject to review to ensure such purchases were made in a manner consistent with the terms of the GCIM.

For Summer Leased Storage Refill:

For summer refill of leased storage, Buyer shall pay to Seller an amount based on averaging the seven summer monthly indices for the applicable supply area, and based upon presuming storage refill quantities to be equally split between the summer months. For summer refill of company storage, the parties will agree on the extent to which an index average method will be used, after consideration of the operational scheduling needs of company storage. In addition, all other applicable variable costs as identified below shall apply.

For Storage Withdrawals:

For quantities of storage withdrawals for which Buyer has previously paid for commodity, applicable storage withdrawal variable costs as identified below shall apply.

For Applicable Indices:

Contract No.Contract RateIndex

WDS 3Appendix J.3    ANR – Louisiana

WDS 4Appendix J.4    Trunkline - WLA

ADS 5    Appendix K.5    Chicago-LDCs, large e-us

ADS 6    Appendix K.6    Texas Gas – Zone SL

ADS 8    Appendix K.8    Texas Gas – Zone SL

ADS 9    Appendix K.9    Texas Gas – Zone SL

ADS 10    Appendix K.10    Texas Gas – Zone SL

ADS 11    Appendix K.11    PEPL – Texas, Oklahoma

ADS 14    Appendix K.14    TETCO – (ELA, WLA, ETX, STX)

9

IGC-Appendix E

Gas Sales And Portfolio Administration Agreement    Revised Page No. 2

April 1, 2012

APPENDIX E- Commodity Purchases - Other Variable Costs

The other variable costs applicable to Nominated Daily Quantities and Balancing Quantities shall be determined based upon the rates and charges applicable under each transporter’s tariff, including the sheets identified below, as well as other applicable sheets, as all of those sheets may be in effect from time to time, and costs arising under applicable agreements, including the agreements identified below, as well as this Agreement.

North/East

PEPL

Contract No.Contract Rate

ADS 11            Appendix K.11

ADS 12            Appendix K.12

SDS 1            Appendix M.1

Trunkline

Contract No.Contract Rate

WDS 4            Appendix J.4

North/East & Central

ANR

Contract No.Contract Rate

WDS 2            Appendix J.2

WDS 3            Appendix J.3

Central/Terre Haute System

Texas Gas Z-3

Contract No.Contract Rate

ADS 5            Appendix K.5

ADS 6            Appendix K.6

ADS 8            Appendix K.8

South System

Texas Gas Z-4

Contract No.Contract Rate

ADS 9            Appendix K.9

ADS 10            Appendix K.10

10

IGC-Appendix E

Gas Sales And Portfolio Administration Agreement    Revised Page No. 3

April 1, 2012

APPENDIX E - Commodity Purchases - Other Variable Costs

Westport System

Texas Eastern    

Contract No.Contract Rate

ADS 14            Appendix K.14

While Seller and Buyer agree that the identified tariff sheets and agreements are intended to be a complete listing of the applicable tariff sheets and applicable agreements, they further agree that the omission of the reference of one or more sheets or agreements from that list will not affect Buyer’s obligation to Seller for rates, charges and costs incurred thereunder.

Amendment

Seller and Buyer agree that this Appendix E may be amended from time to time by mutual agreement of the Parties, which ultimately will be memorialized in a revised Appendix E.

PROLIANCE ENERGY, LLC.            INDIANA GAS COMPANY, INC.

By: _/s/ David C. Pentzien ________________        By: /s/ Jerrold L. Ulrey        

David C. Pentzien    Jerrold L. Ulrey        

Its: Vice President of Sales & Marketing        Its: Vice President, Regulatory Affairs and Fuels

11

IGC-Appendix F

Gas Sales And Portfolio Administration Agreement    Revised Page No. 1

April 1, 2012

Appendix F-Notices

Invoice Information:

Buyer:                        Seller:

Indiana Gas Company, Inc.    Accounting/ Treasury

Attn.: Director, Gas Supply    ProLiance Energy, LLC
One Vectren Square     111 Monument Circle    Suite 2200
Evansville, IN. 47708    Indianapolis, IN 46204-5178
(812) 491-4670    (317) 231-6800

Payments:

Buyer:                        Seller:

PNC Bank    1/7^th Refill Gas Costs:

Huntington National Bank

For the Account of:    Indianapolis, Indiana

For the Account of:

Indiana gas Company, Inc.    ProLiance Energy, LLC

ABA# 044000024

ACCT# 01401007177

All Other Gas & Delivery Service Costs:

PNC Bank, N.A.

East Brunswick, NJ

For the Account of:

ProLiance Energy, LLC

ABA# 031207607

ACCT# 8026582295

Supply Plans/Operational/Force Majeure:

Buyer:    Seller:

Supply PlansSupply Plans
Stephanie Willis    Tessa Woodall
(812) 491-4486    (317) 231-6937    
OperationalOperational
Randy Gary    Tessa Woodall
(812) 491-4730    (317) 231-6937

Force MajeureForce Majeure
Randy Gary (812) 491-4730    Tessa Woodall - (317) 231-6937
Perry M. Pergola (812) 491-4670    Paula Montgomery- (317) 231-6946
Gas Controller on Duty (812) 491-4530    ProLiance Energy, LLC

Indiana Gas Company, Inc.    111 Monument Circle
One Vectren Square    Suite 2200
Evansville, IN 47708    Indianapolis, Indiana 46204-5178
(812) 491-4687 (Telecopy)    (317) 231-6901 (Telecopy)

                          IGC-Appendix F

Gas Sales And Portfolio Administration Agreement    Revised Page No. 2

April 1, 2012

12

APPENDIX F-Notices
(Continued)

All Other Notices:

Buyer:                        Seller:

Indiana Gas Company, Inc.    ProLiance Energy, LLC
Attn.: Director, Gas Supply    Attn: Paula Montgomery
One Vectren Square    111 Monument Circle
Evansville, IN 47708    Suite 2200

Indianapolis, Indiana 46204-5178

Amendment

Seller and Buyer agree that this Appendix F may be amended from time to time as provided in this Agreement, which amendment ultimately will be memorialized in a revised Appendix F.

PROLIANCE ENERGY, LLC.            INDIANA GAS COMPANY, INC.

By: _/s/ David C. Pentzien ________________        By: /s/ Jerrold L. Ulrey        

David C. Pentzien    Jerrold L. Ulrey        

Its: Vice President of Sales & Marketing        Its: Vice President, Regulatory Affairs and Fuels

13

     IGC-Appendix G

Gas Sales And Portfolio Administration Agreement              Revised Page No. 1

April 1, 2012

APPENDIX G - Invoice/Payment Data

Invoice Date -         On or before the tenth (10th) day after the Contract Month.

Due Date -         All Delivery Service Costs due on or before the 20^th day of the month

All Gas Costs due on or before the 25^th day of the month.

Payment Method -    By wire transfer to account specified on invoice.

Amendment

Seller and Buyer agree that this Appendix G may be amended from time to time by mutual agreement of the Parties, which amendment ultimately will be memorialized in a revised Appendix G.

PROLIANCE ENERGY, LLC.            INDIANA GAS COMPANY, INC.

By: _/s/ David C. Pentzien ________________        By: /s/ Jerrold L. Ulrey        

David C. Pentzien    Jerrold L. Ulrey        

Its: Vice President of Sales & Marketing        Its: Vice President, Regulatory Affairs and Fuels

14

IGC-Appendix H

Gas Sales and Portfolio Administration Agreement    Revised Page No. 1

April 1, 2012

APPENDIX H – Demand Cost Charges

This Annual Net Demand cost covers all delivery services provided by Seller to Buyer under Appendix I through Appendix M.1.  Other, additional, charges payable by Buyer to Seller for delivery services are specifically described in each Appendix Service (Appendix I through Appendix M.1)

Month	Gross Demand Cost	Demand Credit	Net Demand Cost
Apr	$4,482,034.00	$21,586.00	$4,460,448.00
May	$3,806,738.00	$21,587.00	$3,785,151.00
Jun	$3,771,778.00	$21,586.00	$3,750,192.00
Jul	$3,788,326.00	$21,587.00	$3,766,739.00
Aug	$3,788,327.00	$21,587.00	$3,766,740.00
Sep	$3,771,778.00	$21,586.00	$3,750,192.00
Oct	$4,703,453.00	$21,587.00	$4,681,866.00
Nov	$6,255,781.00	$21,586.00	$6,234,195.00
Dec	$6,682,128.00	$21,587.00	$6,660,541.00
Jan	$6,682,127.00	$21,587.00	$6,660,540.00
Feb	$6,497,483.00	$21,587.00	$6,475,896.00
Mar	$6,317,328.00	$21,587.00	$6,295,741.00
Total	$60,547,281.00	$259,040.00	$60,288,241.00

PROLIANCE ENERGY, LLC.            INDIANA GAS COMPANY, INC.

By: _/s/ David C. Pentzien ________________        By: /s/ Ronald E. Christian        

David C. Pentzien    Ronald E. Christian        

Its: Vice President of Sales & Marketing        Its: Executive Vice President        

IGC-Appendix I

15

Gas Sales And Portfolio Administration Agreement    Revised Page No. 1

April 1, 2012

APPENDIX I- Diversion of Entitlements

I. Diversion of Delivered Gas Sales Entitlements from Buyer

Seller shall have the right to schedule entitlements of Buyer to Citizens Gas & Coke Utility, provided that:

A.    Seller shall reimburse Buyer for applicable variable costs Buyer incurs in replacing diverted supply with its own on system gas sources.

B.    If such diversion causes Buyer to incur gas costs related to on system gas sources, Seller shall reimburse Buyer or otherwise assure Buyer suffers no economic detriment from such incurrence of gas costs.

C.    The “Shoulder Month Season” shall be the consecutive months of October, November, December, January, February, March and April during the term of this Agreement. Unless otherwise agreed, the maximum diversion quantity shall not exceed 60,000 Dth on any day or 600,000 Dth for any Shoulder Month Season.

D.    Seller shall administer Buyer’s gas supply portfolio such that any diversion will not endanger Buyer’s ability to meet system demands.

II. Diversion of Entitlements to Buyer

Buyer shall have the right to entitlements from Seller, as follows:

A. Delivered Peaking Sales Service (“PSS”)

1. Seller shall provide Buyer PSS with the following entitlements:

Contract Month	Maximum Daily PSS	Maximum Annual PSS
December 16th -31st	60,000 Dth/day	600,000 Dth during any
January	60,000 Dth/day	December, January,
February 1st -14th	60,000 Dth/day	February period

2. Unless otherwise agreed upon, Seller shall provide 60,000 of the entitlements to Buyer’s Central system.

3.    For PSS nominated for Buyer, Buyer shall pay Seller ;

a. The total cost/Dth of Appendix I Diversions from Citizens Gas & Coke Utility to Seller for the applicable gas day, plus any cost to transfer or exchange the diverted gas.    

4.     PSS service expires March 31, 2013.

16

IGC-Appendix I

Gas Sales And Portfolio Administration Agreement    Revised Page No.2

April 1, 2012

APPENDIX I- Diversion of Entitlements

Amendment

Seller and Buyer agree that this Appendix I may be amended from time to time by mutual agreement of the Parties, which amendment ultimately will be memorialized in a revised Appendix I.

PROLIANCE ENERGY, LLC.            INDIANA GAS COMPANY, INC.

By: _/s/ David C. Pentzien ________________        By: /s/ Jerrold L. Ulrey        

David C. Pentzien    Jerrold L. Ulrey        

Its: Vice President of Sales & Marketing        Its: Vice President, Regulatory Affairs and Fuels

17

IGC-Appendix J.2

Gas Sales And Portfolio Administration Agreement    Revised Page No.1

April 1, 2012

APPENDIX J.2 - Winter Delivery Service 2

Winter Delivery Service (“WDS 2”)

1. WDS 2 shall incorporate the no-notice features, cyclability, annual storage deliverability, and other service provisions (“Service Provisions”) reflected in ANR FERC Tariffs for ETS, NNS and FSS.                                        

2. Seller shall provide Buyer with WDS 2 with the following delivered service entitlements:

Contract MonthsNominated Daily QtyUn-Nominated Daily QtyMaximum Daily Qty

November - March    30,000 Dth/day    29,000 Dth/day    59,000 Dth/day                                

April-October*        29,000 Dth/day    29,000 Dth/day

Max Annual WDS 2 - 4,436,100 Dth

3. Buyer shall pay Seller as follows:

a. For WDS 2 Commodity:

Summer purchase quantities will be determined jointly, by both parties, prior to April 1 of each year. During each summer month, Buyer shall pay Seller one-seventh of the summer purchase quantity times the agreed Monthly Index price. Other purchases shall be agreed upon, by Buyer and Seller; pursuant to Appendix E.

b. For WDS 2 Variable Costs:

Variable Cost & Fuels under applicable max rate tariffs for ANR ETS, FSS and NNS tariff. Applicable pipeline costs if any as agreed to by both parties.

c. For WDS 2 Other Costs:        

Other applicable costs if any as billed including penalties, overrun charges, etc as mutually agreed upon by both parties.

4.    Notice for this WDS 2 service is March 31, 2018. Service expires March 31, 2019.

Amendment

Seller and Buyer agree that this Appendix J.2 may be amended from time to time by mutual agreement of the Parties which amendment ultimately will be memorialized in a revised Appendix J.2.

PROLIANCE ENERGY, LLC.            INDIANA GAS COMPANY, INC.

By: _/s/ David C. Pentzien ______________        By: /s/ Jerrold L. Ulrey        

David C. Pentzien    Jerrold L. Ulrey        

Its: Vice President of Sales & Marketing        Its: Vice President, Regulatory Affairs and Fuels

18

IGC-Appendix J.3

Gas Sales And Portfolio Administration Agreement    Revised Page No. 1

April 1, 2012

APPENDIX J.3 - Winter Delivery Service 3

Winter Delivery Service 3 ANR (“WDS 3”)

1. Starting April 1, 2012, consistent with Buyer’s supply plans, Seller shall provide Buyer with WDS 3 with the following delivered service entitlements:

Contract MonthsMax Nominated

Daily Qty

November - March     32,500 Dth/day        

April - October         0 Dth/day        

2.    Unless otherwise agreed upon, Seller shall provide entitlements to Buyer’s North/East/Central system.

3.    Buyer shall pay Seller as follows:

a.    For Nominated Commodity as follows:

Purchase quantities will be determined jointly by the parties and priced pursuant to Appendix E.

b.    For WDS 3 Variable Costs:

Variable Cost & Fuels under applicable max rate tariffs for ANR ETS tariff (ML-3) and other applicable pipeline costs if any as agreed to by both parties.

c.    For WDS 3 Other Costs:        

Other applicable costs if any as billed including penalties, overrun charges, etc as mutually agreed upon by both parties.

4.    Service expires March 31, 2014.

5. Sellers provisions of WDS 3 shall be subject to the provisions of service reflected in ANR’s Gathering & ETS tariffs, as well as other ANR FERC tariffs as may be applicable to the provision of those services.

Amendment

Seller and Buyer agree that this Appendix J.3 may be amended from time to time by mutual agreement of the Parties which amendment ultimately will be memorialized in a revised Appendix J.3

PROLIANCE ENERGY, LLC.            INDIANA GAS COMPANY, INC.

By: _/s/ David C. Pentzien ________________        By: /s/ Jerrold L. Ulrey        

David C. Pentzien    Jerrold L. Ulrey        

Its: Vice President of Sales & Marketing        Its: Vice President, Regulatory Affairs and Fuels

19

IGC-Appendix J.4

Gas Sales And Portfolio Administration Agreement    Revised Page No. 1

April 1, 2012

APPENDIX J.4 - Winter Delivery Service 4

Winter Delivery Service 4 Trunkline/PEPL (“WDS 4”)

1. Starting April 1, 2012, consistent with Buyer’s supply plans, Seller shall provide Buyer with WDS 4 with the following delivered service entitlements:

Contract MonthsMax Nominated

Daily Qty

November - March         32,500 Dth/day        

April - October         0 Dth/day        

2.    Unless otherwise agreed upon, Seller shall provide entitlements to Buyer’s North/East system.

3.    Buyer shall pay Seller as follows:

a.    For Nominated Commodity as follows:

Purchase quantities will be determined jointly by the parties and priced pursuant to Appendix E.

b.    For WDS 4 Variable Costs:

Variable Cost & Fuels under applicable max rate tariffs for Trunkline FT (WLA-1B) / PEPL EFT tariff (500 - 700) and other applicable pipeline costs if any as agreed to by both parties.

c.    For WDS 4 Other Costs:        

Other applicable costs if any as billed including penalties, overrun charges, etc as mutually agreed upon by both parties.

4.    Service expires March 31, 2014.

5. Sellers provisions of WDS 4 shall be subject to the provisions of service reflected in Trunkline FT & Panhandle Eastern EFT tariffs, as well as other Trunkline & Panhandle Eastern FERC tariffs as may be applicable to the provision of those services.

Amendment

Seller and Buyer agree that this Appendix J.4 may be amended from time to time by mutual agreement of the Parties which amendment ultimately will be memorialized in a revised Appendix J.4

PROLIANCE ENERGY, LLC.            INDIANA GAS COMPANY, INC.

By: _/s/ David C. Pentzien ________________        By: /s/ Jerrold L. Ulrey        

David C. Pentzien    Jerrold L. Ulrey        

Its: Vice President of Sales & Marketing        Its: Vice President, Regulatory Affairs and Fuels

20

IGC-Appendix K.5

Gas Sales And Portfolio Administration Agreement         Revised Page No. 1

         June 1, 2011

APPENDIX K.5 - Annual Delivery Service 5

Annual Delivery Service 5 (“ADS 5”)

1. Starting June 1, 2011, consistent with the Buyer’s supply plans, Seller shall provide Buyer with ADS 5 with the following delivered Service entitlements:

Contract MonthsMaximum Daily ADS 5Maximum Monthly ADS 5

November – October    5,000 Dth/day    5,000 Dth times the number    

of days in the month.

2. Delivery of these volumes will be into the Central system.                            

3. Buyer shall pay Seller as follows:

a.    For ADS 5 Commodity as follows:                            

Purchase quantities will be determined Priced at Chicago Index pursuant to Appendix E pricing.                                    

b.    For ADS 5 Variable Costs:                                

Variable Costs & Fuels under applicable max rate tariffs for Midwestern Gas Transmission FT-A (Chicago to Texas Gas Zone 3) and Texas Gas FT (Zone 3 to Zone 3) (together the “Chicago Route”)    

c. For ADS 5 Other Costs:        

Other applicable costs if any as billed including penalties, overrun charges, etc. as mutually agreed upon by both parties.

4. Service expires May 31, 2012.

5. ADS 5 shall be subject to the provisions of service reflected in applicable FERC tariffs.

Amendment

Seller and Buyer agree that this Appendix K.5 may be amended from time to time by mutual agreement of the Parties which amendment ultimately will be memorialized in a revised Appendix K.5.

PROLIANCE ENERGY, LLC.            INDIANA GAS COMPANY, INC.

By: _/s/ David C. Pentzien ________________        By: /s/ Jerrold L. Ulrey        

David C. Pentzien    Jerrold L. Ulrey        

Its: Vice President of Sales & Marketing        Its: Vice President, Regulatory Affairs and Fuels

21

IGC-Appendix K.5

Gas Sales And Portfolio Administration Agreement    Revised Page No. 1

June 1, 2012

APPENDIX K.5 - Annual Delivery Service 5

Annual Delivery Service 5 (“ADS 5”)

1. Starting June 1, 2012, consistent with the Buyer’s supply plans, Seller shall provide Buyer with ADS 5 with the following delivered Service entitlements:

Contract MonthsMaximum Daily ADS 5Maximum Monthly ADS 5

November – October    5,000 Dth/day    5,000 Dth times the number    

of days in the month.

2. Delivery of these volumes will be to the Midwestern Indiana Gas Meter.                            

3. Buyer shall pay Seller as follows:

a.    For ADS 5 Commodity as follows:                            

Purchase quantities will be determined Priced at Chicago Index pursuant to Appendix E pricing.                                    

b.    For ADS 5 Variable Costs:                                

Variable Costs & Fuels under applicable max rate tariffs for Midwestern Gas Transmission FT-A (Chicago to Vigo)

c. For ADS 5 Other Costs:        

Other applicable costs if any as billed including penalties, overrun charges, etc as mutually agreed upon by both parties.

4. Notice for this ADS 5 service is November 30, 2013. Service expires May 31, 2014.

5. ADS 5 shall be subject to the provisions of service reflected in applicable FERC tariffs.

Amendment

Seller and Buyer agree that this Appendix K.5 may be amended from time to time by mutual agreement of the Parties which amendment ultimately will be memorialized in a revised Appendix K.5.

PROLIANCE ENERGY, LLC.            INDIANA GAS COMPANY, INC.

By: _/s/ David C. Pentzien ________________        By: /s/ Jerrold L. Ulrey        

David C. Pentzien    Jerrold L. Ulrey        

Its: Vice President of Sales & Marketing        Its: Vice President, Regulatory Affairs and Fuels

22

IGC-Appendix K.6

Gas Sales And Portfolio Administration Agreement    Revised Page No. 1

April 1, 2012

APPENDIX K.6 - Annual Delivery Service 6

Annual Delivery Service 6 TGT (“ADS 6”)

1. Starting April 1, 2012, consistent with Buyer’s supply plans, Seller shall provide Buyer with ADS 6 with the following delivered service entitlements:

Contract Month	MNDQ Central	MNDQ Terre Haute	MUNDQ Central	MUNDQ Terre Haute	Total MDQ
November-March	27,553	14,836	39,779	21,419	103,587
April	17,912	9,646	26,622	14,336	68,516
May-September	17,912	9,646			27,558
October	17,912	9,646	39,897	13,300	80,755

Maximum Seasonal Qty    Nov. – Mar.        Apr. – Oct.

8,207,672         4,090,529

Unnominated Winter Seasonal Qty 1,806,897        

2. Unless otherwise agreed upon, Seller shall provide entitlements to Buyer’s Central and Terre Haute systems (as outlined above).

3.    Buyer shall pay Seller as follows:

a. For Unnominated Quantities:

Summer purchase quantities will be determined jointly by the parties prior to April 1 of each year to replace quantities delivered during the prior winter season. During each summer month, Buyer shall pay Seller one seventh of the summer purchase quantity times the Texas Gas Monthly Index price.

b. For Nominated Commodity as follows:

Purchase quantities will be determined jointly by the parties and priced pursuant to Appendix E.

c. For ADS 6 Variable Costs:

Variable Cost & Fuels under the effective max rate Texas Gas NNS rate schedule Zone 3 and other applicable costs, if any as billed.

d. For ADS 6 Other Costs:        

Other applicable costs if any as billed including penalties, overrun charges, etc as mutually agreed upon by both parties.

23

IGC-Appendix K.6

Gas Sales And Portfolio Administration Agreement    Revised Page No. 2

     April 1, 2012

4. Notice & Service Expiration Dates for this ADS 6 service as detailed below:

a. Notice Oct. 31, 2013    Service Expires : Oct. 31, 2014

Contract Month	MNDQ Central	MNDQ Terre Haute	MUNDQ Central	MUNDQ Terre Haute	Total MDQ
November-March	9,184	4,945	13,260	7,140	34,529
April	5,971	3,215	8,874	4,779	22,839
May-September	5,971	3,215			9,186
October	5,971	3,215	13,299	4,434	26,919
		Nov. – Mar	Apr. – Oct.
Maximum Seasonal Qty		2,735,891	1,363,510
Un-nominated Winter Seasonal Qty		602,299

b. Notice Oct. 31, 2014    Service Expires : Oct. 31, 2015

Contract Month	MNDQ Central	MNDQ Terre Haute	MUNDQ Central	MUNDQ Terre Haute	Total MDQ
November-March	9,184	4,945	13,260	7,140	34,529
April	5,971	3,215	8,874	4,779	22,839
May-September	5,971	3,215			9,186
October	5,971	3,215	13,299	4,434	26,919
		Nov. – Mar	Apr. – Oct.
Maximum Seasonal Qty		2,735,891	1,363,510
Un-nominated Winter Seasonal Qty		602,299

c. Notice Oct. 31, 2015    Service Expires : Oct. 31, 2016

Contract Month	MNDQ Central	MNDQ Terre Haute	MUNDQ Central	MUNDQ Terre Haute	Total MDQ
November-March	9,185	4,946	13,259	7,139	34,529
April	5,970	3,216	8,874	4,778	22,838
May-September	5,970	3,216			9,186
October	5,970	3,216	13,299	4,432	26,917
		Nov. – Mar	Apr. – Oct.
Maximum Seasonal Qty		2,735,890	1,363,509
Un-nominated Winter Seasonal Qty		602,299

24

IGC-Appendix K.6

Gas Sales And Portfolio Administration Agreement    Revised Page No. 3

     April 1, 2012

5. Sellers provisions of ADS 6 shall be subject to the provisions of service reflected in Texas Gas NNS tariffs, as well as other Texas Gas FERC tariffs as may be applicable to the provision of those services

Amendment

Seller and Buyer agree that this Appendix K.6 may be amended from time to time by mutual agreement of the Parties which amendment ultimately will be memorialized in a revised Appendix K.6

PROLIANCE ENERGY, LLC.            INDIANA GAS COMPANY, INC.

By: _/s/ David C. Pentzien ________________        By: /s/ Jerrold L. Ulrey        

David C. Pentzien    Jerrold L. Ulrey        

Its: Vice President of Sales & Marketing        Its: Vice President, Regulatory Affairs and Fuels

25

IGC-Appendix K.8

Gas Sales And Portfolio Administration Agreement    Revised Page No. 1

April 1, 2012

APPENDIX K.8 - Annual Delivery Service 8

Annual Delivery Service 8 TGT (“ADS 8”)

1. Starting April 1, 2012, consistent with Buyer’s supply plans, Seller shall provide Buyer with ADS 8 with the following delivered service entitlements:

Contract Month Max Nominated

Daily Qty

November - October 6,500 Dth/day            

2. Unless otherwise agreed upon, Seller shall provide 6,500 Dth/day of entitlements to Buyer’s Central System, the remaining entitlements shall be provided to Buyer’s South system.

3.    Buyer shall pay Seller as follows:

a. For Nominated Commodity as follows:

Purchase quantities will be determined jointly by the parties and priced pursuant to Appendix E.

b. For ADS 8 Variable Costs:

Variable Cost & Fuels under the effective max rate Texas Gas FT rate schedule (SL-Zone 3 for Central System) and other applicable costs, if any as billed.

c. For ADS 8 Other Costs:        

Other applicable costs if any as billed including penalties, overrun charges, etc as mutually agreed upon by both parties.

4.    Notice for this ADS 8 service is March 31, 2013. Service expires March 31, 2014.

5. Sellers provisions of ADS 8 shall be subject to the provisions of service reflected in Texas Gas FT tariffs, as well as other Texas Gas FERC tariffs as may be applicable to the provision of those services.

Amendment

Seller and Buyer agree that this Appendix K.8 may be amended from time to time by mutual agreement of the Parties which amendment ultimately will be memorialized in a revised Appendix K.8

PROLIANCE ENERGY, LLC.            INDIANA GAS COMPANY, INC.

By: _/s/ David C. Pentzien ________________        By: /s/ Jerrold L. Ulrey        

David C. Pentzien    Jerrold L. Ulrey        

Its: Vice President of Sales & Marketing        Its: Vice President, Regulatory Affairs and Fuels

26

IGC-Appendix K.9

Gas Sales And Portfolio Administration Agreement    Revised Page No. 1

April 1, 2012

APPENDIX K.9 - Annual Delivery Service 9

Annual Delivery Service 9 TGT (“ADS 9”)

1. Starting April 1, 2011, consistent with Buyer’s supply plans, Seller shall provide Buyer with ADS 9 with the following delivered service entitlements:

Contract Month Max Nominated

Daily Qty

November - March 13,500 Dth/day            

April - October 3,500 Dth/day            

2. Unless otherwise agreed upon, Seller shall provide entitlements to Buyer’s South system.

3.    Buyer shall pay Seller as follows:

a. For Nominated Commodity as follows:

Purchase quantities will be determined jointly by the parties and priced pursuant to Appendix E.

b. For ADS 9 Variable Costs:

Variable Cost & Fuels under the effective max rate Texas Gas STF rate schedule (SL-Zone 4 for South system) and other applicable costs, if any as billed.

c. For ADS 9 Other Costs:        

Other applicable costs if any as billed including penalties, overrun charges, etc as mutually agreed upon by both parties.

4.    Notice for this ADS 9 service is March 31, 2014. Service expires March 31, 2015.

5. Sellers provisions of ADS 9 shall be subject to the provisions of service reflected in Texas Gas SFT tariffs, as well as other Texas Gas FERC tariffs as may be applicable to the provision of those services.

Amendment

Seller and Buyer agree that this Appendix K.9 may be amended from time to time by mutual agreement of the Parties which amendment ultimately will be memorialized in a revised Appendix K.9

PROLIANCE ENERGY, LLC.            INDIANA GAS COMPANY, INC.

By: _/s/ David C. Pentzien ________________        By: /s/ Jerrold L. Ulrey        

David C. Pentzien    Jerrold L. Ulrey        

Its: Vice President of Sales & Marketing        Its: Vice President, Regulatory Affairs and Fuels

27

IGC-Appendix K.10

Gas Sales And Portfolio Administration Agreement    Revised Page No. 1

     April 1, 2012

APPENDIX K.10 - Annual Delivery Service 10

Annual Delivery Service 10 TGT (“ADS 10”)

1. Starting April 1, 2012, consistent with Buyer’s supply plans, Seller shall provide Buyer with ADS 10 with the following delivered service entitlements:

Contract MonthsMax NominatedMax Unnominated Total MDQ    

Daily Qty Daily Qty

November - March        14,718 Dth/day        25,669 Dth/day    40,387 Dth/day    

April     10,721 Dth/day    16,873 Dth/day    27,594 Dth/day    

May - September     10,721 Dth/day            10,721 Dth/day    

October     10,721 Dth/day    22,007 Dth/day    32,728 Dth/day    

Maximum Seasonal Qty            Nov. – Mar.        Apr. – Oct.

3,354,151         1,162,588

Un-nominated Winter Seasonal Qty 1,131,733        

2. Unless otherwise agreed upon, Seller shall provide entitlements to Buyer’s South system.

3. Buyer shall pay Seller as follows:

a. For Un-nominated Quantities:

Summer purchase quantities will be determined jointly by the parties prior to April 1 of each year to replace quantities delivered during the prior winter season. During each summer month, Buyer shall pay Seller one seventh of the summer purchase quantity times the Texas Gas Monthly Index price.

b. For Nominated Commodity as follows:

Purchase quantities will be determined jointly by the parties and priced pursuant to Appendix E.

c. For ADS 10 Variable Costs:

Variable Cost & Fuels under the effective max rate Texas Gas NNSrate schedule (Zone 4)and other applicable costs, if any as billed.

d. For ADS 10 Other Costs:        

Other applicable costs if any as billed including penalties, overrun charges, etc as mutually agreed upon by both parties.

28

IGC-Appendix K.10

Gas Sales And Portfolio Administration Agreement    Revised Page No. 2

     April 1, 2012

4. Notice & Expiration dates for the following portions of ADS 10 service as listed below:

a. Notice Oct. 31, 2014    Service Expires : Oct. 31, 2015

Contract MonthsMax NominatedMax Unnominated Total MDQ

Daily Qty Daily Qty

November - March     7,359 Dth/day    12,834 Dth/day    20,193 Dth/day

April          5,361 Dth/day     8,436 Dth/day    13,797 Dth/day

May - September     5,361 Dth/day         5,361 Dth/day

October             5,361 Dth/day    11,003 Dth/day    16,364 Dth/day

Maximum Seasonal Qty.     Nov. – Mar.    Apr. – Oct.

1,677,076     581,294

Un-nominated Winter Seasonal Qty 565,867    

b. Notice Oct. 31, 2015    Service Expires : Oct. 31, 2016

Contract MonthsMax NominatedMax Unnominated Total MDQ

Daily Qty Daily Qty

November - March     7,359 Dth/day    12,835 Dth/day    20,194 Dth/day

April          5,360 Dth/day     8,437 Dth/day    13,797 Dth/day

May - September          5,360 Dth/day         5,360 Dth/day

October             5,360 Dth/day    11,004 Dth/day    16,364 Dth/day

Maximum Seasonal Qty.     Nov. – Mar.    Apr. – Oct.

1,677,076     581,294

Un-nominated Winter Seasonal Qty 565,867

5. Sellers provisions of ADS 10 shall be subject to the provisions of service reflected in Texas Gas NNS tariffs, as well as other Texas Gas FERC tariffs as may be applicable to the provision of those services.

Amendment

Seller and Buyer agree that this Appendix K.10 may be amended from time to time by mutual agreement of the Parties which amendment ultimately will be memorialized in a revised Appendix K.10

PROLIANCE ENERGY, LLC.            INDIANA GAS COMPANY, INC.

By: _/s/ David C. Pentzien ________________        By: /s/ Jerrold L. Ulrey        

David C. Pentzien    Jerrold L. Ulrey        

Its: Vice President of Sales & Marketing        Its: Vice President, Regulatory Affairs and Fuels

29

IGC-Appendix K.11

Gas Sales And Portfolio Administration Agreement    Revised Page No. 1

April 1, 2012

APPENDIX K.11 - Annual Delivery Service 11

Annual Delivery Service 11 (“ADS 11”)

1. Starting April 1, 2012, consistent with the Buyer’s supply plans, Seller shall provide Buyer with ADS 11 with the following delivered Service entitlements:

Contract MonthsMaximum Daily ADS 11

November-March    195,115 Dth/day    

April- October    155,115 Dth/day    

2. Delivery of these volumes will be into the Northeast system.                            

3.    Buyer shall pay Seller as follows:

a.    For ADS 11 Commodity as follows:                            

Purchase quantities will be determined pursuant to Appendix E pricing.                                    

b.    For ADS 11 Variable Costs:                                

Variable Cost & Fuels under applicable max rate tariffs for Panhandle Eastern EFT (Field to 700) and other applicable pipeline costs if any.

c. For ADS 11 Other Costs:        

Other applicable costs if any as billed including penalties, overrun charges, etc as mutually agreed upon by both parties.

4. 38,572 Dth/day of this ADS 11 service expires on March 31, 2013.

Notice for 51,431 Dth/day of this ADS 11 service is March 31, 2014 expiring on March 31, 2015.

Notice for 38,572 Dth/day of this ADS 11 service is March 31, 2016 expiring on March 31, 2017.

Notice for 17,144 Dth/day of this ADS 11 service is March 31, 2023 expiring on March 31, 2024.

Notice for 5,037 Dth/day of this ADS 11 service is Oct. 31, 2023 expiring on Oct. 31, 2024.

Notice for 17,144 Dth/day of this ADS 11 service is March 31, 2028 expiring on March 31, 2029.

Notice for 5,035 Dth/day of this ADS 11 service is Oct. 31, 2028 expiring on Oct. 31, 2029.

Notice for 17,143 Dth/day of this ADS 11 service is March 31, 2033 expiring on March 31, 2034.

Notice for 5,037 Dth/day of this ADS 11 service is Oct. 31, 2033 expiring on Oct. 31, 2034.

5. Sellers provisions of ADS 11 shall be subject to the provisions of service reflected in Panhandle Eastern EFT tariffs, as well as other Panhandle Eastern FERC tariffs as may be applicable to the provision of those services.

Amendment

Seller and Buyer agree that this Appendix K.11 may be amended from time to time by mutual agreement of the Parties which amendment ultimately will be memorialized in a revised Appendix K.11.

PROLIANCE ENERGY, LLC.            INDIANA GAS COMPANY, INC.

By: _/s/ David C. Pentzien ________________        By: /s/ Jerrold L. Ulrey        

David C. Pentzien    Jerrold L. Ulrey        

Its: Vice President of Sales & Marketing        Its: Vice President, Regulatory Affairs and Fuels

30

IGC-Appendix K.12

Gas Sales And Portfolio Administration Agreement     Revised Page No. 1

April 1, 2012

APPENDIX K.12 - Annual Delivery Service 12

Annual Delivery Service 12 (“ADS 12”)

1. Starting April 1, 2012, consistent with Buyer’s supply plans, Seller shall provide Buyer with ADS 12 with the following delivered service entitlements:

Max

ContractUnnominated

MonthsDaily Qty

November-March     100,000 Dth/day    

April     10,000 Dth/day*    

May - September     0 Dth/day    

October     10,000 Dth/day*    

Maximum Unnominated Qty.    Oct. – April                                                 9,099,120    

* Subject to nomination and availability within Maximum Unnominated Qty.

2. Unless otherwise agreed upon, delivery of these volumes will be into the Northeast system.

3. Buyer shall pay Seller as follows:

a) For Unnominated Quantities:

Summer purchase quantities will be determined jointly by the parties prior to April 1 of each year to replace quantities delivered during the prior winter season. During each summer month, Buyer shall pay Seller one seventh of the summer purchase quantity times the Panhandle Eastern Gas Monthly Index price.

b) For ADS 12 Quantities Variable Costs:

Variable Cost & Fuels under applicable max rate tariffs for Panhandle Eastern EFT, FS, IOS, GDS and other applicable pipeline costs if any as agreed to by both parties.    

c) For ADS 12 Other Costs:        

Other applicable costs if any as billed including penalties, overrun charges, etc as mutually agreed upon by both parties.

4. 1,346,640 Dth of this ADS 12 service expires on March 31, 2013.

Notice for 1,346,640 Dth of this ADS 12 service is March 31, 2014 expiring on March 31, 2015.

Notice for 1,346,640 Dth of this ADS 12 service is March 31, 2016 expiring on March 31, 2017.

Notice for 1,686,400 Dth of this ADS 12 service is March 31, 2023 expiring on March 31, 2024.

Notice for 1,686,400 Dth of this ADS 12 service is March 31, 2028 expiring on March 31, 2029.

Notice for 1,686,400 Dth of this ADS 12 service is March 31, 2033 expiring on March 31, 2034.

31

IGC-Appendix K.12

Gas Sales And Portfolio Administration Agreement     Revised Page No. 2

April 1, 2012

5. Sellers provisions of ADS 12 shall be subject to the provisions of Panhandle Eastern EFT, FS, IOS, GDStariffs as well as applicable FERC tariffs. . Subject to the tariff, the GDS service, which requires the EFT, FS and IOS services, provides for injections during the winter and withdrawals during the summer.

Amendment

Seller and Buyer agree that this Appendix K.12 may be amended from time to time by mutual agreement of the Parties which amendment ultimately will be memorialized in a revised Appendix K.12.

PROLIANCE ENERGY, LLC.            INDIANA GAS COMPANY, INC.

By: _/s/ David C. Pentzien ________________        By: /s/ Jerrold L. Ulrey        

David C. Pentzien    Jerrold L. Ulrey        

Its: Vice President of Sales & Marketing        Its: Vice President, Regulatory Affairs and Fuels

32

IGC-Appendix K.14

Gas Sales And Portfolio Administration Agreement    Revised Page No. 1

April 1, 2012

APPENDIX K.14 - Annual Delivery Service 14

Annual Delivery Service 14 (“ADS 14”)

1. Starting April 1, 2011, consistent with Buyer’s supply plans, Seller shall provide Buyer with ADS 14 with the following delivered service entitlements:

Max

Contract Nominated

Months Daily Qty

November - October 750 Dth/day    

2. Unless otherwise agreed upon, delivery of these volumes will be into the Westport system.

3. Buyer shall pay Seller as follows:

a.For ADS 14 Commodity as follows:

Purchase quantities will be determined jointly by the parties and priced pursuant to Appendix E.

b. For ADS 14 Variable Costs:

Variable Cost & Fuels under applicable max rate tariffs for Texas Eastern SCT tariff and other pipeline costs as agreed to by both parties.

c. For ADS 14 Other Costs:        

Other applicable costs if any as billed including penalties, overrun charges, etc as mutually agreed upon by both parties.

4. Notice for this ADS 14 Service is April 30, 2012. Service expires April 30, 2014. A 2 year notice is required for termination of this service. Service rolls 1 year out each year.

5. Sellers provisions of ADS 14 shall be subject to the provisions of Texas Eastern SCT Tariff as well as applicable FERC tariffs.

Amendment

Seller and Buyer agree that this Appendix K.14 may be amended from time to time by mutual agreement of the Parties which amendment ultimately will be memorialized in a revised Appendix K.14.

PROLIANCE ENERGY, LLC.            INDIANA GAS COMPANY, INC.

By: _/s/ David C. Pentzien ________________        By: /s/ Jerrold L. Ulrey        

David C. Pentzien    Jerrold L. Ulrey        

Its: Vice President of Sales & Marketing        Its: Vice President, Regulatory Affairs and Fuels

33

IGC-Appendix M.1

Gas Sales And Portfolio Administration Agreement    Revised Page No. 1

April 1, 2012

APPENDIX M.1 - Summer Delivery Service 1

Summer Delivery Service 1 (“SDS 1”)

1. Starting April 1, 2012, consistent with the Buyer’s supply plans, Seller shall provide Buyer with SDS 1 with the following delivered Service entitlements:

Contract MonthsMaximum Daily SDS1

April - October    20,000 Dth/day

2. These delivery service entitlements shall be available at the PEPL-ANR Defiance interconnect, subject to availability, within Buyer’s supply plan, of unutilized entitlements at the Indiana Gas Gate on Panhandle Eastern Pipeline.                                                                

3. Buyer shall pay Seller as follows:

a.    For SDS 1 Variable Costs:                                

Variable Cost & Fuels under applicable max rate tariffs for Panhandle Eastern EFT.

b. For SDS 1 Other Costs:        

Other applicable costs if any as billed including penalties, overrun charges, etc as mutually agreed upon by both parties.

4. This SDS 1 service expires October 31, 2013.

5. Sellers provisions of SDS 1 shall be subject to the provisions of service reflected in Panhandle Eastern EFT tariffs, as well as other Panhandle Eastern FERC tariffs as may be applicable to the provision of those services.

Amendment

Seller and Buyer agree that this Appendix M.1 may be amended from time to time by mutual agreement of the Parties which amendment ultimately will be memorialized in a revised Appendix M.1.

PROLIANCE ENERGY, LLC.            INDIANA GAS COMPANY, INC.

By: _/s/ David C. Pentzien ________________        By: /s/ Jerrold L. Ulrey    

David C. Pentzien    Jerrold L. Ulrey        

Its: Vice President of Sales & Marketing        Its: Vice President, Regulatory Affairs and Fuels

34

EX-10.4

EXHIBIT 10.4

Gas Sales and Portfolio Administration Agreement

APPENDICES INDEX

Buyer's Primary Delivery Points        A

Buyer’s Maximum Quantities        B

“Reserved for Future Use”            C

Supplier Reservation Costs        D

Commodity Purchases-Gas Cost

Incentive Mechanism            E

Notices                    F

Invoice/Payment Data            G

Demand Cost Charges            H

“Reserved”                I

Portfolio Services                J - K

SIGECO-Appendix A

1

2

Gas Sales And Portfolio Administration Agreement         Revised Page No. 1

April 1, 2012

APPENDIX A - Buyer’s Primary Delivery Points

Texas Gas Transmission Corporation:

Meter No.Meter Station Name

1808    SIGECO South Shipper Deduct (includes all of the following)

Elberfeld

Boonville Road

Long Road

Levee (Evansville)

Haubstadt

Snake Run

Francisco

Wagner

1809    SIGECO North Shipper Deduct (includes all of the following)

Bicknell

Edwardsport

Freelandville

Monroe City

Oaktown

Petersburg

Washington Road

Rural – SIGECO

Rural – Hoosier Gas

9540     Dogtown

Midwestern Gas Transmission:

Meter No.Meter Station Name

7071-Chrisney

02-7100    Ohio Valley Hub

3

SIGECO-Appendix A

Gas Sales And Portfolio Administration Agreement         Revised Page No. 2

April 1, 2012

ANR Gas Pipeline:

Meter No.Meter Station Name

032410100    South Chrisney (SIGECO)

Texas Eastern Gas Transmission:

Meter No.Meter Station Name

79730    SIGECO - LDC Allocation Point

70539    Ft. Branch, IN

72648    Southern Indiana Posey Co., IN

Ohio Valley Hub, LLC:

Meter No.Meter Station Name

Monroe City Storage Field

9401     Texas Gas - Ohio Valley Hub Interconnect

Amendment

Seller and Buyer agree that this Appendix A may be amended as provided in this Agreement, which amendment ultimately will be memorialized in a revised Appendix A.

PROLIANCE ENERGY, LLC.            SOUTHERN INDIANA GAS AND ELECTRIC COMPANY

By: _/s/ David C. Pentzien ________________        By: /s/ Jerrold L. Ulrey        

David C. Pentzien    Jerrold L. Ulrey        

Its: Vice President of Sales & Marketing        Its: Vice President, Regulatory Affairs and Fuels

4

SIGECO-Appendix B

Gas Sales And Portfolio Administration Agreement          Revised Page No. 1

April 1, 2012

APPENDIX B - Buyer’s Maximum Quantities

MonthDaily

April         73,233        

May         62,327        

June     62,327        

July     62,327        

August     62,327            

September     62,327        

October          76,595     

November         71,200                    

December     71,200            

January     71,200        

February     71,200        

March     71,200        

Amendment

Seller and Buyer agree that this Appendix B may be amended as provided in this Agreement, which amendment ultimately will be memorialized in a revised Appendix B.

PROLIANCE ENERGY, LLC.            SOUTHERN INDIANA GAS AND ELECTRIC COMPANY

By: _/s/ David C. Pentzien ________________        By: /s/ Jerrold L. Ulrey        

David C. Pentzien    Jerrold L. Ulrey        

Its: Vice President of Sales & Marketing        Its: Vice President, Regulatory Affairs and Fuels

5

SIGECO-Appendix D

Gas Sales And Portfolio Administration Agreement             Revised Page No. 1

    April 1, 2012

APPENDIX D - Supplier Reservation Costs

Supplier Reservation Costs

April 1, 2012 through October 31, 2012

I.    Reserved Commodity Quantities

a. Monthly Baseload Reserved Quantity (Dth/Day)

Month	MGT	TGT Gulf Coast	TETCO
November, 2011	0	17,600	424
December, 2011	6,061	23,746	428
January, 2012	6,061	23,746	428
February, 2012	5,051	19,311	428
March, 2012	3,030	14,351	428
April, 2012	667	10,877	106
May, 2012	645	10,526	106
June, 2012	667	10,877	106
July, 2012	645	8,913	106
August, 2012	645	8,913	106
September, 2012	667	9,210	106
October, 2012	645	8,913	106

Buyer and Seller agree that some portion of the quantities identified as Monthly Baseload Reserved Quantities may be provided at fixed, collared, or hedged prices mutually agreed upon pursuant to the GCIM.

6

SIGECO-Appendix D

Gas Sales And Portfolio Administration Agreement             Revised Page No. 2

    April 1, 2012

APPENDIX D - Supplier Reservation Costs

b. Daily Swing Reserved Quantity (Dth/Day)

Month	MGT	TGT Gulf Coast	TETCO
November, 2011	35,354	6,306	636
December, 2011	29,293	160	641
January, 2012	29,293	160	641
February, 2012	30,303	4,596	641
March, 2012	32,323	7,037	641
April, 2012	34,333	14,370	1,980
May, 2012	34,355	14,721	1,980
June, 2012	34,333	14,370	1,980
July, 2012	34,355	16,334	1,980
August, 2012	34,355	16,334	1,980
September, 2012	34,333	16,037	1,980
October, 2012	34,355	16,334	1,980

Buyer and Seller agree that some portion of the quantities identified as Daily Swing Reserved Quantities may be provided at fixed, collared, or hedged prices mutually agreed upon pursuant to the GCIM.

II.    Applicable Reservation Rates ($/Dth/Day)

System	Winter Months (Nov.-Mar.)			Summer Months (Apr.-Oct.)
	Monthly Index ReservedQuantity	Daily Index ReservedQuantity	Monthly Index ReservedQuantity		Daily Index ReservedQuantity
MGT	$0.0174	$0.0100	$0.00		$0.00
TGT Gulf Coast	$0.0000	$0.0025	$0.00		$0.00
TETCO	$0.0025	$0.0050	$0.00		$0.00

7

SIGECO-Appendix D

Gas Sales And Portfolio Administration Agreement             Revised Page No. 3

    April 1, 2012

APPENDIX D - Supplier Reservation Costs

Amendment

Seller and Buyer agree that this Appendix D may be amended from time to time by mutual agreement of the Parties, which ultimately will be memorialized in a revised Appendix D.

PROLIANCE ENERGY, LLC SOUTHERN INDIANA GAS AND ELECTRIC COMPANY

By: _/s/ David C. Pentzien _______________        By: /s/ Jerrold L. Ulrey        

David C. Pentzien    Jerrold L. Ulrey        

Its: Vice President of Marketing & Sales        Its: Vice President, Regulatory Affairs and Fuels

8

SIGECO-Appendix E

Gas Sales And Portfolio Administration Agreement         Revised Page No. 1

April 1, 2012

APPENDIX E –Commodity Purchases – Gas Cost Incentive Mechanism

The commodity purchased by Buyer shall be provided in accordance with the Commission approved Gas Cost Incentive Mechanism described in Appendix E of the Settlement. All record keeping and reporting shall be performed in a manner consistent with the terms of the GCIM. Seller agrees and acknowledges the reasonableness of the Gas purchases made shall be subject to review to ensure such purchases were made in a manner consistent with the terms of the GCIM.

For Summer Storage Refill:

For summer refill of leased storage, Buyer shall pay to Seller an amount based on averaging the seven summer monthly indices for the applicable supply area, and based upon presuming storage refill quantities to be equally split between the summer months. For summer refill of company storage, the parties will agree on the extent to which an index average method will be used, after consideration of the operational scheduling needs of company storage. In addition, all other applicable variable costs as identified below shall apply.

For Storage Withdrawals:

For quantities of storage withdrawals for which Buyer has previously paid for commodity, applicable storage withdrawal variable costs as identified below shall apply.

For Applicable Indices:

Contract No.Contract RateIndex

ADS 1    Appendix K.1        Texas Gas – Zone SL

ADS 2    Appendix K.2        Texas Gas – Zone SL

ADS 3    Appendix K.3    Chicago-LDCs, large e-us

ADS 7    Appendix K.7        TETCO – (ELA, WLA, ETX, STX)

9

SIGECO-Appendix E

Gas Sales And Portfolio Administration Agreement          Revised Page No. 2

April 1, 2012

APPENDIX E- Commodity Purchases- Other Variable Costs

(Continued)

The other variable costs applicable to Nominated Daily Quantities and Balancing Quantities shall be determined based upon the rates and charges applicable under each transporter’s tariff, including the sheets identified below, as well as other applicable sheets, as all of those sheets may be in effect from time to time, and costs arising under applicable agreements, including the agreements identified below, as well as this Agreement.

SIGECO

Texas Eastern

Contract No.Contract Rate

ADS 7    Appendix K.7    

Midwestern                            

Contract No.Contract Rate

ADS 3            Appendix K.3

Texas Gas Z-3        

Contract No.Contract Rate

WDS 1    Appendix J.1    

ADS 1    Appendix K.1

ADS 2    Appendix K.2    

ADS 5     Appendix K.5    

ADS 6    Appendix K.6

Ohio Valley Hub

Contract No.Contract Rate

ADS 4             Appendix K.4                                

10

SIGECO-Appendix E

Gas Sales And Portfolio Administration Agreement          Revised Page No. 3

April 1, 2012

APPENDIX E - Commodity Purchases - Other Variable Costs

While Seller and Buyer agree that the identified tariff sheets and agreements are intended to be a complete listing of the applicable tariff sheets and applicable agreements, they further agree that the omission of the reference of one or more sheets or agreements from that list will not affect Buyer’s obligation to Seller for rates, charges and costs incurred thereunder.

Amendment

Seller and Buyer agree that this Appendix E may be amended from time to time by mutual agreement of the Parties, which ultimately will be memorialized in a revised Appendix E.

PROLIANCE ENERGY, LLC.            SOUTHERN INDIANA GAS AND ELECTRIC COMPANY

By: _/s/ David C. Pentzien ________________        By: /s/ Jerrold L. Ulrey        

David C. Pentzien    Jerrold L. Ulrey        

Its: Vice President of Sales & Marketing        Its: Vice President, Regulatory Affairs and Fuels

11

SIGECO-Appendix F

Gas Sales And Portfolio Administration Agreement          Revised Page No. 1

April 1, 2012

Appendix F-Notices

Invoice Information:

Buyer:                        Seller:

Southern Indiana Gas and Electric Company    ProLiance Energy, LLC

Attn.: Director, Gas Supply    Attn: Accounting/Treasury
One Vectren Square     111 Monument Circle    Suite 2200
Evansville, IN 47708    Indianapolis, IN 46204-5178
(812) 491-4670    (317) 231-6800

Payments:

Buyer:                        Seller:

PNC Bank    1/7^th Refill Gas Costs:

Huntington National Bank

For the Account of:    Indianapolis, Indiana

For the Account of:

Indiana gas Company, Inc.    ProLiance Energy, LLC

ABA# 044000024

ACCT# 01401007177

All Other Gas & Delivery Service Costs:

PNC Bank, N.A.

East Brunswick, NJ

For the Account of:

ProLiance Energy, LLC

ABA# 031207607

ACCT# 8026582295

Supply Plans/Operational/Force Majeure:

Buyer:    Seller:

Supply PlansSupply Plans
Gas Supply Analyst    Chris Kershner
(812) 491-4333    (317) 231-6952    
OperationalOperational
Randy Gary    Chris Kershner
(812) 491-4730    (317) 231-6952

Force MajeureForce Majeure
Randy Gary (812) 491-4730    Chris Kershner - (317) 231-6952
Perry M. Pergola (812) 491-4670    Paula Montgomery - (317) 231-68
Gas Controller on Duty (812) 491-4530    ProLiance Energy, LLC
Southern Indiana Gas and Electric Company    111 Monument Circle
One Vectren Square    Suite 2200
Evansville, IN 47708    Indianapolis, Indiana 46204-5178
(812) 491-4687 (Telecopy)    (317) 231-6901 (Telecopy)

SIGECO-Appendix F

12

Gas Sales And Portfolio Administration Agreement          Revised Page No. 2

April 1, 2012

APPENDIX F-Notices
(Continued)

All Other Notices:

Buyer:    Seller:

Southern Indiana Gas and Electric Company    ProLiance Energy, LLC
Attn.: Director, Gas Supply    Attn: Paula Montgomery

One Vectren Square    111 Monument Circle    

Evansville, IN 47708    Suite 2200    

Indianapolis, Indiana 46204-5178

Amendment

Seller and Buyer agree that this Appendix F may be amended from time to time as provided in this Agreement, which amendment ultimately will be memorialized in a revised Appendix F.

PROLIANCE ENERGY, LLC.            SOUTHERN INDIANA GAS AND ELECTRIC COMPANY

By: _/s/ David C. Pentzien ________________        By: /s/ Jerrold L. Ulrey        

David C. Pentzien    Jerrold L. Ulrey        

Its: Vice President of Sales & Marketing        Its: Vice President, Regulatory Affairs and Fuels

13

SIGECO-Appendix G

Gas Sales And Portfolio Administration Agreement          Revised Page No. 1

April 1, 2012

APPENDIX G - Invoice/Payment Data

Invoice Date -     On or before the tenth (10th) day after the Contract Month.

Due Date -      All Delivery Service Costs due on or before the 20^th day of the month

All Gas Costs due on or before the 25^th day of the month.

Payment Method -    By wire transfer to account specified on invoice.

Amendment

Seller and Buyer agree that this Appendix G may be amended from time to time by mutual agreement of the Parties, which amendment ultimately will be memorialized in a revised Appendix G.

PROLIANCE ENERGY, LLC.            SOUTHERN INDIANA GAS AND ELECTRIC COMPANY

By: _/s/ David C. Pentzien ________________        By: /s/ Jerrold L. Ulrey        

David C. Pentzien    Jerrold L. Ulrey        

Its: Vice President of Sales & Marketing        Its: Vice President, Regulatory Affairs and Fuels

14

SIGECO-Appendix H

Gas Sales and Portfolio Administration Agreement          Revised Page No. 1

April 1, 2012

APPENDIX H – Demand Cost Charges

This Annual Net Demand cost covers all delivery services provided by Seller to Buyer under Appendix I through Appendix K.  Other, additional, charges payable by Buyer to Seller for delivery services are specifically described in each Appendix Service (Appendix I through Appendix K)

Month	Gross Demand Cost	Demand Credit	Net Demand Cost
Apr	$505,257.00	$264.00	$504,993.00
May	$399,555.00	$265.00	$399,290.00
Jun	$389,337.00	$264.00	$389,073.00
Jul	$399,555.00	$265.00	$399,290.00
Aug	$399,555.00	$264.00	$399,291.00
Sep	$389,337.00	$265.00	$389,072.00
Oct	$556,265.00	$264.00	$556,001.00
Nov	$531,319.00	$265.00	$531,054.00
Dec	$683,629.00	$264.00	$683,365.00
Jan	$683,629.00	$265.00	$683,364.00
Feb	$624,050.00	$264.00	$623,786.00
Mar	$546,764.00	$265.00	$546,499.00
Total	$6,108,252.00	$3,174.00	$6,105,078.00

PROLIANCE ENERGY, LLC.            SOUTHERN INDIANA GAS AND ELECTRIC COMPANY

By: _/s/ David C. Pentzien ________________        By: /s/ Ronald E. Christian        

David C. Pentzien    Ronald E. Christian        

Its: Vice President of Sales & Marketing        Its: Executive Vice President         

SIGECO-Appendix J.1

15

Gas Sales And Portfolio Administration Agreement         Revised Page No. 1

April 1, 2012

APPENDIX J.1 - Winter Delivery Service 1

Winter Delivery Service 1 TGT (“WDS 1”)

1. Starting April 1, 2012, consistent with Buyer’s supply plans, Seller shall provide Buyer with WDS 1 with the following delivered service entitlements:

Contract Months Max NominatedMonthly

Daily Qty Demand $

November 0 Dth/day        

December-February 25,000 Dth/day        

March- October 0 Dth/day        

2.    Unless otherwise agreed upon, Seller shall provide entitlements from the TGT/Ohio Valley Hub Meter to Buyer’s SIGECO South Shipper Deduct Texas Gas city gate.

3. Buyer shall pay Seller as follows:

a.    For Nominated Commodity as follows:

Purchase quantities will be determined jointly by the parties and priced pursuant to Appendix E.

b. For WDS 1 Variable Costs:

Variable Cost & Fuels under the effective Texas Gas STF (Zone3-Zone 3) max rate schedule and other applicable costs, if any as billed.

c. For WDS 1 Other Costs:        

Other applicable costs if any as billed including penalties, overrun charges, etc as mutually agreed upon by both parties.

4. Service expires March 31, 2013.

5. Sellers provisions of WDS 1 shall be subject to the provisions of service reflected in Texas Gas STF tariffs, as well as other Texas Gas tariffs as may be applicable to the provision of those services

Amendment

Seller and Buyer agree that this Appendix J.1 may be amended from time to time by mutual agreement of the Parties which amendment ultimately will be memorialized in a revised Appendix J.1

PROLIANCE ENERGY, LLC.            SOUTHERN INDIANA GAS AND ELECTRIC COMPANY

By: _/s/ David C. Pentzien ________________        By: /s/ Jerrold L. Ulrey        

David C. Pentzien    Jerrold L. Ulrey        

Its: Vice President of Sales & Marketing        Its: Vice President, Regulatory Affairs and Fuels

16

SIGECO-Appendix J.1

Gas Sales And Portfolio Administration Agreement         Revised Page No. 1

April 1, 2013

APPENDIX J.1 - Winter Delivery Service 1

Winter Delivery Service 1 TGT (“WDS 1”)

1. Starting April 1, 2013, consistent with Buyer’s supply plans, Seller shall provide Buyer with WDS 1 with the following delivered service entitlements:

Contract Months Max NominatedMonthly

Daily Qty Demand $

November 0 Dth/day        

December-February 20,000 Dth/day        

March- October 0 Dth/day        

2.    Unless otherwise agreed upon, Seller shall provide entitlements from the TGT/Ohio Valley Hub Meter to Buyer’s SIGECO South Shipper Deduct Texas Gas city gate.

3. Buyer shall pay Seller as follows:

a.    For Nominated Commodity as follows:

Purchase quantities will be determined jointly by the parties and priced pursuant to Appendix E.

b. For WDS 1 Variable Costs:

Variable Cost & Fuels under the effective Texas Gas STF (Zone3-Zone 3) max rate schedule and other applicable costs, if any as billed.

c. For WDS 1 Other Costs:        

Other applicable costs if any as billed including penalties, overrun charges, etc as mutually agreed upon by both parties.

4. Notice for this WDS 1 service is March 31, 2013. Service expires March 31, 2014.

5. Sellers provisions of WDS 1 shall be subject to the provisions of service reflected in Texas Gas STF tariffs, as well as other Texas Gas tariffs as may be applicable to the provision of those services

Amendment

Seller and Buyer agree that this Appendix J.1 may be amended from time to time by mutual agreement of the Parties which amendment ultimately will be memorialized in a revised Appendix J.1

PROLIANCE ENERGY, LLC.            SOUTHERN INDIANA GAS AND ELECTRIC COMPANY

By: _/s/ David C. Pentzien ________________        By: /s/ Jerrold L. Ulrey        

David C. Pentzien    Jerrold L. Ulrey        

Its: Vice President of Sales & Marketing        Its: Vice President, Regulatory Affairs and Fuels

17

SIGECO -Appendix K.1

Gas Sales And Portfolio Administration Agreement     Revised Page No. 1

     April 1. 2012

APPENDIX K.1 – Annual Delivery Service 1

Annual Delivery Service (“ADS 1”)

1. Starting April 1, 2012, consistent with Buyer’s supply plans, Seller shall provide Buyer with ADS 1 with the following delivered service entitlements:

Contract Month	MNDQ South	MUNDQ South	MNDQ North	MUNDQ North	Total MDQ
November - March	5,628	15,686	2,560	1,126	25,000
April	6,447	9,130	3,800	1,776	21,153
May- September	6,447		3,800		10,247
October	6,447	11,944	3,800	2,324	24,515

Nov. – Mar.        Apr. – Oct.

Maximum Seasonal Qty             1,674,952         1,754,361

Unnominated Winter Seasonal Qty     439,564    

2. Unless otherwise agreed upon, Seller shall provide entitlements to Buyer’s TGT City gates (as outlined above).

3.    Buyer shall pay Seller as follows:

a. For Unnominated Quantities:

Summer purchase quantities will be determined jointly by the parties prior to April 1 of each year to replace quantities delivered during the prior winter season. During each summer month, Buyer shall pay Seller one seventh of the summer purchase quantity times the Texas Gas Monthly Index price.

b. For Nominated Commodity as follows:

Purchase quantities will be determined jointly by the parties and priced pursuant to Appendix E.

c. For ADS 1 Variable Costs:

Variable Cost & Fuel under the effective Texas Gas NNS (Zone 3) max rate schedule and other applicable costs, if any as billed.

d. For ADS 1 Other Costs:        

Other applicable costs if any as billed including penalties, overrun charges, etc as mutually agreed upon by both parties.

4.    Notice for this ADS 1 service is October 31, 2014. Service expires October 31, 2015.        

18

SIGECO -Appendix K.1

Gas Sales And Portfolio Administration Agreement     Revised Page No. 2

April 1, 2012

5. Sellers provisions of ADS 1 shall be subject to the provisions of service reflected in Texas Gas NNS tariffs, as well as other Texas Gas FERC tariffs as may be applicable to the provision of those services

Amendment

Seller and Buyer agree that this Appendix K.1 may be amended from time to time by mutual agreement of the Parties which amendment ultimately will be memorialized in a revised Appendix K.1

PROLIANCE ENERGY, LLC.            SOUTHERN INDIANA GAS AND ELECTRIC COMPANY

By: _/s/ David C. Pentzien ________________        By: /s/ Jerrold L. Ulrey        

David C. Pentzien    Jerrold L. Ulrey        

Its: Vice President of Sales & Marketing        Its: Vice President, Regulatory Affairs and Fuels

19

SIGECO -Appendix K.2

Gas Sales And Portfolio Administration Agreement     Revised Page No. 1

April 1, 2012

APPENDIX K.2 – Annual Delivery Service 2

Annual Delivery Service 2 TGT (“ADS 2”)

1. Starting April 1, 2012, consistent with Buyer’s supply plans, Seller shall provide Buyer with ADS 2 with the following delivered service entitlements:

Contract Month	MNDQ South	MNDQ North	Total MDQ
November-October	13,000	2,000	15,000

Maximum Seasonal Qty    Nov. – Mar.        Apr. – Oct.

2,265,000         3,210,000

2. Unless otherwise agreed upon, Seller shall provide entitlements to Buyer’s SIGECO North & South Shipper Deduct TGT City gate.

3.    Buyer shall pay Seller as follows:

a. For Nominated Commodity as follows:

Purchase quantities will be determined jointly by the parties and priced pursuant to Appendix E.

b. For ADS 2 Variable Costs:

Variable Cost & Fuel per the effective max rates under Texas Gas FT (SL- Zone 3) rate schedule and other applicable costs, if any as billed.

c. For ADS 7 Other Costs:        

Other applicable costs if any as billed including penalties, overrun charges, etc as mutually agreed upon by both parties.

4.    Notice for this ADS 2 service is March 31, 2014. Service expires March 31, 2015.        

5. Sellers provisions of ADS 2 shall be subject to the provisions of service reflected in Texas Gas FT tariffs, as well as other Texas Gas FERC tariffs as may be applicable to the provision of those services.

Amendment

Seller and Buyer agree that this Appendix K.2 may be amended from time to time by mutual agreement of the Parties which amendment ultimately will be memorialized in a revised Appendix K.2

PROLIANCE ENERGY, LLC.            SOUTHERN INDIANA GAS AND ELECTRIC COMPANY

By: _/s/ David C. Pentzien ________________        By: /s/ Jerrold L. Ulrey        

David C. Pentzien    Jerrold L. Ulrey        

Its: Vice President of Sales & Marketing        Its: Vice President, Regulatory Affairs and Fuels

20

SIGECO -Appendix K.3

Gas Sales And Portfolio Administration Agreement     Revised Page No. 1

April 1, 2012

APPENDIX K.3 - Annual Delivery Service 3

Annual Delivery Service 3 MGT (“ADS 3”)

1. Starting April 1, 2012, consistent with Buyer’s supply plans, Seller shall provide Buyer with ADS 3 with the following delivered service entitlements:

Contract Months Max Nominated

Daily Qty

April - October 35,000 Dth/day

November - March 30,000 Dth/day        

2. Unless otherwise agreed upon, Seller shall provide entitlements to Buyer’s system.

3. Buyer shall pay Seller as follows:

a.    For Nominated Commodity as follows:

Purchase quantities will be determined jointly by the parties and priced pursuant to Appendix E.

b. For ADS 3 Variable Costs:

Variable Cost & Fuel under the effective max rate Midwestern FT-A rate schedule and other applicable costs, if any as billed.

c. For ADS 3 Other Costs:        

Other applicable costs if any as billed including penalties, overrun charges, etc as mutually agreed upon by both parties.

4. Notice for30,000 Dth/day is October 1, 2013. Service expires March 31, 2014.

5,000 DTH/day expires October 31, 2012

5. Sellers provisions of ADS 3 shall be subject to the provisions of service reflected in Midwestern FT tariffs, as well as other Midwestern FERC tariffs as may be applicable to the provision of those services.

Amendment

Seller and Buyer agree that this Appendix K.3 may be amended from time to time by mutual agreement of the Parties which amendment ultimately will be memorialized in a revised Appendix K.3

PROLIANCE ENERGY, LLC.            SOUTHERN INDIANA GAS AND ELECTRIC COMPANY

By: _/s/ David C. Pentzien ________________        By: /s/ Jerrold L. Ulrey        

David C. Pentzien    Jerrold L. Ulrey        

Its: Vice President of Sales & Marketing        Its: Vice President, Regulatory Affairs and Fuels

21

SIGECO -Appendix K.4

Gas Sales And Portfolio Administration Agreement     Revised Page No. 1

November 1, 2011

APPENDIX K.4 - Annual Delivery Service 4

Annual Delivery Service 4 OVH (“ADS 4”)

1. Starting November 1, 2011, consistent with Buyer’s supply plans, Seller shall provide Buyer with ADS 4 with the following delivered service entitlements:

Contract Months Max Nominated

Daily Qty

November - October 25,000 Dth/day        

2.    Unless otherwise agreed upon, Seller shall provide entitlements to Buyer’s City gate.

3. Buyer shall pay Seller as follows:

a.    For Nominated Commodity as follows:

Purchase quantities will be determined jointly by the parties and priced pursuant to Appendix E.

b.    For ADS 4 Variable Costs:

Variable Cost Rate of $.031/Dth and other applicable costs, if any as billed.

c. For ADS 4 Other Costs:        

Other applicable costs if any as billed including penalties, overrun charges, etc as mutually agreed upon by both parties.

4. Service expires October 31, 2013.

5. Sellers provisions of ADS 4 shall be subject to the provisions of service reflected in Ohio Valley Hub FT tariffs, as well as other Ohio Valley Hub tariffs as may be applicable to the provision of those services

Amendment

Seller and Buyer agree that this Appendix K.4 may be amended from time to time by mutual agreement of the Parties which amendment ultimately will be memorialized in a revised Appendix K.4

PROLIANCE ENERGY, LLC.            SOUTHERN INDIANA GAS AND ELECTRIC COMPANY

By: _/s/ David C. Pentzien ________________        By: /s/ Jerrold L. Ulrey        

David C. Pentzien    Jerrold L. Ulrey        

Its: Vice President of Sales & Marketing        Its: Vice President, Regulatory Affairs and Fuels

22

SIGECO -Appendix K.4

Gas Sales And Portfolio Administration Agreement     Revised Page No. 1

November 1, 2012

APPENDIX K.4 - Annual Delivery Service 4

Annual Delivery Service 4 OVH (“ADS 4”)

1. Starting November 1, 2013, consistent with Buyer’s supply plans, Seller shall provide Buyer with ADS 4 with the following delivered service entitlements:

Contract Months Max Nominated

Daily Qty

November - October 20,000 Dth/day        

2.    Unless otherwise agreed upon, Seller shall provide entitlements to Buyer’s City gate.

3. Buyer shall pay Seller as follows:

a.    For Nominated Commodity as follows:

Purchase quantities will be determined jointly by the parties and priced pursuant to Appendix E.

b.    For ADS 4 Variable Costs:

Variable Cost Rate of $.031/Dth and other applicable costs, if any as billed.

c. For ADS 4 Other Costs:        

Other applicable costs if any as billed including penalties, overrun charges, etc as mutually agreed upon by both parties.

4. Notice for termination is October 31, 2012. Service will roll 1 year without notice. Service expires October 31, 2014.

5. Sellers provisions of ADS 4 shall be subject to the provisions of service reflected in Ohio Valley Hub FT tariffs, as well as other Ohio Valley Hub tariffs as may be applicable to the provision of those services

Amendment

Seller and Buyer agree that this Appendix K.4 may be amended from time to time by mutual agreement of the Parties which amendment ultimately will be memorialized in a revised Appendix K.4

PROLIANCE ENERGY, LLC.            SOUTHERN INDIANA GAS AND ELECTRIC COMPANY

By: _/s/ David C. Pentzien ____________________        By: /s/ Jerrold L. Ulrey        

David C. Pentzien    Jerrold L. Ulrey        

Its: Vice President of Sales & Marketing        Its: Vice President, Regulatory Affairs and Fuels

23

SIGECO -Appendix K.7

Gas Sales And Portfolio Administration Agreement     Revised Page No. 1

April 1, 2012

APPENDIX K.7 - Annual Delivery Service 7

Annual Delivery Service 7 TETCO (“ADS 7”)

1. Starting April 1, 2012, consistent with Buyer’s supply plans, Seller shall provide Buyer with ADS 7 with the following delivered service entitlements:

Max Daily

Contract Nominated

Months Daily Qty

April – October    2,080 Dth/day

November – March    1,200 Dth/day    

2. Unless otherwise agreed upon, delivery of these volumes will be into the SIGECO system.

3. Buyer shall pay Seller as follows:

a. For ADS 7 Nominated Commodity as follows:

Purchase quantities will be determined jointly by the parties and priced pursuant to Appendix E

b. For ADS 7 Nominated Quantities Variable Costs:

Variable costs & Fuel under applicable max rate tariffs for Texas Eastern SCT tariff and other pipeline costs as mutually agreed upon by both parties.

c. For ADS 7 Other Costs:        

Other applicable costs if any as billed including penalties, overrun charges, etc as mutually agreed upon by both parties.

4. This ADS 7 service expires October 31, 2014. A 2 year written notice is required to terminate. Service rolls 1 year out each year.

5. Sellers provisions of ADS 7 shall be subject to the provisions of TETCO SCT Tariffs as well as applicable FERC tariffs.

Amendment

Seller and Buyer agree that this Appendix K.7 may be amended from time to time by mutual agreement of the Parties which amendment ultimately will be memorialized in a revised Appendix K.7.

PROLIANCE ENERGY, LLC.            SOUTHERN INDIANA GAS AND ELECTRIC COMPANY

By: _/s/ David C. Pentzien ________________        By: /s/ Jerrold L. Ulrey        

David C. Pentzien    Jerrold L. Ulrey        

Its: Vice President of Sales & Marketing        Its: Vice President, Regulatory Affairs and Fuels

24

SIGECO -Appendix K.8

Gas Sales And Portfolio Administration Agreement     Revised Page No. 1

April 1, 2012

APPENDIX K.8 – Annual Delivery Service 8

Annual Delivery Service 8 TGT (“ADS 8”)

1. Starting April 1, 2011, consistent with Buyer’s supply plans, Seller shall provide Buyer with ADS 8 with the following delivered service entitlements:

Contract Month	Total MDQ
April-March	9,000

2. Unless otherwise agreed upon, Seller shall provide entitlements from TGT meter 9567 (Henderson-Dogtown) to Buyer’s SIGECO TGT City gate Meter # 9540 Dogtown.

3.    Buyer shall pay Seller as follows:

a. For Nominated Commodity as follows:

Purchase quantities will be determined jointly by the parties and priced pursuant to Appendix E.

b. For ADS 8 Variable Costs:

Demand, Variable, and other costs will be determined pursuant to Buyer’s Texas Gas Contract (# 26787) and as billed by Texas Gas, for Contract #26787, to ProLiance Energy as agent for Vectren Energy Delivery of Indiana South.

c. For ADS 8 Fuel Rates:

Fuel Rates will be applied to Daily Wellhead Quantities pursuant to Texas Gas’s FT tariff for the Z3-Z3 deliveries.

d. For ADS 8 Other Costs:        

Other applicable costs if any as billed including penalties, overrun charges, etc as mutually agreed upon by both parties.

4. Notice for this ADS 8 service is March 31, 2028. Service expires March 31, 2029 and corresponds with the termination of Buyer’s Texas Gas Contract #26787.    

5. Sellers provisions of ADS 8 shall be subject to the provisions of service reflected in Texas Gas FT tariffs, as well as other Texas Gas FERC tariffs as may be applicable to the provision of those services and as reflected in Buyer’s Texas Gas Contract #26787.

Amendment

Seller and Buyer agree that this Appendix K.8 may be amended from time to time by mutual agreement of the Parties which amendment ultimately will be memorialized in a revised Appendix K.8

PROLIANCE ENERGY, LLC.            SOUTHERN INDIANA GAS AND ELECTRIC COMPANY

By: _/s/ David C. Pentzien ________________        By: /s/ Jerrold L. Ulrey    

David C. Pentzien    Jerrold L. Ulrey        

Its: Vice President of Sales & Marketing        Its: Vice President, Regulatory Affairs and Fuels

25

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 15, 2013, 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, 2012.

/s/ Deloitte & Touche LLP

Indianapolis, Indiana

February 15, 2013

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 15, 2013

/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 15, 2013

/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 15th day of February, 2013.

/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)

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Nonutility Real Estate & Other Legacy Holdings (Tables)

12 Months Ended

Dec. 31, 2012

Nonutility Real Estate Other Legacy Holdings [Abstract]

Investment by type of investment

Further separation of that 2012 investment by type of investment follows:

	December 31, 2012
			Value Included In
(In millions)	Carrying Value		Other Nonutility Investments		Investments in Unconsolidated Affiliates
Commercial real estate investments	$	8.0	$	8.0	$	—
Leveraged lease	13.8		13.8		—
Other investments	6.9		3.1		3.8
	$	28.7	$	24.9	$	3.8

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Acquisition of Minnesota Limited, Inc. (Details) (USD $)	3 Months Ended								12 Months Ended
	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Business Combinations [Abstract]
Acquisition date										March 31, 2011
Purchase price allocation [Abstract]
Business acquisition, net of cash acquired									$ 0	$ 83,400,000	$ 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					600,000					600,000
Transaction costs associated with the acquisition included in other operating expenses during the period									781,000,000	652,200,000	538,400,000
Lease Obligation										83,333
Number of years the company is obligated to lease acquiree's corporate headquarters					10					10
Contribution to Nonutility revenues									899,800,000	870,200,000	567,400,000
Net income (loss)	42,800,000	39,300,000	25,600,000	51,300,000	46,600,000	35,300,000	15,100,000	44,600,000	159,000,000	141,600,000	133,700,000
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 included in other operating expenses during the period										200,000
Contribution to Nonutility revenues										116,500,000
Net income (loss)										9,400,000
Business Acquisition, Pro Forma Revenue										2,346,300,000	2,239,700,000
Business Acquisition, Pro Forma Net Income (Loss)										$ 141,400,000	$ 134,600,000
Business Acquisition, Pro Forma Earnings Per Share, Basic										$ 1.73	$ 1.66
Business Acquisition, Pro Forma Earnings Per Share, Diluted										$ 1.73	$ 1.66

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Additional Balance Sheet & Operational Information (Tables)

12 Months Ended

Dec. 31, 2012

Additional Balance Sheet and Operational Information [Abstract]

Summary of inventories

Inventories consist of the following:

	At December 31,
(In millions)	2012		2011
Gas in storage – at LIFO cost	$	22.4	$	31.8
Coal & oil for electric generation - at average cost	52.0		60.6
Materials & supplies	57.6		54.9
Nonutility coal - at LIFO cost	25.4		13.0
Other	1.2		1.6
Total inventories	$	158.6	$	161.9

Summary of prepayments and other current assets

Prepayments & other current assets consist of the following:

	At December 31,
(In millions)	2012		2011
Prepaid gas delivery service	$	28.5	$	42.4
Deferred income taxes	—		16.0
Prepaid taxes	26.4		5.1
Other prepayments & current assets	18.4		20.8
Total prepayments & other current assets	$	73.3	$	84.3

Schedule of investments in unconsolidated affiliates

Investments in unconsolidated affiliates consist of the following:

	At December 31,
(In millions)	2012		2011
ProLiance Holdings, LLC	$	73.9	$	85.4
Other nonutility partnerships & corporations	4.0		7.3
Other utility investments	0.2		0.2
Total investments in unconsolidated affiliates	$	78.1	$	92.9

Other utility and corporate investments in the consolidated balance sheets

Other utility & corporate investments consist of the following:

	At December 31,
(In millions)	2012		2011
Cash surrender value of life insurance policies	$	29.1	$	27.3
Municipal bond	3.6		3.9
Restricted cash & other investments	1.9		3.2
Other utility & corporate investments	$	34.6	$	34.4

Goodwill by operating segment

Goodwill by operating segment follows:

	At December 31,
(In millions)	2012		2011
Utility Group
Gas Utility Services	$	205.0	$	205.0
Nonutility Group
Infrastructure Services	55.2		55.2
Energy Services	2.1		2.1
Consolidated goodwill	$	262.3	$	262.3

Accrued Liabilities

Accrued liabilities consist of the following:

	At December 31,
(In millions)	2012		2011
Refunds to customers & customer deposits	$	53.1	$	56.4
Accrued taxes	34.4		33.5
Accrued interest	23.1		21.7
Deferred compensation & post-retirement benefits	6.8		6.5
Deferred income taxes	14.9		—
Accrued salaries & other	66.5		63.0
Total accrued liabilities	$	198.8	$	181.1

Asset retirement obligation

Asset retirement obligations roll forward as follows:

(In millions)	2012			2011
Asset retirement obligation, January 1	$	43.7		$	38.7
Accretion	2.7			2.5
Changes in estimates, net of cash payments	(8.7		)	2.5
Asset retirement obligation, December 31	37.7			43.7
Accrued liabilities	$	—		$	0.2
Deferred credits & other liabilities	$	37.7		$	43.5

Equity in earnings (losses) of unconsolidated affiliates

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

	Year Ended December 31,
(In millions)	2012			2011			2010
ProLiance Holdings, LLC	$	(22.7	)	$	(28.6	)	$	(2.5	)
Haddington Energy Partners, LP	(0.7		)	—			(6.1		)
Other	0.1			(3.4		)	—
Total equity in (losses) of unconsolidated affiliates	$	(23.3	)	$	(32.0	)	$	(8.6	)

Other, net in the consolidated statements of income

Other income (expense) – net consists of the following:

	Year Ended December 31,
(In millions)	2012			2011			2010
AFUDC – borrowed funds	$	4.6		$	2.5		$	1.4
AFUDC – equity funds	0.4			0.2			0.3
Nonutility plant capitalized interest	1.8			2.1			2.1
Interest income, net	1.1			1.4			1.7
Other nonutility investment impairment charges	(2.7		)	(9.9		)	(4.7		)
Cash surrender value of life insurance policies	1.8			0.1			1.9
All other income	1.3			0.1			2.1
Total other income (expense) – net	$	8.3		$	(3.5	)	$	4.8

Supplemental cash flow information

Supplemental Cash Flow Information:

	Year Ended December 31,
(In millions)	2012		2011			2010
Cash paid (received) for:
Interest	$	94.6	$	108.6		$	104.5
Income taxes	21.8		(9.0		)	8.1

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Fair Value Measurements (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other Assets, Fair Value Disclosure	$ 2.1	$ 2.1
Period to recover call premiums on reacquisition of long-term debt	15
Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	1,659.8	1,622.3
Short-term borrowings & notes payable	278.8	227.1
Cash and cash equivalents	19.5	8.6
Estimated Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	1,873.3	1,804.4
Short-term borrowings & notes payable	278.8	227.1
Cash and cash equivalents	$ 19.5	$ 8.6

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Sale of Retail Gas Marketing Operations (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011
Discontinued Operations and Disposal Groups [Abstract]
Gain (loss) on disposal	$ 25.4

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Share-Based Compensation & Deferred Compensation Arrangements (Tables)

12 Months Ended

Dec. 31, 2012

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)	2012		2011		2010
Total cost of share-based compensation	$	6.3	$	5.8	$	4.9
Less capitalized cost	1.2		0.8		1.7
Total in other operating expense	5.1		5.0		3.2
Less income tax benefit in earnings	2.1		2.0		1.3
After tax effect of share-based compensation	$	3.0	$	3.0	$	1.9

Restricted stock units and shares outstanding

A summary of the status of awards separated between those accounted for as liabilities and equity as of December 31, 2012, and changes during the year ended December 31, 2012, follows:

	Equity Awards
		Wtd. Avg.
		Grant Date		Liability Awards
	Shares	Fair value		Shares/Units	Fair value
Awards at January 1, 2012	54,013	$	25.22	698,110
Granted	35,458	29.82		250,211
Vested	(2,635)	24.76		(149,374)
Forfeited	(16,343)	25.12		(170,137)
Awards at December 31, 2012	70,493	$	27.45	628,810	$	29.40

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, 2012, and changes during the year ended December 31, 2012, follows:

		Weighted average			Aggregate
	Shares	Exercise Price		Remaining Contractual Term (years)	Intrinsic Value (In millions)
Outstanding at January 1, 2012	407,633	$	25.74
Exercised	(21,068)	$	23.18
Outstanding at December 31, 2012	386,565	$	25.88	1.6	$	1.4
Exercisable at December 31, 2012	386,565	$	25.88	1.6	$	1.4

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SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

12 Months Ended

Dec. 31, 2012

Valuation and Qualifying Accounts [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 2012 – Accumulated provision for
uncollectible accounts	$	6.7	$	8.2	$	—	$	8.1	$	6.8
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 2012 – Reserve for impaired
notes receivable	$	15.7	$	0.5	$	—	$	15.6	$	0.6
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
OTHER RESERVES:
Year 2012 – Restructuring costs	$	0.4	$	—	$	—	$	0.1	$	0.3
Year 2011 – Restructuring costs	$	0.4	$	—	$	—	$	—	$	0.4
Year 2010 – Restructuring costs	$	0.5	$	—	$	—	$	0.1	$	0.4

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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, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Quarterly Financial Information Disclosure [Abstract]
Operating revenues	$ 644.1	$ 513.5	$ 470.6	$ 604.6	$ 627.4	$ 539.4	$ 475.8	$ 682.6	$ 2,232.8	$ 2,325.2	$ 2,129.5
Operating income	90.8	81.6	70.2	109.9	111.0	94.1	61.6	103.3	352.5	370.0	316.8
Net Income	$ 42.8	$ 39.3	$ 25.6	$ 51.3	$ 46.6	$ 35.3	$ 15.1	$ 44.6	$ 159.0	$ 141.6	$ 133.7
Earnings per share [Abstract]
Basic	$ 0.52	$ 0.48	$ 0.31	$ 0.63	$ 0.56	$ 0.43	$ 0.19	$ 0.55	$ 1.94	$ 1.73	$ 1.65
DILUTED (in dollars per share)	$ 0.52	$ 0.48	$ 0.31	$ 0.62	$ 0.56	$ 0.43	$ 0.18	$ 0.55	$ 1.94	$ 1.73	$ 1.64

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Nonutility Real Estate & Other Legacy Holdings (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Investments by type [Abstract]
Other nonutility investments	$ 24.9	$ 29.6
Investments in unconsolidated affiliates	78.1	92.9
Commercial real estate
Equity in earnings (losses) of unconsolidated affiliates	(23.3)	(32.0)	(8.6)
Nonutility Group [Member]
Investments by type [Abstract]
Total carrying value by type of investment	28.7	36.9
Other nonutility investments	24.9
Investments in unconsolidated affiliates	3.8
Carrying value of legacy investments less deferred taxes of leveraged leases	17.9
Nonutility Group [Member] | Leveraged Leases [Member]
Investments by type [Abstract]
Total carrying value by type of investment	13.8
Other nonutility investments	13.8
Investments in unconsolidated affiliates	0
Leveraged Leases
Total equipment and facilities cost	27.5
Rentals due under the leases and a security interest in the leased property	22.9
Book value of leveraged lease	3.0
Leveraged Lease Deferred Taxes	10.8
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
Commercial real estate
Impairment charge		15.4
Amount of impairment charge included in Other-net		8.8
Equity in earnings (losses) of unconsolidated affiliates		3.6
Other operating expenses		3.0
Nonutility Group [Member] | Other Investments [Member]
Investments by type [Abstract]
Total carrying value by type of investment	6.9
Other nonutility investments	3.1
Investments in unconsolidated affiliates	3.8
Haddington Energy Partnerships [Abstract]
Percentage of ownership interest in both Haddington Ventures (in hundredths)	40.00%
ProLiance Holdings, LLC [Member]
Investments by type [Abstract]
Investments in unconsolidated affiliates	73.9	85.4
Commercial real estate
Equity in earnings (losses) of unconsolidated affiliates	$ (22.7)	$ (28.6)	$ (2.5)

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Segment Reporting (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Segment Reporting Information [Line Items]
Number of reporting segments	3								3
Number of operating segments in the Nonutility Group	5								5
Portion Of Indiana That Is Provided Natural Gas Distribution And Transportation Services By Gas Utility Services Segment	66.66667%								66.66667%
Revenues	$ 644.1	$ 513.5	$ 470.6	$ 604.6	$ 627.4	$ 539.4	$ 475.8	$ 682.6	$ 2,232.8	$ 2,325.2	$ 2,129.5
Net income (loss)	42.8	39.3	25.6	51.3	46.6	35.3	15.1	44.6	159.0	141.6	133.7
Amounts Included in Profitability Measures [Abstract]
Depreciation and Amortization									254.6	244.3	229.1
Interest Expense									96.0	106.5	104.6
Income Taxes									82.5	86.4	74.7
Capital Expenditures									365.8	321.3	277.2
Assets	5,089.1				4,878.9				5,089.1	4,878.9	4,764.2
Utility Group [Member]
Segment Reporting Information [Line Items]
Revenues									1,333.6	1,457.0	1,563.7
Net income (loss)									138.0	122.9	123.9
Amounts Included in Profitability Measures [Abstract]
Depreciation and Amortization									190.0	192.3	188.2
Interest Expense									71.5	80.3	81.4
Income Taxes									85.3	82.9	77.1
Capital Expenditures									246.0	233.4	225.1
Assets	4,046.8				3,974.5				4,046.8	3,974.5	3,924.5
Utility Group [Member] | Gas Utility Services [Member]
Segment Reporting Information [Line Items]
Revenues									738.1	819.1	954.1
Net income (loss)									60.0	52.5	53.7
Amounts Included in Profitability Measures [Abstract]
Depreciation and Amortization									85.4	84.3	80.7
Interest Expense									31.8	37.1	38.8
Income Taxes									39.1	34.5	35.1
Capital Expenditures									128.8	113.5	88.7
Assets	2,173.5				2,125.2				2,173.5	2,125.2	2,161.7
Utility Group [Member] | Electric Utility Services [Member]
Segment Reporting Information [Line Items]
Revenues									594.9	635.9	608.0
Net income (loss)									68.0	65.0	60.9
Amounts Included in Profitability Measures [Abstract]
Depreciation and Amortization									81.3	80.2	80.8
Interest Expense									33.8	36.4	36.4
Income Taxes									46.4	45.3	40.8
Capital Expenditures									108.8	102.2	120.1
Assets	1,705.1				1,656.5				1,705.1	1,656.5	1,666.5
Utility Group [Member] | Other Operations [Member]
Segment Reporting Information [Line Items]
Revenues									40.1	43.9	44.5
Net income (loss)									10.0	5.4	9.3
Amounts Included in Profitability Measures [Abstract]
Depreciation and Amortization									23.3	27.8	26.7
Interest Expense									5.9	6.8	6.2
Income Taxes									(0.2)	3.1	1.2
Capital Expenditures									16.2	17.8	22.5
Assets	168.2				192.8				168.2	192.8	96.3
Utility Group [Member] | Intersegment Elimination [Member]
Segment Reporting Information [Line Items]
Revenues									(39.5)	(41.9)	(42.9)
Utility Group [Member] | Non-Cash Cost and Change in Accruals [Member]
Amounts Included in Profitability Measures [Abstract]
Capital Expenditures									(7.8)	(0.1)	(6.2)
Nonutility Group [Member]
Segment Reporting Information [Line Items]
Number of reporting segments	5								5
Revenues									1,017.6	1,018.6	735.2
Net income (loss)									21.7	23.8	9.8
Amounts Included in Profitability Measures [Abstract]
Depreciation and Amortization									64.6	52.0	40.9
Interest Expense									24.9	27.0	23.6
Income Taxes									(1.7)	6.3	(1.5)
Capital Expenditures									119.8	87.9	52.1
Assets	980.7				888.3				980.7	888.3	868.5
Nonutility Group [Member] | Other Operations [Member]
Amounts Included in Profitability Measures [Abstract]
Depreciation and Amortization									0.2	0	0
Nonutility Group [Member] | Infrastructure Services [Member]
Segment Reporting Information [Line Items]
Revenues									663.6	421.3	235.6
Net income (loss)									40.5	14.9	3.1
Amounts Included in Profitability Measures [Abstract]
Depreciation and Amortization									20.7	14.9	8.8
Interest Expense									7.5	7.4	3.3
Income Taxes									29.6	10.7	2.7
Capital Expenditures									53.7	22.8	12.0
Assets	420.0				295.0				420.0	295.0	174.6
Nonutility Group [Member] | Energy Services [Member]
Segment Reporting Information [Line Items]
Revenues									117.7	161.8	146.9
Net income (loss)									5.7	6.7	6.4
Amounts Included in Profitability Measures [Abstract]
Depreciation and Amortization									1.9	1.5	1.2
Interest Expense									0.4	0.6	0.2
Income Taxes									(9.0)	1.1	2.5
Capital Expenditures									2.3	9.7	1.2
Assets	69.7				81.2				69.7	81.2	67.4
Nonutility Group [Member] | Coal Mining [Member]
Segment Reporting Information [Line Items]
Revenues									235.8	285.6	209.9
Net income (loss)									(3.5)	16.6	11.9
Amounts Included in Profitability Measures [Abstract]
Depreciation and Amortization									41.8	35.1	30.4
Interest Expense									11.5	11.3	10.1
Income Taxes									(8.6)	3.9	1.9
Capital Expenditures									63.8	55.1	38.7
Assets	380.0				352.8				380.0	352.8	362.5
Nonutility Group [Member] | Energy Marketing [Member]
Segment Reporting Information [Line Items]
Revenues									0	149.9	142.8
Net income (loss)									(17.6)	(4.2)	(4.2)
Amounts Included in Profitability Measures [Abstract]
Depreciation and Amortization									0	0.5	0.5
Interest Expense									4.8	6.4	8.5
Income Taxes									(11.7)	(2.4)	(2.7)
Capital Expenditures									0	0.3	0.2
Assets	73.9				112.5				73.9	112.5	209.1
Nonutility Group [Member] | Other Businesses [Member]
Segment Reporting Information [Line Items]
Revenues									0.5	0	0
Net income (loss)									(3.4)	(10.2)	(7.4)
Amounts Included in Profitability Measures [Abstract]
Interest Expense									0.7	1.3	1.5
Income Taxes									(2.0)	(7.0)	(5.9)
Assets	37.1				46.8				37.1	46.8	54.9
Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues									(118.4)	(150.4)	(169.4)
Amounts Included in Profitability Measures [Abstract]
Assets	(724.0)				(711.2)				(724.0)	(711.2)	(735.0)
Corporate and Other Group [Member]
Segment Reporting Information [Line Items]
Net income (loss)									(0.7)	(5.1)	0
Amounts Included in Profitability Measures [Abstract]
Interest Expense									(0.4)	(0.8)	(0.4)
Income Taxes									(1.1)	(2.8)	(0.9)
Assets	$ 785.6				$ 727.3				$ 785.6	$ 727.3	$ 706.2

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2012

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

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 2012 and thereafter (in millions) are $6.8 in 2013, $5.5 in 2014, $3.8 in 2015, $2.2 in 2016, $1.2 in 2017, and $3.3 thereafter.  Total lease expense (in millions) was $8.5 in 2012, $6.9 in 2011, and $7.3 in 2010.

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, 2012, parent level guarantees support a maximum of $25 million of ESG’s performance contracting commitments and warranty obligations and $28 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 $24 million of other guarantees outstanding supporting other consolidated subsidiary operations, of which $18 million represent letters of credit supporting other nonutility operations.  Guarantees issued and outstanding on behalf of unconsolidated affiliates approximated $3 million at December 31, 2012.  These guarantees relate primarily to arrangements between ProLiance and various natural gas pipeline operators.  The Company has not been called upon to satisfy any obligations pursuant to these parental guarantees and has accrued no significant liabilities related to these guarantees.

Performance Guarantees & Product Warranties

In the normal course of business, 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, 2012, there are 62 open surety bonds supporting future performance.  The average face amount of these obligations is $5.2 million, and the largest obligation has a face amount of $57.3 million.  The maximum exposure from these obligations is limited by the level of work already completed and guarantees issued to ESG by various subcontractors. At December 31, 2012, approximately 56 percent of work was completed on projects with open surety bonds.  A significant portion of these open surety bonds will be released 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, 2012. In addition, ESG has an $8 million stand-alone letter of credit facility and as of December 31, 2012, $3.4 million was outstanding.

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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Organization and Nature of Operations (Details)	12 Months Ended
	Dec. 31, 2012
Organization, Consolidation and Presentation of Financial Statements [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)	566,000
Estimated number of electric customers located near Evansville in southwestern Indiana serviced by Southern Indiana Gas and Electric Company (in number of customers)	142,000
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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Retirement Plans & Other Postretirement Benefits (Tables)

12 Months Ended

Dec. 31, 2012

Compensation and Retirement Disclosure [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, 2012 follows:

	Pension Benefits									Other Benefits
(In millions)	2012			2011			2010			2012			2011			2010
Service cost	$	7.7		$	6.9		$	6.3		$	0.5		$	0.5		$	0.5
Interest cost	15.5			15.9			15.9			2.8			4.3			4.6
Expected return on plan assets	(21.2		)	(21.2		)	(18.4		)	—			—			(0.4		)
Amortization of prior service cost (benefit)	1.6			1.7			1.6			(2.5		)	(0.8		)	(0.8		)
Amortization of actuarial loss (gain)	6.8			3.8			3.2			0.7			0.6			0.5
Amortization of transitional obligation	—			—			—			0.5			1.1			1.2
Net periodic benefit cost	$	10.4		$	7.1		$	8.6		$	2.0		$	5.7		$	5.6

Schedule of assumptions used

The benefit obligation as of December 31, 2012 and 2011 was calculated using the following weighted average assumptions:

	Pension Benefits				Other Benefits
	2012		2011		2012		2011
Discount rate	4.03	%	4.82	%	3.91	%	4.78	%
Rate of compensation increase	3.50	%	3.50	%	N/A		N/A
Expected increase in Consumer Price Index	N/A		N/A		2.75	%	2.75	%

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

	Pension Benefits						Other Benefits
	2012		2011		2010		2012		2011		2010
Discount rate	4.82	%	5.50	%	6.00	%	4.75	%	5.50	%	6.00	%
Rate of compensation increase	3.50	%	3.50	%	3.50	%	N/A		N/A		N/A
Expected return on plan assets	7.75	%	8.00	%	8.00	%	N/A		8.00	%	8.00	%
Expected increase in Consumer Price Index	N/A		N/A		N/A		2.75	%	3.00	%	3.00	%

Schedule of changes in projected benefit obligations

A reconciliation of the Company’s benefit obligations at December 31, 2012 and 2011 follows:

	Pension Benefits						Other Benefits
(In millions)	2012			2011			2012			2011
Benefit obligation, beginning of period	$	329.2		$	297.3		$	79.7		$	80.7
Service cost – benefits earned during the period	7.7			6.9			0.5			0.5
Interest cost on projected benefit obligation	15.5			15.9			2.8			4.3
Plan participants' contributions	—			—			1.6			1.9
Plan amendments	0.7			—			(26.6		)	—
Actuarial loss (gain)	39.0			23.1			2.8			(0.5		)
Medicare subsidy receipts	—			—			0.5			1.0
Benefit payments	(14.8		)	(14.0		)	(6.9		)	(8.2		)
Benefit obligation, end of period	$	377.3		$	329.2		$	54.4		$	79.7

Schedule of changes in fair value of plan assets

A reconciliation of the Company’s plan assets at December 31, 2012 and 2011 follows:

	Pension Benefits						Other Benefits
(In millions)	2012			2011			2012			2011
Plan assets at fair value, beginning of period	$	261.0		$	237.2		$	—		$	3.1
Actual return on plan assets	33.8			2.1			—			0.1
Employer contributions	15.7			35.7			5.3			3.1
Plan participants' contributions	—			—			1.6			1.9
Benefit payments	(14.8		)	(14.0		)	(6.9		)	(8.2		)
Fair value of plan assets, end of period	$	295.7		$	261.0		$	—		$	—

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, 2012 and December 31, 2011 by asset category and by fair value hierarchy are as follows:

	As of December 31, 2012
(In millions)	Level 1		Level 2		Level 3		Total
Domestic equities & equity funds	$	62.8	$	77.6	$	—	$	140.4
International equities & equity funds	34.3		—		—		34.3
Domestic bonds & bond funds	41.7		42.3		—		84.0
Inflation protected security fund	—		12.6		—		12.6
Real estate, commodities & other	8.0		12.5		3.9		24.4
Total plan investments	$	146.8	$	145.0	$	3.9	$	295.7

	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

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)	2012			2011
Fair value, beginning of year	$	3.8		$	3.7
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	$	3.9		$	3.8

Schedule of net funded status of plans

The funded status of the plans as of December 31, 2012 and 2011 follows:

	Pension Benefits						Other Benefits
(In millions)	2012			2011			2012			2011
Qualified Plans
Benefit obligation, end of period	$	(360.0	)	$	(314.7	)	$	(54.4	)	$	(79.7	)
Fair value of plan assets, end of period	295.7			261.0			—			—
Funded Status of Qualified Plans, end of period	(64.3		)	(53.7		)	(54.4		)	(79.7		)
Benefit obligation of SERP Plan, end of period	(17.3		)	(14.5		)	—			—
Total funded status, end of period	$	(81.6	)	$	(68.2	)	$	(54.4	)	$	(79.7	)
Accrued liabilities	$	1.0		$	0.7		$	4.5		$	5.1
Deferred credits & other liabilities	$	80.6		$	67.5		$	49.9		$	74.6

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.

	Pensions						Other Benefits
(In millions)	Prior Service Cost			Net Gain or Loss			Prior Service Cost			Net Gain or Loss			Transition Obligation
Balance at January 1, 2010	$	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 at 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 at December 31, 2011	$	5.4		$	116.6		$	(1.2	)	$	9.1		$	2.7
Amounts arising during the period	0.7			26.4			(24.4		)	2.8			(2.2		)
Reclassification to benefit costs	(1.6		)	(6.8		)	2.5			(0.7		)	(0.5		)
Balance at December 31, 2012	$	4.5		$	136.2		$	(23.1	)	$	11.2		$	—

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, 2012 and 2011.

(In millions)	2012						2011
	Pensions			Other Benefits			Pensions			Other Benefits
Prior service cost	$	4.5		$	(23.1	)	$	5.4		$	(1.2	)
Unamortized actuarial gain/(loss)	136.2			11.2			116.6			9.1
Transition obligation	—			—			—			2.7
	140.7			(11.9		)	122.0			10.6
Less: Regulatory asset deferral	(137.9		)	11.7			(115.9		)	(10.1		)
AOCI before taxes	$	2.8		$	(0.2	)	$	6.1		$	0.5

Schedule of Multiemployer Contributions In Current Year [Table Text Block]

The multi-employer contributions listed in the table below are the Company's multi-employer contributions made in 2012, 2011, and 2010.

(In millions)
		Pension Protection Act Zone Status			Multi-Employer Contributions
Pension Fund	EIN/Pension Plan Number	2012	2011	FIP/RP Status Pending/Implemented	2012	2011	2010	Surcharge Imposed
Central Pension Fund	36-6052390-001	Green	Green	No	$4.0	$2.3	$1.1	No
Pipeline Industry Benefit Fund	73-0742835-001	Green	Green	No	3.9	1.0	0.7	No
Indiana Laborers Pension Fund (1)	35-6027150-001	Yellow	Yellow	Implemented	3.2	1.6	1.4	No
Minnesota Laborers Pension Fund	41-6159599-001	Green	Green	No	2.0	0.7	—	No
Other					14.5	12.7	6.8
Total Contributions					$27.6	$18.3	$10.0

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Acquisition of Minnesota Limited, Inc. (Tables)

12 Months Ended

Dec. 31, 2012

Business Combinations [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 year ended December 31, 2011 and 2010 as if the acquisition had occurred on January 1, 2010.

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

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Utility & Nonutility Plant (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Utility & Nonutility Plant
Original Cost	$ 5,176.8	$ 4,979.9
Cost of Non-Utility plant, net of depreciation and amortization	598.0	550.8
Utility Group [Member]
Utility & Nonutility Plant
Original Cost	5,176.8	4,979.9
Size of Unit 4 Warrick Power Plant (in megawatts)	300
Southern Indiana Gas And Electric Company's Share Of Cost Of Unit 4	185.9
Southern Indiana Gas And Electric Company's Share Of Accumulated Depreciation Of Unit 4	78.9
Utility Group [Member] | Gas Utility Plant [Member]
Utility & Nonutility Plant
Original Cost	2,614.3	2,516.8
Depreciation Rates as a Percent of Original Cost (in hundredths)	3.50%	3.50%
Utility Group [Member] | Electric Utility Plant [Member]
Utility & Nonutility Plant
Original Cost	2,463.6	2,316.8
Depreciation Rates as a Percent of Original Cost (in hundredths)	3.30%	3.30%
Utility Group [Member] | Common Utility Plant [Member]
Utility & Nonutility Plant
Original Cost	52.0	51.6
Depreciation Rates as a Percent of Original Cost (in hundredths)	3.00%	2.90%
Utility Group [Member] | Construction Work in Progress [Member]
Utility & Nonutility Plant
Original Cost	46.9	94.7
Depreciation Rates as a Percent of Original Cost (in hundredths)	0.00%	0.00%
Nonutility Group [Member]
Utility & Nonutility Plant
Cost of Non-Utility plant, net of depreciation and amortization	598.0	550.8
Nonutility plant accumulated depreciation and amortization	468.4	418.5
Capitalized interest on nonutility plant construction projects	1.8	2.1	2.1
Nonutility Group [Member] | Coal Mine Development Costs and Equipment [Member]
Utility & Nonutility Plant
Cost of Non-Utility plant, net of depreciation and amortization	241.9	222.0
Nonutility Group [Member] | Computer Hardware and Software [Member]
Utility & Nonutility Plant
Cost of Non-Utility plant, net of depreciation and amortization	97.3	101.9
Nonutility Group [Member] | Land and Buildings [Member]
Utility & Nonutility Plant
Cost of Non-Utility plant, net of depreciation and amortization	120.4	112.0
Nonutility Group [Member] | Vehicles and Equipment [Member]
Utility & Nonutility Plant
Cost of Non-Utility plant, net of depreciation and amortization	119.8	92.5
Nonutility Group [Member] | All Other [Member]
Utility & Nonutility Plant
Cost of Non-Utility plant, net of depreciation and amortization	$ 18.6	$ 22.4

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Commitments and Contingencies (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Commitments [Abstract]
Future minimum operating lease payments due within one year of the balance sheet date	$ 6.8
Future minimum operating lease payments due within the second year of the balance sheet date	5.5
Future minimum operating lease payments due within the third year of the balance sheet date	3.8
Future minimum operating lease payments due within the fourth year of the balance sheet date	2.2
Future minimum operating lease payments due within the fifth year of the balance sheet date	1.2
Future minimum operating lease payments due within after the fifth year of the balance sheet date	3.3
Total lease expense	8.5	6.9	7.3
Guarantees for ESG [Member]
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)	62
Average face amount of surety bonds wholly owned subsidiary has outstanding	5.2
Maximum face amount of surety bond wholly owned subsidiary had outstanding	57.3
Percent of work completed on projects covered by open surety bonds (in hundredths)	56.00%
Timeframe when significant portion of performance guarantee commitments will be fulfilled	within one year
Guarantees for Other Unconsolidated Affiliates [Member]
Corporate Guarantees [Abstract]
Maximum exposure by parent company on guarantees.	3
Performance Guarantee [Member] | Guarantees for ESG [Member]
Corporate Guarantees [Abstract]
Maximum exposure by parent company on guarantees.	25
Performance Guarantee [Member] | Guarantees for Other Unconsolidated Affiliates [Member]
Corporate Guarantees [Abstract]
Maximum exposure by parent company on guarantees.	24
Other Guarantees Outstanding [Member] | Guarantees for ESG [Member]
Corporate Guarantees [Abstract]
Maximum exposure by parent company on guarantees.	28
Financial Standby Letter of Credit [Member] | Guarantees for ESG [Member]
Performance Guarantees and Product Warranties [Abstract]
Letter of Credit, Gross Amount	8.0
Letters of Credit Outstanding, Amount	3.4
Financial Standby Letter of Credit [Member] | Guarantees for Other Unconsolidated Affiliates [Member]
Corporate Guarantees [Abstract]
Maximum exposure by parent company on guarantees.	$ 18

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Borrowing Arrangements (Details) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Long term debt [Abstract]
Total long term debt outstanding	$ 1,661,500,000	$ 1,524,200,000
Current maturities of long-term debt	(106,400,000)	(62,700,000)
Short-term borrowings expected to be refinanced	0	100,000,000
Unamortized debt premium and discount - net	(1,700,000)	(1,900,000)
Long-term debt - net of current maturities and debt subject to tender	1,553,400,000	1,559,600,000
Long-term debt death put repayments		800,000	1,800,000
Maturities of long term debt [Abstract]
Debt maturing within 12 months following date of latest balance sheet	106,400,000
Debt maturing within two years following date of latest balance sheet	30,000,000
Debt maturing within three years following date of latest balance sheet	279,800,000
Debt maturing within four years following date of latest balance sheet	73,000,000
Debt maturing within five years following date of latest balance sheet	75,000,000
Debt maturing thereafter 5 years following date of the latest balance sheet	1,095,600,000
Covenants [Abstract]
Ratio of consolidated total debt to consolidated total capitalization, maximum ( in hundredths)	not exceed 65 percent
Other Long Term Notes Payable [Member]
Long term debt [Abstract]
Total long term debt outstanding	1,400,000	4,100,000
Utility Holdings [Member]
Long term debt [Abstract]
Letters of Credit Outstanding, Amount	41,700,000
Debt guarantees [Abstract]
Long-term guarantees	821,000,000
Short-term debt guarantees	117,000,000
Utility Holdings [Member] | 2039, 6.25% [Member]
Long term debt [Abstract]
Call date	2/4/2013
Debt Instrument Put And Call Exercise Date	Apr. 01, 2013
Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member]
Long term debt [Abstract]
Total long term debt outstanding	821,600,000	721,600,000
Proceeds from the sale of the notes, net of issuance costs		149,000,000
Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2013, 5.25% [Member]
Long term debt [Abstract]
Total long term debt outstanding	100,000,000	100,000,000
Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2015, 5.45% [Member]
Long term debt [Abstract]
Total long term debt outstanding	75,000,000	75,000,000
Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2018, 5.75% [Member]
Long term debt [Abstract]
Total long term debt outstanding	100,000,000	100,000,000
Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2020, 6.28% [Member]
Long term debt [Abstract]
Total long term debt outstanding	100,000,000	100,000,000
Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2021, 4.67 [Member]
Long term debt [Abstract]
Total long term debt outstanding	55,000,000	55,000,000
Fixed rate stated percentage (in hundredths)	4.67%
Maturity date	Nov. 30, 2021
Debt Instrument Issuance Date	11/30/2011
Debt Issuance	55,000,000
Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2026, 5.02% [Member]
Long term debt [Abstract]
Total long term debt outstanding	60,000,000	60,000,000
Fixed rate stated percentage (in hundredths)	5.02%
Maturity date	Nov. 30, 2026
Debt Instrument Issuance Date	11/30/2011
Debt Issuance	60,000,000
Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2035, 6.10% [Member]
Long term debt [Abstract]
Total long term debt outstanding	75,000,000	75,000,000
Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2039, 6.25% [Member]
Long term debt [Abstract]
Total long term debt outstanding	121,600,000	121,600,000
Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2041, 5.99% [Member]
Long term debt [Abstract]
Total long term debt outstanding	35,000,000	35,000,000
Fixed rate stated percentage (in hundredths)	5.99%
Maturity date	Dec. 02, 2041
Debt Instrument Issuance Date	11/30/2011
Debt Issuance	35,000,000
Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2042, 5.00% [Member]
Long term debt [Abstract]
Total long term debt outstanding	100,000,000	0
Fixed rate stated percentage (in hundredths)	5.00%
Maturity date	Feb. 03, 2042
Debt Instrument Issuance Date	February 1, 2012
Debt Issuance	100,000,000
Proceeds from the sale of the notes, net of issuance costs	99,500,000
Utility Holdings [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2036, 5.95% [Member]
Long term debt [Abstract]
Total long term debt outstanding			96,200,000
Call date		10/21/2011
Debt Instrument Put And Call Exercise Date		Nov. 21, 2011
Utility Holdings [Member] | Senior Guaranteed Notes [Member] | FixedRateSeniorGuaranteedNotes2043425 [Member]
Long term debt [Abstract]
Fixed rate stated percentage (in hundredths)	4.25%
Maturity date	Jun. 05, 2043
Debt Instrument Issuance Date	June 5, 2013
Debt Issuance	80,000,000
Utility Holdings [Member] | Senior Guaranteed Notes [Member] | FixedRateSeniorGuaranteedNotes2028320 [Member]
Long term debt [Abstract]
Fixed rate stated percentage (in hundredths)	3.20%
Maturity date	Jun. 05, 2028
Debt Instrument Issuance Date	June 5, 2013
Debt Issuance	45,000,000
Indiana Gas [Member] | Fixed Rate Senior Unsecured Notes [Member]
Long term debt [Abstract]
Total long term debt outstanding	121,000,000	121,000,000
Indiana Gas [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2013, Series E, 6.69% [Member]
Long term debt [Abstract]
Total long term debt outstanding	5,000,000	5,000,000
Indiana Gas [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2015, Series E, 7.15% [Member]
Long term debt [Abstract]
Total long term debt outstanding	5,000,000	5,000,000
Indiana Gas [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2015, Series E1, 6.69% [Member]
Long term debt [Abstract]
Total long term debt outstanding	10,000,000	10,000,000
Indiana Gas [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2015, Series E, 6.69% [Member]
Long term debt [Abstract]
Total long term debt outstanding	5,000,000	5,000,000
Indiana Gas [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2025, Series E, 6.53% [Member]
Long term debt [Abstract]
Total long term debt outstanding	10,000,000	10,000,000
Indiana Gas [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2027, Series E, 6.42% [Member]
Long term debt [Abstract]
Total long term debt outstanding	5,000,000	5,000,000
Indiana Gas [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2027, Series E, 6.68% [Member]
Long term debt [Abstract]
Total long term debt outstanding	1,000,000	1,000,000
Indiana Gas [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2027, Series F, 6.34% [Member]
Long term debt [Abstract]
Total long term debt outstanding	20,000,000	20,000,000
Indiana Gas [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2028, Series F, 6.36% [Member]
Long term debt [Abstract]
Total long term debt outstanding	10,000,000	10,000,000
Indiana Gas [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2028, Series F, 6.55% [Member]
Long term debt [Abstract]
Total long term debt outstanding	20,000,000	20,000,000
Indiana Gas [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2029, Series G, 7.08% [Member]
Long term debt [Abstract]
Total long term debt outstanding	30,000,000	30,000,000
SIGECO [Member] | First Mortgage Bonds [Member]
Long term debt [Abstract]
Total long term debt outstanding	267,500,000	267,500,000
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	2,800,000,000
SIGECO [Member] | First Mortgage Bonds [Member] | 2015, 1985 Pollution Control Series A, current adjustable rate 0.15%, tax exempt, 2012 weighted average: 0.17%
Long term debt [Abstract]
Total long term debt outstanding	9,800,000	9,800,000
SIGECO [Member] | First Mortgage Bonds [Member] | 2016, 1986 Series, 8.875% [Member]
Long term debt [Abstract]
Total long term debt outstanding	13,000,000	13,000,000
SIGECO [Member] | First Mortgage Bonds [Member] | 2020, 1998 Pollution Control Series B, 4.50%, tax exempt [Member]
Long term debt [Abstract]
Total long term debt outstanding	4,600,000	4,600,000
SIGECO [Member] | First Mortgage Bonds [Member] | 2023, 1993 Environmental Improvement Series B, 5.15%, tax exempt [Member]
Long term debt [Abstract]
Total long term debt outstanding	22,600,000	22,600,000
SIGECO [Member] | First Mortgage Bonds [Member] | 2024, 2000 Environmental Improvement Series A, 4.65%, tax exempt [Member]
Long term debt [Abstract]
Total long term debt outstanding	22,500,000	22,500,000
SIGECO [Member] | First Mortgage Bonds [Member] | 2025, 1998 Pollution Control Series A, current adjustable rate 0.15%, tax exempt, 2012 weighted average: 0.16%
Long term debt [Abstract]
Total long term debt outstanding	31,500,000	31,500,000
SIGECO [Member] | First Mortgage Bonds [Member] | 2029, 1999 Senior Notes, 6.72% [Member]
Long term debt [Abstract]
Total long term debt outstanding	80,000,000	80,000,000
SIGECO [Member] | First Mortgage Bonds [Member] | 2030, 1998 Pollution Control Series B, 5.00%, tax exempt [Member]
Long term debt [Abstract]
Total long term debt outstanding	22,000,000	22,000,000
SIGECO [Member] | First Mortgage Bonds [Member] | 2030, 1998 Pollution Control Series C, 5.35%, tax exempt [Member]
Long term debt [Abstract]
Total long term debt outstanding	22,200,000	22,200,000
SIGECO [Member] | First Mortgage Bonds [Member] | 2040, 2009 Environmental Improvement Series, 5.40%, tax exempt [Member]
Long term debt [Abstract]
Total long term debt outstanding	22,300,000	22,300,000
SIGECO [Member] | First Mortgage Bonds [Member] | 2041, 2007 Pollution Control Series, 5.45%, tax exempt [Member]
Long term debt [Abstract]
Total long term debt outstanding	17,000,000	17,000,000
Vectren Capital Corp. [Member]
Debt guarantees [Abstract]
Long-term guarantees	450,000,000
Short-term debt guarantees	162,000,000
Vectren Capital Corp. [Member] | Fixed Rate Senior Unsecured Notes [Member]
Long term debt [Abstract]
Total long term debt outstanding	450,000,000	410,000,000
Proceeds from the sale of the notes, net of issuance costs			124,000,000
Amount of the proceeds that replaced the issuance of debt maturities due	48,000,000
Vectren Capital Corp. [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2012, 5.13% [Member]
Long term debt [Abstract]
Total long term debt outstanding	0	25,000,000
Vectren Capital Corp. [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2012, 7.43% [Member]
Long term debt [Abstract]
Total long term debt outstanding	0	35,000,000
Vectren Capital Corp. [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2014, 6.37% [Member]
Long term debt [Abstract]
Total long term debt outstanding	30,000,000	30,000,000
Vectren Capital Corp. [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2015, 5.31% [Member]
Long term debt [Abstract]
Total long term debt outstanding	75,000,000	75,000,000
Vectren Capital Corp. [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2016, 6.92% [Member]
Long term debt [Abstract]
Total long term debt outstanding	60,000,000	60,000,000
Vectren Capital Corp. [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2017, 3.48% [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. 15, 2017
Debt Instrument Issuance Date	12/15/2010
Debt Issuance	75,000,000
Vectren Capital Corp. [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2019, 7.30% [Member]
Long term debt [Abstract]
Total long term debt outstanding	60,000,000	60,000,000
Vectren Capital Corp. [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2025, 4.53% [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. 15, 2025
Debt Instrument Issuance Date	12/15/2010
Debt Issuance	50,000,000
Vectren Capital Corp. [Member] | Fixed Rate Senior Unsecured Notes [Member] | 2015, 1.22% Current Adjustable Rate [Member]
Long term debt [Abstract]
Total long term debt outstanding	100,000,000	0
Vectren Capital Corp. [Member] | Term Loan [Member]
Long term debt [Abstract]
Debt Instrument Issuance Date	11/1/2012
Debt Issuance	$ 100,000,000
Loan term (in years)	3
Term loan interest rate	Loans under the term loan agreement bear interest at either a Eurodollar rate or base rate plus a fixed adder, as defined in the loan agreement.

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Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2012

Fair Value Disclosures [Abstract]

Carrying value and estimated fair value of other financial instruments

The carrying values and estimated fair values using primarily Level 2 assumptions of the Company's other financial instruments follow:

	At December 31,
	2012				2011
(In millions)	Carrying Amount		Est. Fair Value		Carrying Amount		Est. Fair Value
Long-term debt	$	1,659.8	$	1,873.3	$	1,622.3	$	1,804.4
Short-term borrowings & notes payable	278.8		278.8		227.1		227.1
Cash & cash equivalents	19.5		19.5		8.6		8.6

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Organization and Nature of Operations

12 Months Ended

Dec. 31, 2012

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Organization and Nature of Operations

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 566,000 natural gas customers located in central and southern Indiana.  SIGECO provides energy delivery services to approximately 142,000 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 owns coal 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 a leveraged lease, among other investments.  All of the above are collectively referred to as the Nonutility Group.  Pursuant to service contracts, the Nonutility Group provides the Company's regulated utilities natural gas supply services, coal, and infrastructure services.

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Borrowing Arrangements Short-Term Borrowings (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Short-term borrowings [Abstract]
Short-term borrowing capacity	$ 600
Short term credit facilities expiration date	9/30/2016
Year end [Abstract]
Balance Outstanding, end of period	278.8	227.1
Utility Group [Member]
Short-term borrowings [Abstract]
Short-term borrowing capacity	350
Short term borrowings available	233
Year end [Abstract]
Balance Outstanding, end of period	116.7	242.8	47.0
Weighted Average Interest Rate, end of period (in hundredths)	0.40%	0.57%	0.41%
Annual Average [Abstract]
Balance Outstanding, annual average	77.6	39.6	14.0
Weighted Average Interest Rate, annual average (in hundredths)	0.47%	0.48%	0.40%
Maximum Month End Balance Outstanding	214.2	242.8	47.0
Nonutility Group [Member]
Short-term borrowings [Abstract]
Short-term borrowing capacity	250
Short term borrowings available	88
Year end [Abstract]
Balance Outstanding, end of period	162.1	84.3	71.3
Weighted Average Interest Rate, end of period (in hundredths)	1.35%	1.45%	2.01%
Annual Average [Abstract]
Balance Outstanding, annual average	151.5	124.9	143.2
Weighted Average Interest Rate, annual average (in hundredths)	1.44%	1.92%	0.93%
Maximum Month End Balance Outstanding	$ 216.1	$ 180.1	$ 174.6

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Borrowing Arrangements (Tables)

12 Months Ended

Dec. 31, 2012

Debt Disclosure [Abstract]

Short term borrowing arrangements

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

	Utility Group Borrowings									Nonutility Group Borrowings
(In millions)	2012			2011			2010			2012			2011			2010
Year End
Balance Outstanding	$	116.7		$	242.8		$	47.0		$	162.1		$	84.3		$	71.3
Weighted Average Interest Rate	0.40		%	0.57		%	0.41		%	1.35		%	1.45		%	2.01		%
Annual Average
Balance Outstanding	$	77.6		$	39.6		$	14.0		$	151.5		$	124.9		$	143.2
Weighted Average Interest Rate	0.47		%	0.48		%	0.40		%	1.44		%	1.92		%	0.93		%
Maximum Month End Balance Outstanding	$	214.2		$	242.8		$	47.0		$	216.1		$	180.1		$	174.6

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)	2012		2011
Utility Holdings
Fixed Rate Senior Unsecured Notes
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		55.0
2026, 5.02%	60.0		60.0
2035, 6.10%	75.0		75.0
2039, 6.25%	121.6		121.6
2041, 5.99%	35.0		35.0
2042, 5.00%	100.0		—
Total Utility Holdings	821.6		721.6
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 0.15%, tax exempt,
2012 weighted average: 0.17%	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 0.15%, tax exempt,
2012 weighted average: 0.16%	31.5		31.5
2029, 1999 Series, 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

	At December 31,
(In millions)	2012			2011
Vectren Capital Corp.
Fixed Rate Senior Unsecured Notes
2012, 5.13%	—			25.0
2012, 7.43%	—			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
Variable Rate Term Loan
2015, current adjustable rate 1.22%	100.0			—
Total Vectren Capital Corp.	450.0			410.0
Other Long-Term Notes Payable	1.4			4.1
Total long-term debt outstanding	1,661.5			1,524.2
Current maturities of long-term debt	(106.4		)	(62.7		)
Short-term borrowings refinanced in 2012	—			100.0
Unamortized debt premium & discount - net	(1.7		)	(1.9		)
Total long-term debt-net	$	1,553.4		$	1,559.6

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Segment Reporting

12 Months Ended

Dec. 31, 2012

Segment Reporting [Abstract]

Segment Reporting

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.  The sale of Vectren Source was completed on December 31, 2011 (See Note 6) and the results of Vectren Source's operations are included in the Energy Marketing operating segment in 2011 and 2010. Information related to the Company’s business segments is summarized as follows:

	Year Ended December 31,
(In millions)	2012			2011			2010
Revenues
Utility Group
Gas Utility Services	$	738.1		$	819.1		$	954.1
Electric Utility Services	594.9			635.9			608.0
Other Operations	40.1			43.9			44.5
Eliminations	(39.5		)	(41.9		)	(42.9		)
Total Utility Group	1,333.6			1,457.0			1,563.7
Nonutility Group
Infrastructure Services	663.6			421.3			235.6
Energy Services	117.7			161.8			146.9
Coal Mining	235.8			285.6			209.9
Energy Marketing	—			149.9			142.8
Other Businesses	0.5			—			—
Total Nonutility Group	1,017.6			1,018.6			735.2
Eliminations	(118.4		)	(150.4		)	(169.4		)
Consolidated Revenues	$	2,232.8		$	2,325.2		$	2,129.5
Profitability Measures - Net Income
Utility Group Net Income
Gas Utility Services	$	60.0		$	52.5		$	53.7
Electric Utility Services	68.0			65.0			60.9
Other Operations	10.0			5.4			9.3
Total Utility Group Net Income	138.0			122.9			123.9
Nonutility Group Net Income (Loss)
Infrastructure Services	40.5			14.9			3.1
Energy Services	5.7			6.7			6.4
Coal Mining	(3.5		)	16.6			11.9
Energy Marketing	(17.6		)	(4.2		)	(4.2		)
Other Businesses	(3.4		)	(10.2		)	(7.4		)
Total Nonutility Group Net Income	21.7			23.8			9.8
Corporate & Other Net Loss	(0.7		)	(5.1		)	—
Consolidated Net Income	$	159.0		$	141.6		$	133.7

	Year Ended December 31,
(In millions)	2012			2011			2010
Amounts Included in Profitability Measures
Depreciation & Amortization
Utility Group
Gas Utility Services	$	85.4		$	84.3		$	80.7
Electric Utility Services	81.3			80.2			80.8
Other Operations	23.3			27.8			26.7
Total Utility Group	190.0			192.3			188.2
Nonutility Group
Infrastructure Services	20.7			14.9			8.8
Energy Services	1.9			1.5			1.2
Coal Mining	41.8			35.1			30.4
Energy Marketing	—			0.5			0.5
Other Businesses	0.2			—			—
Total Nonutility Group	64.6			52.0			40.9
Consolidated Depreciation & Amortization	$	254.6		$	244.3		$	229.1
Interest Expense
Utility Group
Gas Utility Services	$	31.8		$	37.1		$	38.8
Electric Utility Services	33.8			36.4			36.4
Other Operations	5.9			6.8			6.2
Total Utility Group	71.5			80.3			81.4
Nonutility Group
Infrastructure Services	7.5			7.4			3.3
Energy Services	0.4			0.6			0.2
Coal Mining	11.5			11.3			10.1
Energy Marketing	4.8			6.4			8.5
Other Businesses	0.7			1.3			1.5
Total Nonutility Group	24.9			27.0			23.6
Corporate & Other	(0.4		)	(0.8		)	(0.4		)
Consolidated Interest Expense	$	96.0		$	106.5		$	104.6
Income Taxes
Utility Group
Gas Utility Services	$	39.1		$	34.5		$	35.1
Electric Utility Services	46.4			45.3			40.8
Other Operations	(0.2		)	3.1			1.2
Total Utility Group	85.3			82.9			77.1
Nonutility Group
Infrastructure Services	29.6			10.7			2.7
Energy Services	(9.0		)	1.1			2.5
Coal Mining	(8.6		)	3.9			1.9
Energy Marketing	(11.7		)	(2.4		)	(2.7		)
Other Businesses	(2.0		)	(7.0		)	(5.9		)
Total Nonutility Group	(1.7		)	6.3			(1.5		)
Corporate & Other	(1.1		)	(2.8		)	(0.9		)
Consolidated Income Taxes	$	82.5		$	86.4		$	74.7

	Year Ended December 31,
(In millions)	2012			2011			2010
Capital Expenditures
Utility Group
Gas Utility Services	$	128.8		$	113.5		$	88.7
Electric Utility Services	108.8			102.2			120.1
Other Operations	16.2			17.8			22.5
Non-cash costs & changes in accruals	(7.8		)	(0.1		)	(6.2		)
Total Utility Group	246.0			233.4			225.1
Nonutility Group
Infrastructure Services	53.7			22.8			12.0
Energy Services	2.3			9.7			1.2
Coal Mining	63.8			55.1			38.7
Energy Marketing	—			0.3			0.2
Total Nonutility Group	119.8			87.9			52.1
Consolidated Capital Expenditures	$	365.8		$	321.3		$	277.2
	At December 31,
(In millions)	2012			2011			2010
Assets
Utility Group
Gas Utility Services	$	2,173.5		$	2,125.2		$	2,161.7
Electric Utility Services	1,705.1			1,656.5			1,666.5
Other Operations, net of eliminations	168.2			192.8			96.3
Total Utility Group	4,046.8			3,974.5			3,924.5
Nonutility Group
Infrastructure Services	420.0			295.0			174.6
Energy Services	69.7			81.2			67.4
Coal Mining	380.0			352.8			362.5
Energy Marketing	73.9			112.5			209.1
Other Businesses, net of eliminations and reclassifications	37.1			46.8			54.9
Total Nonutility Group	980.7			888.3			868.5
Corporate & Other	785.6			727.3			706.2
Eliminations	(724.0		)	(711.2		)	(735.0		)
Consolidated Assets	$	5,089.1		$	4,878.9		$	4,764.2

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Fair Value Measurements

12 Months Ended

Dec. 31, 2012

Fair Value Disclosures [Abstract]

Fair Value Measurements

Fair Value Measurements

The carrying values and estimated fair values using primarily Level 2 assumptions of the Company's other financial instruments follow:

	At December 31,
	2012				2011
(In millions)	Carrying Amount		Est. Fair Value		Carrying Amount		Est. Fair Value
Long-term debt	$	1,659.8	$	1,873.3	$	1,622.3	$	1,804.4
Short-term borrowings & notes payable	278.8		278.8		227.1		227.1
Cash & cash equivalents	19.5		19.5		8.6		8.6

For the balance sheets presented, the Company had no material assets or liabilities marked to fair value.

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 certain other 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, 2012 and 2011, the fair value for these financial instruments was not estimated.  The carrying value of these investments was approximately $2.1 million at both December 31, 2012 and 2011.

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Investment in ProLiance Holdings, LLC (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Investments in unconsolidated Affiliates [Line Items]
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	$ 279.7	$ 381.9
Noncurrent assets	55.6	56.1
Current liabilities	215.1	298.5
Noncurrent liabilities	0.3	0.7
Members' equity	124.3	161.5
Accumulated other comprehensive income (loss)	(7.5)	(26.0)
Noncontrolling interest	3.1	3.3
Investments in unconsolidated affiliates	78.1	92.9
Equity in earnings (losses) of unconsolidated affiliates	(23.3)	(32.0)	(8.6)
Equity method investment holding minority interest in equity method investment (in hundredths)	25.00%
Equity Method Investment Minority Interest In Joint Ventures	35.0
Impairment Charge Recorded By Investee Of Companys Equity Method Investments				132
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	42.3
Firm transportation and storage agreements due in more than one and within two years of the balance sheet date	40.7
Firm transportation and storage agreements due in more than two and within three years of the balance sheet date	33.5
Firm transportation and storage agreements due in more than three and within four years of the balance sheet date	29.6
Firm transportation and storage agreements due in more than four and within five years of the balance sheet date	26.2
Firm transportation and storage agreements due after five years from the balance sheet date	180.1
Fixed payments for firm storage and transportation commitments	54.5	73.0	76.8
Purchases from ProLiance for resale and for injections into storage	274.5	378.7	437.7
Amounts owed to ProLiance for those purchases	29.7	36.8
ProLiance Holdings, LLC [Member]
Summarized balance sheet information:
Investments in unconsolidated affiliates	73.9	85.4
Equity in earnings (losses) of unconsolidated affiliates	(22.7)	(28.6)	(2.5)
Summarized Statement of Income [Member]
Summarized Statement of Income information [Abstract]
Revenues	1,001.3	1,410.5	1,497.0
Operating income (loss)	(34.8)	(44.5)	(3.1)
ProLiance's earnings (losses)	$ (38.3)	$ (47.3)	$ (3.7)

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Earnings Per Share (Tables)

12 Months Ended

Dec. 31, 2012

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, 2012:

	Year Ended December 31,
(In millions, except per share data)	2012		2011		2010
Numerator:
Numerator for basic EPS	$	159.0	$	141.6	$	133.6
Add back earnings attributable to participating securities	—		—		0.1
Reported net income (Numerator for Diluted EPS)	$	159.0	$	141.6	$	133.7
Denominator:
Weighted average common shares outstanding (Basic EPS)	82.0		81.8		81.2
Conversion of share based compensation arrangements	0.1		0.0		0.1
Adjusted weighted average shares outstanding and
assumed conversions outstanding (Diluted EPS)	82.1		81.8		81.3
Basic earnings per share	$	1.94	$	1.73	$	1.65
Diluted earnings per share	$	1.94	$	1.73	$	1.64

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Additional Balance Sheet & Operational Information

12 Months Ended

Dec. 31, 2012

Additional Balance Sheet and Operational Information [Abstract]

Additional Balance Sheet and Operational Information

Additional Balance Sheet & Operational Information

Inventories consist of the following:

	At December 31,
(In millions)	2012		2011
Gas in storage – at LIFO cost	$	22.4	$	31.8
Coal & oil for electric generation - at average cost	52.0		60.6
Materials & supplies	57.6		54.9
Nonutility coal - at LIFO cost	25.4		13.0
Other	1.2		1.6
Total inventories	$	158.6	$	161.9

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, 2012, and 2011, by approximately $12.7 million and $12.0 million, respectively.

Prepayments & other current assets consist of the following:

	At December 31,
(In millions)	2012		2011
Prepaid gas delivery service	$	28.5	$	42.4
Deferred income taxes	—		16.0
Prepaid taxes	26.4		5.1
Other prepayments & current assets	18.4		20.8
Total prepayments & other current assets	$	73.3	$	84.3

Investments in unconsolidated affiliates consist of the following:

	At December 31,
(In millions)	2012		2011
ProLiance Holdings, LLC	$	73.9	$	85.4
Other nonutility partnerships & corporations	4.0		7.3
Other utility investments	0.2		0.2
Total investments in unconsolidated affiliates	$	78.1	$	92.9

Other utility & corporate investments consist of the following:

	At December 31,
(In millions)	2012		2011
Cash surrender value of life insurance policies	$	29.1	$	27.3
Municipal bond	3.6		3.9
Restricted cash & other investments	1.9		3.2
Other utility & corporate investments	$	34.6	$	34.4

Goodwill by operating segment follows:

	At December 31,
(In millions)	2012		2011
Utility Group
Gas Utility Services	$	205.0	$	205.0
Nonutility Group
Infrastructure Services	55.2		55.2
Energy Services	2.1		2.1
Consolidated goodwill	$	262.3	$	262.3

Accrued liabilities consist of the following:

	At December 31,
(In millions)	2012		2011
Refunds to customers & customer deposits	$	53.1	$	56.4
Accrued taxes	34.4		33.5
Accrued interest	23.1		21.7
Deferred compensation & post-retirement benefits	6.8		6.5
Deferred income taxes	14.9		—
Accrued salaries & other	66.5		63.0
Total accrued liabilities	$	198.8	$	181.1

Asset retirement obligations roll forward as follows:

(In millions)	2012			2011
Asset retirement obligation, January 1	$	43.7		$	38.7
Accretion	2.7			2.5
Changes in estimates, net of cash payments	(8.7		)	2.5
Asset retirement obligation, December 31	37.7			43.7
Accrued liabilities	$	—		$	0.2
Deferred credits & other liabilities	$	37.7		$	43.5

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

	Year Ended December 31,
(In millions)	2012			2011			2010
ProLiance Holdings, LLC	$	(22.7	)	$	(28.6	)	$	(2.5	)
Haddington Energy Partners, LP	(0.7		)	—			(6.1		)
Other	0.1			(3.4		)	—
Total equity in (losses) of unconsolidated affiliates	$	(23.3	)	$	(32.0	)	$	(8.6	)

Other income (expense) – net consists of the following:

	Year Ended December 31,
(In millions)	2012			2011			2010
AFUDC – borrowed funds	$	4.6		$	2.5		$	1.4
AFUDC – equity funds	0.4			0.2			0.3
Nonutility plant capitalized interest	1.8			2.1			2.1
Interest income, net	1.1			1.4			1.7
Other nonutility investment impairment charges	(2.7		)	(9.9		)	(4.7		)
Cash surrender value of life insurance policies	1.8			0.1			1.9
All other income	1.3			0.1			2.1
Total other income (expense) – net	$	8.3		$	(3.5	)	$	4.8

Supplemental Cash Flow Information:

	Year Ended December 31,
(In millions)	2012		2011			2010
Cash paid (received) for:
Interest	$	94.6	$	108.6		$	104.5
Income taxes	21.8		(9.0		)	8.1

As of December 31, 2012 and 2011, the Company has accruals related to utility and nonutility plant purchases totaling approximately $11.1 million and $15.9 million, respectively.

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Impact of Recently Issued Accounting Guidance

12 Months Ended

Dec. 31, 2012

Impact of Recently Issued Accounting Principles [Abstract]

Recently Issued Accounting Standards

Impact of Recently Issued Accounting Guidance

Other Comprehensive Income (OCI)

In 2011, the FASB issued new accounting guidance regarding the presentation of comprehensive income within financial statements.  The new guidance requires 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 adopted this guidance, as amended for condensed quarterly reporting, for the quarterly reporting period ended March 31, 2012 by reporting comprehensive income as required.

Goodwill Testing

In September 2011, the FASB issued new accounting guidance regarding testing goodwill for impairment.  The new guidance allows 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 Company considered this option during its quarterly reporting period ended March 31, 2012 and concluded the continuation of the use of a quantitative approach is appropriate.

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 Company adopted this guidance for its quarterly reporting period ended March 31, 2012.  The adoption of this guidance did not have a material impact on our financial position, results of operations or cash flows.

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Statement of Shareholders' Equity (Parenthetical) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Common stock
Dividends (in dollars per share)	$ 1.405	$ 1.385	$ 1.365

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Quarterly Financial Data (Unaudited)

12 Months Ended

Dec. 31, 2012

Quarterly Financial Information Disclosure [Abstract]

Quarterly Financial Data (Unaudited)

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 2012 and 2011 follows:

(In millions, except per share amounts)		Q1		Q2		Q3		Q4
2012
	Operating revenues	$	604.6	$	470.6	$	513.5	$	644.1
	Operating income	109.9		70.2		81.6		90.8
	Net income	51.3		25.6		39.3		42.8
	Earnings per share:
	Basic	$	0.63	$	0.31	$	0.48	$	0.52
	Diluted	0.62		0.31		0.48		0.52
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

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Intangible Assets (Tables)

12 Months Ended

Dec. 31, 2012

Goodwill and Intangible Assets Disclosure [Abstract]

Intangible Assets

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

(In millions)	At December 31,
	2012				2011
	Amortizing		Non-amortizing		Amortizing		Non-amortizing
Customer-related assets	$	18.9	$	—	$	20.6	$	—
Market-related assets	2.7		7.0		3.6		7.0
Intangible assets, net	$	21.6	$	7.0	$	24.2	$	7.0

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Regulatory Assets & Liabilities (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Regulatory Assets [Line Items]
Regulatory Assets Currently Being Recovered in Base Rates	$ 41.6
Regulatory assets	252.7	226.0
Weighted average recovery period of regulatory assets currently being recovered (in years)	18
Regulatory Liabilities [Abstract]
Regulatory liabilities	364.2	345.2
Asset Retirement Obligations and Other [Member]
Regulatory Liabilities [Abstract]
Regulatory liabilities	349.5	320.9
Future Amounts Recoverable From Ratepayers [Member]
Regulatory Assets [Line Items]
Regulatory assets	124.9	129.6
Future Amounts Recoverable From Ratepayers [Member] | Benefit Obligations [Member]
Regulatory Assets [Line Items]
Regulatory assets	126.2	126.0
Future Amounts Recoverable From Ratepayers [Member] | Deferred Income Taxes [Member]
Regulatory Assets [Line Items]
Regulatory assets	(3.9)	1.3
Future Amounts Recoverable From Ratepayers [Member] | Asset Retirement Obligations and Other [Member]
Regulatory Assets [Line Items]
Regulatory assets	2.6	2.3
Amounts Deferred for Future Recovery [Member]
Regulatory Assets [Line Items]
Regulatory assets	52.6	24.1
Amounts Deferred for Future Recovery [Member] | Cost Recovery Riders Other [Member]
Regulatory Assets [Line Items]
Regulatory assets	10.2	6.4
Amounts Deferred for Future Recovery [Member] | Deferred Coal Costs [Member]
Regulatory Assets [Line Items]
Regulatory assets	42.4	17.7
Amounts Currently Recovered in Customer Rates [Member]
Regulatory Assets [Line Items]
Regulatory assets	75.2	72.3
Amounts Currently Recovered in Customer Rates [Member] | Unamortized Debt Issue Costs and Hedging Proceeds [Member]
Regulatory Assets [Line Items]
Regulatory assets	32.6	34.3
Amounts Currently Recovered in Customer Rates [Member] | Demand Side Management Programs [Member]
Regulatory Assets [Line Items]
Regulatory assets	4.4	6.3
Amounts Currently Recovered in Customer Rates [Member] | Indiana Authorized Trackers [Member]
Regulatory Assets [Line Items]
Regulatory assets	32.1	24.3
Amounts Currently Recovered in Customer Rates [Member] | Ohio Authorized Trackers [Member]
Regulatory Assets [Line Items]
Regulatory assets	1.5	1.0
Amounts Currently Recovered in Customer Rates [Member] | Premiums Paid to Reaquire Debt [Member]
Regulatory Assets [Line Items]
Regulatory assets	2.7	3.3
Amounts Currently Recovered in Customer Rates [Member] | Other Base Rate Recoveries [Member]
Regulatory Assets [Line Items]
Regulatory assets	$ 1.9	$ 3.1

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Additional Balance Sheet & Operational Information (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Inventory, Net [Abstract]
Gas in storage - at LIFO cost	$ 22.4	$ 31.8
Coal and Oil for electric generation - at average cost	52.0	60.6
Materials and supplies	57.6	54.9
Nonutility Coal - at LIFO cost	25.4	13.0
Other	1.2	1.6
Total inventories	158.6	161.9
Amount by which cost of replacing inventories carried at LIFO cost exceeded carrying value	12.7	12.0
Prepayments and other current assets [Abstract]
Prepaid gas delivery service	28.5	42.4
Deferred income taxes	0	16.0
Prepaid taxes	26.4	5.1
Other prepayments and current assets	18.4	20.8
Total prepayments and other current assets	73.3	84.3
Investments in unconsolidated affiliates [Abstract]
Total investments in unconsolidated affiliates	78.1	92.9
Equity in earnings (loss) of unconsolidated affiliates [Abstract]
Equity in (losses) of unconsolidated affiliates	(23.3)	(32.0)	(8.6)
Other utility and corporate investments [Abstract]
Cash surrender value of life insurance policies	29.1	27.3
Municipal bond	3.6	3.9
Restricted cash & other investments	1.9	3.2
Other utility and corporate investments	34.6	34.4
Goodwill	262.3	262.3
Accrued liabilities [Abstract]
Refunds to customers and customer deposits	53.1	56.4
Accrued taxes	34.4	33.5
Accrued interest	23.1	21.7
Deferred compensation & post-retirement benefits	6.8	6.5
Deferred income taxes	14.9	0
Accrued salaries and other	66.5	63.0
Total accrued liabilities	198.8	181.1
Asset Retirement Obligation [Roll Forward]
Asset retirement obligation, beginning balance	43.7	38.7
Accretion	2.7	2.5
Changes in estimates, net of cash payments	(8.7)	2.5
Asset retirement obligation, ending balance	37.7	43.7	38.7
Other - net in the consolidated statement of income [Abstract]
AFUDC - borrowed funds	4.6	2.5	1.4
AFUDC - equity funds	0.4	0.2	0.3
Nonutility plant capitalized interest	1.8	2.1	2.1
Interest income, net	1.1	1.4	1.7
Other nonutility investment impairment charges	(2.7)	(9.9)	(4.7)
Cash surrender value of life insurance policies	1.8	0.1	1.9
All other income	1.3	0.1	2.1
Total other income (expense) – net	8.3	(3.5)	4.8
Cash paid (received) for [Abstract]
Interest	94.6	108.6	104.5
Income taxes	21.8	(9.0)	8.1
Accruals related to utility and nonutility plant purchases [Abstract]
Accruals related to utility and nonutility plant purchases	11.1	15.9
Accrued Liabilities [Member]
Asset Retirement Obligation [Roll Forward]
Asset retirement obligation, ending balance	0	0.2
Deferred Credits and Other Liabilities [Member]
Asset Retirement Obligation [Roll Forward]
Asset retirement obligation, ending balance	37.7	43.5
ProLiance Holdings, LLC [Member]
Investments in unconsolidated affiliates [Abstract]
Total investments in unconsolidated affiliates	73.9	85.4
Equity in earnings (loss) of unconsolidated affiliates [Abstract]
Equity in (losses) of unconsolidated affiliates	(22.7)	(28.6)	(2.5)
Haddington Energy Partners, LP [Member]
Equity in earnings (loss) of unconsolidated affiliates [Abstract]
Equity in (losses) of unconsolidated affiliates	(0.7)	0	(6.1)
Other Nonutility Partnerships and Corporations [Member]
Investments in unconsolidated affiliates [Abstract]
Total investments in unconsolidated affiliates	4.0	7.3
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]
Equity in (losses) of unconsolidated affiliates	0.1	(3.4)	0
Utility Group [Member] | Gas Utility Services [Member]
Other utility and corporate investments [Abstract]
Goodwill	205.0	205.0
Nonutility Group [Member]
Investments in unconsolidated affiliates [Abstract]
Total investments in unconsolidated affiliates	3.8
Nonutility Group [Member] | Infrastructure Services [Member]
Other utility and corporate investments [Abstract]
Goodwill	55.2	55.2
Nonutility Group [Member] | Energy Services [Member]
Other utility and corporate investments [Abstract]
Goodwill	$ 2.1	$ 2.1

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Balance Sheet (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Current Assets
Cash and cash equivalents	$ 19.5	$ 8.6
Accounts receivable - less reserves of $6.8 & $6.7, respectively	216.7	221.3
Accrued unbilled revenues	185.0	121.5
Inventories	158.6	161.9
Recoverable fuel and natural gas costs	25.3	12.4
Prepayments and other current assets	73.3	84.3
Total current assets	678.4	610.0
Utility Plant
Original cost	5,176.8	4,979.9
Less: accumulated depreciation and amortization	2,057.2	1,947.3
Net utility plant	3,119.6	3,032.6
Investments in unconsolidated affiliates	78.1	92.9
Other utility and corporate investments	34.6	34.4
Other nonutility investments	24.9	29.6
Nonutility plant - net	598.0	550.8
Goodwill - net	262.3	262.3
Regulatory assets	252.7	226.0
Other assets	40.5	40.3
TOTAL ASSETS	5,089.1	4,878.9
Current Liabilities
Accounts payable	180.6	185.8
Accounts payable to affiliated companies	29.7	36.8
Accrued liabilities	198.8	181.1
Short-term borrowings	278.8	227.1
Current maturities of long-term debt	106.4	62.7
Total current liabilities	794.3	693.5
Long-term Debt - Net of Current Maturities	1,553.4	1,559.6
Deferred Income Taxes and Other Liabilities
Deferred income taxes	637.2	575.7
Regulatory liabilities	364.2	345.2
Deferred credits and other liabilities	213.9	239.4
Total deferred credits and other liabilities	1,215.3	1,160.3
Commitments & Contingencies (Notes 7, 17-19)
Common Shareholders' Equity
Common stock (no par value) – issued & outstanding 82.2 & 81.9 shares, respectively	700.5	692.6
Retained earnings	829.9	786.2
Accumulated other comprehensive income/(loss)	(4.3)	(13.3)
Total common shareholders' equity	1,526.1	1,465.5
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$ 5,089.1	$ 4,878.9

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Accumulated Other Comprehensive Income (Tables)

12 Months Ended

Dec. 31, 2012

Accumulated Other Comprehensive Income (Loss), Net of Tax [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:

	2010									2011						2012
	Beginning of Year			Changes During			End of Year			Changes During			End of Year			Changes During			End of Year
(In millions)	Balance			Year			Balance			Year			Balance			Year			Balance
Unconsolidated affiliates	$	(7.1	)	$	0.5		$	(6.6	)	$	(9.3	)	$	(15.9	)	$	11.3		$	(4.6	)
Pension & other benefit costs	(4.4		)	(0.5		)	(4.9		)	(1.7		)	(6.6		)	4.0			(2.6		)
Cash flow hedges	0.1			3.9			4.0			(3.9		)	0.1			(0.1		)	—
Deferred income taxes	4.6			(1.5		)	3.1			6.0			9.1			(6.2		)	2.9
Accumulated other comprehensive income (loss)	$	(6.8	)	$	2.4		$	(4.4	)	$	(8.9	)	$	(13.3	)	$	9.0		$	(4.3	)

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Statement of Cash Flows (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$ 159.0	$ 141.6	$ 133.7
Adjustments to reconcile net income to cash from operating activities:
Depreciation and amortization	254.6	244.3	229.1
Deferred income taxes and investment tax credits	84.3	71.7	69.3
Equity in losses of unconsolidated affiliates	23.3	32.0	8.6
Provision for uncollectible accounts	8.2	11.8	16.8
Expense portion of pension and postretirement benefit cost	8.7	9.0	10.0
(Gain) on sale of business in 2011, net of other non-cash charges	9.8	(0.1)	15.9
Changes in working capital accounts:
Accounts receivable and accrued unbilled revenue	(67.1)	(17.5)	(48.3)
Inventories	3.3	(26.1)	(19.3)
Recoverable/refundable fuel and natural gas costs	(12.9)	(4.5)	(30.2)
Prepayments and other current assets	(5.1)	17.9	(23.5)
Accounts payable, including to affiliated companies	(14.8)	(21.2)	5.5
Accrued liabilities	3.4	6.4	10.2
Unconsolidated affiliate dividends	0.1	0.1	42.7
Employer contributions to pension and postretirement plans	(20.5)	(38.8)	(22.0)
Changes in noncurrent assets	(35.3)	0.3	(7.6)
Changes in noncurrent liabilities	(11.6)	(10.0)	(6.1)
Net cash flows from operating activities	387.4	416.9	384.8
Proceeds from:
Long-term debt, net of issuance costs	199.5	148.9	124.2
Dividend reinvestment plan and other common stock issuances	7.2	7.9	14.0
Requirements for:
Dividends on common stock	(115.3)	(113.2)	(110.8)
Retirement of long-term debt	(62.7)	(349.1)	(49.3)
Other financing activities	0	(2.3)	(0.2)
Net change in short-term borrowings	(48.3)	208.8	(95.2)
Net cash flows from financing activities	(19.6)	(99.0)	(117.3)
Proceeds from:
Sale of business	0	84.3	0
Unconsolidated affiliate distributions	0.2	0.5	0.5
Other collections	9.9	1.1	10.8
Requirements for:
Capital expenditures, excluding AFUDC equity	(365.8)	(321.3)	(277.2)
Business acquisition, net of cash acquired	0	(83.4)	0
Other investments	(1.2)	(0.9)	(3.1)
Net cash flows from investing activities	(356.9)	(319.7)	(269.0)
Net change in cash and cash equivalents	10.9	(1.8)	(1.5)
Cash and cash equivalents at beginning of period	8.6	10.4	11.9
Cash and cash equivalents at end of period	$ 19.5	$ 8.6	$ 10.4

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Income Taxes (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
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)	4.00%	4.20%	3.80%
Amortization of investment tax credit (in hundredths)	(0.30%)	(0.30%)	(0.40%)
Depletion (in hundredths)	(1.50%)	(1.90%)	(2.00%)
Energy efficiency building deductions	(3.00%)	(1.10%)	(0.50%)
Other tax credits (in hundredths)	(0.10%)	(0.20%)	(0.20%)
Adjustment of income tax accruals and all other-net (in hundredths)	0.10%	2.20%	0.10%
Effective tax rate (in hundredths)	34.20%	37.90%	35.80%
Noncurrent deferred tax liabilities (assets) [Abstract]
Depreciation and cost recovery timing differences	$ 681.6	$ 625.5
Leveraged leases	10.8	13.8
Regulatory assets recoverable through future rates	23.5	25.1
Other comprehensive income	(4.0)	(10.2)
Alternative minimum tax carryforward	(44.1)	(35.1)
Employee benefit obligations	(2.1)	(9.4)
Net operating loss and other carryforwards	(11.7)	(6.7)
Regulatory liabilities to be settled through future rates	(18.3)	(17.2)
Impairments	(6.1)	(11.4)
Other - net	7.6	1.3
Net noncurrent deferred tax liability	637.2	575.7
Deferred Tax (Assets) Liabilities Current [Abstract]
Deferred fuel costs-net	25.7	6.0
Demand side management programs	2.7	0.7
Alternative minimum tax carryforward	(2.7)	(15.6)
Other - net	(10.8)	(7.1)
Net current deferred tax liability (asset)	14.9	(16.0)
Net deferred tax liability	652.1	559.7
Investment tax credits	3.7	4.3
Remaining life of NOL's and business credit carryforwards (in years)	5 to 20 years
Indiana House Bill 1004 [Abstract]
Description of Indiana House Bill 1004 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
Current: [Abstract]
Federal	(8.2)	4.4	(0.8)
State	6.4	10.3	6.2
Total current taxes	(1.8)	14.7	5.4
Deferred: [Abstract]
Federal	80.3	66.0	65.6
State	4.6	6.4	4.5
Total deferred taxes	84.9	72.4	70.1
Amortization of investment tax credits	(0.6)	(0.7)	(0.8)
Total income tax expense	82.5	86.4	74.7
Uncertain tax positions [Roll Forward]
Unrecognized tax benefits at beginning of period	12.4	13.3	11.5
Gross increases - tax positions in prior periods	0.2	3.3	1.6
Gross decreases - tax positions in prior periods	(9.4)	(4.5)	(0.3)
Gross increases - current period tax positions	1.9	0.6	1.0
Settlements	(0.3)	(0.3)	0
Lapse of statute of limitations	0	0	(0.5)
Unrecognized tax benefits at end of period	4.8	12.4	13.3
Uncertain tax positions [Abstract]
Amount of unrecognized tax benefits, which if recognized, that would impact the effective tax rate	0.7	0.7	0.7
Interest and penalties	(0.7)	0.4	0.3
Payment of interest and penalties accrued	0.6	1.3
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	$ 3.2	$ 10.1

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Utility & Nonutility Plant (Tables)

12 Months Ended

Dec. 31, 2012

Property, Plant and Equipment [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)	2012				2011
	Original Cost		Depreciation Rates as a Percent of  Original Cost		Original Cost		Depreciation Rates as a Percent of  Original Cost
Gas utility plant	$	2,614.3	3.5	%	$	2,516.8	3.5	%
Electric utility plant	2,463.6		3.3	%	2,316.8		3.3	%
Common utility plant	52.0		3.0	%	51.6		2.9	%
Construction work in progress	46.9		—		94.7		—
Total original cost	$	5,176.8			$	4,979.9

Nonutility Plant, Net of Depreciation and Amortization

Nonutility plant, net of accumulated depreciation and amortization follows:

	At December 31,
(In millions)	2012		2011
Coal mine development costs & equipment	$	241.9	$	222.0
Computer hardware & software	97.3		101.9
Land & buildings	120.4		112.0
Vehicles & equipment	119.8		92.5
All other	18.6		22.4
Nonutility plant - net	$	598.0	$	550.8

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Accumulated Other Comprehensive Income (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Accumulated other comprehensive income (loss), net of income taxes [Line Items]
Balance, beginning of period	$ (13.3)	$ (4.4)	$ (6.8)
Changes during period	9.0	(8.9)	2.4
Balance, end of period	(4.3)	(13.3)	(4.4)
Unconsolidated Affiliates [Member]
Accumulated other comprehensive income (loss), net of income taxes [Line Items]
Balance, beginning of period	(15.9)	(6.6)	(7.1)
Changes during period	11.3	(9.3)	0.5
Balance, end of period	(4.6)	(15.9)	(6.6)
Pension and Other Benefit Costs [Member]
Accumulated other comprehensive income (loss), net of income taxes [Line Items]
Balance, beginning of period	(6.6)	(4.9)	(4.4)
Changes during period	4.0	(1.7)	(0.5)
Balance, end of period	(2.6)	(6.6)	(4.9)
Cash Flow Hedges [Member]
Accumulated other comprehensive income (loss), net of income taxes [Line Items]
Balance, beginning of period	0.1	4.0	0.1
Changes during period	(0.1)	(3.9)	3.9
Balance, end of period	0	0.1	4.0
Deferred Income Taxes [Member]
Accumulated other comprehensive income (loss), net of income taxes [Line Items]
Balance, beginning of period	9.1	3.1	4.6
Changes during period	(6.2)	6.0	(1.5)
Balance, end of period	$ 2.9	$ 9.1	$ 3.1

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Earnings Per Share

12 Months Ended

Dec. 31, 2012

Earnings Per Share [Abstract]

Earnings Per Share

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. Participating securities have declined over time as share based awards to employess that can be settled in shares and that participate in dividends have vested and replaced with awards where dividends are subject to forfeiture.

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, 2012:

	Year Ended December 31,
(In millions, except per share data)	2012		2011		2010
Numerator:
Numerator for basic EPS	$	159.0	$	141.6	$	133.6
Add back earnings attributable to participating securities	—		—		0.1
Reported net income (Numerator for Diluted EPS)	$	159.0	$	141.6	$	133.7
Denominator:
Weighted average common shares outstanding (Basic EPS)	82.0		81.8		81.2
Conversion of share based compensation arrangements	0.1		0.0		0.1
Adjusted weighted average shares outstanding and
assumed conversions outstanding (Diluted EPS)	82.1		81.8		81.3
Basic earnings per share	$	1.94	$	1.73	$	1.65
Diluted earnings per share	$	1.94	$	1.73	$	1.64

For the year ended December 31, 2012 and 2011 there were no antidilutive options outstanding.  For the year ended December 31, 2010, options to purchase 308,800 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 price for these options ranged from $24.90 to $27.15 for the year ended December 31, 2010.

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Regulatory Assets & Liabilities (Tables)

12 Months Ended

Dec. 31, 2012

Regulatory Assets and Liabilities Disclosure [Abstract]

Schedule of Regulatory Assets

Regulatory assets consist of the following:

	At December 31,
(In millions)	2012			2011
Future amounts recoverable from ratepayers related to:
Benefit obligations (See Note 11)	$	126.2		$	126.0
Deferred income taxes (See Note 10)	(3.9		)	1.3
Asset retirement obligations & other	2.6			2.3
	124.9			129.6
Amounts deferred for future recovery related to:
Deferred coal costs (See Note 18)	42.4			17.7
Cost recovery riders & other	10.2			6.4
	52.6			24.1
Amounts currently recovered in customer rates related to:
Unamortized debt issue costs & hedging proceeds	32.6			34.3
Demand side management programs	4.4			6.3
Indiana authorized trackers	32.1			24.3
Ohio authorized trackers	1.5			1.0
Premiums paid to reacquire debt	2.7			3.3
Other base rate recoveries	1.9			3.1
	75.2			72.3
Total regulatory assets	$	252.7		$	226.0

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Share-Based Compensation & Deferred Compensation Arrangements

12 Months Ended

Dec. 31, 2012

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

Share-Based Compensation and Deferred Compensation Arrangements

Share-Based Compensation & Deferred Compensation Arrangements

The Company has share-based compensation programs to encourage Company officers, 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 has in the past issued stock options and both performance-based and time-based awards.  All share-based compensation programs are shareholder approved.  Currently, awards issued to officers of the Company, which comprise a substantial majority of the awards issued, are performance-based, are settled in cash, and dividends that accrue are also subject to performance measures. In addition, the Company maintains a deferred compensation plan for executives and non-employee directors where participants can invest earned compensation and vested share-based awards in phantom Company stock units, among other options.  Certain vesting grants 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)	2012		2011		2010
Total cost of share-based compensation	$	6.3	$	5.8	$	4.9
Less capitalized cost	1.2		0.8		1.7
Total in other operating expense	5.1		5.0		3.2
Less income tax benefit in earnings	2.1		2.0		1.3
After tax effect of share-based compensation	$	3.0	$	3.0	$	1.9

Performance Based Awards & Other Awards

The vesting of awards issued to Company officers and other key non-officer employees is contingent upon meeting a total return and/or return on equity performance objectives.  Grants to Company officers 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 have also been time-vested awards that vest ratably over a three year period.  In addition non-employee directors receive a portion of their fees in share based awards.  These awards to non-employee directors are not performance based and generally vest over one year.  Because Company officers and non-employee directors have the choice of settling awards in 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 awards separated between those accounted for as liabilities and equity as of December 31, 2012, and changes during the year ended December 31, 2012, follows:

	Equity Awards
		Wtd. Avg.
		Grant Date		Liability Awards
	Shares	Fair value		Shares/Units	Fair value
Awards at January 1, 2012	54,013	$	25.22	698,110
Granted	35,458	29.82		250,211
Vested	(2,635)	24.76		(149,374)
Forfeited	(16,343)	25.12		(170,137)
Awards at December 31, 2012	70,493	$	27.45	628,810	$	29.40

As of December 31, 2012, there was $8.1 million of total unrecognized compensation cost associated with outstanding grants.  That cost is expected to be recognized over a weighted-average period of 1.9 years.  The total fair value of shares vested for liability awards during the years ended December 31, 2012, 2011, and 2010, was $4.4 million, $3.0 million, and $5.0 million, respectively.  The total fair value of equity awards vesting during the year ended December 31, 2012, 2011, and 2010 was $0.1 million, $0.2 million, $0.2 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, 2012, and changes during the year ended December 31, 2012, follows:

		Weighted average			Aggregate
	Shares	Exercise Price		Remaining Contractual Term (years)	Intrinsic Value (In millions)
Outstanding at January 1, 2012	407,633	$	25.74
Exercised	(21,068)	$	23.18
Outstanding at December 31, 2012	386,565	$	25.88	1.6	$	1.4
Exercisable at December 31, 2012	386,565	$	25.88	1.6	$	1.4

The total intrinsic value of options exercised during the year ended December 31, 2012 , 2011, and 2010 was $0.1 million, $2.4 million, and $1.3 million respectively.  The actual tax benefit realized for tax deductions from option exercises was approximately $0.1 million , $1.0 million, and $0.5 million in 2012 , 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, 2012 , 2011, and 2010 the Company received cash upon exercise of stock options totaling approximately $0.3 million , $12.3 million, and $9.5 million respectively.  During these periods, the Company repurchased shares totaling approximately $0.1 million , $12.8 million, and $1.2 million respectively.  

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 share-based compensation.  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, 2012 and 2011, the liability associated with these plans totaled $22.9 million and $21.1 million, respectively.  Other than $1.3 million and $0.7 million which are classified in Accrued liabilities at December 31, 2012 and 2011, respectively, the liability is included in Deferred credits & other liabilities.  The impact of these plans on Other operating expenses was expense of $1.7 million in 2012, $2.1 million in 2011 and $2.3 million in 2010.  The amount recorded in earnings related to the investment activities in Vectren phantom stock associated with these plans during the years ended December 31, 2012, 2011, and 2010, was a cost of $0.6 million, $1.7 million and $1.6 million, respectively.

The Company has certain investments currently funded primarily through corporate-owned life insurance policies.  These investments, which are consolidated, are available to pay deferred compensation benefits.  These investments are also subject to the claims of the Company's creditors.  The cash surrender value of these policies included in Other corporate & utility investments on the Consolidated Balance Sheets were $29.1 million and $27.3 million at December 31, 2012 and 2011, respectively.  Earnings from those investments, which are recorded in Other-net, were earnings of $1.8 million in 2012, $0.1 million in 2011, and $1.9 million in 2010.

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Rate & Regulatory Matters (Details) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Vectren South Electric Base Rate Filing [Abstract]
Amount of infrastructure construction in the three years leading up to December 2009 rate filing	$ 325,000,000
Rate of return included in rate increase (in hundredths)	7.29%
Dollar amount of the rate base included in rate increase	1,295,600,000
Amount of rate of return on equity included in rate base (in hundredths)	10.40%
Expected capital investment in dense pack technology to improve the efficiency of generating station	32,000,000
Amount of expected capital investment invested to date related to investment in dense pack technology	25,500,000
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	3,000,000	1,000,000
Coal Procurement Procedures [Abstract]
Number of years for recovery of coal costs	6
Reduction to coal inventory balance related to deferral		17,700,000
Deferrals related to coal purchases in the current year	24,700,000
Cumulative total deferrals related to coal purchases	42,400,000
Pipeline Safety Law [Member]
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items]
Estimated amount of operating expenses that could accumulate associated with expanded compliance requirements	9,000,000
Indiana [Member] | Indiana Recovery and Deferral Mechanisms [Member]
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items]
Allowable capital expenditures under Vectren North Program	20,000,000
Allowable expenditures under Vectren South program	3,000,000
Regulatory Assset balance associated with Vectren north and south programs	8,500,000	4,700,000
Indiana [Member] | Senate Bill 251 [Member]
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items]
Description of Legislation - Senate Bill 251	In April 2011, Senate Bill 251 was signed into Indiana law. The law 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 a return on the federally mandated capital investment, along with recovery of depreciation and other operating costs associated with these mandates. The remaining 20 percent of those costs are to be deferred for future recovery in the utility's next general rate case.
Indiana [Member] | Pipeline Safety Law [Member]
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items]
Estimated amount of operating expenses that could accumulate associated with expanded compliance requirements	6,000,000
Ohio [Member] | Ohio Recovery and Deferral Mechanisms [Member]
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items]
Cumulative gross plant invesment made under Distribution Replacement Rider	80,000,000
Distribution Replacement Rider revenues	6,500,000	3,600,000	1,400,000
Other income (AFUDC borrowed)	1,800,000	2,000,000	900,000
Regulatory Asset associated with DRR deferrals of depreciation and post in-service carrying costs	6,500,000	3,000,000	1,000,000
Estimated budget related to Ohio capital expenditure program	23,500,000
Time period (in months) included in VEDO application	15
Bill impact per customer per month	1.50
Cost deferrals associated with VEDO capital expenditure program	1,500,000
Amount of deferral in other income	900,000
Amount of deferral related to depreciation and property tax expense	$ 600,000

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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, 2009	$ 1,397.2	$ 666.8	$ 737.2	$ (6.8)
Balance at beginning of period (in shares) at Dec. 31, 2009	81.1
Comprehensive income:
Net Income	133.7		133.7
Other comprehensive income	2.4			2.4
Common stock:
Issuance: option exercises and dividend reinvestment plan (in shares)	0.6
Stock Issued During Period Value Stock Options Exercised And Dividend Reinvestment Plan	14.0	14.0
Dividends ($1.405, $1.385, and $1.365 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
Comprehensive income:
Net Income	141.6		141.6
Other comprehensive income	(8.9)			(8.9)
Common stock:
Issuance: option exercises and dividend reinvestment plan (in shares)	0.2
Stock Issued During Period Value Stock Options Exercised And Dividend Reinvestment Plan	7.9	7.9
Dividends ($1.405, $1.385, and $1.365 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
Comprehensive income:
Net Income	159.0		159.0
Other comprehensive income	9.0			9.0
Common stock:
Issuance: option exercises and dividend reinvestment plan (in shares)	0.3
Stock Issued During Period Value Stock Options Exercised And Dividend Reinvestment Plan	7.2	7.2
Dividends ($1.405, $1.385, and $1.365 per share)	(115.3)		(115.3)
Other	0.7	0.7
Balance at end of period at Dec. 31, 2012	$ 1,526.1	$ 700.5	$ 829.9	$ (4.3)
Balance at end of period (in shares) at Dec. 31, 2012	82.2

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Income Statement (USD $) In Millions, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
OPERATING REVENUES
Gas utility	$ 738.1	$ 819.1	$ 954.1
Electric utility	594.9	635.9	608.0
Nonutility	899.8	870.2	567.4
Total operating revenues	2,232.8	2,325.2	2,129.5
OPERATING EXPENSES
Cost of gas sold	301.3	375.4	504.7
Cost of fuel and purchased power	192.0	240.4	235.0
Cost of nonutility revenues	295.1	385.3	243.3
Other operating	781.0	652.2	538.4
Depreciation and amortization	254.6	244.3	229.1
Taxes other than income taxes	56.3	57.6	62.2
Total operating expenses	1,880.3	1,955.2	1,812.7
OPERATING INCOME	352.5	370.0	316.8
OTHER INCOME (EXPENSE)
Equity in (losses) of unconsolidated affiliates	(23.3)	(32.0)	(8.6)
Other income (expense) - net	8.3	(3.5)	4.8
Total other income (expense)	(15.0)	(35.5)	(3.8)
Interest expense	96.0	106.5	104.6
INCOME BEFORE INCOME TAXES	241.5	228.0	208.4
Income taxes	82.5	86.4	74.7
Net income	$ 159.0	$ 141.6	$ 133.7
AVERAGE COMMON SHARES OUTSTANDING (in shares)	82.0	81.8	81.2
DILUTED COMMON SHARES OUTSTANDING (in shares)	82.1	81.8	81.3
EARNINGS PER SHARE OF COMMON STOCK:
BASIC (in dollars per share)	$ 1.94	$ 1.73	$ 1.65
DILUTED (in dollars per share)	$ 1.94	$ 1.73	$ 1.64

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Intangible Assets

12 Months Ended

Dec. 31, 2012

Goodwill and Intangible Assets Disclosure [Abstract]

Intangible Assets

Intangible Assets

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

(In millions)	At December 31,
	2012				2011
	Amortizing		Non-amortizing		Amortizing		Non-amortizing
Customer-related assets	$	18.9	$	—	$	20.6	$	—
Market-related assets	2.7		7.0		3.6		7.0
Intangible assets, net	$	21.6	$	7.0	$	24.2	$	7.0

As of December 31, 2012, the weighted average remaining life for amortizing customer-related assets and all amortizing intangibles is 13 years.  These amortizing intangible assets have no significant residual values.  Intangible assets are presented net of accumulated amortization totaling $6.6 million for customer-related assets and $1.7 million for market-related assets at December 31, 2012 and $5.1 million for customer-related assets and $0.9 million for market-related assets at December 31, 2011.  Annual amortization associated with intangible assets totaled $2.6 million in 2012 and $2.3 million in 2011 and $0.6 million2010.  Amortization should approximate (in millions) $2.3, $2.3, $2.2, $1.6, and $1.4 in 2013, 2014, 2015, 2016, and 2017, respectively. Intangible assets are primarily in the Nonutility Group.

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Document And Entity Information (USD $)	12 Months Ended
	Dec. 31, 2012	Jan. 31, 2013	Jun. 30, 2012
Entity Information [Line Items]
Entity Registrant Name	VECTREN CORP
Entity Central Index Key	0001096385
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	No
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$ 2,415,396,451
Entity Common Stock, Shares Outstanding		82,204,242
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	FY
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2012
Current Fiscal Year End Date	--12-31

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Income Taxes

12 Months Ended

Dec. 31, 2012

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

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

	Year Ended December 31,
	2012		2011		2010
Statutory rate:	35.0	%	35.0	%	35.0	%
State & local taxes-net of federal benefit	4.0		4.2		3.8
Amortization of investment tax credit	(0.3	)	(0.3	)	(0.4	)
Depletion	(1.5	)	(1.9	)	(2.0	)
Energy efficiency building deductions	(3.0	)	(1.1	)	(0.5	)
Other tax credits	(0.1	)	(0.2	)	(0.2	)
Adjustment of income tax accruals and all other-net	0.1		2.2		0.1
Effective tax rate	34.2	%	37.9	%	35.8	%

Significant components of the net deferred tax liability follow:

	At December 31,
(In millions)	2012			2011
Noncurrent deferred tax liabilities (assets):
Depreciation & cost recovery timing differences	$	681.6		$	625.5
Leveraged lease	10.8			13.8
Regulatory assets recoverable through future rates	23.5			25.1
Other comprehensive income	(4.0		)	(10.2		)
Alternative minimum tax carryforward	(44.1		)	(35.1		)
Employee benefit obligations	(2.1		)	(9.4		)
Net operating loss & other carryforwards	(11.7		)	(6.7		)
Regulatory liabilities to be settled through future rates	(18.3		)	(17.2		)
Impairments	(6.1		)	(11.4		)
Other – net	7.6			1.3
Net noncurrent deferred tax liability	637.2			575.7
Current deferred tax liabilities (assets):
Deferred fuel costs-net	25.7			6.0
Demand side management programs	2.7			0.7
Alternative minimum tax carryforward	(2.7		)	(15.6		)
Other – net	(10.8		)	(7.1		)
Net current deferred tax liability (asset)	14.9			(16.0		)
Net deferred tax liability	$	652.1		$	559.7

At December 31, 2012 and 2011, investment tax credits totaling $3.7 million and $4.3 million respectively, are included in Deferred credits & other liabilities.  At December 31, 2012, the Company has alternative minimum tax carryforwards which do not expire.  In addition, the Company has $11.7 million in net operating loss and general business credit carryforwards, which will expire in 5 to 20 years.

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 million decrease in Regulatory assets.

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

	Year Ended December 31,
(In millions)	2012			2011			2010
Current:
Federal	$	(8.2	)	$	4.4		$	(0.8	)
State	6.4			10.3			6.2
Total current taxes	(1.8		)	14.7			5.4
Deferred:
Federal	80.3			66.0			65.6
State	4.6			6.4			4.5
Total deferred taxes	84.9			72.4			70.1
Amortization of investment tax credits	(0.6		)	(0.7		)	(0.8		)
Total income tax expense	$	82.5		$	86.4		$	74.7

Uncertain Tax Positions

Following is a roll forward of unrecognized tax benefits for the three years ended December 31, 2012:

(In millions)	2012			2011			2010
Unrecognized tax benefits at January 1	$	12.4		$	13.3		$	11.5
Gross increases - tax positions in prior periods	0.2			3.3			1.6
Gross decreases - tax positions in prior periods	(9.4		)	(4.5		)	(0.3		)
Gross increases - current period tax positions	1.9			0.6			1.0
Settlements	(0.3		)	(0.3		)	—
Lapse of statute of limitations	—			—			(0.5		)
Unrecognized tax benefits at December 31	$	4.8		$	12.4		$	13.3

Of the change in unrecognized tax benefits during 2012, 2011, and 2010, 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 each of December 31, 2012, 2011 and 2010.  As of December 31, 2012, the unrecognized tax benefit relates to tax positions for which the ultimate deductibility is more likely than not 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 income related to a reversal of interest expense previously accrued and net of penalties totaling $0.7 million in 2012 and recognized expense related to interest and penalties totaling approximately $0.4 million in 2011, and $0.3 million in 2010.  The Company had approximately $0.6 million and $1.3 million for the payment of interest and penalties accrued as of December 31, 2012 and 2011, 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 $3.2 million and $10.1 million, respectively, at December 31, 2012 and 2011.

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 have recently been examined by the IRS, and such examination resulted in no assessments but is in IRS Joint Committee review currently. The primary focus of the IRS examination was certain repairs and maintenance deductions, an area of particular focus by the IRS throughout the utility industry. In 2012, the IRS suspended all examinations related to this issue generally, resulting in the elimination of the audit risk in this area for the company through 2012.  To the extent IRS guidance changes in this area, any impact is not expected to be material to the Company's result 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 2008 for Indiana income tax.

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Balance Sheet (Parenthetical) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Current Assets
Reserves	$ 6.8	$ 6.7
Common Shareholders' Equity
Common stock Shares, Issued (in shares)	82.2	81.9
Common stock, Shares Outstanding (in shares)	82.2	81.9

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Regulatory Assets & Liabilities

12 Months Ended

Dec. 31, 2012

Regulatory Assets and Liabilities Disclosure [Abstract]

Regulatory Assets and Liabilities

Regulatory Assets & Liabilities

Regulatory Assets

Regulatory assets consist of the following:

	At December 31,
(In millions)	2012			2011
Future amounts recoverable from ratepayers related to:
Benefit obligations (See Note 11)	$	126.2		$	126.0
Deferred income taxes (See Note 10)	(3.9		)	1.3
Asset retirement obligations & other	2.6			2.3
	124.9			129.6
Amounts deferred for future recovery related to:
Deferred coal costs (See Note 18)	42.4			17.7
Cost recovery riders & other	10.2			6.4
	52.6			24.1
Amounts currently recovered in customer rates related to:
Unamortized debt issue costs & hedging proceeds	32.6			34.3
Demand side management programs	4.4			6.3
Indiana authorized trackers	32.1			24.3
Ohio authorized trackers	1.5			1.0
Premiums paid to reacquire debt	2.7			3.3
Other base rate recoveries	1.9			3.1
	75.2			72.3
Total regulatory assets	$	252.7		$	226.0

Of the $75.2 million currently being recovered in customer rates, $4.4 million that is associated with demand side management programs is earning a return.  The weighted average recovery period of regulatory assets currently being recovered in base rates, which totals $41.6 million, is 18 years.  The remainder of the regulatory assets are being recovered timely through tracking mechanisms. 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, 2012 and 2011, the Company has approximately $364.2 million and $345.2 million, respectively, in Regulatory liabilities.  Of these amounts, $349.5 million and $320.9 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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Utility & Nonutility Plant

12 Months Ended

Dec. 31, 2012

Property, Plant and Equipment [Abstract]

Utility and Nonutility Plant

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)	2012				2011
	Original Cost		Depreciation Rates as a Percent of  Original Cost		Original Cost		Depreciation Rates as a Percent of  Original Cost
Gas utility plant	$	2,614.3	3.5	%	$	2,516.8	3.5	%
Electric utility plant	2,463.6		3.3	%	2,316.8		3.3	%
Common utility plant	52.0		3.0	%	51.6		2.9	%
Construction work in progress	46.9		—		94.7		—
Total original cost	$	5,176.8			$	4,979.9

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, 2012, is $185.9 million with accumulated depreciation totaling $78.9 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 operatingexpenses in the Consolidated Statements of Income.

Nonutility plant, net of accumulated depreciation and amortization follows:

	At December 31,
(In millions)	2012		2011
Coal mine development costs & equipment	$	241.9	$	222.0
Computer hardware & software	97.3		101.9
Land & buildings	120.4		112.0
Vehicles & equipment	119.8		92.5
All other	18.6		22.4
Nonutility plant - net	$	598.0	$	550.8

Nonutility plant is presented net of accumulated depreciation and amortization totaling $468.4 million and $418.5 million as of December 31, 2012 and 2011, respectively.  For the years ended December 31, 2012, 2011, and 2010, the Company capitalized interest totaling $1.8 million, $2.1 million, and $2.1 million, respectively, on nonutility plant construction projects.

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Accumulated Other Comprehensive Income

12 Months Ended

Dec. 31, 2012

Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]

Accumulated Other Comprehensive Income

Accumulated Other Comprehensive Income

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

	2010									2011						2012
	Beginning of Year			Changes During			End of Year			Changes During			End of Year			Changes During			End of Year
(In millions)	Balance			Year			Balance			Year			Balance			Year			Balance
Unconsolidated affiliates	$	(7.1	)	$	0.5		$	(6.6	)	$	(9.3	)	$	(15.9	)	$	11.3		$	(4.6	)
Pension & other benefit costs	(4.4		)	(0.5		)	(4.9		)	(1.7		)	(6.6		)	4.0			(2.6		)
Cash flow hedges	0.1			3.9			4.0			(3.9		)	0.1			(0.1		)	—
Deferred income taxes	4.6			(1.5		)	3.1			6.0			9.1			(6.2		)	2.9
Accumulated other comprehensive income (loss)	$	(6.8	)	$	2.4		$	(4.4	)	$	(8.9	)	$	(13.3	)	$	9.0		$	(4.3	)

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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Retirement Plans & Other Postretirement Benefits

12 Months Ended

Dec. 31, 2012

Compensation and Retirement Disclosure [Abstract]

Retirement Plans and Other Postretirement Benefits

Retirement Plans & Other Postretirement Benefits

At December 31, 2012, the Company maintains three qualified defined benefit pension plans, a nonqualified supplemental executive retirement plan (SERP), and a postretirement benefit plan.  The defined benefit pension plans and postretirement benefit plan, 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.”  The postretirement benefit plan is presented 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, 2012 follows:

	Pension Benefits									Other Benefits
(In millions)	2012			2011			2010			2012			2011			2010
Service cost	$	7.7		$	6.9		$	6.3		$	0.5		$	0.5		$	0.5
Interest cost	15.5			15.9			15.9			2.8			4.3			4.6
Expected return on plan assets	(21.2		)	(21.2		)	(18.4		)	—			—			(0.4		)
Amortization of prior service cost (benefit)	1.6			1.7			1.6			(2.5		)	(0.8		)	(0.8		)
Amortization of actuarial loss (gain)	6.8			3.8			3.2			0.7			0.6			0.5
Amortization of transitional obligation	—			—			—			0.5			1.1			1.2
Net periodic benefit cost	$	10.4		$	7.1		$	8.6		$	2.0		$	5.7		$	5.6

A portion of the net periodic benefit cost disclosed in the table above is capitalized as Utility plant.  Costs capitalized in 2012, 2011, and 2010 are estimated at $3.7 million, $3.9 million, and $4.3 million, respectively.

The Company lowered the discount rate used to measure periodic cost from 5.50 percent in 2011 to 4.82 percent in 2012 due to lower benchmark interest rates that approximate the expected duration of the Company’s benefit obligations.  For fiscal year 2013, the weighted average discount rate will be 4.03 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
	2012		2011		2010		2012		2011		2010
Discount rate	4.82	%	5.50	%	6.00	%	4.75	%	5.50	%	6.00	%
Rate of compensation increase	3.50	%	3.50	%	3.50	%	N/A		N/A		N/A
Expected return on plan assets	7.75	%	8.00	%	8.00	%	N/A		8.00	%	8.00	%
Expected increase in Consumer Price Index	N/A		N/A		N/A		2.75	%	3.00	%	3.00	%

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, 2012 and 2011 follows:

	Pension Benefits						Other Benefits
(In millions)	2012			2011			2012			2011
Benefit obligation, beginning of period	$	329.2		$	297.3		$	79.7		$	80.7
Service cost – benefits earned during the period	7.7			6.9			0.5			0.5
Interest cost on projected benefit obligation	15.5			15.9			2.8			4.3
Plan participants' contributions	—			—			1.6			1.9
Plan amendments	0.7			—			(26.6		)	—
Actuarial loss (gain)	39.0			23.1			2.8			(0.5		)
Medicare subsidy receipts	—			—			0.5			1.0
Benefit payments	(14.8		)	(14.0		)	(6.9		)	(8.2		)
Benefit obligation, end of period	$	377.3		$	329.2		$	54.4		$	79.7

The accumulated benefit obligation for all defined benefit pension plans was $354.5 million and $310.9 million at December 31, 2012 and 2011, respectively.

Postretirement Benefit Change

Effective September 1, 2012, the Company no longer offers postretirement health coverage for participants 65 and older.  Rather, the Company provides a subsidy to plan participants to purchase health coverage through a private Medicare exchange.  This change in benefits provides a comparable benefit at a reduced cost made possible by current market pricing.  Since this change in benefits was a significant event pursuant to GAAP, the Company remeasured its postretirement benefit obligations as of June 1, 2012, consistent with the notification date to participants.  The change in benefits, net of the impacts associated with remeasuring the benefit obligations using a lower discount rate, resulted in a $23 million reduction in the postretirement liability.  Substantially all of the amount was recorded as a reduction to Regulatory Assets, as the Company's retirement costs primarily relate to its regulated utilities.  The discount rate used to remeasure the postretirement benefit obligation was 3.93 percent. 

The benefit obligation as of December 31, 2012 and 2011 was calculated using the following weighted average assumptions:

	Pension Benefits				Other Benefits
	2012		2011		2012		2011
Discount rate	4.03	%	4.82	%	3.91	%	4.78	%
Rate of compensation increase	3.50	%	3.50	%	N/A		N/A
Expected increase in Consumer Price Index	N/A		N/A		2.75	%	2.75	%

To calculate the 2012 ending postretirement benefit obligation, medical claims costs in 2013 were assumed to be 7.50 percent higher than those incurred in 2012.  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 $0.7 million.

Plan Assets

A reconciliation of the Company’s plan assets at December 31, 2012 and 2011 follows:

	Pension Benefits						Other Benefits
(In millions)	2012			2011			2012			2011
Plan assets at fair value, beginning of period	$	261.0		$	237.2		$	—		$	3.1
Actual return on plan assets	33.8			2.1			—			0.1
Employer contributions	15.7			35.7			5.3			3.1
Plan participants' contributions	—			—			1.6			1.9
Benefit payments	(14.8		)	(14.0		)	(6.9		)	(8.2		)
Fair value of plan assets, end of period	$	295.7		$	261.0		$	—		$	—

The Company’s overall investment strategy for its retirement plan trusts is to maintain investments in a diversified portfolio, comprised of primarily equity and fixed income investments, which are further diversified among various asset classes.  The diversification is designed to minimize the risk of large losses while maximizing total return within reasonable and prudent levels of risk.  The investment objectives specify a targeted investment allocation for the pension plans of 60 percent equities, 35 percent debt, and 5 percent for other investments, including real estate.  Both the equity and debt securities have a blend of domestic and international exposures.  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 53 percent and 38 percent, respectively, of their fair value as of December 31, 2012 and approximately 52 percent and 40 percent, respectively, as of December 31, 2011.  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 $145.0 million at December 31, 2012 and $128.2 million at December 31, 2011.  In relation to these investments, there are no unfunded commitments.  Also, the Plan can exchange shares with minimal restrictions. However, in certain events 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, 2012 and 2011, the estimate of undiscounted funds necessary to satisfy John Hancock’s remaining obligation was $3.6 million and $3.4 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, 2012 and 2011 was 5.17 percent and 5.26 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, 2012 and December 31, 2011 by asset category and by fair value hierarchy are as follows:

	As of December 31, 2012
(In millions)	Level 1		Level 2		Level 3		Total
Domestic equities & equity funds	$	62.8	$	77.6	$	—	$	140.4
International equities & equity funds	34.3		—		—		34.3
Domestic bonds & bond funds	41.7		42.3		—		84.0
Inflation protected security fund	—		12.6		—		12.6
Real estate, commodities & other	8.0		12.5		3.9		24.4
Total plan investments	$	146.8	$	145.0	$	3.9	$	295.7

	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

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

(In millions)	2012			2011
Fair value, beginning of year	$	3.8		$	3.7
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	$	3.9		$	3.8

Funded Status

The funded status of the plans as of December 31, 2012 and 2011 follows:

	Pension Benefits						Other Benefits
(In millions)	2012			2011			2012			2011
Qualified Plans
Benefit obligation, end of period	$	(360.0	)	$	(314.7	)	$	(54.4	)	$	(79.7	)
Fair value of plan assets, end of period	295.7			261.0			—			—
Funded Status of Qualified Plans, end of period	(64.3		)	(53.7		)	(54.4		)	(79.7		)
Benefit obligation of SERP Plan, end of period	(17.3		)	(14.5		)	—			—
Total funded status, end of period	$	(81.6	)	$	(68.2	)	$	(54.4	)	$	(79.7	)
Accrued liabilities	$	1.0		$	0.7		$	4.5		$	5.1
Deferred credits & other liabilities	$	80.6		$	67.5		$	49.9		$	74.6

Expected Cash Flows

In 2013, the Company expects to make contributions of approximately $10 million to its pension plan trusts.  In addition, the Company expects to make payments totaling approximately $1.0 million directly to SERP participants and approximately $3.5 million directly to those participating in the postretirement plan.

Estimated retiree pension benefit payments, including the SERP, projected to be required during the years following 2012 are approximately (in millions) $23.8 in 2013, $24.1 in 2014, $23.9 in 2015, $25.8 in 2016, $35.0 in 2017, and $142.0 in years 2018-2022.  Expected benefit payments projected to be required for postretirement benefits during the years following 2012 (in millions) are approximately $4.5 in 2013, $4.7 in 2014, $4.8 in 2015, $5.0 in 2016, and $5.3 in 2017 and $30.8 in years 2018-2022.

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.

	Pensions						Other Benefits
(In millions)	Prior Service Cost			Net Gain or Loss			Prior Service Cost			Net Gain or Loss			Transition Obligation
Balance at January 1, 2010	$	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 at 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 at December 31, 2011	$	5.4		$	116.6		$	(1.2	)	$	9.1		$	2.7
Amounts arising during the period	0.7			26.4			(24.4		)	2.8			(2.2		)
Reclassification to benefit costs	(1.6		)	(6.8		)	2.5			(0.7		)	(0.5		)
Balance at December 31, 2012	$	4.5		$	136.2		$	(23.1	)	$	11.2		$	—

Following is a reconciliation of the amounts in Accumulated other comprehensive income (AOCI) and Regulatory assets related to retirement plan obligations at December 31, 2012 and 2011.

(In millions)	2012						2011
	Pensions			Other Benefits			Pensions			Other Benefits
Prior service cost	$	4.5		$	(23.1	)	$	5.4		$	(1.2	)
Unamortized actuarial gain/(loss)	136.2			11.2			116.6			9.1
Transition obligation	—			—			—			2.7
	140.7			(11.9		)	122.0			10.6
Less: Regulatory asset deferral	(137.9		)	11.7			(115.9		)	(10.1		)
AOCI before taxes	$	2.8		$	(0.2	)	$	6.1		$	0.5

Related to pension plans, $1.4 million of prior service cost and $10.2 million of actuarial gain/loss is expected to be amortized to cost in 2013.  Related to other benefits, $0.8 million of actuarial gain/loss is expected to be amortized to periodic cost in 2013, and $3.2 million of prior service cost is expected to reduce cost in 2013.

Multi-employer Benefit Plan

The Company, through its Infrastructure Services operating segment, participates in several industry wide multi-employer pension plans for its union employees which provide for monthly benefits based on length of service. The risks of participating in multi-employer pension plans are different from the risks of participating in single-employer pension plans in the following respects: 1) assets contributed to the multi-employer plan by one employer may be used to provide benefits to employees of other participating employers, 2) if a participating employer stops contributing to the plan, the unfunded obligations of the plan allocable to such withdrawing employer may be borne by the remaining participating employers, and 3) if the Company stops participating in some of its multi-employer pension plans, the Company may be required to pay those plans an amount based on its allocable share of the underfunded status of the plan, referred to as a withdrawal liability.

Expense is recognized as payments are accrued for work performed or when withdrawal liabilities are probable and estimable.  Expense associated with multi-employer plans was $27.6 million, $18.3 million and $10.0 million for the years ended December 31, 2012, 2011, and 2010, respectively. The increase in expense is due primarily to the increase in work performed. During 2012, the Company, through its Infrastructure Services operating segment, made contributions to these multi-employer plans on behalf of employees that participate in approximately 370 local unions.  Contracts with these unions are negotiated with trade agreements through two primary contractor associations. These trade agreements have varying expiration dates ranging from 2014 through 2016. The average contribution related to these local unions was less than $0.1 million, and the largest contribution was $3.6 million.  Multiple unions can contribute to a single multi-employer plan.  The Company made contributions to at least 41 plans in 2012, four of which are considered significant plans based on, among other things, the amount of the contributions, the number of employees participating in the plan, and the funded status of the plan. Further, of the 41 plans identified, there are four plans that are less than 65 percent funded (i.e. red zone status) and two plans where the Company's contributions represent more than 5 percent of the total contributions received by the plan; however, none of these plans are significant to the Company.

The Company's participation in the significant plans is outlined in the following table. The Employer Identification Number (EIN) / Pension Plan Number column provides the Employer Identification Number ("EIN") and three digit pension plan numbers. The most recent Pension Protection Act Zone Status available in 2012 and 2011 is for the plan year end at January 31, 2012 and 2011 for the Central Pension Fund, December 31, 2011 and 2010 for the Pipeline Industry Benefit Fund, May 31, 2011 and 2010 for the Indiana Laborers Pension Fund, and December 31, 2011 and 2010 for the Minnesota Laborers Pension Fund, respectively. Generally, plans in the red zone are less than 65 percent funded, plans in the yellow zone are less than 80 percent funded and plans in the green zone are at least 80 percent funded. The FIP/RP Status Pending / Implemented column indicates plans for which a funding improvement plan ("FIP") or rehabilitation plan ("RP") is either pending or has been implemented. The multi-employer contributions listed in the table below are the Company's multi-employer contributions made in 2012, 2011, and 2010.

(In millions)
		Pension Protection Act Zone Status			Multi-Employer Contributions
Pension Fund	EIN/Pension Plan Number	2012	2011	FIP/RP Status Pending/Implemented	2012	2011	2010	Surcharge Imposed
Central Pension Fund	36-6052390-001	Green	Green	No	$4.0	$2.3	$1.1	No
Pipeline Industry Benefit Fund	73-0742835-001	Green	Green	No	3.9	1.0	0.7	No
Indiana Laborers Pension Fund (1)	35-6027150-001	Yellow	Yellow	Implemented	3.2	1.6	1.4	No
Minnesota Laborers Pension Fund	41-6159599-001	Green	Green	No	2.0	0.7	—	No
Other					14.5	12.7	6.8
Total Contributions					$27.6	$18.3	$10.0

(1) Federal law requires pension plans in endangered status to adopt a funding improvement plan aimed at restoring the financial health of the plan. Since this plan became endangered as of June 1, 2008, a funding improvement plan was previously set in place to begin June 1, 2009. The funding improvement plan requires that the plan's funded percentage improve at least one-third of the way to 100 percent over a 10-year period. The target for this plan under the law is a funded percentage of 78 percent by 2019. The plan must also meet the federal minimum funding requirements during this 10-year period. Based on the plan's most current actuarial projections, the plan is on track to meet or exceed these benchmarks.

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 2012, 2011 and 2010, the Company made contributions to these plans of $6.7 million, $6.2 million, and $6.6 million, respectively.

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Investment in ProLiance Holdings, LLC

12 Months Ended

Dec. 31, 2012

ProLiance Holdings, LLC [Abstract]

Investment in ProLiance Holdings, LLC

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 former 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 2012, 2011, and 2010.

Summarized Financial Information

	Year Ended December 31,
(In millions)	2012			2011			2010
Summarized Statement of Income information:
Revenues	$	1,001.3		$	1,410.5		$	1,497.0
Operating loss	(34.8		)	(44.5		)	(3.1		)
ProLiance's losses	(38.3		)	(47.3		)	(3.7		)

	As of December 31,
(In millions)	2012			2011
Summarized balance sheet information:
Current assets	$	279.7		$	381.9
Noncurrent assets	55.6			56.1
Current liabilities	215.1			298.5
Noncurrent liabilities	0.3			0.7
Members' equity	124.3			161.5
Accumulated other comprehensive loss	(7.5		)	(26.0		)
Noncontrolling interest	3.1			3.3

Vectren records its 61 percent share of ProLiance’s results in Equity in (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, 2012 and 2011, the Company’s investment balance is $73.9 million and $85.4 million, respectively. The amounts recorded to Equity in (losses) of unconsolidated affiliates related to ProLiance’s operations totaled a pre-tax loss of $22.7 million, $28.6 million, and $2.5 million for the years ended December 31, 2012, 2011, and 2010, respectively.  Lower natural gas prices, which have resulted in narrowed summer/winter spreads and locational margins, have negatively impacted ProLiance’s results. 

The Company continues to evaluate and assess strategic alternatives related to the investment in its energy marketing affiliate, ProLiance Holdings.  The Company believes the carrying value of its investment in ProLiance Holdings at December 31, 2012 is appropriate, based upon projections and other valuation data received from ProLiance. If the Company, however, proceeds with one of the strategic alternatives being evaluated, which could include a disposition of its investment in ProLiance Holdings or a disposition by ProLiance Holdings of one or more of its operating subsidiaries or their assets, the amount realized could be materially below the carrying value of the Company's investment.

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, which resulted in Liberty recording a $132 million impairment charge. The Company, through ProLiance, recorded its share of the charge in 2009. 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.  Approximately 12 Bcf of the storage at the South site, which comprises three of the four FERC certified caverns, is fully tested but additional work is required to connect the caverns to the pipeline system.  ProLiance's investment in Liberty is approximately $35 million.

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.  As such, as of December 31, 2012, ProLiance has no material reserve recorded related to this matter and this litigation has not materially impacted ProLiance's results of operations or statement of financial position.

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 2031.  At December 31, 2012, the estimated aggregated amounts of such required future payments were $42.3 million, $40.7 million, $33.5 million, $29.6 million, $26.2 million, and $180.1 million for 2013, 2014, 2015, 2016, 2017, and thereafter, respectively.  During 2012, 2011, and 2010, fixed payments under these agreements were $54.5 million, $73.0 million, and $76.8 million, respectively.  ProLiance also made variable payments under these agreements in 2012, 2011, and 2010. 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, 2012, 2011, and 2010, totaled $274.5 million, $378.7 million, and $437.7 million, respectively.  Amounts owed to ProLiance at December 31, 2012, and 2011, for those purchases were $29.7 million and $36.8 million, respectively, and are included in Accounts payable to affiliated companies in the Consolidated Balance Sheets. Vectren received regulatory approval on March 17, 2011, from the IURC for ProLiance to continue to provide natural gas supply services to the Company’s Indiana utilities and Citizens Energy Group's utilities through March 2016.  Amounts charged by ProLiance for gas supply services are established by supply agreements with each utility.

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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
Net periodic benefit costs [Abstract]
Portion of benefit costs capitalized as Utility plant	$ 3.7		$ 3.9		$ 4.3
Plan Assets [Roll Forward]
Plan assets at fair value, beginning of period [Roll Forward]	261.0
Fair value of plan assets, end of period	295.7		261.0
Fair Value of guaranteed annuity contract [Roll Forward]
Guaranteed Annuity Contract - estimate of undiscounted funds necessary to satisfy John Hancock's remaining obligation	3.6		3.4
Guaranteed Annuity Contract - percent of composite investment return, net of manger fees and other charges (in hundredths)	5.17%		5.26%
Fair value, beginning of year	3.8		3.7
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	3.9		3.8
Qualified Plans
Fair value of plan assets, end of period	295.7		261.0
Payments expected to be made to SERP participants in the next fiscal year	1.0
Reconciliation of amounts in Accumulated other comprehensive income and Regulatory assets
Less: Regulatory asset deferral	252.7		226.0
Multiemployer Benefit Plan [Abstract]
Number of unions the Company contributed to on behalf of employees	370
Average contributions to each union	.1
Largest union multiemployer plan contribution	3.6
Expense for the Multiemployer Benefit plan	27.6		18.3		10.0
Description of Multiemployer Plan	Multiple unions can contribute to a single multi-employer plan.  The Company made contributions to at least 36 plans in 2012, four of which are considered significant plans based on, among other things, the amount of the contributions, the number of employees participating in the plan, and the funded status of the plan. Further, of the 36 plans identified, there are four plans that are less than 65 percent funded (i.e. red zone status) and two plans where the Company's contributions represent more than 5 percent of the total contributions received by the plan; however, none of these plans are significant to the Company. The most recent Pension Protection Act Zone Status available in 2012 and 2011 is for the plan year end at December 31, 2011 and 2010, respectively. Generally, plans in the red zone are less than 65 percent funded, plans in the yellow zone are less than 80 percent funded and plans in the green zone are at least 80 percent funded.
Defined Contribution Plan [Abstract]
Contributions to Defined Contribution Plan	6.7		6.2		6.6
Central Pension Fund [Member]
Multiemployer Benefit Plan [Abstract]
Expense for the Multiemployer Benefit plan	4.0		2.3		1.1
Pipeline Industry Benefit Fund [Member]
Multiemployer Benefit Plan [Abstract]
Expense for the Multiemployer Benefit plan	3.9		1.0		0.7
Indiana Laborers Pension Fund [Member]
Multiemployer Benefit Plan [Abstract]
Expense for the Multiemployer Benefit plan	3.2	[1]	1.6	[1]	1.4	[1]
Minnesota Laborers Pension Fund [Member]
Multiemployer Benefit Plan [Abstract]
Expense for the Multiemployer Benefit plan	2.0		0.7		0
Other Pension Funds [Member]
Multiemployer Benefit Plan [Abstract]
Expense for the Multiemployer Benefit plan	14.5		12.7		6.8
Domestic equities and equity funds [Member]
Plan Assets [Roll Forward]
Fair value of plan assets, end of period	140.4		121.2
Qualified Plans
Fair value of plan assets, end of period	140.4		121.2
International equities and equity funds [Member]
Plan Assets [Roll Forward]
Fair value of plan assets, end of period	34.3		28.6
Qualified Plans
Fair value of plan assets, end of period	34.3		28.6
Domestic bonds and bond funds [Member]
Plan Assets [Roll Forward]
Fair value of plan assets, end of period	84.0		77.3
Qualified Plans
Fair value of plan assets, end of period	84.0		77.3
Inflation protected security fund [Member]
Plan Assets [Roll Forward]
Fair value of plan assets, end of period	12.6		11.8
Qualified Plans
Fair value of plan assets, end of period	12.6		11.8
Real estate, commodities and other [Member]
Plan Assets [Roll Forward]
Fair value of plan assets, end of period	24.4		22.1
Qualified Plans
Fair value of plan assets, end of period	24.4		22.1
Fair Value, Inputs, Level 1 [Member]
Plan Assets [Roll Forward]
Fair value of plan assets, end of period	146.8		129.0
Qualified Plans
Fair value of plan assets, end of period	146.8		129.0
Fair Value, Inputs, Level 1 [Member] | Domestic equities and equity funds [Member]
Plan Assets [Roll Forward]
Fair value of plan assets, end of period	62.8		54.7
Qualified Plans
Fair value of plan assets, end of period	62.8		54.7
Fair Value, Inputs, Level 1 [Member] | International equities and equity funds [Member]
Plan Assets [Roll Forward]
Fair value of plan assets, end of period	34.3		28.6
Qualified Plans
Fair value of plan assets, end of period	34.3		28.6
Fair Value, Inputs, Level 1 [Member] | Domestic bonds and bond funds [Member]
Plan Assets [Roll Forward]
Fair value of plan assets, end of period	41.7		38.2
Qualified Plans
Fair value of plan assets, end of period	41.7		38.2
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
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	8.0		7.5
Qualified Plans
Fair value of plan assets, end of period	8.0		7.5
Fair Value, Inputs, Level 2 [Member]
Plan Assets [Roll Forward]
Fair value of plan assets, end of period	145.0		128.2
Common Collective Trust Funds [Abstract]
Portion of Common Collective Trust Funds comprised of equity funds (in hundredths)	53.00%		52.00%
Portion of Common Collective Trust Funds comprised of fixed income funds (in hundredths)	38.00%		40.00%
Fair value of Common Collective Trust Funds	145.0		128.2
Maximum number of days restriction for exchange of shares in Common Collective Trust Funds (in days)	31
Qualified Plans
Fair value of plan assets, end of period	145.0		128.2
Fair Value, Inputs, Level 2 [Member] | Domestic equities and equity funds [Member]
Plan Assets [Roll Forward]
Fair value of plan assets, end of period	77.6		66.5
Qualified Plans
Fair value of plan assets, end of period	77.6		66.5
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
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	42.3		39.1
Qualified Plans
Fair value of plan assets, end of period	42.3		39.1
Fair Value, Inputs, Level 2 [Member] | Inflation protected security fund [Member]
Plan Assets [Roll Forward]
Fair value of plan assets, end of period	12.6		11.8
Qualified Plans
Fair value of plan assets, end of period	12.6		11.8
Fair Value, Inputs, Level 2 [Member] | Real estate, commodities and other [Member]
Plan Assets [Roll Forward]
Fair value of plan assets, end of period	12.5		10.8
Qualified Plans
Fair value of plan assets, end of period	12.5		10.8
Fair Value, Inputs, Level 3 [Member]
Plan Assets [Roll Forward]
Fair value of plan assets, end of period	3.9		3.8
Qualified Plans
Fair value of plan assets, end of period	3.9		3.8
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
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
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
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
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	3.9		3.8
Qualified Plans
Fair value of plan assets, end of period	3.9		3.8
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	7.7		6.9		6.3
Interest cost	15.5		15.9		15.9
Expected return on plan assets	(21.2)		(21.2)		(18.4)
Amortization of prior service cost (benefit)	1.6		1.7		1.6
Amortization of actuarial loss (gain)	6.8		3.8		3.2
Amortization of transitional obligation	0		0		0
Net periodic benefit cost	10.4		7.1		8.6
Discount Rate (in hundredths)	4.82%		5.50%		6.00%
Rate of compensation increase (in hundredths)	3.50%		3.50%		3.50%
Expected return on plan assets (in hundredths)	7.75%		8.00%		8.00%
Assumptions used to calculate benefit obligations [Abstract]
Discount rate (in hundredths)	4.03%		4.82%
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Rate of Compensation Increase	3.50%		3.50%
Benefit Obligation [Roll Forward]
Benefit obligation, beginning of period	329.2		297.3
Service cost - benefits earned during the period	7.7		6.9		6.3
Interest cost on projected benefit obligation	15.5		15.9		15.9
Plan participants' contributions	0		0
Plan amendments	0.7		0
Actuarial loss (gain)	39.0		23.1
Medicare subsidy receipts	0		0
Benefit payments	(14.8)		(14.0)
Benefit obligation, end of period	377.3		329.2		297.3
Accumulated benefit obligation for all defined benefit pension plans	354.5		310.9
Plan Assets [Roll Forward]
Plan assets at fair value, beginning of period [Roll Forward]	261.0		237.2
Actual return on plan assets	33.8		2.1
Employer contributions	15.7		35.7
Plan participants' contributions	0		0
Benefit payments	(14.8)		(14.0)
Fair value of plan assets, end of period	295.7		261.0		237.2
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%
Qualified Plans
Benefit obligation, end of period	(360.0)		(314.7)
Fair value of plan assets, end of period	295.7		261.0		237.2
Funded Status of Qualified Plans, end of period	(64.3)		(53.7)
Benefit obligation of SERP Plan, end of period	(17.3)		(14.5)
Total funded status, end of period	(81.6)		(68.2)
Accrued liabilities	1.0		0.7
Deferred credits and other liabilities	80.6		67.5
Contributions expected to be made to pension plan trusts in the next fiscal year	10
Estimated future benefit payments [Abstract]
Expected future benefit payments, year one	23.8
Expected future benefit payments, year two	24.1
Expected future benefit payments, year three	23.9
Expected future benefit payments, year four	25.8
Expected future benefit payments, year five	35.0
Expected future benefit payments, years six through ten	142.0
Prior service costs [Roll Forward]
Balance, beginning of year	5.4		7.1		7.9
Amounts arising during the period	0.7		0		0.8
Reclassification to benefit costs	(1.6)		(1.7)		(1.6)
Balance, end of year	4.5		5.4		7.1
Net gain or loss [Roll Forward]
Balance, beginning of year	116.6		78.2		68.5
Amounts arising during the period	26.4		42.2		12.9
Reclassification to benefit costs	(6.8)		(3.8)		(3.2)
Balance, end of year	136.2		116.6		78.2
Transition obligation [Roll Forward]
Balance, beginning of year	0
Balance, end of year	0		0
Reconciliation of amounts in Accumulated other comprehensive income and Regulatory assets
Prior service cost	4.5		5.4		7.1
Unamortized actuarial gain/(loss)	136.2		116.6		78.2
Transition obligation	0		0
Sub total	140.7		122.0
Less: Regulatory asset deferral	(137.9)		(115.9)
AOCI before taxes	2.8		6.1
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	1.4
Actuarial gain/loss expected to be amortized in next year	10.2
Other Postretirement Benefit Plans, Defined Benefit [Member]
Net periodic benefit costs [Abstract]
Service cost	0.5		0.5		0.5
Interest cost	2.8		4.3		4.6
Expected return on plan assets	0		0		(0.4)
Amortization of prior service cost (benefit)	(2.5)		(0.8)		(0.8)
Amortization of actuarial loss (gain)	0.7		0.6		0.5
Amortization of transitional obligation	0.5		1.1		1.2
Net periodic benefit cost	2.0		5.7		5.6
Discount Rate (in hundredths)	4.75%		5.50%		6.00%
Expected return on plan assets (in hundredths)			8.00%		8.00%
Expected increase in Consumer Price Index (in hundredths)	2.75%		3.00%		3.00%
Assumptions used to calculate benefit obligations [Abstract]
Discount rate (in hundredths)	3.91%		4.78%
Expected increase in Consumer Price Index (in hundredths)	2.75%		2.75%
Benefit Obligation [Roll Forward]
Benefit obligation, beginning of period	79.7		80.7
Service cost - benefits earned during the period	0.5		0.5		0.5
Interest cost on projected benefit obligation	2.8		4.3		4.6
Plan participants' contributions	1.6		1.9
Plan amendments	(26.6)		0
Actuarial loss (gain)	2.8		(0.5)
Medicare subsidy receipts	0.5		1.0
Benefit payments	(6.9)		(8.2)
Benefit obligation, end of period	54.4		79.7		80.7
Assumption of percentage increase in medical claims cost for next fiscal year (in hundredths)	7.50%
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	0.7
Decrease in recorded liability from remeasurement	23
Discount rate for remeasurement	3.93%
Plan Assets [Roll Forward]
Plan assets at fair value, beginning of period [Roll Forward]	0		3.1
Actual return on plan assets	0		0.1
Employer contributions	5.3		3.1
Plan participants' contributions	1.6		1.9
Benefit payments	(6.9)		(8.2)
Fair value of plan assets, end of period	0		0		3.1
Qualified Plans
Benefit obligation, end of period	(54.4)		(79.7)
Fair value of plan assets, end of period	0		0		3.1
Funded Status of Qualified Plans, end of period	(54.4)		(79.7)
Benefit obligation of SERP Plan, end of period	0		0
Total funded status, end of period	(54.4)		(79.7)
Accrued liabilities	4.5		5.1
Deferred credits and other liabilities	49.9		74.6
Other postretirement benefit payments to be made during the next fiscal year	3.5
Estimated future benefit payments [Abstract]
Expected future benefit payments, year one	4.5
Expected future benefit payments, year two	4.7
Expected future benefit payments, year three	4.8
Expected future benefit payments, year four	5.0
Expected future benefit payments, year five	5.3
Expected future benefit payments, years six through ten	30.8
Prior service costs [Roll Forward]
Balance, beginning of year	(1.2)		(2.0)		(2.8)
Amounts arising during the period	(24.4)		0		0
Reclassification to benefit costs	2.5		0.8		0.8
Balance, end of year	(23.1)		(1.2)		(2.0)
Net gain or loss [Roll Forward]
Balance, beginning of year	9.1		10.3		9.7
Amounts arising during the period	2.8		(0.6)		1.1
Reclassification to benefit costs	(0.7)		(0.6)		(0.5)
Balance, end of year	11.2		9.1		10.3
Transition obligation [Roll Forward]
Balance, beginning of year	2.7		3.8		5.0
Amounts arising during the period	(2.2)		0		0
Reclassification to benefit costs	(0.5)		(1.1)		(1.2)
Balance, end of year	0		2.7		3.8
Reconciliation of amounts in Accumulated other comprehensive income and Regulatory assets
Prior service cost	(23.1)		(1.2)		(2.0)
Unamortized actuarial gain/(loss)	11.2		9.1		10.3
Transition obligation	0		2.7		3.8
Sub total	(11.9)		10.6
Less: Regulatory asset deferral	11.7		(10.1)
AOCI before taxes	(0.2)		0.5
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	(3.2)
Actuarial gain/loss expected to be amortized in next year	$ 0.8

[1] Federal law requires pension plans in endangered status to adopt a funding improvement plan aimed at restoring the financial health of the plan. Since this plan became endangered as of June 1, 2008, a funding improvement plan was previously set in place to begin June 1, 2009. The funding improvement plan requires that the plan's funded percentage improve at least one-third of the way to 100 percent over a 10-year period. The target for this plan under the law is a funded percentage of 78 percent by 2019. The plan must also meet the federal minimum funding requirements during this 10-year period. Based on the plan's most current actuarial projections, the plan is on track to meet or exceed these benchmarks.

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Acquisition of Minnesota Limited, Inc.

12 Months Ended

Dec. 31, 2012

Business Combinations [Abstract]

Acquisition of Minnesota Limited, Inc.

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; 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

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 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 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 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 year ended December 31, 2011 and 2010 as if the acquisition had occurred on January 1, 2010.

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

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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Sale of Retail Gas Marketing Operations

12 Months Ended

Dec. 31, 2012

Discontinued Operations and Disposal Groups [Abstract]

Sale of Retail Gas Marketing Operations

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, excluding minor working capital adjustments.  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 the third party purchaser of Vectren Source.  This third party continues to sell natural gas directly to customers in VEDO’s service territory, and VEDO purchases receivables and natural gas from the third party.  Vectren Source was a component of the Energy Marketing operating segment.

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Nonutility Real Estate & Other Legacy Holdings

12 Months Ended

Dec. 31, 2012

Nonutility Real Estate Other Legacy Holdings [Abstract]

Nonutility Real Estate and Other Legacy Holdings

Nonutility Real Estate & Other Legacy Holdings

Within the nonutility group, there are legacy investments involved in energy-related infrastructure and services, real estate, a leveraged lease, and other ventures.  As of December 31, 2012 and 2011, total remaining legacy investments included in the Other Businesses portfolio total $28.7 million and $36.9 million, respectively.  Further separation of that 2012 investment by type of investment follows:

	December 31, 2012
			Value Included In
(In millions)	Carrying Value		Other Nonutility Investments		Investments in Unconsolidated Affiliates
Commercial real estate investments	$	8.0	$	8.0	$	—
Leveraged lease	13.8		13.8		—
Other investments	6.9		3.1		3.8
	$	28.7	$	24.9	$	3.8

Net of deferred taxes related to the leveraged lease, the net investment at December 31, 2012 was $17.9 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 and affordable housing projects. 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 (losses) of unconsolidated affiliates, and $3.0 million is reflected in Other operating expenses.

Leveraged Lease

At December 31, 2012, the Company has an investment in a leveraged lease.  The original cost for the leased facility was $27.5 million and was partially financed by non-recourse debt provided by lenders who were granted an assignment of rentals due and a security interest in the leased property, which they accepted as their sole remedy in the event of default by the lessee.  Such remaining debt was approximately $22.9 million at December 31, 2012.  The book value of this leverage lease is $3.0 million at December 31, 2012, net of related deferred taxes of $10.8 million.

Other Investments

Other investments totaled $6.9 million at December 31, 2012 and are comprised of investments in partnership-like structures involved in multifamily housing; a 40 percent ownership interest in Haddington Energy Partners LP and Haddington Energy Partners II, LP; and a receivable resulting from a jury verdict, and a minor asset from an exited generation project.  The investments involving multifamily housing are variable interest entities where the Company is a limited partner.  The Company's exposure to loss is limited to its investment, and the Company does not consolidate any of these entities.  Both the Haddington investment and the multifamily housing investments are accounted for using the equity method.  The carrying value of the Haddington investments is fully reserved at December 31, 2012.

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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, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Numerator:
Numerator for basic earnings per share									$ 159.0	$ 141.6	$ 133.6
Earnings attributable to participating securities									0	0	0.1
Reported net income (Numerator for diluted earnings per share)									$ 159.0	$ 141.6	$ 133.7
Denominator:
Weighted average common shares outstanding (Basic earnings per share) (in shares)									82,000,000	81,800,000	81,200,000
Conversion of share based compensation arrangements									100,000	0	100,000
Adjusted weighted average shares outstanding and assumed conversions outstanding (Diluted earnings per share) (in shares)									82,100,000	81,800,000	81,300,000
BASIC (in dollars per share)	$ 0.52	$ 0.48	$ 0.31	$ 0.63	$ 0.56	$ 0.43	$ 0.19	$ 0.55	$ 1.94	$ 1.73	$ 1.65
Diluted earnings per share (in dollars per share)	$ 0.52	$ 0.48	$ 0.31	$ 0.62	$ 0.56	$ 0.43	$ 0.18	$ 0.55	$ 1.94	$ 1.73	$ 1.64
Antidilutive securities excluded from computation of diluted earnings per share (in shares)									0	0	308,800
Stock options, exercise prices range , lower range limit (in dollars per share)											$ 24.90
Stock options, exercise prices range , upper range limit (in dollars per share)											$ 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, 2012	Dec. 31, 2011	Dec. 31, 2010
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Total cost of share-based compensation	$ 6.3	$ 5.8	$ 4.9
Less capitalized cost	1.2	0.8	1.7
Total in other operating expense	5.1	5.0	3.2
Less income tax benefit in earnings	2.1	2.0	1.3
After tax effect of share-based compensation	3.0	3.0	1.9
Deferred Compensation Plans [Abstract]
Liability associated with deferred compensation plans	22.9	21.1
Portion of liability classified in Accrued liabilities	1.3	0.7
Impact of deferred compensation plans on Other operating expenses	1.7	2.1	2.3
Amount recorded in earnings related to the investment activities in phantom stock associated with deferred compensation plans	0.6	1.7	1.6
Cash surrender value of life insurance policies	29.1	27.3
Earnings from investments in corporate-owned life insurance policies	1.8	0.1	1.9
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	third
Share Based Payment Award Equity Instruments Other Than Options [Roll Forward]
Restricted awards at beginning of period (in shares)	698,110
Granted (in shares)	250,211
Vested (in shares)	(149,374)
Forfeited (in shares)	(170,137)
Restricted awards at end of period (in shares)	628,810	698,110
Weighted average grant date fair value at end of period (in dollars per share)	$ 29.40
Total unrecognized compensation cost related to restricted stock awards	8.1
Weighted-average life of unrecognized compensation cost (in years)	1.9
Total fair value of liability awards vested	4.4	3.0	5.0
Restricted Stock [Member]
Share Based Payment Award Equity Instruments Other Than Options [Roll Forward]
Restricted awards at beginning of period (in shares)	54,013
Granted (in shares)	35,458
Vested (in shares)	(2,635)
Forfeited (in shares)	(16,343)
Restricted awards at end of period (in shares)	70,493	54,013
Weighted average grant date fair value at beginning of period (in dollars per share)	$ 25.22
Weighted average grant date fair value of shares granted during period (in dollars per share)	$ 29.82
Weighted average grant date fair value of shares vested during period (in dollars per share)	$ 24.76
Weighted average grant date fair value of shares forfeited during period (in dollars per share)	$ 25.12
Weighted average grant date fair value at end of period (in dollars per share)	$ 27.45	$ 25.22
Total fair value of equity awards vested	0.1	0.2	0.2
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)	407,633
Exercised (in shares)	(21,068)
Outstanding at end of period (in shares)	386,565	407,633
Exercisable at end of period (in shares)	386,565
Weighted average exercise price at beginning of period (in dollars per share)	$ 25.74
Weighted average exercise price of options exercised (in dollars per share)	$ 23.18
Weighted average exercise price at end of period (in dollars per share)	$ 25.88	$ 25.74
Weighted average exercise price of exercisable shares at end of period (in dollars per share)	$ 25.88
Remaining contractual term at end of period (in years)	1.6
Remaining contractual term of exercisable shares at end of period (in years)	1.6
Outstanding at end of period	1.4
Exercisable at end of period	1.4
Intrinsic value of options exercised	0.1	2.4	1.3
Tax benefit realized for tax deductions from option exercises	0.1	1.0	0.5
Cash received upon exercise of stock options	0.3	12.3	9.5
Stock repurchased during period	$ 0.1	$ 12.8	$ 1.2

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Common Shareholder's Equity (Details) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
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)	6.5	6.8
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	391.3

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2012

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 (losses) 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 segments 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.  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 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 postretirement 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 balance sheet 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, 2012 or 2011, 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) 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 recognized as products and services are delivered to customers.  Some nonutility revenues are recognized using the percentage of completion method.  The Company records revenues for services and goods delivered but not billed at the end of an 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 awards 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 share-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 $26.9 million in 2012, $29.3 million in 2011, and $33.8 million in 2010.  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 members 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, 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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Summary of Significant Accounting Policies (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Accounting Policies [Abstract]
Excise taxes and a portion of utility receipts taxes	$ 26.9	$ 29.3	$ 33.8
Number of operating segments in Utility group	3
Number of operating segments in Nonutility group	5

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Common Shareholder's Equity

12 Months Ended

Dec. 31, 2012

Stockholders' Equity Note [Abstract]

Common Shareholder's Equity

Common Shareholders’ Equity

Authorized, Reserved Common and Preferred Shares

At December 31, 2012 and 2011, the Company was authorized to issue 480 million shares of common stock and 20 million shares of preferred stock.  Of the authorized common shares, approximately 6.5 million shares at December 31, 2012 and 6.8 million shares at December 31, 2011, were reserved by the board of directors for issuance through the Company’s share-based compensation plans, benefit plans, and dividend reinvestment plan.  At both December 31, 2012 and 2011, there were 391.3 million 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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Rate & Regulatory Matters

12 Months Ended

Dec. 31, 2012

Rate and Regulatory Matters [Abstract]

Rate and Regulatory Matters

Rate & Regulatory Matters

Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement

Vectren monitors and maintains its natural gas distribution system to ensure that natural gas is delivered in a safe and efficient manner. Vectren's natural gas utilities are currently engaged in replacement programs in both Indiana and Ohio, the primary purpose of which is preventive maintenance and continual renewal and operational improvement.  In 2011, 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 capital investment projects, outside of a base rate proceeding.  Utilization of these recovery mechanisms is discussed below.

Ohio Recovery and Deferral Mechanisms

The PUCO order approving the Company's 2009 base rate case in the Ohio service territory authorized a distribution replacement rider (DRR). The DRR's primary purpose is recovery of investments in utility plant and related operating expenses associated with replacing bare steel and cast iron pipelines and certain other infrastructure. This rider is updated annually for qualifying capital expenditures and allows for a return to be earned on those capital expenditures based upon the rate of return approved in the 2009 base rate case. In addition, deferral of depreciation and the ability to accrue debt-related post in service carrying costs is also allowed until the related capital expenditures are recovered through the DRR. To date, the Company has made capital investments under this rider totaling $80 million. During 2012, 2011, and 2010 gas operating revenues associated with the DRR were $6.5 million, $3.6 million, and $1.4 million, respectively. Other Income associated with the debt-related post in service carrying costs totaled $1.8 million, $2.0 million, and $0.9 million for 2012, 2011, and 2010, respectively. Regulatory assets associated with post in service carrying costs and depreciation deferrals were $6.5 million, $3.0 million, and $1.0 million at December 31, 2012, 2011, and 2010, respectively.

In June 2011, Ohio House Bill 95 was signed into law. Outside of a base rate proceeding, this legislation permits a natural gas company to apply for recovery of much of its capital expenditure program. Once such application is approved, the legislation authorizes a deferral of costs, such as depreciation, property taxes, and debt-related carrying costs. On December 12, 2012, the PUCO issued an order approving the Company's initial application using this law. The order provides for the deferral of depreciation, debt-related post in service carrying costs, and property taxes for its $23.5 million capital expenditure program covering the fifteen month period ending December 31, 2012. Such capital expenditures include infrastructure expansion and improvements not covered by the DRR as well as expenditures necessary to comply with PUCO rules, regulations, orders, and system expansion to some new customers. The order also established a prospective bill impact evaluation on the cumulative deferrals, limiting the total deferrals at a level which would equal $1.50 per residential and general service customer per month. The order created a regulatory asset as of December 31, 2012 of $1.5 million, of which $0.9 million is Other Income related to the accrual of post in service carrying costs, and the remaining $0.6 million is the deferral of depreciation and property tax expense. The Company expects to make a future request for similar accounting authority on its capital expenditure program for the calendar year 2013.

Indiana Recovery and Deferral Mechanisms

The Company's Indiana natural gas utilities received orders in 2008 and 2007 associated with the most recent base rate cases. These orders authorized the deferral of financial impacts associated with bare steel and cast iron replacement activities. The orders provide for the deferral of depreciation and post in service carrying costs on qualifying projects totaling $20 million annually at Vectren North and $3 million annually at Vectren South. For USGAAP accounting purposes only the debt-related post in service carrying costs are recognized in the Consolidated Statements of Income currently. Such deferral is limited by individual qualifying project to three years after being placed into service at Vectren South and four years after being placed into service at Vectren North. The debt-related post in service rate used to calculate the deferral is based on a current cost of funds. At December 31, 2012 and 2011, the Company has USGAAP regulatory assets totaling $8.5 million and $4.7 million, respectively, associated with the deferral of depreciation and debt-related post in service carrying cost activities.

In April 2011, Senate Bill 251 was signed into Indiana law. The law 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 a return on the federally mandated capital investment, along with recovery of depreciation and other operating costs associated with these mandates. The remaining 20 percent of those costs are to be deferred for future recovery in the utility's next general rate case. To date, the Company has not initiated a filing requesting authority to recover costs using the Senate Bill 251 approach and continues to study its applicability to expenditures associated with its natural gas distribution operations.

Pipeline Safety Law

On January 3, 2012, the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 (Pipeline Safety Law) was signed into law. The Pipeline Safety 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 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 over the next two years Those regulations may eventually lead to further regulatory or statutory requirements.

The Company continues to study the impact of the Pipeline Safety 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 law is expected to result in further investment in pipeline inspections, and where necessary, additional investments in 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 by approximately $9 million annually, with $6 million attributable to the Indiana operations. Related to the Indiana operations, the Company expects to seek recovery under Senate Bill 251, or such costs may be recoverable through current tracking mechanisms. Capital investments, associated with the Pipeline Safety Law, are expected to be significant. 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 or other currently authorized recovery mechanisms, such as the Distribution Replacement Rider, in Ohio.

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 provided for a 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, provided for deferred accounting treatment related to the Company's estimated $32 million investment in dense pack technology, of which approximately $25.5 million has been invested as of December 31, 2012. In addition, the IURC 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 (RFP) in April 2011 regarding coal purchases for a four year period beginning in 2012. After negotiations with bidders, Vectren South 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 2011 RFP.  In March 2012, the IURC issued its order in the sub docket which concluded that Vectren South’s 2011 RFP process resulted in the lowest fuel cost reasonably possible.  In late 2012, Vectren South terminated its contract with one of the suppliers due to coal quality issues that were identified during test burns of the coal. In addition to coal purchased under these contracts, Vectren South has also contracted with Vectren Fuels, Inc. to purchase lower priced spot coal. This spot purchase was found to be reasonable in a recent FAC order. The IURC will continue to regularly monitor Vectren South’s procurement process in future fuel adjustment proceedings.

Delivery to Vectren's power plants of lower-priced contract coal from the April 2011 RFP process began during 2012. On December 5, 2011 within the quarterly FAC filing, Vectren South submitted a joint proposal with the OUCC to reduce its fuel costs billed to customers by accelerating into 2012 the impact of lower cost coal under these new term contracts effective after 2012. The cost difference will be deferred to a regulatory asset and recovered over a six-year period without interest beginning in 2014.  The IURC approved this proposal on January 25, 2012, with the reduction to customer’s rates effective February 1, 2012.  The deferred amount includes a reduction in the value of the coal inventory at December 31, 2011 of approximately $17.7 million to reflect existing coal inventory at the new, lower price.  Deferrals related to coal purchases in 2012 have totaled approximately $24.7 million, bringing the total deferred balance as of December 31, 2012, to the expected level of $42.4 million.

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 were 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 complied 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 $3 million in 2012 and $1 million in 2011 associated with small customer DSM programs for subsequent recovery under a tracking mechanism to be proposed by the Company.  On June 20, 2012, the IURC issued an order approving a small customer lost margin recovery mechanism, inclusive of all previous deferrals. This mechanism is an alternative to the electric decoupling proposal that was denied by the IURC in the Company's last base rate proceeding discussed earlier. 

Vectren North Pipeline Safety Investigation

On April 11, 2012, the IURC's pipeline safety division filed a complaint against Vectren North alleging several violations of safety regulations pertaining to damage that occurred at a residence in Vectren North's service territory during a pipeline replacement project. The Company negotiated a settlement with the IURC's pipeline safety division, agreeing to a fine and several modifications to the Company's operating policies. The amount of the fine was not material to the Company's financial results. The IURC approved the settlement but modified certain terms of the settlement and added a requirement that Company employees conduct inspections of pipeline excavations. The Company sought and was granted a request for rehearing on the sole issue related to the requirement to use Company employees to inspect excavations. The Company seeks further clarity on the scope of the requirement and the ability to also use contractors to perform certain inspections. A procedural schedule is expected to be established in late February 2013.

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 for residential base rates 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.

VEDO Continues the Process to Exit the Merchant Function

On April 30, 2008, the PUCO issued an order which approved the first two phases of a three phase plan to exit the merchant function in the Company's Ohio service territory. As a result, substantially all of the Company's Ohio customers now purchase natural gas directly from retail gas marketers rather than from the Company. The PUCO provided for an Exit Transition Cost rider, which allows the Company to recover costs associated with the first two phases of 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 as VEDO, for the most part, no longer purchases gas for resale.

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Quarterly Financial Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2012

Quarterly Financial Information Disclosure [Abstract]

Summarized quarterly financial data

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 2012 and 2011 follows:

(In millions, except per share amounts)		Q1		Q2		Q3		Q4
2012
	Operating revenues	$	604.6	$	470.6	$	513.5	$	644.1
	Operating income	109.9		70.2		81.6		90.8
	Net income	51.3		25.6		39.3		42.8
	Earnings per share:
	Basic	$	0.63	$	0.31	$	0.48	$	0.52
	Diluted	0.62		0.31		0.48		0.52
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

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2012

Income Tax Disclosure [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,
	2012		2011		2010
Statutory rate:	35.0	%	35.0	%	35.0	%
State & local taxes-net of federal benefit	4.0		4.2		3.8
Amortization of investment tax credit	(0.3	)	(0.3	)	(0.4	)
Depletion	(1.5	)	(1.9	)	(2.0	)
Energy efficiency building deductions	(3.0	)	(1.1	)	(0.5	)
Other tax credits	(0.1	)	(0.2	)	(0.2	)
Adjustment of income tax accruals and all other-net	0.1		2.2		0.1
Effective tax rate	34.2	%	37.9	%	35.8	%

Significant components of the net deferred tax liability (assets)

Significant components of the net deferred tax liability follow:

	At December 31,
(In millions)	2012			2011
Noncurrent deferred tax liabilities (assets):
Depreciation & cost recovery timing differences	$	681.6		$	625.5
Leveraged lease	10.8			13.8
Regulatory assets recoverable through future rates	23.5			25.1
Other comprehensive income	(4.0		)	(10.2		)
Alternative minimum tax carryforward	(44.1		)	(35.1		)
Employee benefit obligations	(2.1		)	(9.4		)
Net operating loss & other carryforwards	(11.7		)	(6.7		)
Regulatory liabilities to be settled through future rates	(18.3		)	(17.2		)
Impairments	(6.1		)	(11.4		)
Other – net	7.6			1.3
Net noncurrent deferred tax liability	637.2			575.7
Current deferred tax liabilities (assets):
Deferred fuel costs-net	25.7			6.0
Demand side management programs	2.7			0.7
Alternative minimum tax carryforward	(2.7		)	(15.6		)
Other – net	(10.8		)	(7.1		)
Net current deferred tax liability (asset)	14.9			(16.0		)
Net deferred tax liability	$	652.1		$	559.7

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)	2012			2011			2010
Current:
Federal	$	(8.2	)	$	4.4		$	(0.8	)
State	6.4			10.3			6.2
Total current taxes	(1.8		)	14.7			5.4
Deferred:
Federal	80.3			66.0			65.6
State	4.6			6.4			4.5
Total deferred taxes	84.9			72.4			70.1
Amortization of investment tax credits	(0.6		)	(0.7		)	(0.8		)
Total income tax expense	$	82.5		$	86.4		$	74.7

Roll forward of unrecognized tax benefits

Following is a roll forward of unrecognized tax benefits for the three years ended December 31, 2012:

(In millions)	2012			2011			2010
Unrecognized tax benefits at January 1	$	12.4		$	13.3		$	11.5
Gross increases - tax positions in prior periods	0.2			3.3			1.6
Gross decreases - tax positions in prior periods	(9.4		)	(4.5		)	(0.3		)
Gross increases - current period tax positions	1.9			0.6			1.0
Settlements	(0.3		)	(0.3		)	—
Lapse of statute of limitations	—			—			(0.5		)
Unrecognized tax benefits at December 31	$	4.8		$	12.4		$	13.3

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CONSOLIDATED CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Net Income	$ 159.0	$ 141.6	$ 133.7
Other comprehensive income	9.0	(8.9)	2.4
Total comprehensive income	168.0	132.7	136.1
AOCI of Unconsolidated Affiliates [Member]
Net amount arising during the year before tax	11.3	(9.3)	0.5
Income taxes	(4.6)	3.8	(0.2)
Other comprehensive income	6.7	(5.5)	0.3
Pensions and Other Benefits [Member]
Amounts arising during the year before tax	(3.3)	(41.6)	(14.8)
Reclassifications to periodic cost before tax	7.1	6.4	5.7
Deferrals to regulatory assets	0.2	33.5	8.6
Income taxes	(1.6)	0.7	0.2
Other comprehensive income	2.4	(1.0)	(0.3)
Cash Flow Hedges [Member]
Unrealized gains & losses before tax	0	(3.6)	4.0
Reclassifications to net income before tax	(0.1)	(0.3)	(0.1)
Income taxes	0	1.5	(1.5)
Other comprehensive income	$ (0.1)	$ (2.4)	$ 2.4

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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2012

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

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 of 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 (losses) 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 segments 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.  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 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 postretirement 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 balance sheet 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, 2012 or 2011, 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) 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 recognized as products and services are delivered to customers.  Some nonutility revenues are recognized using the percentage of completion method.  The Company records revenues for services and goods delivered but not billed at the end of an accounting period in Accrued unbilled revenues. The goods and services delivered by the Company subject to unbilled revenue accruals include gas, electricity, and infrastructure services.

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 awards 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 share-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 $26.9 million in 2012, $29.3 million in 2011, and $33.8 million in 2010.  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 members of executive management led by the Chief Executive Officer.  The Company uses net income calculated in accordance with generally accepted accounting principles as its most relevant performance measure.  The Company has three operating segments within its Utility Group, five operating segments in its Nonutility Group, and a Corporate and Other segment.

Fair Value Measurements

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

Level 1	Inputs to the valuation methodology are unadjusted quoted prices for identical assets or liabilities in active markets that the 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

Intangible Assets (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Schedule of intangible assets, excluding goodwill [Line Items]
Amortizing	$ 21.6	$ 24.2
Non-amortizing	7.0	7.0
Weighted average remaining life for amortizing customer-related assets and all amortizing intangibles (in years)	13
Amortization expense	2.6	2.3	0.6
Amortization expense - year one	2.3
Amortization expense - year two	2.3
Amortization expense - year three	2.2
Amortization expense - year four	1.6
Amortization expense - year five	1.4
Customer Related Assets [Member]
Schedule of intangible assets, excluding goodwill [Line Items]
Amortizing	18.9	20.6
Non-amortizing	0	0
Accumulated amortization	6.6	5.1
Market Related Assets [Member]
Schedule of intangible assets, excluding goodwill [Line Items]
Amortizing	2.7	3.6
Non-amortizing	7.0	7.0
Accumulated amortization	$ 1.7	$ 0.9

XML

Environmental Matters (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
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
Property, Plant and Equipment, amount of investment in pollution control equipment included in rate base	411
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%
Clean Water Act [Abstract]
Estimated capital expenditures related to Clean Water Act	40
Coal Ash Waste Disposal and Ash Ponds [Abstract]
Estimated capital expenditures to comply with ash pond and coal ash disposal regulations	30
Potential estimated capital expenditures to comply with ash pond and coal ash disposal regulations with stringent alternative	100
Estimated annual compliance costs maximum with ash pond and coal ash disposal regulation	5
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
Indiana Senate Bill 251 [Abstract]
Description of legislation	Senate Bill 251 also established a voluntary clean energy portfolio standard that provides incentives to electricity suppliers participating in the program.
Description of the goal of legislation	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 Indiana retail customers will be provided by clean energy sources, as defined.
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%
Manufactured Gas Plants
Site contingency, accrual, undiscounted amount	41.7
Remediation cost accrued and not yet spent a the end of the period	4.6	6.5
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	23.2
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	14.0
Expected Site Contingency Recovery from Insurance Carriers of Environmental Remediation Costs	$ 15

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Environmental Matters

12 Months Ended

Dec. 31, 2012

Environmental Matters Disclosure [Abstract]

Environmental Matters

Environmental Matters

Indiana Senate Bill 251 is also applicable to federal environmental mandates impacting Vectren South's electric operations. The Company is currently evaluating the impact Senate Bill 251 may have on its operations, including applicability to the stricter regulations the EPA is currently considering involving air quality, fly ash disposal, cooling tower intake facilities, waste water discharges, and greenhouse gases. These issues are further discussed below.

Air Quality

Clean Air Interstate Rule / Cross-State Air Pollution Rule

In July 2011, the EPA finalized the Cross-State Air Pollution Rule (CSAPR).  CSAPR was 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 SO₂ and NOx allowances, CSAPR reduced the ability of facilities to meet emission reduction targets through allowance trading.  Like CAIR, CSAPR set individual state caps for SO₂ and NOx emissions.  However, unlike CAIR in which states allocated allowances to generating units through state implementation plans, CSAPR allowances were allocated to individual units directly through the federal rule.  CSAPR reductions were to be achieved with initial step reductions beginning January 1, 2012, and final compliance to be achieved in 2014.  Multiple administrative and judicial challenges were filed. On December 30, 2011, the Court granted a stay of CSAPR and left CAIR in place pending its review. On August 21, 2012, the Court vacated CSAPR and directed the EPA to continue to administer CAIR. In October 2012, the EPA filed its request for a hearing before the full federal appeals court that struck down the CSAPR.  EPA's request for rehearing was denied by the Court on January 24, 2013. The Company remains in full compliance with CAIR (see additional information below "Conclusions Regarding Air Regulations").

Mercury and Air Toxics (MATS) Rule

On December 21, 2011, the EPA finalized the Utility MATS Rule.  The MATS 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 MATS 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 (April 2015).  Initiatives to suspend CSAPR’s implementation by the Congress also apply to the implementation of the MATS rule.  Multiple judicial challenges were filed and briefing is proceeding. The EPA also recently announced it will reconsider MATS requirements for new construction. Such requirements are more stringent than those for existing plants. Utilities planning new coal-fired generation had argued standards outlined in the MATS could not be attained even using the best available control technology.

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 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 the MATS Rule and the 2015 requirement imposed by CAIR.  Based upon an initial review, the Company believes that it will be able to meet these requirements with its existing suite of pollution control equipment.  However, it is possible some operational modifications to the control equipment will be required. Additional capital investments, operating expenses, and possibly the purchase of emission allowances may be required and could be significant depending on the required method of compliance with the requirements.  While the Company has not yet quantified what the additional costs may be associated with these efforts, because the compliance is required by government regulation the Company believes that such additional costs, if incurred, should be recoverable under Indiana Senate Bill 251 referenced above.

Notice of Violation Received

The Company received a notice of violation (NOV) from the EPA in November 2011 pertaining to its A.B. Brown power plant.  The NOV asserts that when the power plant was equipped with SCRs the correct permits were not obtained or the best available control technology to control incidental sulfuric acid mist was not installed.  Based on the Company’s understanding of the New Source Review reform in effect when the equipment was installed, it is the Company’s position that its SCR project was exempted from such requirements.  At this time the Company is reviewing the potential impact this NOV could have on capital expenditures and operating costs.  To the extent costs to comply increase, they should be recoverable under Indiana law.

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 2013.  Depending on the final rule and on the Company’s facts and circumstances, capital investments could approximate $40 million if new infrastructure, such as new cooling water towers, is required.  Costs for compliance with these final regulations should qualify as federally mandated regulatory requirements and be recovered under Indiana Senate Bill 251 referenced above.

Under the Clean Water Act, EPA sets technology-based guidelines for water discharges from new and existing facilities. EPA is currently in the process of revising the existing steam electric effluent limitation guidelines that set the technology-based water discharge limits for the electric power industry. EPA is focusing its rulemaking on wastewater generated primarily by pollution control equipment necessitated by the comprehensive air regulations. EPA is under an April 19, 2013 deadline to complete its rule proposal. It is not possible to estimate what potential costs may be required to meet these new water discharge limits, however costs for compliance with these regulations should qualify as federally mandated regulatory requirements and be recovered under 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 have not been finalized 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 modification to, 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 should qualify as federally mandated regulatory requirements and be recovered 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.  EPA's PSD and Title V permitting rules for GHG's were recently upheld by the US Court of Appeals for the District of Columbia. In 2012, the EPA proposed New Source Performance Standards for greenhouse gases for new electric generating facilities under Clean Air Act Section 111(b). While standards for new sources are not yet final, EPA has signaled its intent to propose New Source Performance Standards for greenhouse gases for existing electric generating units under Section 111(d), which would be applicable to the Company's existing units. The Company anticipates that these initial standards will focus on power plant efficiency and other coal fleet carbon intensity reduction measures. The Company believes that such additional costs, if necessary, should be recoverable under Indiana Senate Bill 251 referenced above.

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 should be recoverable from customers through Senate Bill 251. 

Senate Bill 251 also established 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 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 which are defined as clean energy in the legislation, the Company currently has approximately 5 percent of its electricity being provided by clean energy sources due to the long-term wind contracts and landfill gas investment. The Company continues to evaluate whether to participate in this voluntary program.

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.

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 plant 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 has incurred or reasonably expects to incur totaling approximately $41.7 million ($23.2 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.  Likewise, SIGECO has settlement agreements with all known insurance carriers and has received to date approximately $14 million of the expected $15 million in 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 remedial activities which are not presently foreseen and those costs may not be subject to PRP or insurance recovery.  As of December 31, 2012 and 2011, approximately $4.6 million and $6.5 million, respectively, of accrued, but not yet spent, costs are included in Other Liabilities related to both the Indiana Gas and SIGECO sites.

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SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Accumulated Provision for Uncollectible Accounts [Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
Balance, at beginning of year	$ 6.7	$ 5.3	$ 5.2
Additions charged to expenses	8.2	11.8	16.8
Additions charged to other accounts	0	0	0
Deductions from Reserves, Net	8.1	10.4	16.7
Balance, at end of period	6.8	6.7	5.3
Reserve for Impaired Notes Receivable [Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
Balance, at beginning of year	15.7	6.1	9.2
Additions charged to expenses	0.5	9.6	1.2
Additions charged to other accounts	0	0	0
Deductions from Reserves, Net	15.6	0	4.3
Balance, at end of period	0.6	15.7	6.1
Restructuring Costs [Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
Balance, at beginning of year	0.4	0.4	0.5
Additions charged to expenses	0	0	0
Additions charged to other accounts	0	0	0
Deductions from Reserves, Net	0.1	0	0.1
Balance, at end of period	$ 0.3	$ 0.4	$ 0.4

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Investment in ProLiance Holdings, LLC (Tables)

12 Months Ended

Dec. 31, 2012

ProLiance Holdings, LLC [Abstract]

Summarized Financial Information

Summarized Financial Information

	Year Ended December 31,
(In millions)	2012			2011			2010
Summarized Statement of Income information:
Revenues	$	1,001.3		$	1,410.5		$	1,497.0
Operating loss	(34.8		)	(44.5		)	(3.1		)
ProLiance's losses	(38.3		)	(47.3		)	(3.7		)

	As of December 31,
(In millions)	2012			2011
Summarized balance sheet information:
Current assets	$	279.7		$	381.9
Noncurrent assets	55.6			56.1
Current liabilities	215.1			298.5
Noncurrent liabilities	0.3			0.7
Members' equity	124.3			161.5
Accumulated other comprehensive loss	(7.5		)	(26.0		)
Noncontrolling interest	3.1			3.3

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Borrowing Arrangements

12 Months Ended

Dec. 31, 2012

Debt Disclosure [Abstract]

Borrowing Arrangements

Borrowing Arrangements

Long-Term Debt

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

	At December 31,
(In millions)	2012		2011
Utility Holdings
Fixed Rate Senior Unsecured Notes
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		55.0
2026, 5.02%	60.0		60.0
2035, 6.10%	75.0		75.0
2039, 6.25%	121.6		121.6
2041, 5.99%	35.0		35.0
2042, 5.00%	100.0		—
Total Utility Holdings	821.6		721.6
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 0.15%, tax exempt,
2012 weighted average: 0.17%	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 0.15%, tax exempt,
2012 weighted average: 0.16%	31.5		31.5
2029, 1999 Series, 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

	At December 31,
(In millions)	2012			2011
Vectren Capital Corp.
Fixed Rate Senior Unsecured Notes
2012, 5.13%	—			25.0
2012, 7.43%	—			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
Variable Rate Term Loan
2015, current adjustable rate 1.22%	100.0			—
Total Vectren Capital Corp.	450.0			410.0
Other Long-Term Notes Payable	1.4			4.1
Total long-term debt outstanding	1,661.5			1,524.2
Current maturities of long-term debt	(106.4		)	(62.7		)
Short-term borrowings refinanced in 2012	—			100.0
Unamortized debt premium & discount - net	(1.7		)	(1.9		)
Total long-term debt-net	$	1,553.4		$	1,559.6

Vectren Capital 2012 Term Loan

On November 1, 2012, Vectren Capital entered into a $100 millionthree year term loan agreement. Loans under the term loan agreement bear interest at either a Eurodollar rate or base rate plus a fixed adder, as defined in the loan agreement. Interest periods are variable and may range from seven days to six months. The proceeds from this debt transaction were used to repay short-term borrowings outstanding under Vectren Capital's credit facility. The loan agreement is guaranteed by Vectren Corporation and includes customary representations, warranties and covenants, including a leverage covenant consistent with leverage covenants contained in other Vectren Capital borrowing arrangements. 

Utility Holdings 2012 Debt Transactions

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.

On December 20, 2012, Utility Holdings entered into a private placement note purchase agreement pursuant to which institutional investors have agreed to purchase the following tranches of notes:  (i) $45 million3.20 percent Senior Guaranteed Notes, due June 5, 2028 and (ii) $80 million4.25 percent Senior Guaranteed Notes, due June 5, 2043.  The notes will be unconditionally guaranteed by Indiana Gas Company, Inc., Southern Indiana Gas and Electric Company and Vectren Energy Delivery of Ohio, Inc. Subject to the satisfaction of customary conditions precedent, this financing is scheduled to close on or about June 5, 2013. The proceeds received from the issuance of these notes will be used to refinance existing indebtedness that matures or is callable in 2013 and for general corporate purposes.

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 $149 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 million3.48 percent Senior Notes, Series A due December 15, 2017, and (ii) $50 million4.53 percent Senior Notes, Series B due December 15, 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 million.  These notes contain customary representations, warranties and covenants, including a leverage covenant consistent with leverage covenants contained in other Vectren Capital borrowing arrangements.

Long-Term Debt Puts & Calls

Certain long-term debt issues contain put and call provisions that can be exercised on various dates before maturity.  As an example, certain instruments can be put to the Company upon the death of the holder (death puts) or at specific dates.  During 2012, the Company repaid an insignificant amount related to death puts. During 2011 and 2010, the Company repaid approximately $0.8 million and $1.8 million, respectively, related to death puts. On February 4, 2013, the Company notified holders of Utility Holdings $121.6 million6.25 percent senior unsecured notes due 2039, which contained both a put and call provision, of its intent to call the debt at par on April 1, 2013. These notes are the only issue outstanding at December 31, 2012 with a put provision.

On October 21, 2011, the Company notified holders of Utility Holdings $96.2 million5.95 percent senior notes due 2036, of its intent to call those notes.  This call option was exercised at par on November 21, 2011.

Letters of Credit Supporting Long-Term Debt

As of December 31, 2012, 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, 2012.

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 2012 sinking fund requirement by this means and, accordingly, the sinking fund requirement for 2012 is excluded from Current liabilities in the Consolidated Balance Sheets.  At December 31, 2012, $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 $2.8 billion at December 31, 2012.

Consolidated maturities of long-term debt during the five years following 2012 (in millions) are $106.4 in 2013, $30.0 in 2014, $279.8 in 2015, $73.0 in 2016, $75.0 in 2017, and $1,095.6 thereafter.

Debt Guarantees

Vectren Corporation guarantees Vectren Capital’s long-term and short-term debt, which totaled $450 million and $162 million, respectively, at December 31, 2012.  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, 2012, totaled $821 million and $117 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, 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, 2012, the Company was in compliance with all debt covenants.

Short-Term Borrowings

At December 31, 2012, 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 $233 million was available for the Utility Group operations and approximately $88 million was available for the wholly owned Nonutility Group and corporate operations.  Both Vectren Capital’s and Utility Holdings’ short-term credit facilities were renewed in November 2011 and are available through September 2016.  The maximum limit of both facilities remained unchanged.  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.  

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

	Utility Group Borrowings									Nonutility Group Borrowings
(In millions)	2012			2011			2010			2012			2011			2010
Year End
Balance Outstanding	$	116.7		$	242.8		$	47.0		$	162.1		$	84.3		$	71.3
Weighted Average Interest Rate	0.40		%	0.57		%	0.41		%	1.35		%	1.45		%	2.01		%
Annual Average
Balance Outstanding	$	77.6		$	39.6		$	14.0		$	151.5		$	124.9		$	143.2
Weighted Average Interest Rate	0.47		%	0.48		%	0.40		%	1.44		%	1.92		%	0.93		%
Maximum Month End Balance Outstanding	$	214.2		$	242.8		$	47.0		$	216.1		$	180.1		$	174.6

Throughout 2012, 2011, and 2010, the Company has placed commercial paper without any significant issues and did not borrow from Utility Holdings' backup credit facility in any of the periods presented.