Vectren Corp 10K


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, 2006
OR

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

For the transition period from __________________ to ________________________

Commission file number: 1-15467

VECTREN CORPORATION

(Exact name of registrant as specified in its charter)


Vectren Logo

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

Registrant's telephone number, including area code: 812-491-4000
Securities registered pursuant to Section 12(b) of the Act:


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


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

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


Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d0 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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.

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

Large accelerated filer ý             Accelerated filer          Non-accelerated filer

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, 2006, was $2,056,925,411.
 
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
76,252,552
January 31, 2007
Class
Number of Shares
Date

Documents Incorporated by Reference

Certain information in the Company's definitive Proxy Statement for the 2007 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission pursuant to Regulation 14A, not later than 120 days after the end of the fiscal year, is incorporated by reference in Part III of this Form 10-K.

Definitions

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

 
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Table of Contents

      Item
 
Page
      Number
 
Number
Part I
           
 
1
 
Business
 
4
 
1A
 
Risk Factors
 
10
 
1B
 
Unresolved Staff Comments
 
14
 
2
 
Properties
 
14
 
3
 
Legal Proceedings
 
16
 
4
 
Submission of Matters to Vote of Security Holders
 
16
           
Part II
           
 
5
 
Market for the Company’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities
 
16
 
6
 
Selected Financial Data
 
17
 
7
 
Management's Discussion and Analysis of Results of Operations and Financial Condition
 
18
 
7A
 
Qualitative and Quantitative Disclosures About Market Risk
 
43
 
8
 
Financial Statements and Supplementary Data
 
45
 
9
 
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
 
88
 
9A
 
Controls and Procedures, including Management’s Assessment of Internal Controls over Financial ReportingControls and Procedures
 
88
 
9B
 
Other Information
 
88
     
 
   
Part III
           
 
10
 
Directors, Executive Officers and Corporate Governance
 
88
 
11
 
Executive Compensation
 
89
 
12
 
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
 
89
 
13
 
Certain Relationships, Related Transactions and Director Independence
 
89
 
14
 
Principal Accountant Fees and Services
 
90
     
 
   
Part IV
           
 
15
 
Exhibits and Financial Statement Schedules
 
90
     
Signatures
 
95
           

Access to Information

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

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


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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 operating public utilities: Indiana Gas Company, Inc. (Indiana Gas), Southern Indiana Gas and Electric Company (SIGECO), and the Ohio operations. Utility Holdings also has other assets that provide information technology and other services to the three utilities. Utility Holdings’ consolidated operations are collectively referred to as the Utility Group. Both Vectren and Utility Holdings were exempt from registration pursuant to Section 3(a) (1) and 3(c) of the Public Utility Holding Company Act of 1935, which was repealed effective February 8, 2006 by the Energy Policy Act of 2005 (Energy Act). Both Vectren and Utility Holdings are holding companies as defined by the Energy Act.  Vectren was incorporated under the laws of Indiana on June 10, 1999.

Indiana Gas provides energy delivery services to approximately 565,000 natural gas customers located in central and southern Indiana. SIGECO provides energy delivery services to approximately 141,000 electric customers and approximately 112,000 gas customers located near Evansville in southwestern Indiana. SIGECO also owns and operates electric generation to serve its electric customers and optimizes those assets in the wholesale power market. Indiana Gas and SIGECO generally do business as Vectren Energy Delivery of Indiana. The Ohio operations provide energy delivery services to approximately 318,000 natural gas customers located near Dayton in west central Ohio. The Ohio operations are owned as a tenancy in common by Vectren Energy Delivery of Ohio, Inc. (VEDO), a wholly owned subsidiary of Utility Holdings (53% ownership), and Indiana Gas (47% ownership). The Ohio operations generally do business as Vectren Energy Delivery of Ohio.

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

Narrative Description of the Business

The Company segregates its operations into three groups: a Utility Group, a Nonutility Group, and Corporate and Other. At December 31, 2006, the Company had $4.1 billion in total assets, with $3.4 billion (84%) attributed to the Utility Group, $0.6 billion (16%) attributed to the Nonutility Group, and less than $0.1 billion attributed to Corporate and Other. Net income for the year ended December 31, 2006, was $108.8 million, or $1.44 per share of common stock, with $91.4 million attributed to the Utility Group, $18.1 million attributed to the Nonutility Group, and a net loss of $0.7 million attributed to Corporate and Other. Net income for the year ended December 31, 2005, was $136.8 million, or $1.81 per share of common stock. For further information regarding the activities and assets of operating segments within these Groups, refer to Note 16 in the Company’s consolidated financial statements included under “Item 8 Financial Statements and Supplementary Data.”

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

Utility Group

The Utility Group is comprised of Utility Holdings’ operations. The operations of the Utility Group consist of the Company’s regulated operations and other operations that provide information technology and other support services to those regulated operations. The Company segregates its regulated operations into a Gas Utility Services operating segment and an Electric Utility Services operating segment. The Gas Utility Services segment includes the operations of Indiana Gas, the Ohio operations, and SIGECO’s natural gas distribution business and provides natural gas distribution and transportation services to nearly two-thirds of Indiana and to west central Ohio. The Electric Utility Services segment includes the operations of SIGECO’s electric transmission and distribution services, which provides electric distribution services primarily to southwestern Indiana, and includes the Company’s power generating and asset optimization operations. In total, these regulated operations supply natural gas and/or electricity to over one million customers. The Utility Group’s other operations are not significant.
 

 
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Gas Utility Services

At December 31, 2006, the Company supplied natural gas service to approximately 995,000 Indiana and Ohio customers, including 909,000 residential, 84,000 commercial, and 2,000 industrial and other contract customers. This represents customer base growth of 0.3% compared to 2005.

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

Revenues

For the year ended December 31, 2006, gas utility revenues were approximately $1,232.5 million, of which residential customers accounted for 66%, commercial 28%, and industrial and other contract customers 6%.

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 volumes of gas provided to both sales and transportation customers (throughput) were 182.6 MMDth for the year ended December 31, 2006. Gas transported or sold to residential and commercial customers was 97.7 MMDth representing 53% of throughput. Gas transported or sold to industrial and other contract customers was 84.9 MMDth representing 47% of throughput. Rates for transporting gas generally provide for the same margins earned by selling gas under applicable sales tariffs.

The sale of gas is seasonal and strongly affected by variations in weather conditions. To mitigate seasonal demand, the Company has storage capacity at seven active underground gas storage fields and six liquefied petroleum air-gas manufacturing plants. The Company also contracts with its affiliate, ProLiance Energy, LLC (ProLiance), and with other third party gas service providers to ensure availability of gas. ProLiance is an unconsolidated, nonutility, energy marketing affiliate of Vectren and Citizens Gas and Coke Utility (Citizens Gas). (See the discussion of Energy Marketing & Services below and Note 3 in the Company’s consolidated financial statements included in “Item 8 Financial Statements and Supplementary Data” regarding transactions with ProLiance). 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. In lieu of storage, the Company prepays ProLiance for natural gas delivery services during the seven months prior to the peak heating season. The volumes of gas per day that can be delivered during peak demand periods for each utility are located in “Item 2 Properties.”

Gas Purchases

In 2006, the Company purchased 95,561 MDth volumes of gas at an average cost of $8.64 per Dth, of which approximately 72% was purchased from ProLiance and 28% was purchased from other third party providers. Vectren received regulatory approval on April 25, 2006 from the IURC for ProLiance to provide natural gas supply services to the Company’s Indiana utilities through March 2011. As a result of the June 2005 PUCO order, the Company has established an annual bidding process for VEDO’s gas supply and portfolio administration services. Since November 1, 2005, the Company has used a third party provider for these services. Prior to October 31, 2005, ProLiance supplied natural gas to all of the Company’s regulated gas utilities. The average cost of gas per Dth purchased for the previous five years was $8.64 in 2006; $9.05 in 2005; $6.92 in 2004; $6.36 in 2003; and $4.57 in 2002.
 

 
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Electric Utility Services

At December 31, 2006, the Company supplied electric service to approximately 141,000 Indiana customers, including 122,000 residential, 18,800 commercial, and 200 industrial and other customers. This represents customer base growth of 1% compared to 2005. In addition, the Company has firm power commitments to four municipalities and has contingency reserve requirements consistent with Reliability First Corp. standards.

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

Revenues

For the year ended December 31, 2006, retail and firm wholesale electricity sales totaled 6,004.5 GWh, resulting in revenues of approximately $392.5 million. Residential customers accounted for 25% of 2006 revenues; commercial 22%; industrial 43%; and municipal and other 10%. In addition, the Company sold 898.3 GWh through optimization activities in 2006, generating revenue, net of purchased power costs, of $29.7 million.

Generating Capacity

Installed generating capacity as of December 31, 2006, was rated at 1301 MW. Coal-fired generating units provide 1,006 MW of capacity, and natural gas or oil-fired turbines used for peaking or emergency conditions provide 295 MW.

In addition to its generating capacity, in 2006, the Company had 34 MW available under firm contracts and 62 MW available under interruptible contracts. The Company also had a firm purchase supply contract for a maximum of 73 MW for the cooling season months during 2006. This contract ended at the end of September 2006. Also, under the terms of the consent decree between SIGECO, the Department of Justice and USEPA, the Company discontinued operations of Culley Unit 1 (50 MW) effective December 31, 2006. The Company executed a capacity contract for a maximum of 100 MW for the years 2007-2009.

The Company has interconnections with Louisville Gas and Electric Company, Cinergy Services, Inc., Indianapolis Power & Light Company, Hoosier Energy Rural Electric Cooperative, Inc., Big Rivers Electric Corporation, and the City of Jasper, Indiana, providing the historic ability to simultaneously interchange approximately 500 MW. However, the ability of the Company to effectively utilize the electric transmission grid in order to achieve its desired import/export capability has been, and may continue to be, impacted as a result of the ongoing changes in the operation of the midwestern transmission grid. The Company, as a member of the Midwest Independent System Operator (MISO), has turned over operational control of the interchange facilities and its own transmission assets, like many other Midwestern electric utilities, to MISO. See “Item 7 Management’s Discussion and Analysis of Results of Operations and Financial Condition” regarding the Company’s participation in MISO.

Total load for each of the years 2002 through 2006 at the time of the system summer peak, and the related reserve margin, is presented below in MW.

                     
Date of summer peak load
 
8/10/2006
 
7/25/2005
 
7/13/2004
 
8/27/2003
 
8/5/2002
Total load at peak (1)
 
1,325
 
1,315
 
1,222
 
1,272
 
1,258
                     
Generating capability
 
1,351
 
1,351
 
1,351
 
1,351
 
1,351
Firm purchase supply
 
107
 
107
 
105
 
32
 
82
Interruptible contracts
 
62
 
76
 
51
 
95
 
95
Total power supply capacity
 
1,520
 
1,534
 
1,507
 
1,478
 
1,528
                     
Reserve margin at peak
 
15%
 
17%
 
23%
 
16%
 
21%
 
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(1)  
The total load at peak is increased 25 MW in 2006, 2005, 2003, and 2002 from the total load actually experienced. The additional 25 MW represents load that would have been incurred if Summer Cycler program had not been activated. The 25 MW is also included in the interruptible contract portion of the Company’s total power supply capacity in those years. On the date of peak in 2004, Summer Cycler program was not activated.
 
The winter peak load for the 2005-2006 season of approximately 935 MW occurred on December 20, 2005. The prior year winter peak load was approximately 932 MW, occurring on January 18, 2005.

The Company maintains a 1.5% interest in the Ohio Valley Electric Corporation (OVEC). The OVEC is comprised of several electric utility companies, including SIGECO, and supplies power requirements to the United States Department of Energy’s (DOE) uranium enrichment plant near Portsmouth, Ohio. The participating companies are entitled to 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. Because of this decreased demand, the Company’s 1.5% interest in the OVEC makes available approximately 34 MW of capacity for use in other operations. Such generating capacity is included in firm purchase supply in the chart above.

Fuel Costs and Purchased Power

Electric generation for 2006 was fueled by coal (98%) and natural gas (2%). Oil was used only for testing of gas/oil-fired peaking units.

There are substantial coal reserves in the southern Indiana area, and coal for coal-fired generating stations has been supplied from operators of nearby Indiana coal mines, including those owned by Vectren Fuels, Inc., a wholly owned subsidiary of the Company. Approximately 3.5 million tons of coal were purchased for generating electricity during 2006, of which approximately 91% was supplied by Vectren Fuels, Inc. from its mines and third party purchases. The average cost of coal consumed in generating electric energy for the years 2002 through 2006 follows:

                     
   
Year Ended December 31,
Avg. Cost Per
 
2006
 
2005
 
2004
 
2003
 
2002
Ton
 
$ 37.51
 
$ 30.27
 
$ 27.06
 
$ 24.91
 
$ 23.50
MWh
 
18.44
 
14.94
 
13.06
 
11.93
 
11.00

The Company also purchases power as needed from the wholesale market to supplement its generation capabilities in periods of peak demand; however, the majority of power purchased through the wholesale market is used to optimize and hedge the Company’s sales to other wholesale customers. Volumes purchased in 2006 totaled 434,234 MWh.

Competition

The utility industry has undergone dramatic structural change for several years, resulting in increasing competitive pressures faced by electric and gas utility companies. Currently, several states, including Ohio, have passed legislation allowing electricity customers to choose their electricity supplier in a competitive electricity market and several other states are considering such legislation. At the present time, Indiana has not adopted such legislation. Ohio regulation allows gas customers to choose their commodity supplier. The Company implemented a choice program for its gas customers in Ohio in January 2003. At December 31, 2006, over 72,000 customers in Vectren’s Ohio service territory purchase natural gas from a supplier other than the utility. Margin earned for transporting natural gas to those customers, who have purchased natural gas from another supplier, are generally the same as those earned by selling gas under Ohio tariffs. Indiana has not adopted any regulation requiring gas choice; however, the Company operates under approved tariffs permitting large volume customers to choose their commodity supplier.
 

 
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Regulatory and Environmental Matters

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

Nonutility Group

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

Energy Marketing and Services

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

ProLiance
ProLiance, a nonutility gas marketing and energy management affiliate of Vectren and Citizens Gas and Coke Utility (Citizens Gas), 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 primary customers include Vectren’s Indiana utilities and nonutility gas supply operations as well as Citizens Gas. ProLiance’s primary businesses include gas marketing, gas portfolio optimization, and other portfolio and energy management services. The Company, including its retail gas supply operations, contracted for 75% of its natural gas purchases through ProLiance in 2006.

In 2002, the Company integrated a wholly owned subsidiary, SIGCORP Energy Services, LLC (SES), with ProLiance. SES provided natural gas and related services to SIGECO and others prior to the transaction. In exchange for the contribution of SES’ net assets totaling $19.2 million, Vectren’s allocable share of ProLiance’s profits and losses increased from 52.5% to 61%, consistent with Vectren’s current ownership percentage. In March 2001, Vectren’s allocable share of profits and losses increased from 50% to 52.5% when ProLiance began managing the Ohio operations’ gas portfolio. Governance and voting rights remain at 50% for each member; and therefore, Vectren continues to account for its investment in ProLiance using the equity method of accounting.

For the year ended December 31, 2006, ProLiance’s revenues, including sales to Vectren companies, exceeded $2.5 billion.

At December 31, 2006, the pre-tax earnings of ProLiance exceeded 20% of Vectren’s pre-tax earnings and, as a result, ProLiance is a “significant subsidiary” within the meaning of Regulation S-X, paragraph 3-09. As such, ProLiance’s audited financial statements as of and for its fiscal years ending September 30, 2006, 2005, and 2004, are included in this Form 10-K.

Vectren Source
Vectren Retail, LLC (d/b/a Vectren Source) provides natural gas and other related products and services in the Midwest and Southeast United States to 150,000 residential and commercial customers opting for choice among energy providers. Vectren Source generated approximately $162.5 million in revenues in 2006, up from $129.2 million in 2005. Gas sold approximated 12,228 MDth in 2006, 12,411 MDth in 2005 and 9,386 MDth in 2004.

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Coal Mining

The Coal Mining group mines and sells coal to the Company’s utility operations and to third parties through its wholly owned subsidiary Vectren Fuels, Inc (Fuels). The Company’s two coal mines produced 4.0 million tons in 2006, compared to 4.4 million tons in 2005 and 3.6 million tons in 2004.

In April 2006, Fuels secured the rights to open two new underground mines near Vincennes, Indiana. The first mine is expected to be operational by early 2009, with the second mine opening the following year. Reserves at the two mines are estimated at 80 million tons of recoverable number-five coal at 11,200 BTU (British thermal units) and 6-pound sulfur dioxide. Management estimates a $125 million investment to access the reserves. Once in full production, the two new mines are expected to produce 5 million tons of coal per year.

Energy Infrastructure Services 

Energy Infrastructure Services provides energy performance contracting operations through Energy Systems Group, LLC (ESG) and natural gas and water distribution, transmission, construction repair and rehabilitation as well as the repair and rehabilitation of gas, water, and wastewater facilities through Miller Pipeline Corporation (Miller). Miller's customers include Vectren’s utilities.

Energy Systems Group
Performance-based energy contracting operations 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’s customer base is located throughout the Midwest and Southeast United States. Prior to April 2003, ESG was a consolidated venture between the Company and Citizens Gas with the Company owning two-thirds. In April 2003, the Company purchased the remaining interest in ESG.

Miller and Reliant Services, LLC
Effective July 1, 2006, the Company purchased the remaining 50% ownership in Miller, making Miller a wholly owned subsidiary. The results of Miller’s operations, formerly accounted for using the equity method, have been included in consolidated results since July 1, 2006.  Prior to this transaction, Miller was 100 percent owned by Reliant Services, LLC (Reliant). Reliant provided facilities locating and meter reading services to the Company’s utilities, as well as other utilities. Reliant exited the meter reading and facilities locating businesses in 2006.

Other Businesses

The Other Businesses group includes a variety of wholly owned operations and investments that invest in broadband communication services, energy-related opportunities and services, real estate, and leveraged leases, among other investments. Major investments at December 31, 2006, include Haddington Energy Partnerships, two partnerships both approximately 40% owned; and wholly owned subsidiaries, Southern Indiana Properties, Inc. and Energy Realty, Inc.

The Company had an approximate 2% equity interest and a convertible subordinated debt investment in Utilicom Networks, LLC (Utilicom). The Company also had an approximate 19% equity interest in SIGECOM Holdings, Inc. (Holdings), which was formed by Utilicom to hold interests in SIGECOM, LLC (SIGECOM). SIGECOM provides broadband services, such as cable television, high-speed internet, and advanced local and long distance phone services, to the greater Evansville, Indiana area. The Company sold its investment in SIGECOM during 2006. See “Item 7 Management’s Discussion and Analysis of Results of Operations and Financial Condition” regarding the Company’s Other Businesses for additional information related to transactions involving Utilicom.

Synthetic Fuel

The Company has an 8.3 percent ownership interest in Pace Carbon Synfuels, LP (Pace Carbon). Pace Carbon produces and sells coal-based synthetic fuel using Covol technology, and based on current US tax law, its members receive a tax credit for every ton of coal-based synthetic fuel sold. In addition, Vectren Fuels, Inc., a wholly owned subsidiary involved in coal mining, receives processing fees from a synfuel producer unrelated to Pace Carbon for a portion of its coal production.  Under current tax laws, these synfuel related credits and fees end after 2007. See “Item 7 Management’s Discussion and Analysis of Results of Operations and Financial Condition” regarding the Company’s Synfuel-Related activities for additional information related to Pace Carbon and Vectren Fuels.
-9-

Personnel

As of December 31, 2006, the Company and its consolidated subsidiaries had 3,348 employees, of which 1,994 are subject to collective bargaining arrangements. Approximately 1,333 employees are employees of Miller.

During 2006, the Company, through its wholly owned subsidiary, Miller, entered into several distributing and operating agreements with a variety of construction unions including Laborers International Union of America, International Union of Operating Engineers, the Teamsters, and the United Association of Journeymen and Apprentices of the Plumbing and Pipe Fitting Industry. These agreements expire at various dates in 2009 through 2011. Miller negotiates these agreements through the Distribution and Contractors Association and the Pipeline Contractors Association.

In November 2005, the Company reached a four-year agreement with Local 175 of the Utility Workers Union of America, ending October 2009. In September 2005, the Company reached a four-year agreement with Local 135 of the Teamsters, Chauffeurs, Warehousemen, and Helpers Union, ending September 2009.

In July 2004, the Company reached a three-year labor agreement with Local 702 of the International Brotherhood of Electrical Workers, ending June 2007. In January 2004, the Company reached a five-year labor agreement, ending December 2008, with Local 1393 of the International Brotherhood of Electrical Workers and United Steelworkers of America Locals 12213 and 7441.

ITEM 1A. RISK FACTORS

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

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

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

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

The utility industry has been undergoing dramatic structural change for several years, resulting in increasing competitive pressure faced by electric and gas utility companies. Increased competition may create greater risks to the stability of Vectren’s earnings generally and may in the future reduce its earnings from retail electric and gas sales. Currently, several states, including Ohio, have passed legislation that allows customers to choose their electricity supplier in a competitive market. Indiana has not enacted such legislation. Ohio regulation also provides for choice of commodity providers for all gas customers. In 2003, the Company implemented this choice for its gas customers in Ohio. Indiana has not adopted any regulation requiring gas choice except for large-volume customers. 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.

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

Vectren’s gas and electric utility sales are sensitive to variations in weather conditions. The Company forecasts utility sales on the basis of normal weather, which represents a long-term historical average. Since Vectren does not have a weather-normalization mechanism for its electric operations or its Ohio natural gas 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 on October 15, 2005, of a normal temperature adjustment mechanism.

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

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

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

Vectren’s businesses are subject to regulation by federal, state and local regulatory authorities.  In particular, Vectren is subject to regulation by the FERC, the IURC and the PUCO. These authorities regulate many aspects of its transmission and distribution operations, including construction and maintenance of facilities, operations, safety and the rates that the Company can charge customers and the rate of return that Vectren's utilities are authorized to earn. The Company’s ability to obtain rate increases to maintain its current authorized rate of return depends upon regulatory discretion, and there can be no assurance that Vectren will be able to obtain rate increases or rate supplements or earn its current authorized rate of return.

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

Environmental legislation also requires that facilities, sites and other properties associated with Vectren’s operations be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. The Company’s current costs to comply with these laws and regulations are significant to its results of operations and financial condition. In addition, claims against the Company under environmental laws and regulations could result in material costs and liabilities. With the trend toward stricter standards, greater regulation, more extensive permit requirements and an increase in the number and types of assets operated by Vectren subject to environmental regulation, its investment in environmentally compliant equipment, and the costs associated with operating that equipment, have increased and are expected to increase in the future.

Further, there are proposals to address global climate change that would regulate carbon dioxide (CO2) and other greenhouse gases. Any future legislative or regulatory actions taken to address global climate change could adversely affect Vectren’s business and results of operations by, for example, requiring changes in, and increased costs related to, the Company’s fossil fuel generating plants and coal mining operations.

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

The Company, as well as its equity investees such as ProLiance, may be subject to material litigation and regulatory proceedings from time to time. There can be no assurance that the outcome of these matters will not have a material adverse effect on Vectren’s business, results of operations or financial condition.
 

 
-11-

Vectren’s electric operations are subject to various risks.

The Company’s electric generating facilities are subject to operational risks that could result in unscheduled plant outages, unanticipated operation and maintenance expenses and increased purchased power 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.

Vectren may experience significantly increased gas costs.

Commodity prices for natural gas purchases have increased and become more volatile in recent years. Subject to regulatory approval, Vectren’s utility subsidiaries are allowed recovery of gas costs from their retail customers through commission-approved gas cost adjustment mechanisms. As a result, profit margins on gas sales are not expected to be impacted. Nevertheless, regulators may disallow, and have in the past disallowed, recovery of a portion of gas costs for various reasons, including but limited to, a finding by the regulator that natural gas was not prudently procured, as an example. In addition, it is possible that as a result of this near term change in natural gas commodity prices, Vectren’s subsidiaries may experience increased interest expense due to higher working capital requirements, increased uncollectible accounts expense and unaccounted for gas and some level of price sensitive reduction in volumes sold or delivered.  However, the Company believes that the negative earnings impact on the reduction of price sensitive natural gas volumes sold is significantly mitigated by Indiana and Ohio orders received in the fourth quarter of 2006 that authorize lost margin recovery.

The impact of MISO participation is uncertain.

Since February 2002 and with the IURC’s approval, the Company has been a member of the MISO. The MISO serves the electrical transmission needs of much of the Midwest and maintains operational control over Vectren’s electric transmission facilities as well as that of other Midwest utilities.
 
On April 1, 2005, the MISO energy market commenced operation (the Day 2 energy market). As a result of being a market participant, Vectren now bids its owned generation into the Day Ahead and Real Time markets and procure power for its retail customers at Locational Marginal Pricing (LMP) as determined by the MISO market.

As a result of MISO’s operational control over much of the Midwestern electric transmission grid, including Vectren’s electric transmission facilities, its continued ability to import power, when necessary, and export power to the wholesale market has been, and may continue to be, impacted. Given the nature of MISO’s policies regarding use of transmission facilities, as well as ongoing FERC initiatives and uncertainties around Day 2 energy market operations, it is difficult to predict near term operational impacts. However, it is believed that MISO’s regional operation of the transmission system will ultimately lead to reliability improvements within the Midwestern transmission system.

The potential need to expend capital for improvements to the transmission system, both to Vectren’s facilities as well as to those facilities of adjacent utilities, over the next several years will become more predictable as MISO completes studies related to regional transmission planning and improvements. Such expenditures may be significant.

Wholesale power marketing activities may add volatility to earnings.

Vectren’s regulated electric utility engages in wholesale power marketing activities that primarily involve asset optimization strategies. These optimization strategies 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. Projected 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.
 

 
-12-

If Vectren does not accurately forecast future commodities prices or if its hedging procedures do not operate as planned in certain nonutility businesses, the Company’s net income could be reduced or the Company may experience losses.


The operations of ProLiance as well as the Company’s nonutility gas retail supply and coal mining businesses execute forward and option contracts that commit them to purchase and sell natural gas and coal in the future, including forward contracts to purchase commodities to fulfill forecasted sales transactions that may or may not occur. If the value of these contracts changes in a direction or manner that is not anticipated, or if the forecasted sales transactions do not occur, Vectren may experience losses.

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

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

Execution of gas marketing strategies by ProLiance as well as the execution of the Company’s coal mining and energy infrastructure services strategies, and the success of efforts to invest in and develop new opportunities in the nonutility business area is subject to a number of risks. These risks include, but are not limited to, the effects of weather; failure of installed performance contracting products to operate as planned; storage field and mining property development; increased coal mining industry regulation; potential legislation that may limit CO2 and other greenhouse gases emissions; creditworthiness of customers and joint venture partners; factors associated with physical energy trading activities, including price, basis, credit, liquidity, volatility, capacity, and interest rate risks; changes in federal, state or local legal requirements, such as changes in tax laws or rates; and changing market conditions.

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

Vectren’s synfuel results would be adversely affected if synfuel credits are limited or disallowed.

Under current tax laws, synfuel related tax credits and fees end after 2007. The Permanent Subcommittee on Investigations of the U.S. Senate’s Committee on Governmental Affairs has an ongoing investigation relating to synfuel tax credits.

The Internal Revenue Service has issued private letter rulings, which concluded that the synthetic fuel produced at the Pace Carbon facilities should qualify for tax credits. The IRS has completed tax audits of Pace Carbon for the years 1998 through 2001 without challenging tax credit calculations. As a partner of Pace Carbon, Vectren has reflected synfuel tax credits in its consolidated results from inception through December 31, 2006 of approximately $92 million, of which approximately $81 million have been generated since 2001. To date, Vectren has been in a position to utilize or carryforward substantially all of the credits generated.

Synfuel tax credits are only available when the price of oil is less than a base price specified by the tax code, adjusted for inflation. For 2007, Vectren has hedged 100% of expected production to help offset a phase-out due to high oil prices. However, during the year, the hedges could cause quarterly earnings volatility due to mark-to-market accounting. If production is not interrupted during 2007, the average oil price will have an immaterial effect on annual earnings. However, if oil prices increase enough to produce a substantial phase-out prior to year-end and production is halted or Vectren chooses to “opt out”, the proceeds on hedges and the reduction in production costs could result in increased earnings. Also, if production is interrupted for reasons other than oil prices and tax credits are not earned, the Company could be at risk for the cost of the hedges.

 
-13-

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

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

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

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

Workforce risks could affect Vectren’s financial results.

The Company is subject to various workforce risks, including but not limited to, the risk that it will be unable to attract and retain qualified personnel; that it will be unable to effectively transfer the knowledge and expertise of an aging workforce to new personnel as those workers retire; 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.

A downgrade in Vectren’s credit ratings could negatively affect its ability to access capital.

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, Indiana Gas and SIGECO senior unsecured debt
Baa1
A-
Utility Holdings commercial paper program
P-2
A-2

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

Vectren may be required to obtain additional permanent financing (1) to fund its capital expenditures, investments and debt security redemptions and maturities and (2) to further strengthen its capital structure and the capital structures of its subsidiaries. If the rating agencies downgrade the Company’s credit ratings, particularly below investment grade, or withdraw Vectren’s ratings, 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.
 
Anti-takeover provisions in Vectren’s certificate of Articles of Incorporation and Bylaws as well as Vectren’s shareholders rights plan and certain provisions of the Indiana Business Corporation Law could delay or prevent a change in control that might be beneficial to the interests of the Company’s stockholders.

Provisions in Vectren’s Articles of Incorporation and Bylaws as well as Vectren’s shareholders rights plan and certain provisions of the Indiana Business Corporation Law (the ICBL) may make it more difficult and expensive for a third party to acquire control of the Company even if a change of control would be beneficial to the interests of its shareholders. For example, Vectren’s Articles of Incorporation and Bylaws prohibit its shareholders from calling a special meeting, require advance notice for proposals by shareholders and nominations, and prevent the removal of Vectren’s directors by its shareholders other than for cause and with the affirmative vote of the holders of at least 80% of the voting power of all the shares entitled to vote in the election of directors. In addition, the Vectren board has adopted a shareholder rights agreement designed to deter certain takeover tactics that may discourage potential takeover attempts. The IBCL also limits certain business combination transactions between Vectren and any person who acquires 10% or more of the Company’s common shares (an "interested shareholder") without its board's approval or, in certain cases, the approval of holders of a majority of Vectren’s shares not owned by such interested shareholder. The IBCL may also cause a shareholder acquiring shares of the Company’s common stock beyond specified thresholds to lose the right to vote those shares unless a majority of disinterested common shares approves the exercise of such voting rights. The foregoing may adversely affect the market price of Vectren’s common stock by discouraging potential takeover attempts that the Company’s stockholders may favor.

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 58,130 acres of land with an estimated ready delivery from storage capability of 5.6 BCF of gas with maximum peak day delivery capabilities of 145,000 MCF per day. Indiana Gas also owns and operates three liquefied petroleum (propane) air-gas manufacturing plants located in Indiana with the ability to store 1.5 million gallons of propane and manufacture for delivery 33,000 MCF of manufactured gas per day. In addition to its company owned storage and propane capabilities, Indiana Gas has contracted for 17.8 BCF of storage with a maximum peak day delivery capability of 299,717 MMBTU per day. Indiana Gas’ gas delivery system includes 12,505 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.
 

 
-14-

SIGECO owns and operates three underground gas storage fields located in Indiana covering 6,070 acres of land with an estimated ready delivery from storage capability of 6.3 BCF of gas with maximum peak day delivery capabilities of 108,000 MCF per day. In addition to its company owned storage delivery capabilities, SIGECO has contracted for 0.5 BCF of storage with a maximum peak day delivery capability of 19,166 MMBTU per day. SIGECO's gas delivery system includes 3,166 miles of distribution and transmission mains, all of which are located in Indiana.

The Ohio operations own and operate three liquefied petroleum (propane) air-gas manufacturing plants, all of which are located in Ohio. The plants can store .5 million gallons of propane, and the plants can manufacture for delivery 52,187 MCF of manufactured gas per day. In addition to its propane delivery capabilities, the Ohio operations have contracted for 12.0 BCF of storage with a maximum peak day delivery capability of 246,080 MMBTU per day. The Ohio operations’ gas delivery system includes 5,356 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, 2006, was rated at 1,301 MW. SIGECO's coal-fired generating facilities are the Brown Station with two units of 500 MW of combined capacity, located in Posey County approximately eight miles east of Mt. Vernon, Indiana; the Culley Station with two units of 356 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. Pursuant to the settlement between the Company, the Department of Justice, and the USEPA, the Company ceased operation of Culley Unit 1, with generating capacity of 50 MW, effective December 31, 2006 and is excluded from the total capacity above.

SIGECO's transmission system consists of 894 circuit miles of 138,000 and 69,000 volt lines. The transmission system also includes 30 substations with an installed capacity of 5,057 megavolt amperes (Mva). The electric distribution system includes 4,199 pole miles of lower voltage overhead lines and 331 trench miles of conduit containing 1,833 miles of underground distribution cable. The distribution system also includes 99 distribution substations with an installed capacity of 2,010 Mva and 52,449 distribution transformers with an installed capacity of 2,448 Mva.

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

Nonutility Properties

Subsidiaries other than the utility operations have no significant properties other than the ownership and operation of coal mining property in Indiana. The assets of the coal mining operations comprise approximately 4% of total assets. The assets of Miller comprise approximately 3% of total assets.
 

 
-15-

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 arising in the normal course of business. In the opinion of management, there are no legal proceedings 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, rate and regulatory matters and the settlement of a lawsuit involving ProLiance. The consolidated financial statements are included in “Item 8 Financial Statements and Supplementary Data.”

ITEM 4. SUBMISSION OF MATTERS TO VOTE OF SECURITY HOLDERS

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

PART II

ITEM 5. MARKET FOR COMPANY'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES

Market Data, Dividends Paid, and Holders of Record

The Company’s common stock trades on the New York Stock Exchange under the symbol ‘‘VVC.’’ For each quarter in 2006 and 2005, 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
2006
             
 
First Quarter
 
0.305
 
$ 28.00
 
$ 25.60
 
Second Quarter
 
0.305
 
27.52
 
25.24
 
Third Quarter
 
0.305
 
28.42
 
26.00
 
Fourth Quarter
 
0.315
 
29.25
 
26.67
2005
 
 
 
 
 
 
 
 
First Quarter
 
$ 0.295
 
$ 27.95
 
$ 25.82
 
Second Quarter
 
0.295
 
28.98
 
26.01
 
Third Quarter
 
0.295
 
29.46
 
26.50
 
Fourth Quarter
 
0.305
 
28.75
 
25.00

On January 31, 2007, the board of directors declared a dividend of $0.315 per share, payable on March 1, 2007, to common shareholders of record on February 15, 2007.

As of January 31, 2007, there were 10,949 shareholders of record 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 by the Company during the three months ended December 31, 2006.

-16-


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% of earnings over time. On an annual basis, this percentage has varied and will continue to vary due to short-term earnings volatility. The Company has increased its dividend for 47 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 payments of dividends, and the amounts of these dividends, will be reassessed.

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

 
ITEM 6. SELECTED FINANCIAL DATA
 

The following selected financial data is derived from the Company’s audited consolidated financial statements and should be read in conjunction with those financial statements and notes thereto contained in this Form 10-K.
 
                       
                                                    Year Ended December 31,
 
(In millions, except per share data)
 
2006
 
2005
 
2004
 
2003
 
2002
 
                       
Operating Data:
                     
Operating revenues
 
$
2,041.6
 
$
2,028.0
 
$
1,689.8
 
$
1,587.7
 
$
1,523.8
 
Operating income
 
$
220.5
 
$
213.1
 
$
199.5
 
$
196.0
 
$
211.3
 
Net income
 
$
108.8
 
$
136.8
 
$
107.9
 
$
111.2
 
$
114.0
 
Average common shares outstanding
   
75.7
   
75.6
   
75.6
   
70.6
   
67.6
 
Fully diluted common shares outstanding
   
76.2
   
76.1
   
75.9
   
70.8
   
67.9
 
Basic earnings per share
   
   
   
   
   
 
  on common stock
 
$
1.44
 
$
1.81
 
$
1.43
 
$
1.58
 
$
1.69
 
Diluted earnings per share
   
   
   
   
   
 
  on common stock
 
$
1.43
 
$
1.80
 
$
1.42
 
$
1.57
 
$
1.68
 
Dividends per share on common stock
 
$
1.23
 
$
1.19
 
$
1.15
 
$
1.11
 
$
1.07
 
 
   
   
   
   
   
 
Balance Sheet Data:
   
   
   
   
   
 
Total assets
 
$
4,091.6
 
$
3,868.1
 
$
3,586.9
 
$
3,353.4
 
$
3,136.5
 
Long-term debt, net
 
$
1,208.0
 
$
1,198.0
 
$
1,016.6
 
$
1,072.8
 
$
954.2
 
Redeemable preferred stock
 
$
-
 
$
-
 
$
0.1
 
$
0.2
 
$
0.3
 
Common shareholders' equity
 
$
1,174.2
 
$
1,143.3
 
$
1,094.8
 
$
1,071.7
 
$
869.9
 


-17-



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

The following discussion and analysis should be read in conjunction with the consolidated financial statements and notes thereto.
 
Executive Summary of Consolidated Results of Operations
                 
       
Year Ended December 31,
(In millions, except per share data)
 
2006
 
2005
 
2004
                 
Net income
 
$ 108.8
 
$ 136.8
 
$ 107.9
 
Attributed to:
 
 
 
 
 
 
 
 
Utility Group
 
$   91.4
 
$   95.1
 
$   83.1
 
 
Nonutility Group
 
18.1
 
48.2
 
26.4
 
 
Corporate & Other
 
(0.7)
 
(6.5)
 
(1.6)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Basic earnings per share
 
$ 1.44
 
$ 1.81
 
$ 1.43
 
Attributed to:
 
 
 
 
 
 
 
 
Utility Group
 
$ 1.21
 
$ 1.26
 
$ 1.10
 
 
Nonutility Group
 
0.24
 
0.64
 
0.35
 
 
Corporate & Other
 
(0.01)
 
(0.09)
 
(0.02)

Results

For the year ended December 31, 2006, reported earnings were $108.8 million, or $1.44 per share, compared to $136.8 million, or $1.81 per share, in 2005 and $107.9 million, or $1.43 per share, in 2004. The decline in 2006 results compared to 2005 is primarily attributable to the decline in synfuels results of $0.22 per share, a $0.09 per share charge related to the settlement of a lawsuit involving ProLiance Energy, LLC (ProLiance) and continued declines in customer usage. Losses associated with synfuels-related activities were $0.07 per share in 2006, compared to earnings of $0.15 per share in 2005 and earnings of $0.16 per share in 2004. Excluding the results from synfuel-related activities, earnings in 2006 were $1.51 per share compared to $1.66 per share in 2005 and $1.27 per share in 2004.

Utility Group results reflect the impact of a constructive regulatory environment.  The Company received orders in the fourth quarter of 2006 that authorize lost margin recovery related to the Company’s Ohio customers and a majority of Indiana natural gas customers, and an order in the fourth quarter of 2005 for a normal temperature adjustment mechanism with respect to the Company’s Indiana natural gas customers. The Company also utilizes rider mechanisms to recover capital expenditures associated with compliance with Clean Air Act and Clean Air Mercury requirements, among other costs. In addition, the Company has implemented base rate increases since 2003 and currently has two cases before the IURC where orders are expected in 2007. The revenue increases, including the proposed increases in the two pending cases, are required to offset increased operating and financing costs, the effect on usage from higher commodity prices, and the impact of recent weather unfavorable compared to 30-year normal temperatures.

Gas utility base rate increases added revenues of approximately $4.2 million in 2006 compared to 2005, and $33.8 million in 2005 compared to 2004. Increased revenues associated with recovery of pollution control investments were $2.6 million in 2006 compared to 2005 and $14.3 million in 2005 compared to 2004. Increased revenues associated with lost margin recovery were $2.0 million in 2006 compared to 2005.

In 2006 compared to 2005, the decline in Utility Group earnings is primarily the result of continued declines in customer usage, higher depreciation and interest costs, and wholesale power marketing margins $6.2 million, or $3.7 million after tax, lower than the prior year. The decline was mitigated somewhat by the implementation of regulatory initiatives noted above, the impact of a lower effective tax rate, and a gain realized on the sale of a storage asset.

In 2005 compared to 2004, the $0.16 per share earnings increase is largely due to increased base rates, recovery of pollution control investments, weather, and wholesale power marketing activities. The improved utility margins were partially offset by higher operating and depreciation expense. The 2005 results also reflect a $4.1 million, $2.4 million after tax, charge recorded pursuant to the disallowance of Ohio gas costs.

In 2006, 2005, and 2004 weather across all utilities was unfavorable compared to 30-year normal temperatures. Management estimates the effect of weather compared to normal was unfavorable $0.06 per share in 2006, unfavorable $0.04 per share in 2005, and unfavorable $0.09 per share in 2004. The 2006 weather effect contains the full impact of a normal temperature adjustment (NTA) mechanism implemented in the Company’s Indiana natural gas service territories in the fourth quarter of 2005.

 
-18-

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 results of the Utility Group are impacted by weather patterns in its service territory and general economic conditions both in its Indiana and Ohio service territories as well as nationally.

Primary nonutility operations include Energy Marketing and Services companies, Coal Mining operations, and Energy Infrastructure Services companies. Energy Marketing and Services contributed earnings of $14.9 million in 2006, $29.7 million in 2005, and $13.8 million in 2004. Results in 2006 and 2004 contain costs associated with the settlement of a lawsuit involving ProLiance. The Company’s portion of those costs totaled $6.6 million after tax in 2006 and $1.4 million after tax in 2004. Coal Mining operations contributed earnings of $5.0 million in 2006, $5.3 million in 2005, and $0.4 million in 2004. Energy Infrastructure Services contributed earnings of $4.6 million in 2006, $0.3 million in 2005, and $4.6 million in 2004.

In total and excluding the effects of the lawsuit involving ProLiance, the Company’s primary nonutility business groups contributed earnings of $31.1 million, a decrease of $4.2 million compared to 2005. Earnings from ProLiance, which are included in Energy Marketing and Services’ results, decreased $6.2 million year over year due largely to record earnings in 2005. ProLiance’s earnings in 2005 increased significantly due to larger spreads between financial and physical markets, which resulted from market disruptions caused by Gulf Coast hurricanes. The earnings decrease was offset by results from Energy Infrastructure Services companies, which include Energy Systems Group and Miller Pipeline. They contributed additional earnings of $3.4 million and $1.3 million respectively. Earnings growth, excluding the effects of the lawsuit, in 2005 compared to 2004 totaled $15.1 million and was primarily driven by increased earnings from ProLiance and improved coal mining operations.

Effective July 1, 2006, the Company purchased the remaining 50% ownership in Miller Pipeline Corporation (Miller), making Miller a wholly owned subsidiary.  Prior to this transaction, Miller was a 50% owned joint venture accounted for using the equity method. The results of Miller’s operations have been included in consolidated results since July 1, 2006. While the acquisition of Miller is not expected to have a material impact on the overall financial statements, consolidating Miller resulted in, among other impacts, a $77.6 million increase in Nonutility revenues and a $60.8 million increase in Other operating expense in 2006 when compared to 2005. The transaction also increased consolidated Goodwill by approximately $31.0 million and intangible assets, which are included in Other assets, by $14.0 million.

Results from other nonutility businesses, which were losses of $1.1 million in 2006, income of $1.2 million in 2005 and losses of $4.5 million in 2004, were primarily affected by the Company’s broadband investments and its investment in Haddington Energy Partners. In 2006, the Company sold its investment in SIGECOM, LLC to a third party at a loss of approximately $1.3 million. The year ended December 31, 2004 also reflects after tax charges totaling $6.0 million associated with SIGECOM, LLC and other broadband related investments. Earnings associated with Haddington, which sold investments in 2005 and 2004 at net gains, totaled $0.1 million in 2006, compared to $3.9 million in 2005 and $2.0 million in 2004.
 

 
-19-

Finally, and separate from the ongoing operations, 2006 Synfuels-related results, inclusive of the expected phase out of tax credits, the impairment of synfuel-related assets, the related hedging activity, the impact of insurance contracts and processing fees, resulted in losses of $3.8 million in 2006. Mark to market losses associated with financial contracts hedging 2007 production recognized in 2006 totaled $1.5 million. Earnings from Synfuels-related activities were $11.7 million in 2005 and $12.1 million in 2004.

The Nonutility Group generates revenue or earnings from the provision of services to customers. The activities of 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.

The 2005 Corporate and Other $0.09 loss per share reflects an additional contribution to the Vectren Foundation of $6.5 million, or $4.2 million after tax, to sustain its giving program over the next several years. The contribution is included in Other operating expenses in the Consolidated Statements of Income.

In this discussion and analysis of results of operations, the results of the Utility Group and Nonutility Group are presented on a per share basis. Such per share amounts are based on the earnings contribution of each group included in Vectren’s consolidated results divided by Vectren’s 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 either group but rather represent a direct equity interest in Vectren Corporation's assets and liabilities as a whole.

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.

Dividends

Dividends declared for the year ended December 31, 2006, were $1.23 per share compared to $1.19 per share in 2005 and $1.15 per share in 2004. In October 2006, the Company’s board of directors increased its quarterly dividend to $0.315 per share from $0.305 per share. 

Detailed Discussion of Results of Operations

Following is a more detailed discussion of the results of operations of the Company’s Utility and Nonutility operations. The detailed results of operations for these operations are presented and analyzed before the reclassification and elimination of certain intersegment transactions necessary to consolidate those results into the Company’s Consolidated Statements of Income. Other than the $6.5 million contribution made in 2005 to the Vectren Foundation discussed above, Corporate and Other operations are not significant.

-20-


Results of Operations of the Utility Group

Utility operations are 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 into 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 asset optimization operations. In total, these regulated operations supply natural gas and/or electricity to more than one million customers. The results of operations of the Utility Group before certain intersegment eliminations and reclassifications for the years ended December 31, 2006, 2005, and 2004, follow:

   
Year Ended December 31,
 
(In millions, except per share data)
 
2006
 
2005
 
2004
 
OPERATING REVENUES
             
Gas utility
 
$
1,232.5
 
$
1,359.7
 
$
1,126.2
 
Electric utility
   
422.2
   
421.4
   
371.3
 
Other
   
1.8
   
0.7
   
0.5
 
Total operating revenues 
   
1,656.5
   
1,781.8
   
1,498.0
 
OPERATING EXPENSES
                   
Cost of gas sold
   
841.5
   
973.3
   
778.5
 
Cost of fuel & purchased power
   
151.5
   
144.1
   
116.8
 
Other operating
   
239.0
   
241.3
   
220.4
 
Depreciation & amortization
   
151.3
   
141.3
   
127.8
 
Taxes other than income taxes
   
64.2
   
65.2
   
58.2
 
Total operating expenses 
   
1,447.5
   
1,565.2
   
1,301.7
 
OPERATING INCOME
   
209.0
   
216.6
   
196.3
 
OTHER INCOME
                   
Equity in earnings of unconsolidated affiliates
   
-
   
-
   
0.2
 
Other – net
   
7.6
   
5.9
   
7.1
 
Total other income 
   
7.6
   
5.9
   
7.3
 
Interest expense
   
77.5
   
69.9
   
67.4
 
INCOME BEFORE INCOME TAXES
   
139.1
   
152.6
   
136.2
 
Income taxes
   
47.7
   
57.5
   
53.1
 
NET INCOME
 
$
91.4
 
$
95.1
 
$
83.1
 
BASIC EARNINGS PER SHARE
 
$
1.21
 
$
1.26
 
$
1.10
 
 
Significant Fluctuations

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 the Cost of fuel & purchased power. The Company believes Gas utility and Electric utility margins are better indicators of relative contribution than revenues since gas prices and fuel costs can be volatile and are generally collected on a dollar-for-dollar basis from customers. These measures exclude Other operating expenses, Depreciation and amortization, and Taxes other than income taxes, which are included in the calculation of operating income.

Margin generated from the sale of natural gas and electricity to residential and commercial customers is seasonal and is impacted by weather patterns in the Company’s service territories. The weather impact in the Company’s Indiana gas utility service territories is mitigated by a normal temperature adjustment mechanism, which was implemented in the fourth quarter of 2005. Margin generated from sales to large customers (generally industrial, other contract, and firm wholesale customers) is primarily impacted by overall economic conditions. Margin is also impacted by the collection of state mandated taxes, which fluctuate with gas costs, as well as other tracked expenses and is also impacted by some level of price sensitivity in volumes sold or delivered. Electric generating asset optimization activities are primarily affected by market conditions, the level of excess generating capacity, and electric transmission availability. Following is a discussion and analysis of margin generated from regulated utility operations.
 
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Gas utility margin (Gas utility revenues less Cost of gas sold)
Gas utility margin and throughput by customer type follows:

               
   
Year Ended December 31,
(In millions)
 
2006
 
2005
 
2004
 
Gas utility revenues
 
$
1,232.5
 
$
1,359.7
 
$
1,126.2
 
Cost of gas sold
   
841.5
   
973.3
   
778.5
 
Total gas utility margin 
 
$
391.0
 
$
386.4
 
$
347.7
 
Margin attributed to:
                   
Residential & commercial customers 
 
$
330.2
 
$
333.2
 
$
297.7
 
Industrial customers 
   
48.0
   
48.3
   
45.7
 
Other customers 
   
12.8
   
4.9
   
4.3
 
Sold & transported volumes in MMDth attributed to:
                   
Residential & commercial customers 
   
97.7
   
112.9
   
114.5
 
Industrial customers 
   
84.9
   
87.2
   
85.8
 
 Total sold & transported volumes
   
182.6
   
200.1
   
200.3
 
 
Gas utility margins were $391.0 million for the year ended December 31, 2006, an increase of $4.6 million compared to 2005. A full year of base rate increases implemented in the Company’s Ohio service territory which increased margin $4.2 million, a $4.1 million disallowance of Ohio gas costs in 2005, the effects of the normal temperature adjustment mechanism (NTA) implemented in 2005 in the Company’s Indiana service territories, and the lost margin recovery authorization implemented in the fourth quarter of 2006, more than offset the effects of warm weather, lower usage, and decreased tracked expenses recovered dollar for dollar in margin.

For the year ended December 31, 2006, compared to 2005, management estimates that weather 14 percent warmer than normal and 9 percent warmer than prior year would have decreased margins $13.1 million compared to the prior year, had the NTA not been in effect. Weather, net of the NTA, resulted in an approximate $2.0 million year over year increase in gas utility margin. Incremental revenue associated with the lost margin recovery totaled $2.0 million in 2006. Further, for the year ended December 31, 2006, margin associated with tracked expenses and revenue taxes decreased $3.4 million. The average cost per dekatherm of gas purchased for the year ended December 31, 2006, was $8.64 compared to $9.05 in 2005 and $6.92 in 2004.

For the year ended December 31, 2005, gas utility margins increased $38.7 million compared to 2004. The increase is primarily due to the favorable impact of gas base rate increases of $33.8 million and additional pass through expenses and revenue taxes recovered in margins of $5.8 million compared to 2004. Results for the year ended December 31, 2005, reflect the disallowance of Ohio gas costs ordered by the PUCO described above. For the year ended December 31, 2005, weather was 5% warmer than normal but 4% colder than the prior year. Management estimates that weather, including the effects of the normal temperature adjustment mechanism, increased margin an estimated $2.5 million compared to 2004.




-22-


Electric Utility Margin (Electric Utility Revenues less Cost of Fuel and Purchased Power)
Electric Utility margin and volumes sold by customer type follows:


               
   
Year Ended December 31,
(In millions)
 
2006
 
2005
 
2004
 
Electric utility revenues
 
$
422.2
 
$
421.4
 
$
371.3
 
Cost of fuel & purchased power
   
151.5
   
144.1
   
116.8
 
Total electric utility margin 
 
$
270.7
 
$
277.3
 
$
254.5
 
Margin attributed to:
                   
Residential & commercial customers 
 
$
162.9
 
$
170.8
 
$
157.3
 
Industrial customers 
   
70.2
   
66.9
   
63.7
 
Municipal & other customers 
   
24.0
   
19.8
   
18.6
 
 Subtotal: Retail & firm wholesale
 
$
257.1
 
$
257.5
 
$
239.6
 
Asset optimization 
 
$
13.6
 
$
19.8
 
$
14.9
 
Electric volumes sold in GWh attributed to:
                   
Residential & commercial customers 
   
2,789.7
   
2,933.2
   
2,830.9
 
Industrial customers 
   
2,570.4
   
2,575.9
   
2,511.2
 
Municipal & other customers 
   
644.4
   
689.9
   
645.9
 
 Total retail & firm wholesale volumes sold
   
6,004.5
   
6,199.0
   
5,988.0
 

Retail & Firm Wholesale Margin
Electric retail and firm wholesale utility margin was $257.1 million for the year ended December 31, 2006 and was generally flat compared to 2005. The recovery of pollution control related investments and associated operating expenses and related depreciation increased margins $2.6 million year over year. Higher demand charges and other items increased industrial customer margin approximately $3.2 million year over year. These increases were offset by decreased residential and commercial usage. The decreased usage was due primarily to mild weather during the peak cooling season. For 2006 compared to 2005, the estimated decrease in margin due to unfavorable weather was $4.6 million ($4.0 million for below normal cooling weather and $0.6 million for heating weather). During 2006, cooling degree days were 5% below normal. In 2005, cooling degree days were 9% above normal.

Electric retail and firm wholesale utility margin increased $17.9 million in 2005 compared to 2004. The recovery of pollution control related investments and associated operating expenses and depreciation expense increased margins $14.3 million compared to 2004. Cooling weather was 9% warmer than normal and 21% warmer than 2004. In 2005 compared to 2004, the estimated increase in electric margin related to weather was $4.0 million ($3.8 million related to cooling weather and $0.2 million related to heating weather).

Margin from Asset Optimization Activities
Periodically, generation capacity is in excess of that needed to serve retail load and firm wholesale customers. The Company markets this unutilized capacity to optimize the return on its owned generation assets. These optimization strategies primarily involve the sale of excess generation into the MISO day ahead 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.

Asset optimization activity is comprised of the following:
   
Year Ended December 31,
(In millions)
 
2006
 
2005
 
2004
 
Off-system sales
 
$
14.2
 
$
15.3
 
$
8.7
 
Transmission system sales
   
3.5
   
4.5
   
4.6
 
Other
   
(4.1
)
 
0.0
   
1.6
 
Total asset optimization 
 
$
13.6
 
$
19.8
 
$
14.9
 

-23-

For the year ended December 31, 2006, net asset optimization margins were $13.6 million, which represents a decrease of $6.2 million compared to 2005. The decrease is due to the effect lower wholesale prices have had on the Company’s optimization portfolio and lower volumes sold off system. For the year ended December 31, 2005, net asset optimization margins increased $4.9 million as compared to 2004. The increase in margin results primarily from the timing of available capacity and mark to market gains.

In 2005, the Company experienced increased availability of the generating units. The availability of excess capacity was reduced in 2006 and 2004 by scheduled outages of owned generation related to the installation of environmental compliance equipment. Off-system sales totaled 889.4 GWh in 2006, compared to 1,208.1 GWh in 2005 and 670.4 GWh in 2004.

Utility Group Operating Expenses
 
Other Operating
For the year ended December 31, 2006, other operating expenses decreased $2.3 million compared to 2005. Expenses in 2006 are reduced from the inclusion of a gain on the sale of a storage asset of approximately $4.4 million. Excluding this gain, operating expenses would have increased $2.1 million compared to 2005. The increase is primarily the result of electric generation chemical costs $1.3 million higher than the prior year. Bad debt expense in the Company’s Indiana service territories increased $0.6 million year over year due in part to higher gas costs.

Other operating expenses increased $20.9 million for the year ended December 31, 2005, compared to 2004. Amortization of rate case expenses, expenses associated with the Ohio choice program and integrity management programs, and expenses recovered through margin increased $6.5 million. Bad debt expense in the Company’s Indiana service territories was $9.3 million in 2005, an increase of $1.8 million compared to 2004. Compensation and benefit costs increases, including performance and share-based compensation was $6.8 million higher than the prior year, reflective of the return to higher earnings in 2005 as compared to 2004. Higher maintenance, chemical costs, and all other costs account for $5.8 million of the increase.

Depreciation & Amortization
Depreciation expense increased $10.0 million in 2006 compared to 2005 and $13.5 million in 2005 compared to 2004. In addition to depreciation on additions to plant in service, the increases were primarily due to incremental depreciation expense associated with environmental compliance equipment additions. Depreciation expense associated with environmental compliance equipment, which is recovered in Electric utility margin, totaled $14.4 million in 2006, $12.1 million in 2005, and $6.2 million in 2004. Results for 2004 include $1.8 million of lower depreciation due to adjustments of Ohio depreciation rates and amortization of Indiana regulatory assets.
 
Taxes Other Than Income Taxes
Taxes other than income taxes decreased $1.0 million for the year ended December 31, 2006, compared to 2005 and increased $7.0 million in 2005 compared to 2004. The fluctuations are primarily attributable to variations in the collection of utility receipts, excise, and usage taxes. These variations resulted primarily from volatility in revenues and gas volumes sold.

Utility Group Other Income (Expense)

Total other income (expense)-net increased $1.7 million in 2006 compared to 2005, and decreased $1.4 million in 2005 compared to 2004. The fluctuations relate primarily to capitalized interest on utility plant additions.

Utility Group Interest Expense

In 2006, interest expense increased $7.6 million compared to 2005 and increased $2.5 million in 2005 compared to 2004. The increases are primarily driven by rising interest rates and higher levels of short-term borrowings due in part to higher working capital requirements resulting from the increased gas commodity prices.

-24-

Interest costs in 2006 also include the full impact of permanent financing transactions completed in the fourth quarter of 2005 in which $150 million in debt-related proceeds were received and used to retire short-term borrowings and other long-term debt. Results for 2006 also include a partial impact from financing transactions completed in October 2006 in which approximately $93 million in debt related proceeds were raised and used to retire debt outstanding with a higher interest rate.

Utility Group Income Taxes

Federal and state income taxes decreased $9.8 million in 2006 compared to 2005 and increased $4.4 million in 2005 compared to 2004. The changes are impacted by fluctuations in pre-tax income. Income taxes recorded in 2006 reflect a $3.1 million favorable impact for an Indiana tax law change that resulted in the recalculation of certain state deferred income tax liabilities. Income taxes in 2006 also include other adjustments, including adjustments to reflect income taxes reported on 2005 state and federal income tax returns. Income taxes recorded in 2005 reflect favorable adjustments to accruals resulting from the conclusion of state tax audits and other adjustments.

Environmental Matters

The Company is subject to federal, state, and local regulations with respect to environmental matters, principally air, solid waste, and water quality. Pursuant to environmental regulations, the Company is required to obtain operating permits for the electric generating plants that it owns or operates and construction permits for any new plants it might propose to build. Regulations concerning air quality establish standards with respect to both ambient air quality and emissions from electric generating facilities, including particulate matter, sulfur dioxide (SO2), nitrogen oxide (NOx), and mercury. Regulations concerning water quality establish standards relating to intake and discharge of water from electric generating facilities, including water used for cooling purposes in electric generating facilities. Because of the scope and complexity of these regulations, the Company is unable to predict the ultimate effect of such regulations on its future operations, nor is it possible to predict what other regulations may be adopted in the future, including any regulations to address the climate change issue.

Clean Air Act

Clean Air Interstate Rule & Clean Air Mercury Rule

In March of 2005 USEPA finalized two new air emission reduction regulations.  The Clean Air Interstate Rule (CAIR) is an allowance cap and trade program requiring further reductions in Nitrogen Oxides (NOx) and Sulfur Dioxide (SO2) emissions from coal-burning power plants. The Clean Air Mercury Rule (CAMR) is an allowance cap and trade program requiring further reductions in mercury emissions from coal-burning power plants.  Both sets of regulations require emission reductions in two phases. The first phase deadline for both rules is 2010 (2009 for NOx under CAIR), and the second phase deadline for compliance with the emission reductions required under CAIR is 2015, while the second phase deadline for compliance with the emission reduction requirements of CAMR is 2018. The Company is evaluating compliance options and fully expects to be in compliance by the required deadlines.

In February 2006, the IURC approved a multi-emission compliance plan filed by the Company’s utility subsidiary, SIGECO. Once the plan is implemented, SIGECO’s coal-fired plants will be 100% scrubbed for SO2, 90% scrubbed for NOx, and mercury emissions will be reduced to meet the new mercury reduction standards. The order, as previously agreed to by the OUCC and Citizens Action Coalition, allows SIGECO to recover an approximate 8% return on up to $110 million in capital investments through a rider mechanism which is updated every six months for actual costs incurred. The Company will also recover through a rider its operating expenses, including depreciation, once the equipment is placed into service. The order also stipulates that SIGECO study renewable energy alternatives and include a carbon forecast in future filings with regard to new generation and further environmental compliance plans, among other initiatives. As of December 31, 2006, the Company has made capital investments of approximately $62.2 million related to this environmental requirement.

NOx SIP Call Matter
The Company complied with Indiana’s State Implementation Plan (SIP) of the Clean Air Act (the Act). These steps included installation of Selective Catalytic Reduction (SCR) systems at Culley Generating Station Unit 3 (Culley), Warrick Generating Station Unit 4, and A. B. Brown Generating Station Units 1 and 2. SCR systems reduce flue gas NOx emissions to atmospheric nitrogen and water using ammonia in a chemical reaction. This technology is known to currently be the most effective method of reducing nitrogen oxide (NOx) emissions where high removal efficiencies are required.

-25-

The IURC issued orders that approved:
·  
the Company’s project to achieve environmental compliance by investing in clean coal technology;
·  
the Company’s investment of $258 million in capital costs;
·  
a mechanism whereby, prior to an electric base rate case, the Company recovers through a rider that is updated every six months, an 8% return on its weighted capital costs for the project; and
·  
ongoing recovery of operating costs, including depreciation and purchased emission allowances, related to the clean coal technology now that facilities are placed into service.

Related annual operating expenses, including depreciation expense, were $18.7 million in 2006, $15.4 million in 2005, and $9.7 million in 2004.

Culley Generating Station Litigation
During 2003, the U.S. District Court for the Southern District of Indiana entered a consent decree among SIGECO, the Department of Justice (DOJ), and the USEPA that resolved a lawsuit originally brought by the USEPA against SIGECO. The lawsuit alleged violations of the Clean Air Act by SIGECO at its Culley Generating Station for (1) making modifications to a generating station without obtaining required permits, (2) making major modifications to the generating station without installing the best available emission control technology, and (3) failing to notify the USEPA of the modifications.

Under the terms of the agreement, the DOJ and USEPA agreed to drop all challenges of past maintenance and repair activities at the Culley Generating Station. In reaching the agreement, SIGECO did not admit to any allegations in the government’s complaint, and SIGECO continues to believe that it acted in accordance with applicable regulations and conducted only routine maintenance on the units. SIGECO entered into this agreement to further its continued commitment to improve air quality and avoid the cost and uncertainties of litigation.

Under the agreement, SIGECO committed to:
·  
either repower Culley Unit 1 (50 MW) with natural gas and equip it with SCR control technology for further reduction of nitrogen oxide, or cease operation of the unit by December 31, 2006;
·  
operate the existing SCR control technology recently installed on Culley Unit 3 (287 MW) year round at a lower emission rate than that currently required under the NOx SIP Call, resulting in further nitrogen oxide reductions;
·  
enhance the efficiency of the existing scrubber at Culley Units 2 and 3 for additional removal of sulphur dioxide emissions;
·  
install a baghouse for further particulate matter reductions at Culley Unit 3 by June 30, 2007;
·  
conduct a Sulphuric Acid Reduction Demonstration Project as an environmental mitigation project designed to demonstrate an advance in pollution control technology for the reduction of sulfate emissions; and
·  
pay a $600,000 civil penalty.

The Company does not believe that implementation of the settlement will have a material effect on its results of operations or financial condition. The $600,000 civil penalty was expensed and paid during 2003. The Company ceased operation of Culley Unit 1 effective December 31, 2006 and the baghouse, which is included in the $110 million IURC order discussed above, went into service January 1, 2007.

Manufactured Gas Plants

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

Indiana Gas identified the existence, location, and certain general characteristics of 26 gas manufacturing and storage sites for which it may have some remedial responsibility. Indiana Gas completed a remedial investigation/feasibility study (RI/FS) at one of the sites under an agreed order between Indiana Gas and the IDEM, and a Record of Decision was issued by the IDEM in January 2000. Although Indiana Gas has not begun an RI/FS at additional sites, Indiana Gas has submitted several of the sites to the IDEM's Voluntary Remediation Program (VRP) and is currently conducting some level of remedial activities, including groundwater monitoring at certain sites, where deemed appropriate, and will continue remedial activities at the sites as appropriate and necessary.

-26-

In conjunction with data compiled by environmental consultants, Indiana Gas accrued the estimated costs for further investigation, remediation, groundwater monitoring, and related costs for the sites. While the total costs that may be incurred in connection with addressing these sites cannot be determined at this time, Indiana Gas has recorded costs that it reasonably expects to incur totaling approximately $20.4 million.

The estimated accrued costs are limited to Indiana Gas’ proportionate share of the remediation efforts. Indiana Gas has arrangements in place for 19 of the 26 sites with other potentially responsible parties (PRP), which serve to limit Indiana Gas’ share of response costs at these 19 sites to between 20% and 50%. With respect to insurance coverage, Indiana Gas has received and recorded settlements from all known insurance carriers in an aggregate amount approximating $20.4 million.

In October 2002, SIGECO received a formal information request letter from the IDEM regarding five manufactured gas plants that it owned and/or operated and were not enrolled in the IDEM’s VRP. In response, SIGECO submitted to the IDEM the results of preliminary site investigations conducted in the mid-1990’s. These site investigations confirmed that based upon the conditions known at the time, the sites posed no imminent and/or substantial risk to human health or the environment.

On October 6, 2003, SIGECO filed applications to enter four of the manufactured gas plant sites in IDEM's VRP. The remaining site is currently being addressed in the VRP by another Indiana utility. SIGECO added those four sites into the renewal of the global Voluntary Remediation Agreement that Indiana Gas has in place with IDEM for its manufactured gas plant sites. That renewal was approved by the IDEM on February 24, 2004. On July 13, 2004, SIGECO filed a declaratory judgment action against its insurance carriers seeking a judgment finding its carriers liable under the policies for coverage of further investigation and any necessary remediation costs that SIGECO may accrue under the VRP program. While the total costs that may be incurred in connection with addressing these sites cannot be determined at this time, SIGECO has recorded costs that it reasonably expects to incur totaling approximately $7.7 million. With respect to insurance coverage, SIGECO has received and recorded settlements from insurance carriers in an aggregate amount approximating the costs it expects to incur.

Environmental matters related to Indiana Gas’ and SIGECO’s manufactured gas plants have had no material impact on results of operations or financial condition since costs recorded to date approximate PRP and insurance settlement recoveries. While the Company’s utilities have recorded all costs which they presently expect to incur in connection with activities at these sites, it is possible that future events may require some level of additional remedial activities which are not presently foreseen.

Jacobsville Superfund Site

On July 22, 2004, the USEPA listed the Jacobsville Neighborhood Soil Contamination site in Evansville, Indiana, on the National Priorities List under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA). The USEPA has identified four sources of historic lead contamination. These four sources shut down manufacturing operations years ago. When drawing up the boundaries for the listing, the USEPA included a 250 acre block of properties surrounding the Jacobsville neighborhood, including Vectren's Wagner Operations Center. Vectren's property has not been named as a source of the lead contamination, nor does the USEPA's soil testing to date indicate that the Vectren property contains lead contaminated soils. Vectren's own soil testing, completed during the construction of the Operations Center, did not indicate that the Vectren property contains lead contaminated soils. At this time, Vectren anticipates only additional soil testing, if required by the USEPA.

-27-


Global Climate Change

Global climate change remains a policy issue that is regularly considered for government regulation. If legislation requiring reductions in greenhouses gases is adopted, such regulation could substantially affect both the costs and operating characteristics of the Company’s fossil fuel plants. Further, the Company’s nonutility coal mining operations may be adversely affected.

Rate and Regulatory Matters

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

All metered gas rates in Indiana contain a gas cost adjustment (GCA) clause, and all metered gas rates in Ohio contain a gas cost recovery (GCR) clause. GCA and GCR clauses allow the Company to charge for changes in the cost of purchased gas. Metered electric rates contain a fuel adjustment clause (FAC) that allows for adjustment in charges for electric energy to reflect changes in the cost of fuel. The net energy cost of purchased power, subject to an agreed upon benchmark, is also recovered through regulatory proceedings.

GCA, GCR, and FAC procedures involve periodic filings and IURC and PUCO hearings to establish the amount of price adjustments for a designated future period. The procedures also provide for inclusion in later periods of any variances between the estimated cost of gas, cost of fuel, and net energy cost of purchased power and actual costs incurred. The Company records any under-or-over-recovery resulting from gas and fuel adjustment clauses each month in margin. A corresponding asset or liability is recorded until the under-or-over-recovery is billed or refunded to utility customers.

The IURC has also applied the statute authorizing GCA and FAC procedures to reduce rates when necessary to limit net operating income to a level authorized in its last general rate order through the application of an earnings test. For the recent past, the earnings test has not affected the Company’s ability to recover costs.

Ohio and Indiana Lost Margin Recovery/Conservation Filings
In 2005, the Company filed conservation programs and conservation adjustment trackers in Indiana and Ohio designed to help customers conserve energy and reduce their annual gas bills. The programs would allow the Company to recover costs of promoting the conservation of natural gas through conservation trackers that work in tandem with a lost margin recovery mechanism. This mechanism is designed to allow the Company to recover the distribution portion of its rates from residential and commercial customers based on the level of customer revenues established in each utility’s last general rate case.

Indiana
In December 2006, the IURC approved a settlement agreement between the Company and the OUCC that provides for a 5-year energy efficiency program to be implemented. The order allows the Company’s Indiana utilities to recover the costs of promoting the conservation of natural gas through conservation trackers that work in tandem with a lost margin recovery mechanism that would provide for recovery of 85% of the difference between revenues actually collected by the Company and the revenues approved in the Company’s most recent rate case. The order was implemented in the North service territory in December 2006 and will be implemented in South’s service territory after its next general rate case (see below.) While most expenses associated with these programs are recoverable, in the first program year, the Company is required to fund $1.5 million in program costs without recovery. Revenues recorded in 2006 as a result of this order related to lost margin recovery totaled $0.7 million and revenues to fund energy efficiency programs totaled $0.6 million.

Ohio
In September 2006, the PUCO approved a conservation proposal that would implement a decoupling approach, including a related conservation program, for the company’s Ohio operations. The PUCO decision was issued following a hearing process and the submission of a settlement by the Company, the Ohio Consumer Counselor (OCC) and the Ohio Partners for Affordable Energy (OPAE). That settlement was contested by the PUCO Staff. In the decision the PUCO addressed decoupling by approving a two year, $2 million total, low-income conservation program to be funded by the Company, as well as a sales reconciliation rider intended to be a recovery mechanism for the difference between the weather normalized revenues actually collected by the company and the revenues approved by the PUCO in the Company’s most recent rate case. The decision produced an outcome that was different from the settlement. Following the decision, the Company and the OPAE advised the PUCO that they would accept the outcome even though it differed from the terms of the settlement. The OCC sought rehearing of the decision, which was denied in December, and thereafter the OCC advised the PUCO that the OCC was withdrawing from the settlement. At that point the OCC also initiated the process for appealing the PUCO’s September and December decisions to the Ohio Supreme Court. Thereafter, the Company, the OPAE and the PUCO Staff advised the PUCO that they accepted the terms provided in the September decision, as affirmed by the December rehearing decision. Since that time there have been a number of procedural filings by the parties and presently the Company is awaiting a further decision from the PUCO. The Company believes that the PUCO had the necessary legal basis for its decisions and thus should confirm the outcome provided in the September decision.  The Company began recognizing the impact of this order on October 1, 2006, and has recorded revenues in 2006 related to the order in the amount of $1.3 million.

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Vectren South (Southern Indiana Gas & Electric) Base Rate Filings
On September 1, 2006, Vectren South filed petitions with the IURC to adjust its electric and gas base rates in its South service territory. The electric petition requests an increase of $76.7 million in base rates to recover the nearly $120 million additional investment in electric utility infrastructure since its last base rate increase in 1995, which is not currently included in rates charged to customers. The increase in rates also is required to support system growth, maintenance, reliability and recovery of costs deferred under previous IURC orders. The gas petition seeks to increase its gas base (non-gas cost) rates by $10.4 million to cover the ongoing costs of operating and maintaining its natural gas distribution and storage system. Based upon the timelines prescribed by the IURC at the start of these proceedings, decisions in each case are expected to be issued in the late summer of 2007. The initial public hearings in both cases have been conducted. On January 30, 2007, the OUCC filed testimony in the gas rate case proposing an increase of $5.1 million.

IGCC Certificate of Public Convenience and Necessity
On September 7, 2006, Vectren Energy Delivery of Indiana and Duke Energy Indiana, Inc. filed with the IURC a joint petition for a Certificate of Public Convenience and Necessity (CPCN) for the construction of new electric capacity. Specifically, Vectren requested the IURC approve its construction and ownership of up to 20% of an Integrated Gasification Combined Cycle (IGCC) project. Vectren's CPCN filing also seeks timely recovery of its 20% portion of the project's construction costs as well as operation and maintenance costs and additional incentives available for the construction of clean coal technology. Initial studies of plant design have already begun, and if the project moves forward as currently designed, plant construction is expected to begin in 2007 and continue through 2011.

Weather Normalization
On October 5, 2005, the IURC approved the establishment of a normal temperature adjustment (NTA) mechanism for Vectren Energy Delivery of Indiana. The OUCC had previously entered into a settlement agreement with Vectren Energy Delivery of Indiana providing for the NTA. The NTA affects the Company’s Indiana regulated residential and commercial natural gas customers and should mitigate weather risk in those customer classes during the October to April heating season. These Indiana customer classes represent approximately 60-65% of the Company’s total natural gas heating load.

The NTA mechanism will mitigate volatility in distribution charges created by fluctuations in weather by lowering customer bills when weather is colder than normal and increasing customer bills when weather is warmer than normal. The NTA has been applied to meters read and bills rendered after October 15, 2005. Each subsequent monthly bill for the seven-month heating season will be adjusted using the NTA. Resulting from this order, revenues recorded in 2006 totaled $13.6 million while refunds of $1.6 million were made in 2005.

The order provides that the Company will make, on a monthly basis, a commitment of $125,000 to a universal service fund program or other low-income assistance program for the duration of the NTA or until a general rate case.

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Rate structures in the Company’s Indiana electric territory and Ohio gas territory do not include weather normalization-type clauses.

Gas Utility Base Rate Settlements in 2004 and 2005
On June 30, 2004, the IURC approved a $5.7 million base rate increase for SIGECO’s gas distribution business, and on November 30, 2004, approved a $24 million base rate increase for Indiana Gas’ gas distribution business. On April 13, 2005, the PUCO approved a $15.7 million base rate increase for VEDO’s gas distribution business. The base rate change in SIGECO’s service territory was implemented on July 1, 2004; the base rate change in Indiana Gas’ service territory was implemented on December 1, 2004; and the base rate change in VEDO’s service territory was implemented on April 14, 2005.

The orders also permit SIGECO and Indiana Gas to recover the on-going costs to comply with the Pipeline Safety Improvement Act of 2002. The Pipeline Safety Improvement Tracker provides for the recovery of incremental non-capital dollars, capped at $750,000 the first year and $500,000 thereafter for SIGECO and $2.5 million per year for Indiana Gas. Any costs incurred in excess of these annual caps are to be deferred for future recovery. VEDO’s new base rates provide for the recovery of some level of on-going costs to comply with the Pipeline Safety Improvement Act of 2002.

MISO
Since February 2002 and with the IURC’s approval, the Company has been a member of the Midwest Independent System Operator, Inc. (MISO), a FERC approved regional transmission organization. The MISO serves the electrical transmission needs of much of the Midwest and maintains operational control over the Company’s electric transmission facilities as well as that of other Midwest utilities. Pursuant to an order from the IURC received in December 2001, certain MISO startup costs (referred to as Day 1 costs) have been deferred for future recovery in the next general rate case, which was filed in 2006.

On April 1, 2005, the MISO energy market commenced operation (the Day 2 energy market). As a result of being a market participant, the Company now bids its owned generation into the Day Ahead and Real Time markets and procures power for its retail customers at Locational Marginal Pricing (LMP) as determined by the MISO market.

On June 1, 2005, Vectren, together with three other Indiana electric utilities, received regulatory authority from the IURC that allows recovery of fuel related costs and deferral of other costs associated with the Day 2 energy market. The order allows fuel related costs to be passed through to customers in Vectren’s existing fuel cost recovery proceedings. The other non-fuel and MISO administrative related costs are to be deferred for recovery as part of the next electric general rate case proceeding, which was filed in 2006. During 2006, the IURC reaffirmed the definition of certain costs as fuel related; the Company is following those guidelines.

As a result of MISO’s operational control over much of the Midwestern electric transmission grid, including SIGECO’s transmission facilities, SIGECO’s continued ability to import power, when necessary, and export power to the wholesale market has been, and may continue to be, impacted. Given the nature of MISO’s policies regarding use of transmission facilities, as well as ongoing FERC initiatives and uncertainties around Day 2 energy market operations, it is difficult to predict near term operational impacts. However, as stated above, it is believed that MISO’s regional operation of the transmission system will ultimately lead to reliability improvements.

The potential need to expend capital for improvements to the transmission system, both to SIGECO’s facilities as well as to those facilities of adjacent utilities, over the next several years will become more predictable as MISO completes studies related to regional transmission planning and improvements. Such expenditures may be significant.

Gas Cost Recovery (GCR) Audit Proceedings
On June 14, 2005, the PUCO issued an order disallowing the recovery of approximately $9.6 million of gas costs relating to the two-year audit period ended November 2002. That audit period provided the PUCO staff its initial review of the portfolio administration arrangement between VEDO and ProLiance. The disallowance includes approximately $1.3 million relating to pipeline refunds and penalties and approximately $4.5 million of costs for winter delivery services purchased by VEDO to ensure reliability over the two-year period. The PUCO also held that ProLiance should have credited to VEDO an additional $3.8 million more than credits actually received for the right to use VEDO’s gas transportation capacity periodically during the periods when it was not required for serving VEDO’s customers. The PUCO also directed VEDO to either submit its receipt of portfolio administration services to a request for proposal process or to in-source those functions. During 2003, the Company recorded a reserve of $1.1 million for this matter. An additional pretax charge of $4.1 million was recorded in Cost of gas sold in 2005. The reserve reflects management’s assessment of the impact of the PUCO decisions, an estimate of any current impact that decision may have on subsequent audit periods, and an estimate of a sharing in any final disallowance by Vectren’s partner in ProLiance.

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VEDO filed its request for rehearing on July 14, 2005, and on August 10, 2005, the PUCO granted rehearing to further consider the $3.8 million portfolio administration issue and all interest on the findings, but denied rehearing on all other aspects of the case. On October 7, 2005, the Company filed an appeal with the Ohio Supreme Court requesting that the $4.5 million disallowance related to the winter delivery service issue be reversed. On December 21, 2005, the PUCO granted in part VEDO’s rehearing request, and reduced the $3.8 million disallowance related to portfolio administration to $1.98 million. The Company has appealed the $1.98 million disallowance to the Ohio Supreme Court as well. Briefings of all matters and oral arguments were completed in November 2006, and the parties are awaiting the Court’s ruling.

With respect to the most recent GCR audit covering the period of November 1, 2002 through October 31, 2005, the PUCO staff recommended a disallowance of approximately $830,000 related solely to the retention of a reserve margin for the winter of 2002/2003. The Company had previously reserved for the possible disallowance given the June 2005 PUCO order but has contested the disallowance. The PUCO will issue a decision on that issue in 2007.

As a result of the June 2005 PUCO order, the Company has established an annual bidding process for VEDO’s gas supply and portfolio administration services. Since November 1, 2005, the Company has used a third party provider for these services.

Results of Operations of the Nonutility Group

The Nonutility Group is comprised of Vectren Enterprises’ operations. The Nonutility Group operates in three primary business areas: Energy Marketing and Services, Coal Mining, and Energy Infrastructure Services. Energy Marketing and Services markets and supplies natural gas and provides energy management services. Coal Mining mines and sells coal. Energy Infrastructure Services provides underground construction and repair and energy performance contracting services. Enterprises also has other businesses that invest in energy-related opportunities and services, real estate, and leveraged leases, among other investments. In addition, the Company has investments that generate synfuel tax credits and processing fees relating to the production of coal-based synthetic fuels. Enterprises supports the Company’s regulated utilities pursuant to service contracts by providing natural gas supply services, coal, infrastructure services, and other services. The results of operations of the Nonutility Group for the years ended December 31, 2006, 2005, and 2004, follow:

               
   
Year Ended December 31,
(In millions, except per share amounts)
 
2006
 
2005
 
2004
 
NET INCOME
 
$
18.1
 
$
48.2
 
$
26.4
 
                     
BASIC EARNINGS PER SHARE
 
$
0.24
 
$
0.64
 
$
0.35
 
                     
NET INCOME ATTRIBUTED TO:
                   
Energy Marketing & Services
 
$
14.9
 
$
29.7
 
$
16.6
 
Mining Operations
   
5.0
   
5.3
   
0.4
 
Energy Infrastructure Services
   
4.6
   
0.3
   
1.8
 
Other Businesses
   
(1.1
)
 
1.2
   
(4.5
)
Synfuels-related
   
(5.3
)
 
11.7
   
12.1
 
 
Energy Marketing & Services

Energy Marketing and Services is comprised of the Company’s gas marketing operations, energy management services, and retail gas supply operations.

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ProLiance Energy LLC (ProLiance), a nonutility energy marketing affiliate of Vectren and Citizens Gas and Coke Utility (Citizens Gas), 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 utilities and nonutility gas supply operations and Citizens Gas. 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% of ProLiance’s profits and losses; however, governance and voting rights remain at 50% for each member; and therefore the Company accounts for its investment in ProLiance using the equity method of accounting.

Vectren received regulatory approval on April 25, 2006, from the IURC for ProLiance to continue to provide natural gas supply services to the Company’s Indiana utilities through March 2011. ProLiance has not provided gas supply/portfolio administration services to VEDO since October 31, 2005.

Vectren Retail, LLC (d/b/a Vectren Source), a wholly owned subsidiary, provides natural gas and other related products and services in the Midwest and Southeast United States to customers opting for choice among energy providers.

Net income generated by Energy Marketing and Services for the year ended December 31, 2006, was $14.9 million compared to $29.7 million in 2005 and $13.8 million in 2004. Throughout the periods presented, ProLiance’s operations provided the primary earnings contribution, totaling $18.3 million in 2006, compared to $31.1 million in 2005 and $15.4 million in 2004. Results in 2006 and 2004 contain costs associated with the settlement of a lawsuit by ProLiance. The Company’s portion of those costs totaled $6.6 million after tax in 2006 and $1.4 million after tax in 2004. Earnings in 2005 increased significantly due to larger spreads between financial and physical markets, which resulted from market disruptions caused by Gulf Coast hurricanes.
 
Vectren Source operated at a loss of $0.4 million in 2006, compared to earnings of $0.9 million in 2005 and a loss of $0.4 million in 2004. Vectren Source added approximately 20,000 new customers during 2006, bringing its total customer base to 150,000. The year over year decrease in earnings is primarily due to higher marketing costs and weather. Customer growth was the primary source of increased earnings in 2005 compared to 2004.

ProLiance Lawsuit Settlement

On November 22, 2006, ProLiance agreed to settle a 2002 civil lawsuit between the City of Huntsville, Alabama and ProLiance. The $21.6 million settlement (Huntsville Settlement) relates to a dispute over a contractual relationship with Huntsville Utilities during 2000-2002.

During 2006, ProLiance recorded an $18.3 million charge recognizing the Huntsville Settlement. During 2004, ProLiance recorded $3.9 million as a reserve for loss contingency recognizing the initial unfavorable judgment and the uncertainties related to ultimate outcome. During 2006 and 2005, $0.1 million and $0.5 million of legal fees were charged against the reserve.

As an equity investor in ProLiance, Vectren reflected its share of these charges which totaled $6.6 million after tax in 2006 and $1.4 million after tax in 2004. Vectren is currently exploring whether a portion of those charges may be recoverable from insurance carriers.

Commodity Prices
In response to the effects of higher gas costs, ProLiance increased its unsecured revolving credit facilities. Those facilities expire in June 2009. These facilities provide for a total of $400 million in short-term credit to be available from October 1 through March 31 and $300 million from April 1 through September 30. These credit facilities are not guaranteed by Vectren Corporation.

Coal Mining

Coal Mining Operations mine and sell coal to the Company’s utility operations and to third parties through its wholly owned subsidiary Vectren Fuels, Inc. (Fuels).

Coal Mining net income for the year ended December 31, 2006, was $5.0 million in 2006, compared to $5.3 million in 2005 and $0.4 million in 2004. Mining Operations’ 2006 earnings were generally flat compared to the prior year. Higher revenue and tax benefits from depletion have been offset by unfavorable geologic conditions, the rising costs of commodities used in operations, and high sulfur content. The increased performance in 2005 compared to 2004 is primarily due to greater production, improved yield and higher prices, despite the effects of rising costs for steel, explosives, and diesel fuel. The Company produced 4.0 million tons of coal in 2006, compared to 4.4 million tons of coal in 2005 and 3.6 million tons in 2004.

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In April 2006, Fuels secured the rights to open two new underground mines near Vincennes, Indiana. The first mine is expected to be operational by early 2009, with the second mine opening the following year. Reserves at the two mines are estimated at 80 million tons of recoverable number-five coal at 11,200 BTU (British thermal units) and 6-pound sulfur dioxide. Management estimates a $125 million investment to access the reserves. Once in production, the two new mines are expected to produce 5 million tons of coal per year.

Energy Infrastructure Services

Energy Infrastructure Services provides energy performance contracting operations through Energy Systems Group, LLC (ESG) and natural gas and water distribution, transmission, construction repair and rehabilitation as well as the repair and rehabilitation of gas, water, and wastewater facilities through Miller Pipeline (Miller).

Net income generated by Energy Infrastructure Services for the year ended December 31, 2006, was $4.6 million compared to $0.3 million in 2005 and $4.6 million in 2004. The significant increase in earnings in 2006 compared to 2005 is due primarily to monetizing backlog at ESG and the recent acquisition of the remaining 50 percent ownership interest in Miller. During 2006, the Company exited the meter reading and line locating businesses, which it had previously provided through Reliant Services, LLC.

Energy Infrastructure’s net income decreased $4.3 million in 2005 compared to 2004. The 2005 decrease is primarily attributable to fewer large pipeline projects and delays in the start of an awarded wastewater project at Miller and energy efficiency contracts at ESG. In addition, 2005 results were further affected by increased overhead from an acquisition completed by ESG in 2004.

Other Businesses

The Other Businesses Group includes a variety of operations and investments including investments in the Haddington Energy Partnerships (Haddington). The earnings impact of exiting the broadband business is also included in Other Businesses.

Other Businesses reported a net loss of $1.1 million in 2006 compared to net income of $1.2 million in 2005 and a loss of $4.5 million in 2004. Results for 2006 reflect a $1.3 million loss on the sale of SIGECOM and lower earnings from Haddington. Results for 2005 reflect $1.9 million of increased earnings from Haddington compared to 2004. During 2004, the Company recorded charges related to its broadband investments totaling $6.0 million after tax. Results in 2005 were further affected by planned decreases in leveraged lease income as well as additional charges associated with Vectren Communication Services, Inc.

Haddington
The Haddington Energy Partnerships are equity method investments that invest in energy-related ventures. Earnings from Haddington for the year ended December 31, 2006, were $0.1 million compared to $3.9 million in 2005 and $2.0 million in 2004. In 2005, Haddington sold its investment in Lodi Gas Storage, LLC for cash. The Company recognized its portion of the gain resulting from that sale which totaled $3.9 million after tax. During 2004, these partnerships sold their investments in SAGO Energy, LP, for cash and wrote-down their investment in Nations Energy Holdings, resulting in a net after tax gain of $1.8 million.

Utilicom
The Company had an approximate 2% equity interest and a convertible subordinated debt investment in Utilicom Networks, LLC (Utilicom). The Company also had an approximate 19% equity interest in SIGECOM Holdings, Inc. (Holdings), which was formed by Utilicom to hold interests in SIGECOM, LLC (SIGECOM). SIGECOM provides broadband services, such as cable television, high-speed internet, and advanced local and long distance phone services, to the greater Evansville, Indiana area. The Company accounted for its investments in Utilicom and Holdings using the cost method of accounting.

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Other Utilicom-related subsidiaries also owned franchising agreements to provide broadband services to the greater Indianapolis, Indiana and Dayton, Ohio markets. In 2004, the build out of these markets was further evaluated, and the Company concluded that it was unlikely it would make additional investments in those markets. As a result, the Company recorded charges totaling $6.0 million, or $3.6 million after-tax, to write off investments made in the Indianapolis and Dayton markets and to write down its investment in SIGECOM.

In August 2006, SIGECOM’s majority owner and the Company sold their interests in SIGECOM to WideOpenWest, LLC.  Resulting from the sale, the Company recorded an after tax loss of $1.3 million in 2006. Proceeds to the Company, which include the settlement of notes receivable, are expected to total approximately $45 million. The Company anticipates receiving the proceeds in early 2007.
 
Vectren Communications Services, Inc. (VCS)
In 2004, as part of its decision to no longer expand its broadband-related operations, the Company ceased operations of VCS, a municipal broadband consulting business. This decision resulted in losses of $2.4 million after tax due primarily to inventory write-downs, cessation charges, and other costs. In 2005, the Company incurred approximately $1.3 million in after tax charges associated with the settlement of a lawsuit and other charges. VCS’ total loss for 2006 was $0.2 million, compared to losses of $1.5 million in 2005 and $2.6 million in 2004.

Synfuels-Related Results

Pace Carbon Synfuels, LP (Pace Carbon) is a Delaware limited partnership formed to develop, own, and operate four projects to produce and sell coal-based synthetic fuel (synfuel) utilizing Covol technology.  The Company has an 8.3 percent interest in Pace Carbon which is accounted for using the equity method of accounting.  The Internal Revenue Code provides for manufacturers, such as Pace Carbon, to receive a tax credit for every ton of synthetic fuel sold.  In addition, Vectren Fuels, Inc., a wholly owned subsidiary involved in coal mining, receives processing fees from a synfuel producer unrelated to Pace Carbon for a portion of its coal production.  Under current tax laws, these synfuel related credits and fees cease at the end of 2007.
 
The Internal Revenue Service has issued private letter rulings, which concluded that the synthetic fuel produced at the Pace Carbon facilities should qualify for tax credits.  The IRS has completed tax audits of Pace Carbon for the years 1998 through 2001 without challenging tax credit calculations.  As a partner in Pace Carbon, Vectren has reflected synfuel tax credits in its consolidated results from inception through December 31, 2006 of approximately $92 million, of which approximately $81 million have been generated since 2001. To date, Vectren has been in a position to utilize or carryforward substantially all of the credits generated. Primarily from the use of these credits, the Company generated an Alternative Minimum Tax (AMT) credit carryforward of approximately $42.1 million at December 31, 2006.
 
Synfuel tax credits are only available when the price of oil is less than a base price specified by the Internal Revenue Code, as adjusted for inflation.  The Company estimates that high oil prices caused a 35 percent phase out of synfuel tax credits in 2006. Therefore, of the $21.5 million tax credits generated in 2006, only $14.0 million are reflected as a reduction to the Company’s income tax expense.

In July 2006, the Company suspended its participation in the production of synthetic fuel due to the high price of oil and uncertainty of federal legislation that might favorably affect the reference price of oil governing the phase out of synfuel tax credits.  Consistent with that decision to suspend participation, the Company impaired its investment in Pace Carbon and expensed funding requirements estimated at that time.  Charges approximating $9.5 million, or $5.7 million after tax, were recorded in Other-net in the second quarter of 2006. The Company resumed participation in October 2006 as oil prices began to fall.

For the year ended December 31, 2006, synfuel-related activity, inclusive of the phase out of tax credits, the impairment of synfuel-related assets, the related hedging activity, and estimated impact of insurance contracts, resulted in an after tax loss of $3.8 million, or $0.05 per share. Mark-to-market losses associated with financial contracts hedging 2007 production recognized in 2006 totaled $1.5 million after tax, or $0.02 per share.  The accounting for the contracts hedging 2007 production could result in some earnings volatility throughout 2007.  In 2005 and 2004, synfuel-related earnings totaled $11.7 million and $12.1 million, respectively.

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Impact of Recently Issued Accounting Guidance
SFAS No. 158

On December 31, 2006, and after calculating the balance sheet impact of the Company’s retirement plans using the accounting guidance prescribed by SFAS 87 and SFAS 106, the Company adopted SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans-an amendment of FASB Statements No. 87, 88, 106, and 132(R)” (SFAS 158).  SFAS 158 requires the Company to recognize the funded status of its pension plans and postretirement plans. SFAS 158 defines the funded status of a defined benefit plan as its assets less its projected benefit obligation, which includes projected salary increases, and defines the funded status of a postretirement plan as its assets less its accumulated postretirement benefit obligation. To the extent this obligation exceeded amounts previously recognized, the Company recorded a Regulatory Asset for that portion related to its cost-based and rate regulated utilities. To the extent that excess liability did not relate to a cost-based rate-regulated utility, the offset was recorded as a reduction to equity in Accumulated Other Comprehensive Income. As a result of adopting this standard, the Company’s assets increased $30.0 million, its liabilities increased $22.0 million and its equity increased $8.0 million.

SFAS 158 also requires an employer to measure the funded status of a plan as of the date of its year-end balance sheet and requires disclosure in the notes to the financial statements of certain additional information related to net periodic benefit cost for the next fiscal year. The measurement date provisions are not required to be adopted until 2008.

SFAS No. 157

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (SFAS 157). SFAS 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles (GAAP), and expands disclosures about fair value measurements. This statement does not require any new fair value measurements; however, the standard will impact how other fair value based GAAP is applied. SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years with early adoption encouraged. The Company is currently assessing the impact this statement will have on its financial statements and results of operations.

FIN 48

In June 2006, the FASB issued FASB Interpretation No. 48 (FIN 48) “Accounting for Uncertainty in Income Taxes” an interpretation of SFAS 109, Accounting for Income Taxes. FIN 48 prescribes a recognition threshold and measurement attribute for financial statement recognition and measurement of tax positions taken or expected to be taken in an income tax return. FIN 48 also provides guidance related to reversal of tax positions, balance sheet classification, interest and penalties, interim period accounting, disclosure and transition. The interpretation is effective for fiscal years beginning after December 15, 2006. The adoption of this standard is not expected to have a material impact on operating results or financial condition.

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. Note 2 to the consolidated financial statements describes the significant accounting policies and methods used in the preparation of the consolidated financial statements. Certain estimates used in the financial statements are subjective and use variables that require judgment. These include the estimates to perform goodwill and other asset impairments tests and to determine pension and postretirement benefit obligations. The Company makes other estimates, in the course of accounting for unbilled revenue and the effects of regulation that are critical to the Company’s financial results but that are less likely to be impacted by near term changes. Other estimates that significantly affect the Company’s results, but are not necessarily critical to operations, include depreciating utility and non-utility plant, valuing reclamation liabilities, valuing derivative contracts, and estimating uncollectible accounts, among others. Actual results could differ from these estimates.

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Impairment Review of Investments

The Company has investments in notes receivable, entities accounted for using the cost method of accounting, and entities accounted for using the equity method of accounting. When events occur that may cause one of these investments to be impaired, the Company 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 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 cost method and equity method investments involves comparison of the investment’s estimated fair value to its carrying amount. Fair value is estimated using market comparisons, appraisals, and/or discounted cash flow analyses. Calculating free cash flows and fair value using the above methods is subjective and requires judgment concerning growth assumptions, longevity of cash flows, and discount rates (for fair value calculations). In 2006 and 2004, the Company recorded after tax impairment charges of $7.0 million and $3.6 million, respectively. These charges primarily related to synfuel fuel-related investments and broadband investments as more fully described below.

On July 18, 2006, the Company opted out of its current participation in the production of synthetic fuel due to the high price of oil and the uncertainty of federal legislation that would favorably impact the reference price of oil governing the phase out of synfuel tax credits. Consistent with the Company’s decision to cease its participation in synfuel production activities, the Company completely impaired its $2.9 million investment in Pace Carbon. Further, the Company is obligated to fund Pace Carbon on an installment basis for working capital and as tax credits are earned. The Company estimated this remaining funding obligation and other costs to be $6.6 million and recorded that amount and the impairment charge related to its investment, all totaling $9.5 million, or $5.7 million after tax, in earnings in the second quarter of 2006.

During 2004, the Company performed an impairment analysis on its Utilicom-related investments. The Company used free cash flow analyses to estimate fair value for the cost method portion of the Utilicom investment and recoverability of the related notes receivable. An impairment charge totaling $6.0 million, $3.6 million after tax, was recorded as a result of the analysis. The Company sold these investments in 2006, recording an additional loss at disposition of approximately $1.3 million after tax.

Goodwill

Pursuant to SFAS No. 142, 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 16 to the consolidated financial statements to be the reporting unit. Nonutility Group reporting units are generally defined as the operating companies that aggregate that operating segment. An impairment test performed in accordance with SFAS 142 requires that a reporting unit’s fair value be estimated. The Company used a discounted cash flow model to estimate the fair value of its Gas Utility Services operating segment, and that estimated fair value was compared to its carrying amount, including goodwill. The estimated fair value was in excess of the carrying amount in 2006, 2005, and 2004 and therefore resulted in no impairment. Goodwill related to the Nonutility Group was generally tested during the year using market comparable data or a discounted cash flow model.

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

Pension and 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 relies on actuarial estimates to assess the future potential liability and funding requirements of the Company's pension and postretirement plans. The Company annually measures its obligations on September 30. The Company used the following weighted average assumptions to develop 2006 periodic benefit cost: a discount rate of 5.50 percent, an expected return on plan assets of 8.25 percent, a rate of compensation increase of 3.25 percent, and an inflation assumption of 3.50 percent. During 2006, the Company increased the discount rate by 35 basis points to value 2006 ending pension and postretirement obligations and 2007 benefit cost due to an increase in benchmark interest rates. Future changes in health care costs, work force demographics, interest rates, 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 would have increased 2006 periodic benefit cost by approximately $1.3 million.

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Unbilled Revenues

To more closely match revenues and expenses, the Company records revenues for all gas and electricity delivered to customers but not billed at the end of the accounting period. The Company uses actual units billed during the month to allocate unbilled units by customer class. Those allocated units are multiplied by rates in effect during the month to calculate unbilled revenue at balance sheet dates. While certain estimates are used in the calculation of unbilled revenue, the method from which these estimates are derived is not subject to near-term changes.

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 SFAS No. 71 “Accounting for the Effects of Certain Types of Regulation” (SFAS 71). 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 of SFAS 71, 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. 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 funds the short-term and long-term financing needs of the Utility Group operations, and Vectren Capital Corp (Vectren Capital) funds short-term and long-term financing needs of the Nonutility Group and corporate operations. Vectren Corporation guarantees Vectren Capital’s debt, but does not guarantee Utility Holdings debt. Vectren Capital’s long-term and short-term obligations outstanding at December 31, 2006, totaled $200.0 million and $194.7 million, respectively. Utility Holdings outstanding long-term and short-term borrowing arrangements are jointly and severally guaranteed by Indiana Gas, SIGECO, and VEDO. Utility Holdings long-term and short-term obligations outstanding at December 31, 2006, totaled $700.0 million and $270.1 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.

The Company’s common stock dividends are primarily funded by utility operations. Nonutility operations have demonstrated historical 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 on outstanding senior unsecured debt of Utility Holdings and Indiana Gas, at December 31, 2006, are A-/Baa1 as rated by Standard and Poor's Ratings Services (Standard and Poor’s) and Moody’s Investors Service (Moody’s), respectively. SIGECO's credit ratings on outstanding secured debt are A/A3. 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.
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The Company’s consolidated equity capitalization objective is 45-55% 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% of long-term capitalization at both December 31, 2006, and 2005, respectively. Long-term capitalization includes long-term debt, including current maturities and debt subject to tender, as well as common shareholders’ equity.

The Company expects a significant portion of its capital expenditures, investments, and debt security redemptions to be provided by internally generated funds. However, due to increased levels of forecasted capital expenditures and expected growth in nonutility operations, the Company will likely require additional permanent financing.  As of December 31, 2006, the Company was in compliance with all financial covenants.

Sources & Uses of Liquidity

Operating Cash Flow

The Company's primary historical source of liquidity to fund working capital requirements has been cash generated from operations, which totaled $310.2 million in 2006, compared to $268.4 million in 2005 and $238.0 million in 2004. The $41.8 million increase in cash flow in 2006 compared to 2005 is primarily attributable to earnings before noncash charges increasing $34.4 million year over year. Operating cash flows in 2006 also include a $10.4 million special dividend from ProLiance.

Cash flow from operating activities increased $30.4 million in 2005 compared to 2004. Distributions from equity method investments, which principally consists of dividends from ProLiance, decreased $3.5 million in 2005 compared to 2004. Cash utilized for working capital increases was $6.6 million in 2005 compared to $31.2 million in 2004, and is the primary reason for the increased operating cash flow. Earnings before non-cash charges were impacted by $15.5 million and $31.9 million in alternative minimum taxes in 2005 and 2004, respectively.

Financing Cash Flow

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

Cash flow required for financing activities reflects the impact of long-term financing arrangements executed in 2006 and 2005 and increases in common stock dividends over the periods presented. In 2006, Utility Holdings issued $100 million of senior unsecured securities and used those proceeds to retire higher coupon long-term debt. In 2005, Utility Holdings issued $150 million of senior unsecured securities and used those proceeds to retire higher coupon long-term debt and refinance certain capital projects originally financed with short-term borrowings. In addition, Vectren Capital issued $125 million in senior unsecured securities and used those proceeds to fund $38 million of maturing debt and refinance certain capital projects originally financed with short-term borrowings. These transactions are more fully described below.

Utility Holdings 2006 Debt Issuance
In October 2006, Utility Holdings issued $100 million in 5.95% senior unsecured notes due October 1, 2036 (2036 Notes). The 30-year notes were priced at par. The 2036 Notes are guaranteed by Utility Holdings’ three public utilities: SIGECO, Indiana Gas, and VEDO. These guarantees are full and unconditional and joint and several.  These notes, as well as the timely payment of principal and interest, are insured by a financial guarunty insurance policy by Financial Guaranty Insurance Company (FGIC).

The 2036 Notes have no sinking fund requirements, and interest payments are due quarterly. The notes may be called by Utility Holdings, in whole or in part, at any time on or after October 1, 2011, at 100% of principal amount plus accrued interest. During the first and second quarters of 2006, Utility Holdings entered into several interest rate hedges with a $100 million notional amount. Upon issuance of the notes, these instruments were settled resulting in the payment of approximately $3.3 million, which was recorded as a Regulatory asset pursuant to existing regulatory orders. The value paid is being amortized as an increase to interest expense over the life of the issue maturing October 2036.

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The net proceeds from the sale of the 2036 Notes and settlement of the hedging arrangements totaled approximately $92.8 million. These proceeds were used to repay most of the $100 million outstanding balance of Utility Holdings’ 7.25% Senior Notes originally due October 15, 2031. These notes were redeemed on October 19, 2006 at par plus accrued interest.

Utility Holdings 2005 Debt Issuance
In November 2005, Utility Holdings issued senior unsecured notes with an aggregate principal amount of $150 million in two $75 million tranches. The first tranche was 10-year notes due December 2015, with an interest rate of 5.45% priced at 99.799% to yield 5.47% to maturity (2015 Notes). The second tranche was 30-year notes due December 2035 with an interest rate of 6.10% priced at 99.779% to yield 6.11% to maturity (2035 Notes).

The notes are guaranteed by Utility Holdings’ three public utilities: SIGECO, Indiana Gas, and VEDO. These guarantees are full and unconditional and joint and several. The notes have no sinking fund requirements, and interest payments are due semi-annually. The notes may be called by Utility Holdings, in whole or in part, at any time for an amount equal to accrued and unpaid interest, plus the greater of 100% of the principal amount or the sum of the present values of the remaining scheduled payments of principal and interest, discounted to the redemption date on a semi-annual basis at the Treasury Rate, as defined in the indenture, plus 20 basis points for the 2015 Notes and 25 basis points for the 2035 Notes.

In January and June 2005, Utility Holdings entered into forward starting interest rate swaps with a notional value of $75 million. Upon issuance of the debt, the interest rate swaps were settled resulting in the receipt of approximately $1.9 million in cash, which was recorded as a regulatory liability pursuant to existing regulatory orders. The value received is being amortized as a reduction of interest expense over the life of the issue maturing December 2035.

The net proceeds from the sale of the senior notes and settlement of related hedging arrangements approximated $150 million and were used to repay short-term borrowings and to retire approximately $50 million of long-term debt with higher interest rates.

Vectren Capital Corp. 2005 Debt Issuance
On October 11, 2005, Vectren and Vectren Capital, entered into a private placement Note Purchase Agreement (2005 Note Purchase Agreement) pursuant to which various institutional investors purchased the following tranches of notes from Vectren Capital: (i) $25 million 4.99% Guaranteed Senior Notes, Series A due 2010, (ii) $25 million 5.13% Guaranteed Senior Notes, Series B due 2012 and (iii) $75 million 5.31% Guaranteed Senior Notes, Series C due 2015. These Guaranteed Senior Notes are unconditionally guaranteed by Vectren. The proceeds from this financing were received on December 15, 2005. This Note Purchase Agreement contains customary representations, warranties and covenants, including a covenant to the effect that the ratio of consolidated total debt to consolidated total capitalization will not exceed 75%.

On October 11, 2005, Vectren and Vectren Capital entered into First Amendments with respect to a Note Purchase Agreement dated as of December 31, 2000 pursuant to which Vectren Capital issued to institutional investors the following tranches of notes: (i) $38 million 7.67% Senior Notes due 2005, (ii) $17.5 million 7.83% Senior Notes due 2007, (iii) $22.5 million 7.98% Senior Notes due 2010 and (iv) a Note Purchase Agreement, dated April 25, 1997, pursuant to which Vectren Capital issued to an institutional investor a $35 million 7.43% Senior Note due 2012. The First Amendments (i) conform the covenants to those contained in the 2005 Note Purchase Agreement, (ii) eliminate a credit ratings trigger which would have afforded noteholders the option to require prepayment if the ratings of Indiana Gas or SIGECO fell below a certain level, (iii) substitute the unconditional guarantee by Vectren of the notes for the more limited support agreement previously in place and (iv) provide for a 100 basis point increase in interest rates if the ratio of consolidated total debt to total capitalization exceeds 65%.

Long-Term Debt Put & Call Provisions
Certain long-term debt issues contain put and call provisions that can be exercised on various dates before maturity. The put or call provisions are not triggered by specific events, but are based upon dates stated in the note agreements, such as when notes are remarketed. During 2006 and 2005, no debt was put to the Company. In 2004, debt totaling $2.5 million was put to the Company. Debt that may be put to the Company within one year is classified as Long-term debt subject to tender in current liabilities.

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Utility Holdings, SIGECO and Indiana Gas Debt Calls
In 2006, the Company called at par $100.0 million of Utility Holdings senior unsecured notes originally due in 2031. In 2005, the Company called at par $49.9 million of Indiana Gas insured quarterly senior unsecured notes originally due in 2030, and in 2004, called at par $20.0 million of Indiana Gas insured quarterly senior unsecured notes originally due in 2015. The notes called in 2006, 2005 and 2004 had stated interest rates of 7.25%, 7.45% and 7.15%, respectively.

Other Financing Transactions
At December 31, 2005, $53.7 million of SIGECO notes could be put to the Company in March of 2006, the date of their next remarketing. In March of 2006, the notes were successfully remarketed, and are now classified in Long-term debt. Prior to the remarketing, the notes had tax-exempt interest rates ranging from 4.75% to 5.00%. After the remarketing, interest rates are reset every seven days using an auction process.

During 2004, the Company remarketed two first mortgage bonds outstanding at SIGECO. The remarketing effort converted $32.8 million of outstanding fixed rate debt into variable rate debt where interest rates reset every seven days using an auction process. One bond, due in 2023, had a principal amount of $22.8 million and an interest rate of 6%. The other bond, due in 2015, had a principal amount of $10.0 million and an interest rate of 4.3%. These remarketing efforts resulted in the extinguishment and reissuance of debt at generally the same par value.

As part of the integration of Miller into the Company’s consolidated financing model, $24.0 million of Miller’s outstanding long-term debt was retired in the fourth quarter of 2006.

Other debt totaling $38.0 million in 2005 and $15.0 million in 2004 was retired as scheduled.

Investing Cash Flow

Cash flow required for investing activities was $337.4 million in 2006, $239.6 million in 2005, and $262.0 million in 2004. Capital expenditures are the primary component of investing activities. Capital expenditures were $281.4 million in 2006 compared to $231.6 million in 2005 and $252.5 million in 2004. The years ended December 31, 2006 and 2004 included higher levels of expenditures for environmental compliance equipment. Other investments in 2006 were principally impacted by the acquisition of Miller and advance royalty payments for future coal mine development.

Available Sources of Liquidity 

At December 31, 2006, the Company has $794.0 million of short-term borrowing capacity, including $520.0 million for the Utility Group and $274.0 million for the wholly owned Nonutility Group and corporate operations, of which approximately $250.0 million is available for the Utility Group operations and approximately $79.0 million is available for the wholly owned Nonutility Group and corporate operations.

During the fourth quarter of 2005, in response to higher natural gas prices, Utility Holdings increased its available consolidated short-term borrowing capacity to $520 million, a $165 million increase over previous levels. In addition, Utility Holdings extended the maturity of its largest credit facility, which totals $515 million, through November 2010. Vectren Capital also extended the maturity of its largest facility, which totals $255 million, through November 2010. The amendments were completed on November 10, 2005.

The Company may periodically issue new common shares to satisfy dividend reinvestment plan, stock option plan and other employee benefit plan requirements. New issuances added additional liquidity of $4.5 million in 2004.

Potential & Future Uses of Liquidity

Pension and Postretirement Funding Obligations
The Company believes making contributions to its qualified pension plans in the coming years will be necessary. Management currently estimates that the qualified pension plans will require minimum Company contributions of approximately $8 million in 2007 and approximately $10 million in 2008. During 2006, $8.3 million in contributions were made.

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Planned Capital Expenditures & Investments
Planned capital expenditures and investments in nonutility unconsolidated affiliates, including contractual purchase and investment commitments discussed below, for the five-year period 2007 - 2011 are estimated as follows:
 
                       
(In millions)
 
2007
 
2008
 
2009
 
2010
 
2011
 
Utility Group 
 
$
297.4
 
$
323.6
 
$
351.8
 
$
281.7
 
$
222.7
 
Nonutility Group 
   
74.7
   
108.8
   
72.8
   
26.1
   
31.5
 
   Total capital expenditures & investments
 
$
372.1
 
$
432.4
 
$
424.6
 
$
307.8
 
$
254.2
 

Contractual Obligations
The following is a summary of contractual obligations at December 31, 2006:

                               
(In millions)
 
Total
 
2007
 
2008
 
2009
 
2010
 
2011
 
Thereafter
 
                               
Long-term debt (1)
 
$
1,256.3
 
$
24.0
 
$
-
 
$
-
 
$
47.5
 
$
250.0
 
$
934.8
 
Short-term debt
   
464.8
   
464.8
   
-
   
-
   
-
   
-
   
-
 
Long-term debt interest commitments
   
986.7
   
75.3
   
73.4
   
73.4
   
73.4
   
69.0
   
622.2
 
Firm commodity purchase commitments
   
124.3
   
96.7
   
21.4
   
3.3
   
2.9
   
-
   
-
 
Plant purchase commitments (2)
   
392.4
   
66.4
   
113.0
   
115.0
   
70.0
   
28.0
   
-
 
Operating leases
   
18.3
   
7.7
   
4.6
   
2.6
   
1.5
   
0.9
   
1.0
 
     Total
 
$
3,242.8
 
$
734.9
 
$
212.4
 
$
194.3
 
$
195.3
 
$
347.9
 
$
1,558.0
 
 
(1)  
Certain long-term debt issues contain put and call provisions that can be exercised on various dates before maturity. These provisions allow holders to put debt back to the Company at face value or the Company to call debt at face value or at a premium. Long-term debt subject to tender during the years following 2006 (in millions) is $20.0 in 2007, zero in 2008, $80.0 in 2009, $10.0 in 2010, $30.0 in 2011 and zero thereafter.
(2)  
The settlement period of these utility & nonutility plant obligations is estimated.

The Company’s regulated utilities have both firm and non-firm commitments to purchase commodities 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 and their insignificant impact to earnings, they have not been included in the listing of contractual obligations.

Off Balance Sheet Arrangements

Guarantees and Letters of Credit
In the normal course of business, Vectren issues guarantees to third parties on behalf of its consolidated subsidiaries and unconsolidated affiliates. Such guarantees allow those subsidiaries and affiliates to execute transactions on more favorable terms than the subsidiary or affiliate could obtain without such a guarantee. Guarantees may include posted letters of credit, leasing guarantees, and performance guarantees. As of December 31, 2006, guarantees issued and outstanding on behalf of unconsolidated affiliates approximated $3.0 million. The Company has accrued no liabilities for these guarantees as they relate to guarantees issued among related parties, or such guarantees were executed prior to the adoption of FASB Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.”

In 2006, the Company issued a guarantee with an approximate $5.0 million maximum risk related to the residual value of an operating lease that expires in 2011. As of December 31, 2006, Vectren Corporation has a liability representing the fair value of that guarantee of approximately $0.1 million. Liabilities accrued for, and activity related to, product warranties are not significant. Through December 31, 2006, the Company has not been called upon to satisfy any obligations pursuant to its guarantees.

Ratings Triggers
None of Vectren’s currently outstanding debt arrangements contain ratings triggers.

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Forward-Looking Information

A “safe harbor” for forward-looking statements is provided by the Private Securities Litigation Reform Act of 1995 (Reform Act of 1995). The Reform Act of 1995 was adopted to encourage such forward-looking statements without the threat of litigation, provided those statements are identified as forward-looking and are accompanied by meaningful cautionary statements identifying important factors that could cause the actual results to differ materially from those projected in the statement. Certain matters described in Management’s Discussion and Analysis of Results of Operations and Financial Condition are forward-looking statements. Such statements are based on management’s beliefs, as well as assumptions made by and information currently available to management. When used in this filing, the words “believe”, “anticipate”, “endeavor”, “estimate”, “expect”, “objective”, “projection”, “forecast”, “goal” 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 supply 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.
·  
Increased competition in the energy environment including effects of industry restructuring and unbundling.
·  
Regulatory factors such as unanticipated changes in rate-setting policies or procedures, recovery of investments and costs made under traditional regulation, and the frequency and timing of rate increases.
·  
Financial, regulatory or accounting principles or policies imposed by the Financial Accounting Standards Board; the Securities and Exchange Commission; the Federal Energy Regulatory Commission; state public utility commissions; state entities which regulate electric and natural gas transmission and distribution, natural gas gathering and processing, electric power supply; and similar entities with regulatory oversight.
·  
Economic conditions including the effects of an economic downturn, inflation rates, commodity prices, and monetary fluctuations.
·  
Increased natural gas 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.
·  
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 realization of synfuel income tax credits and the Company’s coal mining, gas marketing, and energy infrastructure strategies.
·  
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.
·  
Employee or contractor workforce factors including changes in key executives, collective bargaining agreements with union employees, aging workforce issues, or work stoppages.
·  
Legal and regulatory delays and other obstacles associated with mergers, acquisitions and investments in joint ventures.
·  
Costs and other effects of legal and administrative proceedings, settlements, investigations, claims, and other matters, including, but not limited to, those described in Management’s Discussion and Analysis of Results of Operations and Financial Condition.
·  
Changes in federal, state or local legislative requirements, such as changes in tax laws or rates, environmental laws and 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.

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ITEM 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK

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

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

Commodity Price Risk

Regulated Operations
The Company’s regulated operations have limited exposure to commodity price risk for purchases and sales of natural gas and electricity for retail customers due to current Indiana and Ohio regulations, which subject to compliance with those regulations, allow for recovery of the cost of such purchases through natural gas and fuel cost adjustment mechanisms. Nevertheless, it is possible regulators may disallow recovery of a portion of gas costs for various reasons, including but not limited to, a finding by the regulator that natural gas was not prudently procured, as an example. Although Vectren’s regulated operations are exposed to limited commodity price risk, volatile natural gas prices can result in higher working capital requirements, increased expenses including unrecoverable interest costs, uncollectible accounts expense, and unaccounted for gas, and some level of price- sensitive reduction in volumes sold or delivered. The Company mitigates these risks by executing derivative contracts that manage the price of forecasted natural gas purchases. These contracts are subject to regulation which allows for reasonable and prudent hedging costs to be recovered through rates. Constructive regulatory orders, such as the Indiana and Ohio orders authorizing lost margin recovery, also mitigate these risks. When regulation is involved, SFAS 71 controls when the offset to mark-to-market accounting is recognized in earnings.

Commodity prices for natural gas purchases have remained above historical levels and continue to be more volatile. Despite hedging strategies, this near term change in natural gas commodity prices may have significant effects on operating results as described above.

Wholesale Power Marketing
The Company’s wholesale power marketing activities include asset optimization strategies that manage the utilization of available electric generating capacity. These optimization strategies involve the sale of excess generation into the MISO day ahead and real-time markets. As part of these strategies, the Company may also execute energy contracts that commit the Company to purchase and sell electricity in the future. Commodity price risk results from forward positions that commit the Company to deliver electricity. The Company mitigates price risk exposure with planned unutilized generation capability and offsetting forward purchase contracts. The Company accounts for asset optimization contracts that are derivatives at fair value with the offset marked to market through earnings.

Market risk resulting from commodity contracts is measured by management using the potential impact on pre-tax earnings caused by the effect a 10% adverse change in forward commodity prices might have on market sensitive derivative positions outstanding on specific dates. For the year ended December 31, 2005, a 10% adverse change in forward commodity prices would have decreased earnings by $0.3 million based upon open positions existing on the last day of that year. No such derivative contracts were outstanding on December 31, 2006.

Synfuel-Related Activities
Synfuel tax credits are only available when the price of oil is less than a base price specified by the Internal Revenue Code, as adjusted for inflation.  The Company has executed derivative instruments designed to limit the effects of a phase out of synfuel tax credits. If 2007 average oil prices are less than $63 per barrel, these derivatives, which as of December 31, 2006, have a fair value of $11.2 million, would expire without generating any value to the Company; however, no synfuel tax credits would likely be phased out. At $64 per barrel, these derivatives are expected to be worth approximately $2.8 million, and for every dollar increase in the price of oil up to $79, these derivatives are expected to increase in value approximately $2.8 million. At $79 per barrel or greater, these derivatives would reach a value in excess of $40 million; however, all synfuel tax credits would likely be phased out.

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

The Company purchases and sales commodities, including electricity, natural gas, and coal to meet customer demands and operational needs. The Company executes forward and option contracts that commit the Company to purchase and sell commodities in the future. Price risk from forward positions obligating the Company to deliver commodities is mitigated using stored inventory, generating capability, and offsetting forward purchase contracts. Price risk also results from forward contracts obligating the Company to purchase commodities to fulfill forecasted nonregulated sales of natural gas and coal that may or may not occur. With the exception of a small portion of contracts that are derivatives that qualify as hedges of forecasted transactions under SFAS 133, these contracts are expected to be settled by physical receipt or delivery of the commodity.

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

Interest Rate Risk

The Company is exposed to interest rate risk associated with its borrowing arrangements. Its risk management program seeks to reduce the potentially adverse effects that market volatility may have on interest expense. The Company manages this risk by allowing 20% and 30% of its total debt to be exposed to variable rate volatility. However, there are times when this targeted range of interest rate exposure may not be attained. To manage this exposure, the Company may use derivative financial instruments. At December 31, 2006, debt subject to short-term interest rate volatility and seasonal increases in short-term debt outstanding, represented 32% of the Company's total debt portfolio.

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 2006 and 2005, the weighted average combined borrowings under these arrangements were $342.2 million and $390.8 million, respectively. At December 31, 2006, and 2005, combined borrowings under these arrangements were $550.9 million and $349.8 million, respectively. Based upon average borrowing rates under these facilities during the years ended December 31, 2006 and 2005, an increase of 100 basis points (one percentage point) in the rates would have increased interest expense by $3.4 million and $3.9 million, respectively.

Other Risks

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

The Company’s customer receivables from gas and electric sales and gas transportation services are primarily derived from a diversified base of residential, commercial, and industrial customers located in Indiana and west central Ohio. The Company manages credit risk associated with its receivables by continually reviewing creditworthiness and requests cash deposits or refunds cash deposits based on that review. Credit risk associated with certain investments is also managed by a review of creditworthiness and receipt of collateral.

 
-44-

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 controls over financial reporting. Those control procedures underlie the preparation of the consolidated balance sheets, statements of income, cash flows, and common shareholders’ equity, and related footnotes contained herein.

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

These consolidated financial statements are also subject to an evaluation of internal control over financial reporting conducted under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer. Based on that evaluation, conducted under the framework in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, the Company concluded that its internal control over financial reporting was effective as of December 31, 2006. Management certified this fact in its Sarbanes Oxley Section 302 certifications, which are attached as exhibits to this 2006 Form 10-K.


-45-


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, 2006 and 2005, and the related consolidated statements of income, common shareholders’ equity and cash flows for each of the three years in the period ended December 31, 2006. Our audits also included the financial statement schedule listed in the Index at Item 15. We also have audited management’s assessment, included in the accompanying Management’s Report on Internal Control over Financial Reporting, included at Item 9A, that the Company maintained effective internal control over financial reporting as of December 31, 2006, 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 these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on these financial statements and financial statement schedule, an opinion on management’s assessment, and an opinion on the effectiveness of the Company’s internal control over financial reporting 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 and whether effective internal control over financial reporting was maintained in all material respects. Our audits of financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

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 consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006, 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. Also, in our opinion, management’s assessment that the Company maintained effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

As discussed in Note 7 to the consolidated financial statements, effective December 31, 2006 the Company adopted the provisions of Statement of Financial Accounting Standards No. 158, (Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans).

DELOITTE & TOUCHE LLP
Indianapolis, Indiana
February 16, 2007


-46-


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


           
   
At December 31,
 
   
2006
 
2005
 
ASSETS
         
           
Current Assets
         
Cash & cash equivalents 
 
$
32.8
 
$
20.4
 
Accounts receivable - less reserves of $3.1 &  
             
   $2.8, respectively
   
198.6
   
197.8
 
Accrued unbilled revenues 
   
146.5
   
240.6
 
Inventories 
   
163.5
   
144.6
 
Recoverable fuel & natural gas costs 
   
1.8
   
15.4
 
Prepayments & other current assets 
   
172.7
   
106.4
 
     Total current assets
   
715.9
   
725.2
 
               
Utility Plant
             
    Original cost
   
3,820.2
   
3,632.0
 
    Less: accumulated depreciation & amortization
   
1,434.7
   
1,380.1
 
     Net utility plant
   
2,385.5
   
2,251.9
 
               
Investments in unconsolidated affiliates
   
181.0
   
214.7
 
Other investments
   
74.5
   
111.6
 
Nonutility property - net
   
294.4
   
240.3
 
Goodwill - net
   
237.8
   
207.1
 
Regulatory assets
   
163.5
   
89.9
 
Other assets
   
39.0
   
27.4
 
TOTAL ASSETS
 
$
4,091.6
 
$
3,868.1
 


















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

 
-47-

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


           
   
At December 31,
 
   
2006
 
2005
 
LIABILITIES & SHAREHOLDERS' EQUITY
         
           
Current Liabilities
         
Accounts payable
 
$
180.0
 
$
159.0
 
Accounts payable to affiliated companies
   
89.9
   
162.3
 
Refundable fuel & natural gas costs
   
35.3
   
7.6
 
Accrued liabilities
   
147.2
   
156.6
 
Short-term borrowings
   
464.8
   
299.9
 
Current maturities of long-term debt
   
24.2
   
0.4
 
Long-term debt subject to tender
   
20.0
   
53.7
 
Total current liabilities
   
961.4
   
839.5
 
               
Long-term Debt - Net of Current Maturities &
             
Debt Subject to Tender
   
1,208.0
   
1,198.0
 
               
Deferred Income Taxes & Other Liabilities
             
Deferred income taxes
   
260.7
   
227.3
 
Regulatory liabilities
   
291.1
   
272.9
 
Deferred credits & other liabilities
   
195.8
   
186.7
 
Total deferred credits & other liabilities
   
747.6
   
686.9
 
               
Minority Interest in Subsidiary
   
0.4
   
0.4
 
               
Commitments & Contingencies (Notes 3, 12-14)
             
               
Common Shareholders' Equity
             
Common stock (no par value) – issued & outstanding
             
76.1 and 76.0, respectively
   
525.5
   
528.1
 
Retained earnings
   
643.6
   
628.8
 
Accumulated other comprehensive loss
   
5.1
   
(13.6
)
Total common shareholders' equity
   
1,174.2
   
1,143.3
 
               
TOTAL LIABILITIES & SHAREHOLDERS' EQUITY
 
$
4,091.6
 
$
3,868.1
 











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

-48-


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


   
Year Ended December 31,
 
   
2006
 
2005
 
2004
 
OPERATING REVENUES
             
Gas utility
 
$
1,232.5
 
$
1,359.7
 
$
1,126.2
 
Electric utility
   
422.2
   
421.4
   
371.3
 
Energy services & other
   
386.9
   
246.9
   
192.3
 
Total operating revenues
   
2,041.6
   
2,028.0
   
1,689.8
 
OPERATING EXPENSES
                   
Cost of gas sold
   
841.5
   
973.3
   
778.5
 
Cost of fuel & purchased power
   
151.5
   
144.1
   
116.8
 
Cost of energy services & other
   
248.7
   
191.0
   
143.5
 
Other operating
   
341.8
   
282.2
   
252.0
 
Depreciation & amortization
   
172.3
   
158.2
   
140.1
 
Taxes other than income taxes
   
65.3
   
66.1
   
59.4
 
Total operating expenses
   
1,821.1
   
1,814.9
   
1,490.3
 
OPERATING INCOME
   
220.5
   
213.1
   
199.5
 
OTHER INCOME
                   
Equity in earnings of unconsolidated affiliates
   
17.0
   
45.6
   
20.6
 
Other – net
   
(2.7
)
 
6.2
   
4.6
 
Total other income
   
14.3
   
51.8
   
25.2
 
Interest expense
   
95.6
   
83.9
   
77.7
 
INCOME BEFORE INCOME TAXES
   
139.2
   
181.0
   
147.0
 
Income taxes
   
30.3
   
44.1
   
39.0
 
Minority interest
   
0.1
   
0.1
   
0.1
 
NET INCOME
 
$
108.8
 
$
136.8
 
$
107.9
 
                     
AVERAGE COMMON SHARES OUTSTANDING
   
75.7
   
75.6
   
75.6
 
DILUTED COMMON SHARES OUTSTANDING
   
76.2
   
76.1
   
75.9
 
                     
EARNINGS PER SHARE OF COMMON STOCK:
                   
BASIC
 
$
1.44
 
$
1.81
 
$
1.43
 
DILUTED
 
$
1.43
 
$
1.80
 
$
1.42
 










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

-49-

VECTREN CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
   
Year Ended December 31,
 
   
2006
 
2005
 
2004
 
CASH FLOWS FROM OPERATING ACTIVITIES
             
Net income
 
$
108.8
 
$
136.8
 
$
107.9
 
Adjustments to reconcile net income to cash from operating activities:
                   
Depreciation & amortization
   
172.3
   
158.2
   
140.1
 
Deferred income taxes & investment tax credits
   
1.4
   
(8.6
)
 
5.9
 
Equity in earnings of unconsolidated affiliates
   
(17.0
)
 
(45.6
)
 
(20.6
)
Provision for uncollectible accounts
   
15.3
   
15.1
   
11.9
 
Expense portion of pension & postretirement benefit cost
   
10.7
   
10.7
   
11.8
 
Other non-cash charges - net
   
11.4
   
1.9
   
8.3
 
Changes in working capital accounts:
                   
Accounts receivable & accrued unbilled revenue
   
108.9
   
(102.9
)
 
(84.0
)
Inventories
   
(17.6
)
 
(71.9
)
 
0.4
 
Recoverable/refundable fuel & natural gas costs
   
41.3
   
3.5
   
8.9
 
Prepayments & other current assets
   
(21.2
)
 
36.1
   
(10.2
)
Accounts payable, including to affiliated companies
   
(71.6
)
 
101.2
   
42.5
 
Accrued liabilities
   
(23.2
)
 
27.4
   
11.2
 
Unconsolidated affiliate dividends
   
35.8
   
18.8
   
22.3
 
Changes in noncurrent assets
   
(25.8
)
 
(6.9
)
 
(3.5
)
Changes in noncurrent liabilities
   
(19.3
)
 
(5.4
)
 
(14.9
)
Net cash flows from operating activities
   
310.2
   
268.4
   
238.0
 
CASH FLOWS FROM FINANCING ACTIVITIES
                   
Proceeds from:
                   
Long-term debt - net of issuance costs
   
92.8
   
274.2
   
32.4
 
Stock option exercises & other stock plans
   
-
   
-
   
4.5
 
Requirements for:
                   
Dividends on common stock
   
(93.1
)
 
(90.5
)
 
(87.3
)
Retirement of long-term debt
   
(124.4
)
 
(88.5
)
 
(70.7
)
Redemption of preferred stock of subsidiary
   
-
   
(0.1
)
 
(0.1
)
Net change in short-term borrowings
   
164.9
   
(112.5
)
 
139.5
 
Other activity
   
(0.6
)
 
(0.6
)
 
-
 
Net cash flows from financing activities
   
39.6
   
(18.0
)
 
18.3
 
CASH FLOWS FROM INVESTING ACTIVITIES
                   
Proceeds from:
                   
Unconsolidated affiliate distributions
   
2.0
   
6.9
   
3.2
 
Other collections
   
3.4
   
4.3
   
9.3
 
Requirements for:
                   
Capital expenditures, excluding AFUDC equity
   
(281.4
)
 
(231.6
)
 
(252.5
)
Unconsolidated affiliate investments
   
(16.7
)
 
(19.2
)
 
(18.2
)
Other investments
   
(44.7
)
 
-
   
(3.8
)
Net cash flows from investing activities
   
(337.4
)
 
(239.6
)
 
(262.0
)
Net increase (decrease) in cash & cash equivalents
   
12.4
   
10.8
   
(5.7
)
Cash & cash equivalents at beginning of period
   
20.4
   
9.6
   
15.3
 
Cash & cash equivalents at end of period
 
$
32.8
 
$
20.4
 
$
9.6
 
                     
Cash paid during the year for:
                   
Interest
 
$
92.9
 
$
79.6
 
$
75.3
 
Income taxes
   
36.3
   
48.1
   
26.6
 
 
The accompanying notes are an integral part of these consolidated financial statements.

-50-

VECTREN CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY
(In millions, except per share amounts)

   
Common Stock
     
Accumulated
 
 
 
 
 
 
 
 
 
 
 
Other
 
 
 
 
 
 
 
 
 
Retained
 
Comprehensive
 
 
 
 
 
Shares
 
Amount
 
Earnings
 
Income (Loss)
 
Total
 
                       
Balance at January 1, 2004
   
75.6
 
$
520.4
 
$
562.4
 
$
(11.1
)
$
1,071.7
 
                                 
Comprehensive income:
                               
Net income
               
107.9
         
107.9
 
Minimum pension liability adjustments &
                               
other - net of tax
                     
(0.1
)
 
(0.1
)
Comprehensive income of unconsolidated
                               
affiliates - net of $2.6 in tax
                     
(3.8
)
 
(3.8
)
Total comprehensive income
                           
104.0
 
Common stock:
                               
Stock option exercises & other stock plans
   
0.2
   
4.5
               
4.5
 
Dividends ($1.15 per share)
               
(87.3
)
       
(87.3
)
Other
   
0.1
   
1.9
               
1.9
 
Balance at December 31, 2004
   
75.9
   
526.8
   
583.0
   
(15.0
)
 
1,094.8
 
                                 
Comprehensive income:
                               
Net income
               
136.8
         
136.8
 
Minimum pension liability adjustments &
                               
other - net of $0.1 in tax
                     
0.2
   
0.2
 
Cash flow hedges
                               
unrealized gains(losses) - net of $2.9 in tax
                     
4.2
   
4.2
 
reclassifications to net income- net of $0.2 in tax
                     
(0.2
)
  (0.2 
Comprehensive income of unconsolidated
                               
affiliates - net of $1.8 in tax
                     
(2.8
)
 
(2.8
)
Total comprehensive income
                           
138.4
 
Common stock:
                               
Dividends ($1.19 per share)
               
(90.5
)
       
(90.5
)
Other
   
0.1
   
1.3
   
(0.5
)
       
0.8
 
Balance at December 31, 2005
   
76.0
   
528.1
   
628.8
   
(13.6
)
 
1,143.3
 
                                 
Comprehensive income:
                               
Net income
               
108.8
         
108.8
 
Minimum pension liability adjustments &
                               
other - net of $5.4 in tax
                     
7.9
   
7.9
 
Cash flow hedge
                               
unrealized gains(losses) - net of $1.7 in tax
                     
(2.6
)
 
(2.6
)
reclassifications to net income- net of $0.7 in tax
                     
(1.0
)
 
(1.0
)
Comprehensive income of unconsolidated
                               
affiliates - net of $4.3 in tax
                     
6.4
   
6.4
 
Total comprehensive income
                           
119.5
 
Adoption of SFAS 158 - net of $5.2 in tax
                     
8.0
   
8.0
 
Common stock:
                               
Dividends ($1.23 per share)
               
(93.1
)
       
(93.1
)
Adoption of SFAS 123R
         
(4.1
)
             
(4.1
)
Other
   
0.1
   
1.5
   
(0.9
)
       
0.6
 
Balance at December 31, 2006
   
76.1
 
$
525.5
 
$
643.6
 
$
5.1
 
$
1,174.2
 
 
The accompanying notes are an integral part of these consolidated financial statements.
-51-



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 operating public utilities: Indiana Gas Company, Inc. (Indiana Gas), Southern Indiana Gas and Electric Company (SIGECO), and the Ohio operations. Utility Holdings also has other assets that provide information technology and other services to the three utilities. Utility Holdings’ consolidated operations are collectively referred to as the Utility Group. Both Vectren and Utility Holdings were exempt from registration pursuant to Section 3(a) (1) and 3(c) of the Public Utility Holding Company Act of 1935, which was repealed effective February 8, 2006 by the Energy Policy Act of 2005 (Energy Act). Both Vectren and Utility Holdings are holding companies as defined by the Energy Act.

Indiana Gas provides energy delivery services to approximately 565,000 natural gas customers located in central and southern Indiana. SIGECO provides energy delivery services to approximately 141,000 electric customers and approximately 112,000 gas customers located near Evansville in southwestern Indiana. SIGECO also owns and operates electric generation to serve its electric customers and optimizes those assets in the wholesale power market. Indiana Gas and SIGECO generally do business as Vectren Energy Delivery of Indiana. The Ohio operations provide energy delivery services to approximately 318,000 natural gas customers located near Dayton in west central Ohio. The Ohio operations are owned as a tenancy in common by Vectren Energy Delivery of Ohio, Inc. (VEDO), a wholly owned subsidiary of Utility Holdings (53% ownership), and Indiana Gas (47% ownership). The Ohio operations generally do business as Vectren Energy Delivery of Ohio.

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

2.  
Summary of Significant Accounting Policies

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

The Company has investments in partnership-like structures that are variable interest entities as defined by FASB Interpretation 46(R), “Consolidation of Variable Interest Entities” as a limited partner or as a subordinated lender. The activities of these entities are to purchase or construct as well as operate multifamily housing and office properties. The Company’s exposure to loss is limited to its investment which as of December 31, 2006, and 2005, totaled $13.4 million and $15.1 million, respectively, of Investments in unconsolidated affiliates, and $11.5 million and $13.4 million, respectively, of Other investments. The Company is also the equity owner in three leveraged leases where its exposure to loss is limited to its net investment, which as of December 31, 2006, and 2005, totaled $10.2 million and $7.8 million, respectively. The Company does not consolidate any of these entities.

B.  
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.

-52-



C.  
Inventories
Inventories consist of the following:
 
   
At December 31,
 
(In millions)
 
2006
 
2005
 
Gas in storage – at average cost
 
$
73.0
 
$
73.3
 
Materials & supplies
   
29.5
   
30.2
 
Fuel (coal & oil) for electric generation
   
31.2
   
19.4
 
Gas in storage – at LIFO cost
   
26.5
   
18.8
 
Other
   
3.3
   
2.9
 
Total inventories
 
$
163.5
 
$
144.6
 

Based on the average cost of gas purchased during December, the cost of replacing gas in storage carried at LIFO cost exceeded LIFO cost at December 31, 2006, and 2005, by approximately $79.0 million and $117.0 million, respectively. Gas in storage of the Indiana regulated operations is stated at LIFO. All other inventories are carried at average cost.

D.  
Utility Plant & Depreciation
Utility plant is stated at historical cost, including AFUDC. Depreciation rates are established through regulatory proceedings and are applied to all in-service utility plant. The original cost of utility plant, together with depreciation rates expressed as a percentage of original cost, follows:


                   
   
At December 31,
     
(In millions)
 
2006
 
 
 
2005
 
   
   
Original Cost
 
Depreciation
Rates as a
Percent of
Original Cost
 
Original Cost
 
Depreciation
Rates as a
 Percent of
 Original Cost
 
Gas utility plant
 
$
1,956.1
   
3.6
%
$
1,879.1
   
3.5
%
Electric utility plant
   
1,685.5
   
3.7
%
 
1,611.4
   
3.7
%
Common utility plant
   
45.2
   
2.6
%
 
44.2
   
2.6
%
Construction work in progress
   
133.4
   
-
   
97.3
   
-
 
Total original cost
 
$
3,820.2
       
$
3,632.0
       

AFUDC represents the cost of borrowed and equity funds which are used for construction purposes, and charged to construction work in progress during the construction period. AFUDC is included in Other - net in the Consolidated Statements of Income. The total AFUDC capitalized into utility plant and the portion of which was computed on borrowed and equity funds for all periods reported follows:


   
 Year Ended December 31,
(In millions)
2006
 
2005
 
2004
AFUDC – borrowed funds
 
$ 2.6
 
$ 1.6
 
$ 1.6
AFUDC – equity funds
 
1.5
 
0.3
 
1.6
 
Total AFUDC
 
$ 4.1
 
$ 1.9
 
$ 3.2

Maintenance and repairs, including the cost of removal of minor items of property and planned major maintenance projects, are charged to expense as incurred. 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. Costs to dismantle and remove retired property are recovered through the depreciation rates identified above.

-53-


Jointly Owned Plant
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, 2006 is $63.2 million with accumulated depreciation totaling $43.5 million. AGC and SIGECO also share equally in the cost of operation and output of the unit. SIGECO's share of operating costs is included in Other operating expenses in the Consolidated Statements of Income.

E.  
Nonutility Property
Nonutility property, net of accumulated depreciation and amortization follows:

   
At December 31,
 
(In millions)
 
2006
 
2005
 
Computer hardware & software
 
$
107.7
 
$
105.6
 
Land & buildings
   
73.4
   
69.5
 
Coal mine development costs & equipment
   
59.7
   
50.0
 
Vehicles & equipment
   
33.0
     1.1   
All other
   
20.6
   
14.1
 
Nonutility property - net
 
$
294.4
 
$
240.3
 
 
The depreciation of nonutility property is charged against income over its estimated useful life (ranging from 5 to 40 years), using the straight-line method of depreciation or units-of-production method of amortization. Repairs and maintenance, which are not considered improvements and do not extend the useful life of the nonutility property, are charged to expense as incurred. 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. Nonutility property is presented net of accumulated depreciation and amortization totaling $217.0 million and $144.6 million as of December 31, 2006, and 2005, respectively. For the years ended December 31, 2006, 2005, and 2004, the Company capitalized interest totaling $1.2 million, $0.4 million, and $1.4 million, respectively, on nonutility plant construction projects.

F.  
Goodwill
Goodwill arising from business combinations is accounted for in accordance with SFAS No. 142, “Goodwill and Other Intangible Assets” (SFAS 142). SFAS 142 requires a portion of goodwill be charged to expense only when it is impaired. The Company tests its goodwill for impairment at a reporting unit level at least annually and that test is performed at the beginning of each year. Impairment reviews consist of a comparison of the fair value of a reporting unit to its carrying amount. If the fair value of a reporting unit is less than its carrying amount, an impairment loss is recognized in operations. Through December 31, 2006, no goodwill impairments have been recorded. Approximately $205.0 million of the Company’s goodwill is included in the Gas Utility Services operating segment. The remaining $32.8 million is attributable to the Nonutility Group.

G.  
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 rate-making and accounting practices of these agencies and to accounting principles generally accepted in the United States, including the provisions of SFAS No. 71 “Accounting for the Effects of Certain Types of Regulation” (SFAS 71).

Refundable or Recoverable Gas Costs and 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 an agreed upon benchmark, 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 for electric generation is charged to operating expense when consumed.
 
Regulatory Assets and 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 assesses the recoverability of costs recognized as regulatory assets and liabilities and the ability to continue to account for its activities based on the criteria set forth in SFAS 71. Based on current regulation, the Company believes such accounting is appropriate. If all or part of the Company's operations cease to meet the criteria of SFAS 71, 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.

-54-

Regulatory assets consist of the following:

   
At December 31,
 
(In millions)
 
2006
 
2005
 
Future amounts recoverable from ratepayers related to:
         
Benefit obligations
 
$
46.7
 
$
-
 
Income taxes
   
13.3
   
11.1
 
Asset retirement obligations & other
   
5.2
   
1.7
 
     
65.2
   
12.8
 
Amounts deferred for future recovery related to:
             
Demand side management programs
   
27.7
   
26.7
 
MISO-related costs
   
17.1
   
9.4
 
Cost recovery riders & other
   
4.7
   
2.5
 
     
49.5
   
38.6
 
Amounts currently recovered through base rates related to:
             
Unamortized debt issue costs
   
23.1
   
20.2
 
Premiums paid to reacquire debt
   
6.0
   
6.5
 
Demand side management programs & other
   
3.3
   
4.5
 
     
32.4
   
31.2
 
Amounts currently recovered through tracking mechanisms related to:
             
Ohio authorized trackers
   
10.3
   
5.6
 
Indiana authorized trackers
   
6.1
   
1.7
 
     
16.4
   
7.3
 
Total regulatory assets
 
$
163.5
 
$
89.9
 

Of the $32.4 million currently being recovered through base rates charged to customers, $1.5 million is earning a return. The weighted average recovery period of regulatory assets currently being recovered is 14.4 years. The Company has rate orders for all deferred costs not yet in rates and therefore believes that future recovery is probable.

Regulatory liabilities consist of the following:

           
 
 At December 31,
 
(In millions)
 
2006
 
2005
 
Advances from rate-payers related to:
         
Cost of removal
 
$
270.6
 
$
251.4
 
Asset retirement obligations
   
11.3
   
11.6
 
     
281.9
   
263.0
 
Amounts currently amortizing related to:
             
Interest rate hedging proceeds (See Note 15)
   
6.1
   
6.8
 
Amounts deferred for future settlement related to:
             
MISO-related costs
   
3.1
   
3.1
 
Total regulatory liabilities
 
$
291.1
 
$
272.9
 
 
-55-

Cost of Removal 
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 as defined by SFAS No. 143, “Accounting for Asset Retirement Obligations” and its related interpretations (SFAS 143).

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 regulatory liability above represents a timing difference between cost recognition described in SFAS 143, and cost recognition established in regulatory proceedings for these obligations.

H.  
Asset Retirement Obligations
SFAS No. 143 requires entities to record 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 entity capitalizes a cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss. To the extent regulation is involved, such gain or loss may be deferred.

Asset retirement obligations total $20.8 million at both December 31, 2006 and 2005, and are included in Other Liabilities. During 2006, the Company recorded reductions in estimates totaling $1.2 million and accretion of $1.2 million. In 2005, the Company recorded accretion of $0.3 million and recorded additional liabilities of $16.1 million. Of those additions, $16.0 million were recognized upon adoption of FASB Interpretation No. 47.
 
I.  
Impairment Review of Long-Lived Assets
Long-lived assets are reviewed as facts and circumstances indicate that the carrying amount may be impaired. This review is performed in accordance with SFAS No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets” (SFAS 144). SFAS 144 establishes one accounting model for all impaired long-lived assets and long-lived assets to be disposed of by sale or otherwise. SFAS 144 requires that the evaluation for impairment involve the comparison of an asset’s carrying value to the estimated future cash flows that the asset is expected to generate over its remaining life. If this evaluation were to conclude that the carrying value of the asset is impaired, an impairment charge would be recorded based on the difference between the asset’s 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.

J.  
Comprehensive Income
Comprehensive income is a measure of all changes in equity that result from the non-shareholder transactions. This information is reported in the Consolidated Statements of Common Shareholders' Equity. A summary of the components of and changes in Accumulated other comprehensive income for the past three years follows:
                               
   
2004
 
2005
 
2006
 
   
Beginning
 
Changes
 
End
 
Changes
 
End
 
Changes
 
End
 
 
 
of Year
 
During
 
of Year
 
During
 
of Year
 
During
 
of Year
 
(In millions)
 
Balance
 
Year
 
Balance
 
Year
 
Balance
 
Year
 
Balance
 
                               
Unconsolidated affiliates
 
$
10.5
 
$
(6.4
)
$
4.1
 
$
(4.6
)
$
(0.5
)
$
10.7
   
10.2
 
Pension & other benefit costs
   
(29.2
)
 
(0.1
)
 
(29.3
)
 
0.3
   
(29.0
)
 
26.5
   
(2.5
)
Cash flow hedges
   
-
   
-
   
-
   
6.7
   
6.7
   
(6.0
)
 
0.7
 
Deferred income taxes
   
7.6
   
2.6
   
10.2
   
(1.0
)
 
9.2
   
(12.5
)
 
(3.3
)
Accumulated other
comprehensive income (loss)
 
$
(11.1
)
$
(3.9
)
$
(15.0
)
$
1.4
 
$
(13.6
)
$
18.7
 
$
5.1
 
 
Accumulated other comprehensive income arising from unconsolidated affiliates is primarily the Company’s portion of ProLiance Energy, LLC’s accumulated comprehensive income related to use of cash flow hedges, including commodity contracts, and the Company’s portion of Haddington Energy Partners, LP’s accumulated comprehensive income related to unrealized gains and losses on marketable securities. (See Note 3 for more information on unconsolidated affiliates.) 
 
K.  
Revenues
Revenues are recorded as products and services are delivered to customers. To more closely match revenues and expenses, the Company records revenues for all gas and electricity delivered to customers but not billed at the end of the accounting period.
 
L.  
Excise and Utility Receipts Taxes
Excise taxes and a portion of utility receipts taxes are included in rates charged to customers. Accordingly, the Company records these taxes received as a component of operating revenues, which totaled $39.7 million in 2006, $42.6 million in 2005, and $38.3 million in 2004. Expense associated with excise and utility receipts taxes are recorded as a component of Taxes other than income taxes.

-56-

 
 
M.  
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates.

N.  
Other Significant Policies
Included elsewhere in these Notes are significant accounting policies related to investments in unconsolidated affiliates (Note 3), income taxes (Note 6), earnings per share (Note 11), and derivatives (Note 15).

As more fully described in Note 9, the Company applied the intrinsic method prescribed in APB Opinion 25, “Accounting for Stock Issued to Employees” (APB 25) and related interpretations when measuring compensation expense for its share-based compensation plans in the years prior to 2006. The exercise price of stock options awarded under the Company’s stock option plans equaled the fair market value of the underlying common stock on the date of grant. Accordingly, no compensation expense was recognized related to stock option plans prior to 2006. The Company also maintains restricted stock and phantom stock plans for executives, employees, and non-employee directors that result in share-based compensation expense recognized in reported net income consistent with expense that would have been recognized if the Company used the fair value based method prescribed in SFAS No. 123 “Accounting for Stock-Based Compensation” (SFAS 123) in those years. For the years ended December 31, 2005 and 2004, the effect on net income and earnings per share as if the fair value based method prescribed in SFAS 123 had been applied follows:


   
Year Ended December 31,
 
(In millions, except per share amounts)
 
2005
 
2004
 
Net Income as reported:
 
$
136.8
 
$
107.9
 
               
Share-based employee compensation included in reported net income-net of tax
   
2.1
   
1.7
 
               
Total share-based employee compensation expense determined under fair value
             
based method for all awards-net of tax
   
(2.8
)
 
(2.6
)
Pro forma
 
$
136.1
 
$
107.0
 
               
Basic earnings per share as reported:
 
$
1.81
 
$
1.43
 
Basic earnings per share pro forma:
   
1.80
   
1.42
 
               
Diluted earnings per share as reported:
 
$
1.80
 
$
1.42
 
Diluted earnings per share pro forma:
   
1.79
   
1.41
 
 
 
3.    
Investments in Unconsolidated Affiliates

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

-57-


Investments in unconsolidated affiliates consist of the following:


   
At December 31,
 
(In millions)
 
2006
 
2005
 
ProLiance Energy, LLC 
 
$
146.7
 
$
136.5
 
Haddington Energy Partnerships 
   
13.8
   
10.8
 
Reliant Services, LLC 
   
2.8
   
29.3
 
Utilicom Networks, LLC & related entities 
   
-
   
11.7
 
Pace Carbon Synfuels, LP 
   
-
   
9.6
 
Other partnerships & corporations 
   
17.7
   
16.8
 
   Total investments in unconsolidated affiliates
 
$
181.0
 
$
214.7
 
 
ProLiance Energy, LLC
ProLiance Energy, LLC (ProLiance), a nonutility gas marketing and energy management affiliate of Vectren and Citizens Gas and Coke Utility (Citizens Gas), 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 primary customers include Vectren’s Indiana utilities and nonutility gas supply operations as well as Citizens Gas. ProLiance’s primary businesses include gas marketing, gas portfolio optimization, and other portfolio and energy management services. The Company, including its retail gas supply operations, contracted for 75% of its natural gas purchases through ProLiance in 2006. Pre-tax income of $35.3 million, $52.4 million, and $25.9 million was recognized as ProLiance’s contribution to earnings for the years ended December 31, 2006, 2005, and 2004, respectively. ProLiance is a significant subsidiary for the purposes of Regulation S-X, paragraph 3.09, as promulgated by the SEC.

Summarized Financial Information

               
   
Year Ended December 31,
 
(in millions)
 
2006
 
2005
 
2004
 
Summarized Statement of Income information:
             
Revenues
 
$
2,506.2
 
$
3,237.0
 
$
2,573.8
 
Margin
   
106.3
   
116.0
   
74.0
 
Operating income
   
74.5
   
87.1
   
43.2
 
ProLiance's earnings
   
57.9
   
86.0
   
42.6
 


           
   
As of December 31,
 
(In millions)
 
2006
 
2005
 
Summarized balance sheet information:
         
Current assets
 
$
641.3
 
$
870.2
 
Noncurrent assets
   
41.5
   
50.7
 
Current liabilities
   
445.0
   
698.2
 
Noncurrent liabilities
   
1.8
   
3.3
 
Equity
   
236.0
   
219.4
 

Vectren’s share of ProLiance’s earnings, after income taxes and allocated interest expense, was $18.3 million, $31.1 million, and $15.4 million for the years ended December 31, 2006, 2005, and 2004, respectively.

Transactions with ProLiance
Purchases from ProLiance for resale and for injections into storage for the years ended December 31, 2006, 2005, and 2004, totaled $777.0 million, $1,049.3 million, and $875.9 million, respectively. Amounts owed to ProLiance at December 31, 2006, and 2005, for those purchases were $84.8 million and $159.1 million, respectively, and are included in Accounts payable to affiliated companies in the Consolidated Balance Sheets. Amounts charged by ProLiance for gas supply services are established by supply agreements with each utility.

Vectren received regulatory approval on April 25, 2006, from the IURC for ProLiance to provide natural gas supply services to the Company’s Indiana utilities through March 2011. ProLiance has not provided gas supply/portfolio administration services to VEDO since October 31, 2005.

-58-

ProLiance Lawsuit Settlement
On November 22, 2006, ProLiance agreed to settle a 2002 civil lawsuit between the City of Huntsville, Alabama and ProLiance. The $21.6 million settlement (Huntsville Settlement) relates to a dispute over a contractual relationship with Huntsville Utilities during 2000-2002.

During 2006, ProLiance recorded an $18.3 million charge recognizing the Huntsville Settlement. During 2004, ProLiance recorded $3.9 million as a reserve for loss contingency recognizing the initial unfavorable judgment and the uncertainties related to ultimate outcome. During 2006 and 2005, $0.1 million and $0.5 million of legal fees were charged against the reserve.

As an equity investor in ProLiance, Vectren recorded its share of these charges which totaled $6.6 million after tax in 2006 and $1.4 million after tax in 2004. Vectren is currently exploring whether a portion of those charges may be recoverable from insurance carriers.

Commodity Prices
In response to the effects of higher gas costs, ProLiance increased its unsecured revolving credit facilities. Those facilities expire in June 2009. These facilities total $400 million from October 1 through March 31 and $300 million from April 1 through September 30. These credit facilities are not guaranteed by Vectren Corporation.

Haddington Energy Partnerships
The Company has an approximate 40% ownership interest in Haddington Energy Partners, LP (Haddington I) and Haddington Energy Partners II, LP (Haddington II). On a combined basis, these partnerships raised a total of $67 million to invest in energy related ventures. As of December 31, 2006, the Company has no further commitments to invest in either Haddington I or II. As of December 31, 2006, these Haddington ventures have two remaining investments related to compressed air storage and liquefied natural gas storage.  Both Haddington ventures are investment companies accounted for using the equity method of accounting.  Pre-tax earnings of $0.3 million, $7.7 million, and $4.5 million were recognized as the partnerships’ contribution to earnings for the years ended December 31, 2006, 2005 and 2004, respectively.

The following is summarized financial information as to the assets, liabilities, and results of operations of the Haddington Partnerships. For the year ended December 31, 2006, revenues, operating loss, and net loss were (in millions) zero, $(0.3), and $(0.3), respectively. For the year ended December 31, 2005, revenues, operating income, and net income were (in millions) $13.2, $12.4, and $22.2, respectively. For the year ended December 31, 2004, revenues, operating income, and net income were (in millions) $3.3, $2.5, and $9.6, respectively. As of December 31, 2006, investments, other assets, and liabilities were (in millions) $31.3, $1.1, and zero, respectively. As of December 31, 2005, investments, other assets, and liabilities were (in millions) $25.0, $1.2, and zero, respectively.

Pace Carbon Synfuels, LP
Pace Carbon Synfuels, LP (Pace Carbon) is a Delaware limited partnership formed to develop, own, and operate four projects to produce and sell coal-based synthetic fuel (synfuel) utilizing Covol technology.  The Company has an 8.3 percent interest in Pace Carbon which is accounted for using the equity method of accounting.  The Internal Revenue Code provides for manufacturers, such as Pace Carbon, to receive a tax credit for every ton of synthetic fuel sold.  Under current tax laws, these synfuel related credits and fees cease at the end of 2007.

The Internal Revenue Service has issued private letter rulings, which concluded that the synthetic fuel produced at the Pace Carbon facilities should qualify for tax credits.  The IRS has completed tax audits of Pace Carbon for the years 1998 through 2001 without challenging tax credit calculations.  As a partner in Pace Carbon, Vectren has reflected synfuel tax credits in its consolidated results from inception through December 31, 2006, of approximately $92 million, of which approximately $81 have been generated since 2001. To date, Vectren has been in a position to utilize or carryforward substantially all of the credits generated. Primarily from the use of these credits, the Company generated an Alternative Minimum Tax (AMT) credit carryforward. The Company has an accumulated AMT credit carryforward of approximately $42.1 million at December 31, 2006.
 
-59-

Synfuel tax credits are only available when the price of oil is less than a base price specified by the Internal Revenue Code, as adjusted for inflation.  The Company estimates that high oil prices caused a 35 percent phase out of synfuel tax credits in 2006. Therefore, of the $21.5 million tax credits generated in 2006, only $14.0 million are reflected as a reduction to the Company’s Income taxes.

In July 2006, the Company suspended its participation in the production of synthetic fuel due to the high price of oil and uncertainty of federal legislation that might favorably affect the reference price of oil governing the phase out of synfuel tax credits.  Consistent with that decision to suspend participation, the Company impaired its investment in Pace Carbon and expensed funding requirements estimated at that time.  Charges approximating $9.5 million, or $5.7 million after tax, were recorded in Other-net in the second quarter of 2006. The Company resumed participation in October 2006 as oil prices began to fall.

For the year ended December 31, 2006, synfuel-related activity, inclusive of the phase out of tax credits, the impairment of synfuel-related assets, the related hedging activity, and estimated impact of insurance contracts, resulted in an after tax loss of $3.8 million, or $0.05 per share. Mark-to-market losses associated with financial contracts hedging 2007 production recognized in 2006 totaled $1.5 million after tax, or $0.02 per share. In 2005 and 2004, synfuel-related earnings totaled $11.7 million and $12.1 million, respectively. The investment in Pace Carbon resulted in losses reflected in Equity in earnings of unconsolidated affiliates totaling $17.8 million in 2006, $15.7 million in 2005, and $12.0 million in 2004.

The following is summarized financial information as to the assets, liabilities, and results of operations of Pace Carbon. For the year ended December 31, 2006, revenues, margin, operating loss, and net loss were (in millions) $389.7, ($116.4), ($175.5), and ($176.8), respectively. For the year ended December 31, 2005, revenues, margin, operating loss, and net loss were (in millions) $333.4, ($135.3), ($170.3), and ($175.7), respectively. For the year ended December 31, 2004, revenues, margin, operating loss, and net loss were (in millions) $243.0, ($99.8), ($128.6), and ($141.1), respectively. As of December 31, 2006, current assets, noncurrent assets, current liabilities, and noncurrent liabilities were (in millions) $61.3, $54.4, $46.6, and $36.5, respectively. As of December 31, 2005, current assets, noncurrent assets, current liabilities, and noncurrent liabilities were (in millions) $72.8, $53.0, $43.4, and $24.5, respectively.

Utilicom Networks, LLC & Related Entities
The Company had an approximate 2% equity interest and a convertible subordinated debt investment in Utilicom Networks, LLC (Utilicom). The Company also had an approximate 19% equity interest in SIGECOM Holdings, Inc. (Holdings), which was formed by Utilicom to hold interests in SIGECOM, LLC (SIGECOM). SIGECOM provides broadband services, such as cable television, high-speed internet, and advanced local and long distance phone services, to the greater Evansville, Indiana area. The Company accounted for its investments in Utilicom and Holdings using the cost method of accounting.

Other Utilicom-related subsidiaries also owned franchising agreements to provide broadband services to the greater Indianapolis, Indiana and Dayton, Ohio markets. In 2004, the build out of these markets was further evaluated, and the Company concluded that it was unlikely it would make additional investments in those markets. As a result, the Company recorded charges totaling $6.0 million, or $3.6 million after-tax, to write off investments made in the Indianapolis and Dayton markets and to write down its investment in SIGECOM.

In August 2006, SIGECOM’s majority owner and the Company sold their interests in SIGECOM to WideOpenWest, LLC.  Resulting from the sale, the Company recorded a loss of $1.3 million after tax in 2006. Proceeds to the Company, which include the settlement of notes receivable, are expected to total approximately $45 million. The Company anticipates receiving the proceeds in early 2007. Since proceeds are expected in 2007, the Company has classified these expected proceeds in Current assets.

Undistributed Earnings of Unconsolidated Affiliates
As of December 31, 2006, undistributed earnings of unconsolidated affiliates approximated $127 million and are primarily comprised of the undistributed earnings of ProLiance.

-60-

4.    
Miller Pipeline Corporation Acquisition

Effective July 1, 2006, the Company purchased the remaining 50% ownership in Miller Pipeline Corporation (Miller), making Miller a wholly owned subsidiary. The results of Miller’s operations, formerly accounted for using the equity method, have been included in consolidated results since July 1, 2006.  Based on current accounting rules, Miller is consolidated on a prospective basis only. Prior periods were not restated.

Miller, originally founded in 1953, performs natural gas and water distribution, transmission, and construction repair and rehabilitation primarily in the Midwest and the repair and rehabilitation of gas, water, and wastewater facilities nationwide.  Miller’s customers include Vectren’s utilities.
 
While the acquisition of Miller is not expected to have a material impact on the overall financial statements, consolidating Miller resulted in, among other impacts, a $77.6 million increase in Nonutility revenues and a $60.8 million increase in Other operating expense when compared to 2005 and 2004. The transaction also increased consolidated Goodwill by approximately $31 million, intangible assets, which are included in Other assets, by $14 million, and $24 million in Long-term debt. The Company is in the process of completing the asset valuation process regarding deferred taxes and intangible assets; thus, the allocation of the purchase price is not complete and is subject to change. Of the $31 million of goodwill, approximately $0.9 million is not deductible for tax purposes based upon the current purchase price allocation.
 
Prior to this transaction, Miller was 100 percent owned by Reliant Services, LLC (Reliant). Reliant, a 50% owned strategic alliance with an affiliate of Duke Energy Corporation, is accounted for using the equity method of accounting, and previously provided facilities locating and meter reading services to the Company’s utilities. For the years ended December 31, 2006, 2005, and 2004, fees paid to Reliant for locating and meter reading services as well as for Miller’s construction-related services totaled $15.9 million, $21.3 million, and $31.2 million, respectively. Amounts charged are market based. Amounts owed to Reliant totaled less than $0.1 million at December 31, 2006 and $3.2 million at December 31, 2005, and are included in Accounts payable to affiliated companies in the Consolidated Balance Sheets. Reliant exited the meter reading and facilities locating businesses in 2006.

5.    
Other Investments

Other investments consist of the following:

   
At December 31,
 
(In millions)
 
2006
 
2005
 
Leveraged leases
 
$
31.0
 
$
32.6
 
Convertible notes receivable from Utilicom-related entities (See Note 3)
   
-
   
33.1
 
Other investments
   
43.5
   
45.9
 
Total other investments 
 
$
74.5
 
$
111.6
 

Leveraged Leases
The Company is a lessor in three leveraged lease agreements under which real estate or equipment is leased to third parties. The total equipment and facilities cost was approximately $76.2 million at both December 31, 2006, and 2005, respectively. The cost of the equipment and facilities was partially financed by non-recourse debt provided by lenders who have been granted an assignment of rentals due under the leases and a security interest in the leased property, which they accepted as their sole remedy in the event of default by the lessee. Such debt amounted to approximately $47.4 million and $44.5 million at December 31, 2006, and 2005, respectively. At December 31, 2006 and 2005, the Company’s leveraged lease investment, net of related deferred tax liabilities, was $10.2 million and $7.8 million, respectively.

Other Investments
Other investments include other notes receivable, the cash surrender value of life insurance policies, restricted cash, and a municipal bond, among other items.

-61-



6.    
Income Taxes

The liability method of accounting is used for income taxes under which deferred income taxes are recognized to reflect the tax effect of temporary differences between the book and tax bases of assets and liabilities at currently enacted income tax rates. Significant components of the net deferred tax liability follow:
   
At December 31,
 
(In millions)
 
2006
 
2005
 
Noncurrent deferred tax liabilities (assets):
         
Depreciation & cost recovery timing differences 
 
$
297.0
 
$
288.3
 
Leveraged leases 
   
20.8
   
24.8
 
Regulatory assets recoverable through future rates 
   
21.0
   
19.3
 
Demand side management programs 
   
8.4
   
7.7
 
Other comprehensive income 
   
2.5
   
(9.2
)
Alternative minimum tax carryforward 
   
(42.1
)
 
(47.4
)
Employee benefit obligations 
   
(39.2
)
 
(36.0
)
Net operating loss & other carryforwards 
   
(10.1
)
 
(1.7
)
   Regulatory liabilities to be settled through future rates      (7.7   (8.2
Other – net 
   
10.1
   
(10.3
)
 Net noncurrent deferred tax liability
   
260.7
   
227.3
 
Current deferred tax (assets)/liabilities:
             
Deferred fuel costs-net 
   
(1.8
)
 
7.6
 
Other – net 
   
(1.8
)
 
-
 
   Net current deferred tax (asset)/liability
   
(3.6
)
 
7.6
 
   Net deferred tax liability
 
$
257.1
 
$
234.9
 

At December 31, 2006, and 2005, investment tax credits totaling $9.9 million and $11.8 million, respectively, are included in Deferred credits and other liabilities. These investment tax credits are amortized over the lives of the related investments. At December 31, 2006, the Company has alternative minimum tax carryforwards of $42.1 million, which do not expire and $1.6 million of other tax credit carryforwards that expire in approximately 20 years. In addition, the Company has $8.3 million in net operating loss carryforwards that relate to the acquisition of Miller, which will expire in 5 to 20 years.

The components of income tax expense and utilization of investment tax credits follow:
 
   
Year Ended December 31,
 
(In millions)
 
2006
 
2005
 
2004
 
Current:
             
Federal
 
$
18.2
 
$
37.9
 
$
24.1
 
State
   
10.7
   
14.8
   
9.0
 
Total current taxes
   
28.9
   
52.7
   
33.1
 
Deferred:
                   
Federal
   
7.0
   
(6.0
)
 
3.8
 
State
   
(3.6
)
 
(0.2
)
 
4.3
 
Total deferred taxes
   
3.4
   
(6.2
)
 
8.1
 
Amortization of investment tax credits
   
(2.0
)
 
(2.4
)
 
(2.2
)
Total income tax expense
 
$
30.3
 
$
44.1
 
$
39.0
 

-62-



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

   
Year Ended December 31,    
 
   
2006
 
 2005
 
 2004
 
Statutory rate
   
35.0
%
 
35.0
%
 
35.0
%
State and local taxes-net of federal benefit
   
5.7
   
5.5
   
5.9
 
Synfuel tax credits
   
(9.6
)
 
(12.3
)
 
(11.6
)
Adjustment of income tax accruals
   
(2.0
)
 
(1.9
)
 
(0.1
)
Tax law change
   
(2.5
)
 
-
   
-
 
Amortization of investment tax credit
   
(1.4
)
 
(1.3
)
 
(1.5
)
Depletion
   
(1.6
)
 
(1.0
)
 
(0.6
)
Other tax credits
   
(0.5
)
 
(0.4
)
 
(0.6
)
All other-net
   
(1.3
)
 
0.8
   
-
 
Effective tax rate
   
21.8
%
 
24.4
%
 
26.5
%
 
7.    
Retirement Plans & Other Postretirement Benefits

At December 31, 2006, the Company maintains three qualified defined benefit pension plans, a nonqualified supplemental executive retirement plan (SERP), and three other postretirement benefit plans. The defined benefit pension and other postretirement benefit plans, which cover eligible full-time regular employees, are primarily noncontributory. The postretirement health care and life insurance plans are a combination of self-insured and fully insured plans. The Company has Voluntary Employee Beneficiary Association (VEBA) Trust Agreements for the partial funding of postretirement health benefits for retirees and their eligible dependents and beneficiaries. Annual VEBA funding is discretionary. To the extent these postretirement benefits are funded, the benefits are not liabilities in these consolidated financial statements. The detailed disclosures of benefit components that follow are based on an actuarial valuation using a measurement date as of September 30. The qualified pension plans and the SERP are aggregated under the heading “Pension Benefits.” Other postretirement benefit plans are aggregated under the heading “Other Benefits.”

Adoption of SFAS 158
On December 31, 2006, and after calculating the balance sheet impact of the Company’s retirement plans using the accounting guidance prescribed by SFAS 87 and SFAS 106, the Company adopted SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans-an amendment of FASB Statements No. 87, 88, 106, and 132(R)” (SFAS 158).  SFAS 158 requires the Company to recognize the funded status of its pension plans and postretirement plans. SFAS 158 defines the funded status of a defined benefit plan as its assets less its projected benefit obligation, which includes projected salary increases, and defines the funded status of a postretirement plan as its assets less its accumulated postretirement benefit obligation. To the extent this obligation exceeded amounts previously recognized, the Company recorded a Regulatory Asset for that portion related to its cost-based and rate regulated utilities. To the extent that excess liability did not relate to a cost-based rate-regulated utility, the offset was recorded as a reduction to equity in Accumulated Other Comprehensive IncomeAs a result of adopting this standard, the Company’s assets increased $30.0 million, its liabilities increased $22.0 million and its equity increased $8.0 million.

SFAS 158 also requires an employer to measure the funded status of a plan as of the date of its year-end balance sheet and requires disclosure in the notes to financial statements certain additional information related to net periodic benefit cost for the next fiscal year. The measurement date provisions are not required to be adopted until 2008.

-63-

Balances related to retirement plans by balance sheet classification as of December 31, 2005, are presented with the effects of adopting SFAS 158 as of December 31, 2006, as follows.
                       
(In Millions)
 
  
 
2005 Balance
 
2006 Balance
Pre SFAS
158
 
Changes Resulting
from
Adoption of SFAS 158
 
2006 Ending Balance
 
                        
Other Long-term Liabilities
                      
  Net Amount Recognized Related To                     
 Other Benefit Obligations
       
$
(61.8
)
$
(60.6
)
$
4.5
 
$
(56.1
)
 Pension Obligations
         
(13.6
)
 
(15.7
)
 
(40.3
)
 
(56.0
)
 SERP Obligations
         
(9.1
)
 
(9.5
)
 
(3.0
)
 
(12.5
)
Additional Minumum Pension Liability 
         
(41.6
)
 
(28.2
)
 
28.2
   
-
 
         
$
(126.1
)
$
(114.0
)
$
(10.6
)
$
(124.6
)
                                 
Accrued Liabilities
                               
Other Benefit Obligations 
       
$
-
 
$
-
 
$
(5.5
)
$
(5.5
)
SERP Obligation 
         
-
   
-
   
(0.8
)
 
(0.8
)
 
        $  -  
$
-
 
$
(6.3
)
$
(6.3
)
Other Long-term Assets
                               
Prepaid Pension Asset 
       
$
3.1
 
$
4.2
 
$
(4.2
)
$
-
 
Intangible Asset 
         
12.6
   
12.5
   
(12.5
)
 
-
 
         
$
15.7
 
$
16.7
 
$
(16.7
)
$
-
 
                                 
Regulatory Assets
       
$
-
 
$
-
 
$
46.7
 
$
46.7
 
                                 
Deferred Income Taxes
       
$
11.8
 
$
6.4
 
$
(5.2
)
$
1.2
 
                                 
Accumulated Other Comprehensive Income
       
$
17.2
 
$
9.3
 
$
(8.0
)
$
1.3
 
 
Following is a reconciliation of the amounts remaining in accumulated other comprehensive income (AOCI) related to retirement plan obligations as of December 31, 2006 and amounts expected to be amortized to earnings in 2007.
                   
(In Millions)
 
As Of December 31, 2006
 
Expected to Amortized in 2007
 
   
Pensions
 
Other Benefits
 
Pensions
 
Other Benefits
 
Prior Service Cost
 
$
12.9
 
$
(5.5
)
$
1.7
 
$
(0.8
)
Unamortized Actuarial Gain/(Loss)
   
35.4
   
(2.3
)
 
1.5
   
(0.1
)
Transition Obligation
   
-
   
8.7
   
-
   
1.1
 
     
48.3
   
0.9
 
$
3.2
 
$
0.2
 
Less Regualtory Asset Deferral
   
(45.9
)
 
(0.8
)
           
AOCI Balance Before Taxes
 
$
2.4
 
$
0.1
             
                           


Net Periodic Benefit Costs
A summary of the components of net periodic benefit cost for the three years ended December 31, 2006, follows:

                           
   
Pension Benefits
 
Other Benefits
 
(In millions)
 
2006
 
2005
 
2004
 
2006
 
2005
 
2004
 
Service cost
 
$
6.0
 
$
5.6
 
$
6.6
 
$
0.6
 
$
0.7
 
$
0.9
 
Interest cost
   
14.1
   
13.8
   
13.4
   
3.9
   
4.5
   
5.3
 
Expected return on plan assets
   
(13.5
)
 
(13.2
)
 
(13.5
)
 
(0.6
)
 
(0.6
)
 
(0.7
)
Amortization of prior service cost
   
1.8
   
1.6
   
0.9
   
(0.8
)
 
(0.6
)
 
-
 
Amortization of actuarial loss (gain)
   
2.4
   
1.8
   
1.0
   
-
   
(0.2
)
 
(0.2
)
Amortization of transitional (asset) obligation
         
-
   
(0.2
)
 
1.1
   
1.5
   
2.9
 
Net periodic benefit cost
 
$
10.8
 
$
9.6
 
$
8.2
 
$
4.2
 
$
5.3
 
$
8.2
 
 
A portion of benefit costs are capitalized as Utility plant. Costs capitalized in 2006, 2005, and 2004 approximated $4.3 million, $4.2 million, and $4.6 million, respectively.

To calculate the expected return on plan assets, the Company uses the plan assets’ market-related value and an expected long-term rate of return. The fair market value of the assets at the measurement date is adjusted to a market-related value by recognizing the change in fair value experienced in a given year ratably over a five-year period.

Based on a targeted 60% equity, 35% debt, and 5% real estate allocation for the pension plans, the Company has used a long-term expected rate of return of 8.25% to calculate 2006 periodic benefit cost. For fiscal 2007, the expected long-term rate of return will also be 8.25%.

In January 2005, the Company announced the amendment of certain postretirement benefit plans, effective January 1, 2006. The amendment resulted in an estimated $4 million annual decrease in periodic cost, of which approximately $3.1 million was recognized in 2005. A union representing bargaining-unit employees at the Company’s regulated subsidiaries has advised the Company that it believes that these changes are not permitted under the existing collective bargaining agreements which govern the relationship between the employees and the affected subsidiaries. With assistance from legal counsel, management has analyzed the union’s position and continues to believe that the Company has reserved the right to amend the affected plans and that changing these benefits for retirees is not subject to mandatory bargaining.

The weighted averages of significant assumptions used to determine net periodic benefit costs follow:
                           
   
Pension Benefits
 
Other Benefits
 
(In millions)
 
2006
 
2005
 
2004
 
2006
 
2005
 
2004
 
Discount rate
   
5.50
%
 
5.75
%
 
6.00
%
 
5.50
%
 
5.75
%
 
6.00
%
Rate of compensation increase
   
3.25
%
 
3.50
%
 
3.50
%
 
3.25
%
 
3.50
%
 
3.50
%
Expected return on plan assets
   
8.25
%
 
8.25
%
 
8.50
%
 
8.25
%
 
8.25
%
 
8.50
%
Expected increase in Consumer Price Index
   
N/A
   
N/A
   
N/A
   
3.50
%
 
3.50
%
 
3.50
%
 
Health care cost trend rate assumptions do not have a material effect on the service and interest cost components of benefit costs. The Company’s benefit plans limit Vectren’s 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.

Expected Cash Flows
In 2007, the Company expects to make contributions of approximately $8.4 million to its pension plan trusts. In addition, the Company expects to make payments totaling approximately $0.8 million directly to SERP participants and approximately $4.8 million directly to those participating in other postretirement plans.

Estimated retiree pension benefit payments, including the SERP, projected to be required during the years following 2006 (in millions) are $12.9 in 2007, $12.9 in 2008, $13.4 in 2009 $14.2 in 2010, $14.8 in 2011 and $121.2 in years 2012-2016. Expected benefit payments projected to be required for postretirement benefits during the years following 2006 (in millions) are $6.7 in 2007, $7.1 in 2008, $7.5 in 2009, $8.0 in 2010, $8.3 in 2011 and $45.0 in years 2012-2016.

-65-

Benefit Obligations
A reconciliation of the Company’s benefit obligations at December 31, 2006, and 2005, follows:

                   
   
Pension Benefits
 
Other Benefits
 
(In millions)
 
2006
 
2005
 
2006
 
2005
 
Benefit obligation, beginning of period
 
$
255.4
 
$
241.1
 
$
72.0
 
$
92.8
 
Service cost – benefits earned during the period
   
6.0
   
5.6
   
0.6
   
0.7
 
Interest cost on projected benefit obligation
   
14.1
   
13.8
   
3.9
   
4.5
 
Plan participants' contributions
   
-
   
-
   
1.7
   
1.4
 
Plan amendments
   
2.1
   
-
   
-
   
(21.7
)
Actuarial loss (gain)
   
(10.2
)
 
6.3
   
(0.4
)
 
2.0
 
Medicare subsidy receipts
   
-
   
-
   
0.3
   
-
 
Benefits paid
   
(12.0
)
 
(11.4
)
 
(8.6
)
 
(7.7
)
Benefit obligation, end of period
 
$
255.4
 
$
255.4
 
$
69.5
 
$
72.0
 
 
The accumulated benefit obligation for all defined benefit pension plans was $234.8 million and $235.8 million at December 31, 2006, and 2005, respectively.

The benefit obligation as of December 31, 2006, and 2005, was calculated using the following weighted average assumptions:
 
                 
     
Pension Benefits
 
Other Benefits
     
2006
 
2005
 
2006
 
2005
Discount rate
 
5.85%
 
5.50%
 
5.85%
 
5.50%
Rate of compensation increase
 
3.75%
 
3.25%
 
3.75%
 
3.25%
Expected increase in Consumer Price Index
 
N/A
 
N/A
 
3.50%
 
3.50%

To calculate the 2006 ending postretirement benefit obligation, medical claims costs in 2007 were assumed to be 9% higher than those incurred in 2006. That trend was assumed to gradually decline to 5% over a four year period and remain level thereafter. A one-percentage point change in assumed health care cost trend rates would have changed the benefit obligation by approximately $1.3 million. To calculate the 2005 ending postretirement benefit obligation, medical claims costs in 2006 were assumed to be 10% higher than those incurred in 2005. That trend was assumed to gradually decline to 5% over a five year period and to remain level thereafter.

Plan Assets
A reconciliation of the Company’s plan assets at December 31, 2006, and 2005, follows:
                   
   
Pension Benefits
 
Other Benefits
 
(In millions)
 
2006
 
2005
 
2006
 
2005
 
Plan assets at fair value, beginning of period
 
$
173.6
 
$
161.2
 
$
7.4
 
$
8.3
 
Actual return on plan assets
   
14.8
   
20.1
   
0.3
   
1.3
 
Employer contributions
   
8.6
   
3.7
   
6.0
   
4.1
 
Plan participants' contributions
   
-
   
-
   
1.7
   
1.4
 
Benefits paid
   
(12.0
)
 
(11.4
)
 
(8.6
)
 
(7.7
)
Fair value of plan assets, end of period
 
$
185.0
 
$
173.6
 
$
6.8
 
$
7.4
 

The asset allocation for the Company's pension and postretirement plans at the measurement date for 2006 and 2005, by asset category, follows:

                   
   
Pension Benefits
 
Other Benefits
 
   
2006
 
2005
 
2006
 
2005
 
Equity securities
   
62
%
 
64
%
 
65
%
 
53
%
Debt securities
   
33
%
 
33
%
 
31
%
 
37
%
Real estate
   
5
%
 
3
%
 
-
   
-
 
Short term investments
   
-
   
-
   
4
%
 
10
%
Total
   
100
%
 
100
%
 
100
%
 
100
%

The Company invests in a master trust that benefits its qualified defined benefit pension plans. The general investment objectives are to invest in a diversified portfolio, comprised of both 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% equities, 35% debt, and 5% real estate for 2006, and for postretirement plans of 55% equities, 35% debt, and 10% short-term investments for 2006. Objectives do not target a specific return by asset class. The portfolio’s return is monitored in total and investment objectives are long-term in nature.

Funded Status
The funded status of the plans, reconciled to amounts reflected in the balance sheets prior to the adoption of SFAS 158 in 2006 and as of December 31, 2005 follows:
                   
   
Pension Benefits
 
Other Benefits
 
(In millions)
 
2006
 
2005
 
2006
 
2005
 
Fair value of plan assets, end of period
 
$
185.0
 
$
173.6
 
$
6.8
 
$
7.4
 
Benefit obligation, end of period
   
(255.4
)
 
(255.4
)
 
(69.5
)
 
(72.0
)
Funded status, end of period
   
(70.4
)
 
(81.8
)
 
(62.7
)
 
(64.6
)
Unrecognized net loss (gain)
   
35.3
   
48.6
   
(2.2
)
 
(2.0
)
Unrecognized prior service cost
   
12.9
   
12.6
   
(5.5
)
 
(6.3
)
Unrecognized transitional (asset) obligation
   
-
   
-
   
8.7
   
9.9
 
Post measurement date adjustments
   
1.2
   
1.0
   
1.1
   
1.2
 
Net amount recognized, prior to adoption of SFAS 158
 
$
(21.0
)
$
(19.6
)
$
(60.6
)
$
(61.8
)
 
Prior to the adoption of SFAS 158 in 2006 and as of December 31, 2005, the funded status of the SERP, which is included in Pension Benefits in the chart above, was an unfunded amount of $13.4 million and $14.4 million, respectively.

Prior to the adoption of SFAS 158 in 2006 and as of December 31, 2005, substantially all pension and postretirement plans had accumulated benefit obligations in excess of plan assets. As required by SFAS 87, the Company recorded an additional minimum pension liability adjustment to reflect the total unfunded accumulated liability arising from its pension plans. This additional minimum pension liability adjustment is included in Deferred credits & other liabilities. The offset to this additional liability was recorded to an intangible asset included in Other assets to the extent pension plans have unrecognized prior service cost. Any unfunded or unaccrued amount in excess of prior service cost was recorded net of tax in Accumulated other comprehensive income in shareholders’ equity.

-67-

 
The effects of additional minimum pension liability adjustments prior to the adoption of SFAS 158 in 2006 and as of December 31, 2005 follow:
           
(In millions)
 
2006
 
2005
 
Minimum pension liability adjustment, beginning of year
 
$
(41.6
)
$
(43.5
)
Change in minimum pension liability adjustment included in:
             
Other comprehensive income before effect of taxes
   
13.4
   
(0.3
)
Other assets
   
-
   
2.2
 
Minimum pension liability adjustment, prior to adoption of SFAS 158
 
$
(28.2
)
$
(41.6
)
 
8.    
Borrowing Arrangements

Long-Term Debt
Long-term senior unsecured obligations and first mortgage bonds outstanding by subsidiary follow:
 
       
 At December 31,
 
(In millions)
      
2006
 
2005
 
Utility Holdings
              
 Fixed Rate Senior Unsecured Notes              
 2011, 6.625%
       
$
250.0
 
$
250.0
 
 2013, 5.25%
         
100.0
   
100.0
 
 2015, 5.45%
         
75.0
   
75.0
 
 2018, 5.75%
         
100.0
   
100.0
 
 2031, 7.25%
         
-
   
100.0
 
 2035, 6.10%
         
75.0
   
75.0
 
 2036, 5.95%
         
100.0
   
-
 
 Total Utility Holdings
         
700.0
   
700.0
 
SIGECO
                   
First Mortgage Bonds 
                   
 2016, 1986 Series, 8.875%
         
13.0
   
13.0
 
 2020, 1998 Pollution Control Series B, 4.50%, tax exempt
         
4.6
   
4.6
 
 2024, 2000 Environmental Improvement Series A, 4.65%, tax exempt
         
22.5
   
22.5
 
 2029, 1999 Senior Notes, 6.72%
         
80.0
   
80.0
 
 2030, 1998 Pollution Control Series B, 5.00%, tax exempt
         
22.0
   
22.0
 
 2015, 1985 Pollution Control Series A, current adjustable rate 4.06%, tax exempt,
                   
 auction rate mode, 2006 weighted average: 3.53%
         
9.8
   
9.8
 
 2023, 1993 Environmental Improvement Series B, current adjustable rate 4.11%,
                   
 tax exempt, auction rate mode, 2006 weighted average: 3.74%
         
22.6
   
22.6
 
 2025, 1998 Pollution Control Series A, current adjustable rate 4.11%, tax exempt,
                   
 auction rate mode, 2006 weighted average: 3.08%
         
31.5
   
31.5
 
 2030, 1998 Pollution Control Series C, current adjustable rate 4.11%, tax exempt,
                   
 auction rate mode, 2006 weighted average: 3.20%
         
22.2
   
22.2
 
 Total SIGECO
         
228.2
   
228.2
 


 
     
At December 31,
(In millions)
2006
 
2005
Indiana Gas
              
  Senior Unsecured Notes             
 2007, Series E, 6.54%
         
6.5
   
6.5
 
 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
         
127.5
   
127.5
 
Vectren Capital Corp.
                   
Fixed Rate Senior Unsecured Notes 
                   
   2007, 7.83%
         
17.5
   
17.5
 
   2010, 4.99%
         
25.0
   
25.0
 
   2010, 7.98%
         
22.5
   
22.5
 
   2012, 5.13%
         
25.0
   
25.0
 
   2012, 7.43%
         
35.0
   
35.0
 
   2015, 5.31%
         
75.0
   
75.0
 
   Total Vectren Capital Corp.
         
200.0
   
200.0
 
Other Long-Term Notes Payable
         
0.6
   
1.2
 
Total long-term debt outstanding
         
1,256.3
   
1,256.9
 
Current maturities of long-term debt 
         
(24.2
)
 
(0.4
)
Debt subject to tender 
         
(20.0
)
 
(53.7
)
Unamortized debt premium & discount - net 
         
(3.8
)
 
(4.4
)
Fair value of hedging arrangements 
         
(0.3
)
 
(0.4
)
  Total long-term debt-net
       
$
1,208.0
 
$
1,198.0
 
 
Utility Holdings 2006 Issuance
In October 2006, Utility Holdings issued $100 million in 5.95% senior unsecured notes due October 1, 2036 (2036 Notes). The 30-year notes were priced at par. The 2036 Notes are guaranteed by Utility Holdings’ three public utilities: SIGECO, Indiana Gas, and VEDO. These guarantees are full and unconditional and joint and several.  These notes, as well as the timely payment of principal and interest, are insured by a financial guaranty insurance policy by Financial Guaranty Insurance Company (FGIC).

The 2036 Notes have no sinking fund requirements, and interest payments are due quarterly. The notes may be called by Utility Holdings, in whole or in part, at any time on or after October 1, 2011, at 100% of principal amount plus accrued interest. During the first and second quarters of 2006, Utility Holdings entered into several interest rate hedges with a $100 million notional amount. Upon issuance of the notes, these instruments were settled resulting in the payment of approximately $3.3 million, which was recorded as a Regulatory asset pursuant to existing regulatory orders. The value paid is being amortized as an increase to interest expense over the life of the issue.

The proceeds from the sale of the 2036 Notes, settlement of the hedging arrangements, and payments of issuance costs totaled approximately $92.8 million.

Utility Holdings 2005 Issuance
In December 2005, Utility Holdings issued senior unsecured notes with an aggregate principal amount of $150 million in two $75 million tranches. The first tranche was 10-year notes due December 2015, with an interest rate of 5.45% priced at 99.799% to yield 5.47% to maturity (2015 Notes). The second tranche was 30-year notes due December 2035 with an interest rate of 6.10% priced at 99.799% to yield 6.11% to maturity (2035 Notes).

-69-

The notes have no sinking fund requirements, and interest payments are due semi-annually. The notes may be called by Utility Holdings, in whole or in part, at any time for an amount equal to accrued and unpaid interest, plus the greater of 100% of the principal amount or the sum of the present values of the remaining scheduled payments of principal and interest, discounted to the redemption date on a semi-annual basis at the Treasury Rate, as defined in the indenture, plus 20 basis points for the 2015 Notes and 25 basis points for the 2035 Notes.

In January and June 2005, Utility Holdings entered into forward starting interest rate swaps with a total notional amount of $75 million. Upon issuance of the debt, the instruments were settled resulting in the receipt of approximately $1.9 million in cash, which was recorded as a regulatory liability pursuant to existing regulatory orders. The value received is being amortized as a reduction of interest expense over the life of the issue maturing December 2035.

The net proceeds from the sale of the senior notes and settlement of related hedging arrangements approximated $150 million.

Vectren Capital Corp. 2005 Debt Issuance
On October 11, 2005, Vectren and Vectren Capital Corp., its wholly-owned subsidiary (Vectren Capital), entered into a private placement Note Purchase Agreement (2005 Note Purchase Agreement) pursuant to which various institutional investors purchased the following tranches of notes from Vectren Capital: (i) $25 million 4.99% Guaranteed Senior Notes, Series A due 2010, (ii) $25 million 5.13% Guaranteed Senior Notes, Series B due 2012 and (iii) $75 million 5.31% Guaranteed Senior Notes, Series C due 2015. These Guaranteed Senior Notes are unconditionally guaranteed by Vectren, the parent of Vectren Capital. The proceeds from this financing were received on December 15, 2005. This Note Purchase Agreement contains customary representations, warranties and covenants, including a covenant to the effect that the ratio of consolidated total debt to consolidated total capitalization will not exceed 75%.

On October 11, 2005, Vectren and Vectren Capital entered into First Amendments with respect to a Note Purchase Agreement dated as of December 31, 2000 pursuant to which Vectren Capital issued to institutional investors the following tranches of notes: (i) $38 million 7.67% Senior Notes due 2005, (ii) $17.5 million 7.83% Senior Notes due 2007, (iii) $22.5 million 7.98% Senior Notes due 2010 and (iv) a Note Purchase Agreement, dated April 25, 1997, pursuant to which Vectren Capital issued to an institutional investor a $35 million 7.43% Senior Note due 2012. The First Amendments (i) conform the covenants to those contained in the 2005 Note Purchase Agreement, (ii) eliminate a credit ratings trigger which would have afforded noteholders the option to require prepayment if the ratings of Indiana Gas or SIGECO fell below a certain level, (iii) substitute the unconditional guarantee by Vectren of the notes for the more limited support agreement previously in place and (iv) provide for a 100 basis point increase in interest rates if the ratio of consolidated total debt to total capitalization exceeds 65%.

Long-Term Debt Put & Call Provisions
Certain long-term debt issues contain put and call provisions that can be exercised on various dates before maturity. The put or call provisions are not triggered by specific events, but are based upon dates stated in the note agreements, such as when notes are remarketed. During 2006 and 2005, no debt was put to the Company. During 2004 debt totaling $2.5 million was put to the Company. Debt which may be put to the Company during the years following 2006 (in millions) is $20.0 in 2007, zero in 2008, $80.0 in 2009, $10.0 in 2010, $30.0 in 2011, and zero thereafter. Debt that may be put to the Company within one year is classified as Long-term debt subject to tender in current liabilities.

Utility Holdings, SIGECO and Indiana Gas Debt Calls
In 2006, the Company called at par $100.0 million of Utility Holdings senior unsecured notes originally due in 2031. In 2005, the Company called at par $49.9 million of Indiana Gas insured quarterly senior unsecured notes originally due in 2030, and in 2004, called at par $20.0 million of Indiana Gas insured quarterly senior unsecured notes originally due in 2015. The notes called in 2006, 2005 and 2004 had stated interest rates of 7.25%, 7.45% and 7.15%, respectively.

Other Financing Transactions
At December 31, 2005, $53.7 million of SIGECO notes could be put to the Company in March of 2006, the date of their next remarketing. In March of 2006, the notes were successfully remarketed, and are now classified in Long-term debt. Prior to the remarketing, the notes had tax-exempt interest rates ranging from 4.75% to 5.00%. After the remarketing, interest rates are reset every seven days using an auction process.  

-70-

During 2004, the Company remarketed two first mortgage bonds outstanding at SIGECO. The remarketing effort converted $32.8 million of outstanding fixed rate debt into variable rate debt where interest rates reset weekly. One bond, due in 2023, had a principal amount of $22.8 million and an interest rate of 6%. The other bond, due in 2015, had a principal amount of $10.0 million and an interest rate of 4.3%. These remarketing efforts resulted in the extinguishment of debt and the reissuance of new debt at generally the same par value. These bonds are classified in Long-term debt. 

As part of the integration of Miller into the Company’s consolidated financing model, $24.0 million of Miller’s outstanding long-term debt was retired in the fourth quarter of 2006.

Other Company debt totaling $38.0 million in 2005, and $15.0 million in 2004 was retired as scheduled.

Future Long-Term Debt Sinking Fund Requirements & Maturities
The annual sinking fund requirement of SIGECO's first mortgage bonds is 1% 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 2007 sinking fund requirement by this means and, accordingly, the sinking fund requirement for 2007 is excluded from Current liabilities in the Consolidated Balance Sheets. At December 31, 2006, $739.1 million of SIGECO's utility plant remained unfunded under SIGECO's Mortgage Indenture. SIGECO’s gross utility plant balance subject to the Mortgage Indenture approximated $2.0 billion at December 31, 2006.

Consolidated maturities of long-term debt during the five years following 2006 (in millions) are $24.0 in 2007, zero in 2008 and in 2009, $47.5 in 2010, and $250.0 in 2011.

Short-Term Borrowings
At December 31, 2006, the Company has $794.0 million of short-term borrowing capacity, including $520.0 million for the Utility Group operations and $274.0 million for the wholly owned Nonutility Group and corporate operations, of which approximately $250.0 million is available for the Utility Group operations and approximately $79.0 million is available for wholly owned Nonutility Group and corporate operations. These primarily short-term borrowing arrangements expire in 2010. Utility Group credit facilities are primarily used to support the Company’s access to the commercial paper market. Interest rates and outstanding balances associated with short-term borrowing arrangements follows.
               
   
Year Ended December 31,
 
(In millions)
 
2006
 
2005
 
2004
 
Weighted average commercial paper and bank loans
             
outstanding during the year
 
$
256.1
 
$
304.5
 
$
211.4
 
Weighted average interest rates during the year
                   
Commercial paper
   
5.16
%
 
3.42
%
 
1.78
%
Bank loans
   
5.51
%
 
3.82
%
 
2.12
%
                     
   
At December 31, 
       
(In millions)
   
2006
   
2005
       
Commercial paper
 
$
270.1
 
$
226.9
       
Bank loans
   
194.7
   
73.0
       
Total short-term borrowings
 
$
464.8
 
$
299.9
       
 
During 2005, the Company increased the capacity of its utility-related credit facilities by approximately $165 million in response to increased natural gas costs.

Covenants
Both long-term and short-term borrowing arrangements contain customary default provisions; restrictions on liens, sale-leaseback transactions, mergers or consolidations, and sales of assets; and restrictions on leverage and interest coverage, among other restrictions. As of December 31, 2006, the Company was in compliance with all financial covenants.

-71-

Ratings Triggers
None of Vectren’s currently outstanding debt arrangements contain ratings triggers.

Debt Guarantees
Vectren Corporation guarantees Vectren Capital’s long-term and short-term debt, which totaled $200.0 million and $194.7 million, respectively, at December 31, 2006. 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 and short-term debt outstanding at December 31, 2006, totaled $700.0 million and $270.1 million, respectively.

9.        
Share-Based Compensation and Adoption of SFAS 123R

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

On January 1, 2006, the Company adopted SFAS 123R “Share Based Compensation” (SFAS 123R) using the modified prospective method. Accordingly, information prior to the adoption has not been restated. Prior to the adoption of SFAS 123R, the Company accounted for these programs using APB Opinion 25, “Accounting for Stock Issued to Employees” (APB 25), and its related interpretations. From the Company’s perspective, the primary cost recognition difference between SFAS 123R and APB 25 is that costs related to stock options were not recognized in the financial statements in those years prior to SFAS 123R’s adoption.

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)
 
2006
 
2005
 
2004
 
Total cost of share-based compensation
 
$
3.2
 
$
4.5
 
$
4.0
 
Less capitalized cost
   
0.9
   
1.0
   
1.1
 
Total in other operating expense
   
2.3
   
3.5
   
2.9
 
Less income tax benefit in earnings
   
0.6
   
1.4
   
1.2
 
After tax effect of share-based compensation
 
$
1.7
 
$
2.1
 
$
1.7
 

Restricted Stock Related Matters
The Company periodically grants executives and other key non-officer employees restricted stock whose vesting is contingent upon meeting a total return and/or return on equity performance objectives.  In addition non-employee directors receive a portion of their fees in restricted stock. Grants to executives and key non-officer employees generally vest at the end of a four-year period, with performance measured at the end of the third year. Based on that performance, awards could double or could be entirely forfeited. Awards to non-employee directors are not performance based and generally vest over one year. Because executives and non-employee directors have the choice of settling vested restricted stock awards in shares 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. Upon adoption of SFAS 123R, the Company reclassified the earned value of these awards, which totaled $4.1 million on January 1, 2006, from equity to other long-term liabilities. Awards to key non-officer employees must be settled in shares and are therefore accounted for in equity at their grant date fair value.

-72-

A summary of the status of the Company’s restricted stock awards separated between those accounted for as liabilities and equity as of December 31, 2006, and changes during the twelve months ended December 31, 2006, is presented below:

   
Equity Awards
 
Liability Awards
 
   
 
 
Wtd. Avg.
 
 
 
 
 
 
 
 
 
Grant Date
 
 
 
Wtd. Avg.
 
 
 
Shares
 
Fair value
 
Shares
 
Fair value
 
Restricted at January 1, 2006
   
17,369
 
$
26.42
   
336,216
 
$
27.16
 
Granted
   
10,690
   
26.60
   
185,027
   
27.54
 
Vested
   
(84
)
 
27.62
   
(68,235
)
 
26.60
 
Forfeited
   
(4,966
)
 
27.24
   
(76,823
)
 
24.46
 
Restricted at December 31, 2006
   
23,009
 
$
26.32
   
376,185
 
$
28.28
 
 
As of December 31, 2006, there was $6.2 million of total unrecognized compensation cost related to restricted stock awards.  That cost is expected to be recognized over a weighted-average period of 2.1 years.  The total fair value of shares vested for awards to executives and non-employee directors (Liability Awards) during the years ended December 31, 2006, 2005, and 2004, was $1.8 million, $2.1 million, and $2.0 million, respectively.  On January 1, 2007, 167,100 awards that will be accounted for as liabilities were granted to officers of the Company.

Stock Option Related Matters
Option awards are generally granted to executives with an exercise price equal to the market price of the Company’s stock at the date of grant; those option awards generally require 3 years of continuous service and have 10-year contractual terms. Share awards generally vest on a pro-rata basis over 3 years. No options were granted in 2006, and the Company does not intend to issue options in 2007.

The fair value of option awards granted in prior years was estimated on the date of grant using a Black-Scholes option valuation model that used the assumptions noted below.  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. The fair value of each option granted used to determine pro forma net income as disclosed in Note 2, was estimated as of the date of grant using the Black-Scholes option pricing model with the following weighted average assumptions used for grants in the years ended December 31, 2005 and 2004: risk-free rate of return of 4.22% and 4.37%, respectively; expected option term of 8 years for both years; expected volatility of 21.43% and 24.01%, respectively; and dividend yield of 4.4% and 4.65%, respectively. The weighted average fair value of options granted in 2005 and 2004 were $4.36 and $4.39, respectively.

A summary of the status of the Company’s stock option awards as of December 31, 2006, and changes during the period ended December 31, 2006, follows:

                   
       
Weighted average
 
Aggregate
 
 
 
 
 
 
 
Remaining
 
Intrinsic
 
 
 
Shares
 
Exercise
 
Contractual
 
Value
 
 
 
 
 
Price
 
Term (years)
 
(In millions)
 
Outstanding at January 1, 2006
   
2,123,579
 
$
23.18
             
Granted
   
-
   
-
             
Exercised
   
149,948
 
$
21.39
             
Forfeited or expired
   
9,646
 
$
21.09
             
Outstanding at December 31, 2006
   
1,963,985
 
$
23.33
   
5.3
 
$
9.7
 
                           
Exercisable at December 31, 2006
   
1,696,803
 
$
22.89
   
4.9
 
$
9.1
 

-73-

The total intrinsic value of options exercised during the twelve months ended December 31, 2006, 2005, and 2004 was $0.8 million, $1.6 million, and $2.6 million, respectively. As of December 31, 2006, there was less than $0.1 million of total unrecognized compensation cost related to vesting stock options. That cost is expected to be recognized over a weighted-average period of less than 1.0 year. The actual tax benefit realized for tax deductions from option exercises was approximately $0.2 million in 2006, $0.1 million in 2005, and $0.3 million in 2004.

The Company periodically issues new shares and also from time to time repurchases shares on the open market to satisfy share option exercises. During the twelve months ended December 31, 2006, 2005, and 2004, the Company received value upon exercise of stock options totaling approximately $3.2 million, $1.6 million, and $1.7 million, respectively. During those periods, the Company repurchased shares totaling $3.8 million in 2006 and $2.1 million in 2005. No shares were purchased on the open market in 2004. The Company does not expect future period repurchase activity to be materially different. 

Deferred Compensation Plan Matters
As discussed above, the Company has nonqualified deferred compensation plans that include an option to invest in Company phantom stock. The amount recorded in earnings related to the investment activities in Vectren phantom stock associated with these plans during the years ended December 31, 2006, 2005 and 2004, was a benefit of $0.3 million, and a cost of $1.5 million and $0.7 million, respectively.

10.      
Common Shareholders’ Equity

Authorized, Reserved Common and Preferred Shares
At December 31, 2006, and 2005, the Company was authorized to issue 480.0 million shares of common stock and 20.0 million shares of preferred stock. Of the authorized common shares, approximately 7.2 million shares at December 31, 2006, and 6.4 million shares at December 31, 2005, were reserved by the board of directors for issuance through the Company’s share-based compensation plans, benefit plans, and dividend reinvestment plan. At December 31, 2006, and 2005, there were 396.7 million and 397.6 million, respectively, of authorized shares of common stock and all authorized shares of preferred stock, available for a variety of general corporate purposes, including future public offerings to raise additional capital and for facilitating acquisitions.

Shareholder Rights Agreement
The Company’s board of directors previously adopted a Shareholder Rights Agreement (Rights Agreement). As part of the Rights Agreement, the board of directors declared a dividend distribution of one right for each outstanding Vectren common share. Each right entitles the holder to purchase from Vectren one share of common stock at a price of $65.00 per share (subject to adjustment to prevent dilution). The rights become exercisable 10 days following a public announcement that a person or group of affiliated or associated persons (Vectren Acquiring Person) has acquired beneficial ownership of 15% or more of the outstanding Vectren common shares (or a 10% acquirer who is determined by the board of directors to be an adverse person), or 10 days following the announcement of an intention to make a tender offer or exchange offer, the consummation of which would result in any person or group becoming a Vectren Acquiring Person. The Vectren Shareholder Rights Agreement expires October 21, 2009.

11.      
Earnings Per Share

Basic earnings per share is computed by dividing net income available to common shareholders by the weighted average number of common shares outstanding for the period. Diluted earnings per share assumes the conversion of stock options into common shares using the treasury stock method and the conversion of restricted shares into unrestricted shares using the contingently issuable share method to the extent the effect would be dilutive.

-74-


The following table illustrates the basic and dilutive earnings per share calculations for the three years ended December 31, 2006:


   
Year Ended December 31,
 
(In millions, except per share data)
 
2006
 
2005
 
2004
 
Numerator:
             
Numerator for basic and diluted EPS - Net income 
 
$
108.8
 
$
136.8
 
$
107.9
 
Denominator:
                   
Denominator for basic EPS - Weighted average 
                   
  common shares outstanding
   
75.7
   
75.6
   
75.6
 
Conversion of stock options and lifting of 
                   
  restrictions on issued restricted stock
   
0.5
   
0.5
   
0.3
 
Denominator for diluted EPS - Adjusted weighted 
                   
  average shares outstanding and assumed
                   
  conversions outstanding
   
76.2
   
76.1
   
75.9
 
Basic earnings per share
 
$
1.44
 
$
1.81
 
$
1.43
 
Diluted earnings per share
 
$
1.43
 
$
1.80
 
$
1.42
 

Options to purchase 4,200 shares of common stock for the year ended December 31, 2004 were excluded in the computation of dilutive earnings per share because the options’ exercise price was greater than the average market price of a share of common stock during the period. The exercise price for options excluded from the computation was $25.59 in 2004. For the year ended December 31, 2006 and 2005, all options were dilutive.

12.  
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 2006 and thereafter (in millions) are $7.7 in 2007, $4.6 in 2008, $2.6 in 2009, $1.5 in 2010, $0.9 in 2011, and $1.0 thereafter. Total lease expense (in millions) was $8.5 in 2006, $6.1 in 2005, and $6.7 in 2004.

Firm purchase commitments for commodities by consolidated companies total (in millions) $96.7 million in 2007, $21.4 million in 2008, $3.3 million in 2009, $2.9 million in 2010, and zero in 2011 and thereafter. Firm purchase commitments for utility and nonutility plant total (in millions) $66.4 million in 2007, $113.0 million in 2008, $115.0 million in 2009, $70.0 million in 2010, and $28.0 million in 2011.

Other Guarantees
Vectren issues guarantees to third parties on behalf of its unconsolidated affiliates. Such guarantees allow those affiliates to execute transactions on more favorable terms than the affiliate could obtain without such a guarantee. Guarantees may include posted letters of credit, leasing guarantees, and performance guarantees. As of December 31, 2006, guarantees issued and outstanding on behalf of unconsolidated affiliates approximated $3.0 million. The Company has accrued no liabilities for these guarantees as they relate to guarantees issued among related parties, or such guarantees were executed prior to the adoption of FASB Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.”

In 2006, the Company issued a guarantee with an approximate $5 million maximum risk related to the residual value of an operating lease that expires in 2011. As of December 31, 2006, Vectren Corporation has a liability representing the fair value of that guarantee of approximately $0.1 million. Liabilities accrued for, and activity related to, product warranties are not significant.

Legal Proceedings
The Company is party to various legal proceedings arising in the normal course of business. In the opinion of management, there are no legal proceedings 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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13.  
Environmental Matters

Clean Air Act

Clean Air Interstate Rule & Clean Air Mercury Rule

In March of 2005 USEPA finalized two new air emission reduction regulations.  The Clean Air Interstate Rule (CAIR) is an allowance cap and trade program requiring further reductions in Nitrogen Oxides (NOx) and Sulfur Dioxide (SO2) emissions from coal-burning power plants. The Clean Air Mercury Rule (CAMR) is an allowance cap and trade program requiring further reductions in mercury emissions from coal-burning power plants.  Both sets of regulations require emission reductions in two phases. The first phase deadline for both rules is 2010 (2009 for NOx under CAIR), and the second phase deadline for compliance with the emission reductions required under CAIR is 2015, while the second phase deadline for compliance with the emission reduction requirements of CAMR is 2018. The Company is evaluating compliance options and fully expects to be in compliance by the required deadlines.

In February 2006, the IURC approved a multi-emission compliance plan filed by the Company’s utility subsidiary, SIGECO. Once the plan is implemented, SIGECO’s coal-fired plants will be 100% scrubbed for SO2, 90% scrubbed for NOx, and mercury emissions will be reduced to meet the new mercury reduction standards. The order, as previously agreed to by the OUCC and Citizens Action Coalition, allows SIGECO to recover an approximate 8% return on up to $110 million in capital investments through a rider mechanism which is updated every six months for actual costs incurred. The Company will also recover through a rider its operating expenses, including depreciation, once the equipment is placed into service. The order also stipulates that SIGECO study renewable energy alternatives and include a carbon forecast in future filings with regard to new generation and further environmental compliance plans, among other initiatives. As of December 31, 2006, the Company has made capital investments of approximately $62.2 million related to this environmental requirement.

NOx SIP Call Matter
The Company complied with Indiana’s State Implementation Plan (SIP) of the Clean Air Act (the Act). These steps included installation Selective Catalytic Reduction (SCR) systems at Culley Generating Station Unit 3 (Culley), Warrick Generating Station Unit 4, and A. B. Brown Generating Station Units 1 and 2. SCR systems reduce flue gas NOx emissions to atmospheric nitrogen and water using ammonia in a chemical reaction. This technology is known to currently be the most effective method of reducing nitrogen oxide (NOx) emissions where high removal efficiencies are required.

The IURC issued orders that approved:
·  
the Company’s project to achieve environmental compliance by investing in clean coal technology;
·  
the Company’s investment of $258 million in capital costs;
·  
a mechanism whereby, prior to an electric base rate case, the Company recovers through a rider that is updated every six months, an 8% return on its weighted capital costs for the project; and
·  
ongoing recovery of operating costs, including depreciation and purchased emission allowances, related to the clean coal technology now that facilities are placed into service.

Culley Generating Station Litigation
During 2003, the U.S. District Court for the Southern District of Indiana entered a consent decree among SIGECO, the Department of Justice (DOJ), and the USEPA that resolved a lawsuit originally brought by the USEPA against SIGECO. The lawsuit alleged violations of the Clean Air Act by SIGECO at its Culley Generating Station for (1) making modifications to a generating station without obtaining required permits, (2) making major modifications to the generating station without installing the best available emission control technology, and (3) failing to notify the USEPA of the modifications.

Under the terms of the agreement, the DOJ and USEPA agreed to drop all challenges of past maintenance and repair activities at the Culley Generating Station. In reaching the agreement, SIGECO did not admit to any allegations in the government’s complaint, and SIGECO continues to believe that it acted in accordance with applicable regulations and conducted only routine maintenance on the units. SIGECO entered into this agreement to further its continued commitment to improve air quality and avoid the cost and uncertainties of litigation.

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Under the agreement, SIGECO committed to:
·  
either repower Culley Unit 1 (50 MW) with natural gas and equip it with SCR control technology for further reduction of nitrogen oxide, or cease operation of the unit by December 31, 2006;
·  
operate the existing SCR control technology recently installed on Culley Unit 3 (287 MW) year round at a lower emission rate than that currently required under the NOx SIP Call, resulting in further nitrogen oxide reductions;
·  
enhance the efficiency of the existing scrubber at Culley Units 2 and 3 for additional removal of sulphur dioxide emissions;
·  
install a baghouse for further particulate matter reductions at Culley Unit 3 by June 30, 2007;
·  
conduct a Sulphuric Acid Reduction Demonstration Project as an environmental mitigation project designed to demonstrate an advance in pollution control technology for the reduction of sulfate emissions; and
·  
pay a $600,000 civil penalty.

The Company does not believe that implementation of the settlement will have a material effect on its results of operations or financial condition. The $600,000 civil penalty was expensed and paid during 2003. The Company ceased operation of Culley Unit 1 effective December 31, 2006 and the baghouse, which is included in the $110 million IURC order discussed above, went into service January 1, 2007.

Manufactured Gas Plants

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

Indiana Gas identified the existence, location, and certain general characteristics of 26 gas manufacturing and storage sites for which it may have some remedial responsibility. Indiana Gas completed a remedial investigation/feasibility study (RI/FS) at one of the sites under an agreed order between Indiana Gas and the IDEM, and a Record of Decision was issued by the IDEM in January 2000. Although Indiana Gas has not begun an RI/FS at additional sites, Indiana Gas has submitted several of the sites to the IDEM's Voluntary Remediation Program (VRP) and is currently conducting some level of remedial activities, including groundwater monitoring at certain sites, where deemed appropriate, and will continue remedial activities at the sites as appropriate and necessary.

In conjunction with data compiled by environmental consultants, Indiana Gas accrued the estimated costs for further investigation, remediation, groundwater monitoring, and related costs for the sites. While the total costs that may be incurred in connection with addressing these sites cannot be determined at this time, Indiana Gas has recorded costs that it reasonably expects to incur totaling approximately $20.4 million.

The estimated accrued costs are limited to Indiana Gas’ proportionate share of the remediation efforts. Indiana Gas has arrangements in place for 19 of the 26 sites with other potentially responsible parties (PRP), which serve to limit Indiana Gas’ share of response costs at these 19 sites to between 20% and 50%. With respect to insurance coverage, Indiana Gas has received and recorded settlements from all known insurance carriers in an aggregate amount approximating $20.4 million.

In October 2002, SIGECO received a formal information request letter from the IDEM regarding five manufactured gas plants that it owned and/or operated and were not enrolled in the IDEM’s VRP. In response, SIGECO submitted to the IDEM the results of preliminary site investigations conducted in the mid-1990’s. These site investigations confirmed that based upon the conditions known at the time, the sites posed no imminent and/or substantial risk to human health or the environment.

On October 6, 2003, SIGECO filed applications to enter four of the manufactured gas plant sites in IDEM's VRP. The remaining site is currently being addressed in the VRP by another Indiana utility. SIGECO added those four sites into the renewal of the global Voluntary Remediation Agreement that Indiana Gas has in place with IDEM for its manufactured gas plant sites. That renewal was approved by the IDEM on February 24, 2004. On July 13, 2004, SIGECO filed a declaratory judgment action against its insurance carriers seeking a judgment finding its carriers liable under the policies for coverage of further investigation and any necessary remediation costs that SIGECO may accrue under the VRP program. While the total costs that may be incurred in connection with addressing these sites cannot be determined at this time, SIGECO has recorded costs that it reasonably expects to incur totaling approximately $7.7 million. With respect to insurance coverage, SIGECO has received and recorded settlements from insurance carriers in an aggregate amount approximating the costs it expects to incur.

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Environmental matters related to Indiana Gas’ and SIGECO’s manufactured gas plants have had no material impact on results of operations or financial condition since costs recorded to date approximate PRP and insurance settlement recoveries. While the Company’s utilities have recorded all costs which they presently expect to incur in connection with activities at these sites, it is possible that future events may require some level of additional remedial activities which are not presently foreseen.

Jacobsville Superfund Site

On July 22, 2004, the USEPA listed the Jacobsville Neighborhood Soil Contamination site in Evansville, Indiana, on the National Priorities List under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA). The USEPA has identified four sources of historic lead contamination. These four sources shut down manufacturing operations years ago. When drawing up the boundaries for the listing, the USEPA included a 250 acre block of properties surrounding the Jacobsville neighborhood, including Vectren's Wagner Operations Center. Vectren's property has not been named as a source of the lead contamination, nor does the USEPA's soil testing to date indicate that the Vectren property contains lead contaminated soils. Vectren's own soil testing, completed during the construction of the Operations Center, did not indicate that the Vectren property contains lead contaminated soils. At this time, Vectren anticipates only additional soil testing, if required by the USEPA.

Global Climate Change

Global climate change remains a policy issue that is regularly considered for government regulation. If legislation requiring reductions in greenhouses gases is adopted, such regulation could substantially affect both the costs and operating characteristics of the Company’s fossil fuel plants. Further, that Company’s nonutility coal mining operations may be adversely affected.

14.      
Rate & Regulatory Matters

Ohio and Indiana Lost Margin Recovery/Conservation Filings
In 2005, the Company filed conservation programs and conservation adjustment trackers in Indiana and Ohio designed to help customers conserve energy and reduce their annual gas bills. The programs would allow the Company to recover costs of promoting the conservation of natural gas through conservation trackers that work in tandem with a lost margin recovery mechanism. This mechanism is designed to allow the Company to recover the distribution portion of its rates from residential and commercial customers based on the level of customer revenues established in each utility’s last general rate case.

Indiana
In December 2006, the IURC approved a settlement agreement between the Company and the OUCC that provides for a 5-year energy efficiency program to be implemented. The order allows the Company’s Indiana utilities to recover the costs of promoting the conservation of natural gas through conservation trackers that work in tandem with a lost margin recovery mechanism that would provide for recovery of 85% of the difference between revenues actually collected by the Company and the revenues approved in the Company’s most recent rate case. The order was implemented in the North service territory in December 2006 and will be implemented in South’s service territory after its next general rate case (see below.) While most expenses associated with these programs are recoverable, in the first program year, the Company is required to fund $1.5 million in program costs without recovery.

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Ohio
In September 2006, the PUCO approved a conservation proposal that would implement a decoupling approach, including a related conservation program, for the Company’s Ohio operations. The PUCO decision was issued following a hearing process and the submission of a settlement by the Company, the Ohio Consumer Counselor (OCC) and the Ohio Partners for Affordable Energy (OPAE). That settlement was contested by the PUCO Staff. In the decision the PUCO addressed decoupling by approving a two year, $2 million total, low-income conservation program to be funded by the Company, as well as a sales reconciliation rider intended to be a recovery mechanism for the difference between the weather normalized revenues actually collected by the company and the revenues approved by the PUCO in the Company’s most recent rate case. The decision produced an outcome that was different from the settlement. Following the decision, the Company and the OPAE advised the PUCO that they would accept the outcome even though it differed from the terms of the settlement. The OCC sought rehearing of the decision, which was denied in December, and thereafter the OCC advised the PUCO that the OCC was withdrawing from the settlement. At that point the OCC also initiated the process for appealing the PUCO’s September and December decisions to the Ohio Supreme Court. Thereafter, the Company, the OPAE and the PUCO Staff advised the PUCO that they accepted the terms provided in the September decision, as affirmed by the December rehearing decision. Since that time there have been a number of procedural filings by the parties and presently the company is awaiting a further decision from the PUCO. The company believes that the PUCO had the necessary legal basis for its decisions and thus should confirm the outcome provided in the September decision.

Vectren South (Southern Indiana Gas & Electric) Base Rate Filings
On September 1, 2006, Vectren South filed petitions with the IURC to adjust its electric and gas base rates in its South service territory. The electric petition requests an increase of $76.7 million in base rates to recover the nearly $120 million additional investment in electric utility infrastructure since its last base rate increase in 1995, which is not currently included in rates charged to customers. The increase in rates also is required to support system growth, maintenance, reliability and recovery of costs deferred under previous IURC orders. The gas petition seeks to increase its gas base (non-gas cost) rates by $10.4 million to cover the ongoing costs of operating and maintaining its natural gas distribution and storage system. Based upon the timelines prescribed by the IURC at the start of these proceedings, decisions in each case are expected to be issued in the late summer of 2007. The initial public hearings in both cases have been conducted. On January 30, 2007, the OUCC filed testimony in the gas rate case proposing an increase of $5.1 million.

IGCC Certificate of Public Convenience and Necessity
On September 7, 2006, Vectren Energy Delivery of Indiana and Duke Energy Indiana, Inc. filed with the IURC a joint petition for a Certificate of Public Convenience and Necessity (CPCN) for the construction of new electric capacity. Specifically, Vectren requested the IURC approve its construction and ownership of up to 20% of an Integrated Gasification Combined Cycle (IGCC) project. Vectren's CPCN filing also seeks timely recovery of its 20% portion of the project's construction costs as well as operation and maintenance costs and additional incentives available for the construction of clean coal technology. Initial studies of plant design have already begun, and if the project moves forward as currently designed, plant construction is expected to begin in 2007 and continue through 2011.

Weather Normalization
On October 5, 2005, the IURC approved the establishment of a normal temperature adjustment (NTA) mechanism for Vectren Energy Delivery of Indiana. The OUCC had previously entered into a settlement agreement with Vectren Energy Delivery of Indiana providing for the NTA. The NTA affects the Company’s Indiana regulated residential and commercial natural gas customers and should mitigate weather risk in those customer classes during the October to April heating season. These Indiana customer classes represent approximately 60-65% of the Company’s total natural gas heating load.

The NTA mechanism will mitigate volatility in distribution charges created by fluctuations in weather by lowering customer bills when weather is colder than normal and increasing customer bills when weather is warmer than normal. The NTA has been applied to meters read and bills rendered after October 15, 2005. Each subsequent monthly bill for the seven-month heating season will be adjusted using the NTA.

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The order provides that the Company will make, on a monthly basis, a commitment of $125,000 to a universal service fund program or other low-income assistance program for the duration of the NTA or until a general rate case.

Rate structures in the Company’s Indiana electric territory and Ohio gas territory do not include weather normalization-type clauses.

Gas Utility Base Rate Settlements in 2004 and 2005
On June 30, 2004, the IURC approved a $5.7 million base rate increase for SIGECO’s gas distribution business, and on November 30, 2004, approved a $24 million base rate increase for Indiana Gas’ gas distribution business. On April 13, 2005, the PUCO approved a $15.7 million base rate increase for VEDO’s gas distribution business. The base rate change in SIGECO’s service territory was implemented on July 1, 2004; the base rate change in Indiana Gas’ service territory was implemented on December 1, 2004; and the base rate change in VEDO’s service territory was implemented on April 14, 2005.

The orders also permit SIGECO and Indiana Gas to recover the on-going costs to comply with the Pipeline Safety Improvement Act of 2002. The Pipeline Safety Improvement Tracker provides for the recovery of incremental non-capital dollars, capped at $750,000 the first year and $500,000 thereafter for SIGECO and $2.5 million per year for Indiana Gas. Any costs incurred in excess of these annual caps are to be deferred for future recovery. VEDO’s new base rates provide for the recovery of some level of on-going costs to comply with the Pipeline Safety Improvement Act of 2002.

MISO
Since February 2002 and with the IURC’s approval, the Company has been a member of the Midwest Independent System Operator, Inc. (MISO), a FERC approved regional transmission organization. The MISO serves the electrical transmission needs of much of the Midwest and maintains operational control over the Company’s electric transmission facilities as well as that of other Midwest utilities. Pursuant to an order from the IURC received in December 2001, certain MISO startup costs (referred to as Day 1 costs) have been deferred for future recovery in the next general rate case, which was filed in 2006.

On April 1, 2005, the MISO energy market commenced operation (the Day 2 energy market). As a result of being a market participant, the Company now bids its owned generation into the Day Ahead and Real Time markets and procures power for its retail customers at Locational Marginal Pricing (LMP) as determined by the MISO market.

On June 1, 2005, Vectren, together with three other Indiana electric utilities, received regulatory authority from the IURC that allows recovery of fuel related costs and deferral of other costs associated with the Day 2 energy market. The order allows fuel related costs to be passed through to customers in Vectren’s existing fuel cost recovery proceedings. The other non-fuel and MISO administrative related costs are to be deferred for recovery as part of the next electric general rate case proceeding, which was filed in 2006. During 2006, the IURC reaffirmed the definition of certain costs as fuel related; the company is following those guidelines.

As a result of MISO’s operational control over much of the Midwestern electric transmission grid, including SIGECO’s transmission facilities, SIGECO’s continued ability to import power, when necessary, and export power to the wholesale market has been, and may continue to be, impacted. Given the nature of MISO’s policies regarding use of transmission facilities, as well as ongoing FERC initiatives and uncertainties around Day 2 energy market operations, it is difficult to predict near term operational impacts. However, as stated above, it is believed that MISO’s regional operation of the transmission system will ultimately lead to reliability improvements.

The potential need to expend capital for improvements to the transmission system, both to SIGECO’s facilities as well as to those facilities of adjacent utilities, over the next several years will become more predictable as MISO completes studies related to regional transmission planning and improvements. Such expenditures may be significant.

Gas Cost Recovery (GCR) Audit Proceedings
On June 14, 2005, the PUCO issued an order disallowing the recovery of approximately $9.6 million of gas costs relating to the two-year audit period ended November 2002. That audit period provided the PUCO staff its initial review of the portfolio administration arrangement between VEDO and ProLiance. The disallowance includes approximately $1.3 million relating to pipeline refunds and penalties and approximately $4.5 million of costs for winter delivery services purchased by VEDO to ensure reliability over the two-year period. The PUCO also held that ProLiance should have credited to VEDO an additional $3.8 million more than credits actually received for the right to use VEDO’s gas transportation capacity periodically during the periods when it was not required for serving VEDO’s customers. The PUCO also directed VEDO to either submit its receipt of portfolio administration services to a request for proposal process or to in-source those functions. During 2003, the Company recorded a reserve of $1.1 million for this matter. An additional pretax charge of $4.1 million was recorded in Cost of gas sold in 2005. The reserve reflects management’s assessment of the impact of the PUCO decisions, an estimate of any current impact that decision may have on subsequent audit periods, and an estimate of a sharing in any final disallowance by Vectren’s partner in ProLiance.

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VEDO filed its request for rehearing on July 14, 2005, and on August 10, 2005, the PUCO granted rehearing to further consider the $3.8 million portfolio administration issue and all interest on the findings, but denied rehearing on all other aspects of the case. On October 7, 2005, the Company filed an appeal with the Ohio Supreme Court requesting that the $4.5 million disallowance related to the winter delivery service issue be reversed. On December 21, 2005, the PUCO granted in part VEDO’s rehearing request, and reduced the $3.8 million disallowance related to portfolio administration to $1.98 million. The Company has appealed the $1.98 million disallowance to the Ohio Supreme Court as well. Briefings of all matters and oral arguments were completed in November 2006, and the parties are awaiting the Court’s ruling.

With respect to the most recent GCR audit covering the period of November 1, 2002 through October 31, 2005, the PUCO staff recommended a disallowance of approximately $830,000 related solely to the retention of a reserve margin for the winter of 2002/2003. The Company had previously reserved for the possible disallowance given the June 2005 PUCO order but has contested the disallowance. The PUCO will issue a decision on that issue in 2007.

As a result of the June 2005 PUCO order, the Company has established an annual bidding process for VEDO’s gas supply and portfolio administration services. Since November 1, 2005, the Company has used a third party provider for these services.

15.      
Derivatives & Other Financial Instruments

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

When an energy contract that is a derivative is designated and documented as a normal purchase or normal sale, it is exempted from mark-to-market accounting. Otherwise, energy contracts and financial contracts that are derivatives 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. The offset resulting from carrying the derivative at fair value on the balance sheet is charged to earnings unless it qualifies as a hedge or is subject to SFAS 71. When hedge accounting is appropriate, the Company assesses and documents hedging relationships between the derivative contract and underlying risks as well as its risk management objectives and anticipated effectiveness. When the hedging relationship is highly effective, derivatives are designated as hedges. The market value of the effective portion of the hedge is marked to market in accumulated other comprehensive income for cash flow hedges or, as an adjustment to the underlying’s basis for fair value hedges. The ineffective portion of hedging arrangements is marked-to-market through earnings. The offset to contracts affected by SFAS 71 are marked-to-market as a regulatory asset or liability. Market value for derivative contracts is determined using quoted market prices from independent sources. Following is a more detailed discussion of the Company’s use of mark-to-market accounting in five primary areas: asset optimization, synfuels hedging, SO2 emission allowance risk management, natural gas procurement, and interest rate management.

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Asset Optimization
Periodically, generation capacity is in excess of that needed to serve native load and firm wholesale customers. The Company markets this unutilized capacity to optimize the return on its owned generation assets. These optimization strategies involve the sale of excess generation into the MISO day ahead and real-time markets. As part of these strategies, the Company may execute energy contracts that are integrated with portfolio requirements around power supply and delivery and are short-term purchase and sale transactions that expose the Company to limited market risk. Contracts with counter-parties subject to master netting arrangements are presented net in the Consolidated Balance Sheets. Asset optimization contracts that are derivatives are recorded at market value.

At December 31, 2006, no asset optimization contracts remained in Prepayments & other current assets. At December 31, 2005, asset optimization contracts recorded at market value approximated $1.3 million of Prepayments & other current assets.

The proceeds received and paid upon settlement of both purchase and sale contracts along with changes in market value of open contracts that are derivatives are recorded in Electric utility revenues. Net revenues from asset optimization activities totaled $29.8 million in 2006, $38.0 million in 2005, and $23.8 million in 2004.

Synfuel Risk Management
As discussed in Note 3, the Company’s synfuel operations are exposed to commodity price risk associated with oil. The Company has executed derivative instruments designed to limit the effects of a phase out of synfuel tax credits. During 2006 the Company purchased contracts with a notional amount of 0.5 million barrels to mitigate 2006 phase out risk. All contracts were settled in 2006 at a loss of $5.3 million, which is recorded in Other-net. In 2006, the Company also purchased contracts with a notional amount of 2.8 million barrels to mitigate 2007 phase out risk. The mark to market loss associated with these contracts totaled $2.5 million in 2006 and is also reflected in Other-net. The fair value of those contracts which is recorded in Prepayments and other current assets totaled $11.2 million as of December 31, 2006. The pretax impact of an insurance contract related to synfuels was earnings of $3.1 million in 2006 and a loss of $1.9 million in 2005. These results are also recorded in Other, net. As of December 31, 2006 and 2005, the fair value of the insurance contract, which is included in Prepayments and other current assets, totaled $4.4 million and $1.3 million, respectively.

SO2 Emission Allowance Risk Management
The Company’s wholesale power marketing operations are exposed to price risk associated with SO2 emission allowances. Recently, the price for emission allowances has become more volatile. To hedge this risk, the Company executed call options in 2004 and 2005 to hedge wholesale emission allowance utilization in future periods. The Company designated and documented these derivatives as cash flow hedges. At December 31, 2006, a deferred gain of approximately $1.4 million remains in accumulated comprehensive income which will be recognized in earnings as emission allowances are utilized. Hedge ineffectiveness totaled $0.2 million of expense in 2006 and $0.8 million of expense in 2005. No SO2 emission allowance hedges are outstanding as of December 31, 2006.

Natural Gas Procurement Activity
The Company’s regulated operations have limited exposure to commodity price risk for purchases and sales of natural gas and electricity for retail customers due to current Indiana and Ohio regulations which, subject to compliance with those regulations, allow for recovery of such purchases through natural gas and fuel cost adjustment mechanisms. Although Vectren’s regulated operations are exposed to limited commodity price risk, volatile natural gas prices can result in higher working capital requirements, increased expenses including unrecoverable interest costs, uncollectible accounts expense, and unaccounted for gas, and some level of price- sensitive reduction in volumes sold. The Company mitigates these risks by executing derivative contracts that manage the price volatility of forecasted natural gas purchases. These contracts are subject to regulation which allows for reasonable and prudent hedging costs to be recovered through rates. When regulation is involved, SFAS 71 controls when the offset to mark-to-market accounting is recognized in earnings. 

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

At December 31, 2006 and 2005, the market values of these contracts and the book value of weather contracts were not significant.

Interest Rate Management
The Company is exposed to interest rate risk associated with its borrowing arrangements. Its risk management program seeks to reduce the potentially adverse effects that market volatility may have on interest expense. The Company has used interest rate swaps and treasury locks to hedge forecasted debt issuances and other interest rate swaps to manage interest rate exposure. Hedging instruments are recorded at market value. Changes in market value, when effective, are recorded in Accumulated other comprehensive income for cash flow hedges, as an adjustment to the outstanding debt balance for fair value hedges, or as regulatory asset/liability when regulation is involved. Amounts are recorded to interest expense as settled.

Interest rate swaps hedging the fair value of fixed-rate debt with a total notional amount of $17.5 million are outstanding. The fair value liability associated with those swaps was $0.3 million at December 31, 2006 and $0.6 million at December 31, 2005. At December 31, 2006, an approximate $2.8 million net regulatory liability remains. Of that net liability, $0.6 million will be reclassified to earnings in 2007, $0.7 million was reclassified to earnings in 2006, and $0.6 million was reclassified to earnings during both 2005 and 2004.

Fair Value of Other Financial Instruments
The carrying values and estimated fair values of the Company's other financial instruments follow:


   
At December 31,
 
   
2006
 
2005
 
(In millions)
 
Carrying Amount
 
Est. Fair Value
 
Carrying Amount
 
Est. Fair Value
 
Long-term debt
 
$
1,256.3
 
$
1,276.1
 
$
1,256.9
 
$
1,312.9
 
Short-term borrowings & notes payable
   
464.8
   
464.8
   
299.9
   
299.9
 

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, its carrying amount approximates its fair value.

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.

Periodically, the Company tests its cost method investments and notes receivable for impairment which may require their fair value to be estimated. Because of the customized nature of these 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 costs. At December 31, 2006, and 2005, the fair value for these financial instruments was not estimated.

16.  
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 into 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 marketing operations. The Company cross manages its regulated operations as separated between Energy Delivery, which includes the gas and electric transmission and distribution functions, and Power Supply, which includes the power generating and marketing operations. In total, regulated operations supply natural gas and /or electricity to over one million customers. In total, the Utility Group has three operating segments of as defined by SFAS 131 “Disclosure About Segments of an Enterprise and Related Information” (SFAS 131).

-83-

The Nonutility Group is comprised of one operating segment as defined by SFAS 131 that includes various subsidiaries and affiliates investing in energy marketing and services, coal mining, and energy infrastructure services, among other energy-related opportunities.

Corporate and Other includes unallocated corporate expenses such as branding and charitable contributions, among other activities, that benefit the Company’s other operating segments. Net income is the measure of profitability used by management for all operations. Information related to the Company’s business segments is summarized below:
 
       
Year Ended December 31,
 
(In millions)
     
2006
 
2005
 
2004
 
Revenues
                 
  Utility Group                
Gas Utility Services
       
$
1,232.5
 
$
1,359.7
 
$
1,126.2
 
Electric Utility Services
         
422.2
   
421.4
   
371.3
 
Other Operations
         
36.6
   
36.1
   
32.9
 
Eliminations
         
(34.8
)
 
(35.4
)
 
(32.4
)
Total Utility Group  
         
1,656.5
   
1,781.8
   
1,498.0
 
Nonutility Group
         
503.2
   
344.3
   
272.1
 
Eliminations
         
(118.1
)
 
(98.1
)
 
(80.3
)
Consolidated Revenues
       
$
2,041.6
 
$
2,028.0
 
$
1,689.8
 
Profitability Measures - Net Income
                         
Gas Utility Services
       
$
41.5
 
$
34.7
 
$
28.1
 
Electric Utility Services
         
41.6
   
50.4
   
47.9
 
Other Operations
         
8.3
   
10.0
   
7.1
 
Utility Group Net Income 
       
 
91.4
 
 
95.1
 
 
83.1
 
Nonutility Group Net Income
         
18.1
   
48.2
   
26.4
 
Corporate & Other Net Loss
         
(0.7
)
 
(6.5
)
 
(1.6
)
Consolidated Net Income
       
$
108.8
  $
136.8
 
$
107.9
 
 
           
Year Ended December 31,
 
(In millions)
         
2006
 
2005
 
2004
 
Amounts Included in Profitability Measures
                     
   Depreciation & Amortization  
 
                 
      Utility Group      
 
             
Gas Utility Services 
             
$
67.6
 
$
64.9
 
$
57.0
 
Electric Utility Services 
               
61.8
   
56.9
   
53.3
 
Other Operations 
               
21.9
   
19.5
   
17.5
 
 Total Utility Group
               
151.3
   
141.3
   
127.8
 
Nonutility Group
               
21.0
   
16.0
   
12.0
 
Corporate & Other
               
-
   
0.9
   
0.3
 
Consolidated Depreciation & Amortization
             
$
172.3
 
$
158.2
 
$
140.1
 



           
Year Ended December 31,
 
(In millions)
         
2006
 
2005
 
2004
 
Interest Expense
                               
Utility Group
                               
Gas Utility Services 
             
$
40.7
 
$
40.2
 
$
41.4
 
Electric Utility Services 
               
28.6
   
23.7
   
21.3
 
Other Operations 
               
8.2
   
6.0
   
4.7
 
 Total Utility Group
               
77.5
   
69.9
   
67.4
 
Nonutility Group
               
20.0
   
14.6
   
11.3
 
Corporate & Other
               
(1.9
)
 
(0.6
)
 
(1.0
)
Consolidated Interest Expense
             
$
95.6
 
$
83.9
   
77.7
 
Equity in Earnings of Unconsolidated Affiliates
                               
Utility Group: Other Operations
             
$
-
 
$
-
 
$
0.2
 
Nonutility Group
               
17.0
   
45.6
   
20.4
 
Consolidated Equity in Earnings of Unconsolidated Affiliates
             
$
17.0
 
$
45.6
 
$
20.6
 
Income Taxes
                               
Utility Group
                               
Gas Utility Services 
             
$
22.6
 
$
22.3
 
$
17.5
 
Electric Utility Services 
               
25.3
   
33.5
   
30.8
 
Other Operations 
               
(0.2
)
 
1.7
   
4.8
 
 Total Utility Group
               
47.7
   
57.5
   
53.1
 
Nonregulated Group
               
(17.6
)
 
(9.9
)
 
(13.6
)
Corporate & Other
               
0.2
   
(3.5
)
 
(0.5
)
Consolidated Income Taxes
             
$
30.3
 
$
44.1
 
$
39.0
 
Capital Expenditures
                               
Utility Group
                               
Gas Utility Services
             
$
76.8
 
$
81.0
 
$
89.1
 
Electric Utility Services
               
156.8
   
100.0
   
150.6
 
Other Operations
               
24.8
   
29.9
   
27.9
 
Non-cash costs & changes in accruals
               
(11.8
)
 
3.6
   
(25.4
)
Total Utility Group 
               
246.6
   
214.5
   
242.2
 
Nonutility Group
               
34.8
   
17.1
   
10.3
 
Consolidated Capital Expenditures
             
$
281.4
 
$
231.6
 
$
252.5
 
Investments in Equity Method Investees
                               
Nonutility Group
             
$
16.7
 
$
19.2
 
$
18.2
 
 
               
       
At December 31,
 
(In millions)
     
2006
 
2005
 
Assets
             
   Utility Group  
 
         
Gas Utility Services
       
$
1,953.6
 
$
2,030.8
 
Electric Utility Services
         
1,277.6
   
1,176.0
 
Other Operations
         
225.9
   
188.9
 
Eliminations
         
(16.3
)
 
(5.6
)
Total Utility Group 
         
3,440.8
   
3,390.1
 
Nonutility Group
         
639.7
   
542.4
 
Corporate & Other
         
466.7
   
369.1
 
Eliminations
         
(455.6
)
 
(433.5
)
Consolidated Assets
       
$
4,091.6
 
$
3,868.1
 



17.      
Additional Operational & Balance Sheet Information

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


           
   
At December 31,
 
(In millions)
 
2006
 
2005
 
Prepaid gas delivery service
 
$
66.2
 
$
69.3
 
Utilicom receivable - current
   
44.6
   
-
 
Fair market value of derivative instruments
   
15.6
   
2.6
 
Prepaid taxes
   
12.3
   
5.3
 
Deferred income taxes
   
3.6
   
-
 
Other prepayments & current assets
   
30.4
   
29.2
 
Total prepayments & other current assets
 
$
172.7
 
$
106.4
 

Accrued liabilities in the Consolidated Balance Sheets consist of the following:
           
   
At December 31,
 
(In millions)
 
2006
 
2005
 
Refunds to customers & customer deposits
 
$
43.0
 
$
36.7
 
Accrued taxes
   
31.6
   
34.2
 
Accrued interest
   
16.8
   
17.2
 
Deferred income taxes
   
-
   
7.6
 
Accrued salaries & other
   
55.8
   
60.9
 
Total accrued liabilities
 
$
147.2
 
$
156.6
 
 
Other - net in the Consolidated Statements of Income consists of the following:

               
   
Year Ended December 31,
 
(In millions)
 
2006
 
2005
 
2004
 
AFUDC & capitalized interest
 
$
5.3
 
$
2.5
 
$
4.6
 
Interest income
   
4.0
   
3.8
   
3.0
 
Synfuel-related activity
   
(11.4
)
 
(1.9
)
 
-
 
Broadband charges
   
(1.9
)
 
(1.1
)
 
(6.0
)
Gain/loss on sale of investments
   
(0.6
)
 
(0.1
)
 
0.4
 
All other income
   
1.9
   
3.0
   
2.6
 
Total other – net
 
$
(2.7
)
$
6.2
 
$
4.6
 

 
18.      
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 2006 and 2005 follows:
                   
(In millions, except per share amounts)
 
Q1
 
Q2
 
Q3
 
Q4
 
2006
                 
Operating revenues 
 
$
774.5
 
$
317.5
 
$
340.5
 
$
609.1
 
Operating income 
   
91.5
   
28.5
   
28.4
   
72.1
 
Net income 
   
57.6
   
4.3
   
12.0
   
34.9
 
Earnings per share: 
                         
 Basic
 
$
0.76
 
$
0.06
 
$
0.16
 
$
0.46
 
 Diluted
   
0.76
   
0.06
   
0.16
   
0.45
 
2005
                         
Operating revenues 
 
$
677.2
 
$
326.2
 
$
310.8
 
$
713.8
 
Operating income 
   
95.2
   
29.2
   
29.9
   
58.8
 
Net income 
   
56.1
   
13.4
   
16.5
   
50.8
 
Earnings per share: 
                         
 Basic
 
$
0.74
 
$
0.18
 
$
0.22
 
$
0.67
 
 Diluted
   
0.74
   
0.18
   
0.22
   
0.66
 

19.      
Impact of Recently Issued Accounting Guidance

SFAS No. 157
In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (SFAS 157). SFAS 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles (GAAP), and expands disclosures about fair value measurements. This statement does not require any new fair value measurements; however, the standard will impact how other fair value based GAAP is applied. SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years with early adoption encouraged. The Company is currently assessing the impact this statement will have on its financial statements and results of operations.
 
FIN 48
In June 2006, the FASB issued FASB Interpretation No. 48 (FIN 48) “Accounting for Uncertainty in Income Taxes” an interpretation of SFAS 109, Accounting for Income Taxes. FIN 48 prescribes a recognition threshold and measurement attribute for financial statement recognition and measurement of tax positions taken or expected to be taken in an income tax return. FIN 48 also provides guidance related to reversal of tax positions, balance sheet classification, interest and penalties, interim period accounting, disclosure and transition. The interpretation is effective for fiscal years beginning after December 15, 2006. The adoption of this standard is not expected to have a material impact on operating results or financial condition.

-87-


ITEM 9. CHANGE 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, 2006, 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, 2006, 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, 2006, to ensure that the information required to be disclosed and filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.
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, 2006.

Management’s assessment of the effectiveness of internal control over financial reporting as of December 31, 2006, 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 definitive Proxy Statement for its 2007 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission pursuant to Regulation 14A, within 120 days after the end of the fiscal year. The Company’s executive officers are the same as those named executive officers detailed in the Proxy Statement.

The Company’s Corporate Governance Guidelines, its charters for each of its Audit, Compensation and Benefits and Nominating and Corporate Governance Committees, and its Code of Ethics covering the Company’s directors, officers and employees are available on the Company’s website, www.vectren.com, and a copy will be mailed upon request to Investor Relations, Attention: Steve Schein, One Vectren Square, Evansville, Indiana 47708. The Company intends to disclose any amendments to the Code of Ethics or waivers of the Code of Ethics on behalf of the Company’s directors or officers including, but not limited to, the principal executive officer, principal financial officer, principal accounting officer or controller 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 Investor Relations, Attention: Steve Schein, One Vectren Square, Evansville, Indiana 47708.

-88-

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 definitive Proxy Statement for its 2007 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission pursuant to Regulation 14A, within 120 days after the end of the fiscal year.

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

Except with respect to equity compensation plan information of the Registrant, which is included herein, the information required by Part III, Item 12 of this Form 10-K is incorporated by reference herein, and made part of this Form 10-K, from the Company's definitive Proxy Statement for its 2007 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission pursuant to Regulation 14A, within 120 days after the end of the fiscal year.

Shares Issuable under Share-Based Compensation Plans

As of December 31, 2006, 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
   
1,963,985
   
(1
)
$
23.33
   
(1
)
 
2,823,947
   
(2
)
Equity compensation plans not approved
                                     
by security holders
   
-
         
-
         
-
       
Total
   
1,963,985
       
$
23.33
         
2,823,947
       
 
(1)  
Includes the following Vectren Corporation Plans: Vectren Corporation At-Risk Compensation Plan and 1994 SIGCORP Stock Option Plan.
(2)  
Future issuances of shares awards can only be made under the Vectren Corporation At-Risk Plan. Shares available for issuance under the At-Risk Plan have been reduced by the issuance of 167,100 restricted shares approved by the board of directors’ Compensation Committee, effective January 1, 2007.

The SIGCORP stock option plan was approved by SIGCORP common shareholders prior to the merger forming Vectren. The At-Risk Compensation plan was approved by Vectren Corporation common shareholders after the merger forming Vectren.

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 definitive Proxy Statement for its 2007 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission pursuant to Regulation 14A, within 120 days after the end of the fiscal year.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

Information required by Part III, Item 14 of this Form 10-K is incorporated by reference herein, and made part of this Form 10-K, from the Company's definitive Proxy Statement for its 2007 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission pursuant to Regulation 14A, within 120 days after the end of the fiscal year.

-89-

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

List of Documents Filed as Part of This Report

Consolidated Financial Statements

The consolidated financial statements and related notes, together with the report of Deloitte & Touche LLP, appear in Part II “Item 8 Financial Statements and Supplementary Data” of this Form 10-K. The financial statements of ProLiance Energy, LLC are attached as exhibit 99.1 to this Form 10-K.

Supplemental Schedules

For the years ended December 31, 2006, 2005, and 2004, 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 2006 – Accumulated provision for
                     
             uncollectible accounts
 
$
2.8
 
$
15.3
 
$
-
 
$
15.0
 
$
3.1
 
Year 2005 – Accumulated provision for
                               
                     uncollectible accounts
 
$
2.0
 
$
15.1
 
$
-
 
$
14.3
 
$
2.8
 
Year 2004 – Accumulated provision for
                               
                     uncollectible accounts
 
$
3.2
 
$
11.9
 
$
-
 
$
13.1
 
$
2.0
 
OTHER RESERVES:
                               
Year 2006 – Restructuring costs
 
$
2.4
 
$
-
 
$
-
 
$
0.7
 
$
1.7
 
Year 2005 – Restructuring costs
 
$
2.7
 
$
-
 
$
-
 
$
0.3
 
$
2.4
 
Year 2004 – Restructuring costs
 
$
3.2
 
$
-
 
$
-
 
$
0.5
 
$
2.7
 



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 beginning on page 94.

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 were filed electronically with the SEC with this filing.

Exhibit
Number
 
Document 
   
21.1
List of Company’s Significant Subsidiaries
 
23.1
Consent of Independent Registered Public Accounting Firm
 
23.2
Consent of Independent Auditors
 
99.1
ProLiance Energy, LLC Consolidated Financial Statements


-91-


INDEX TO EXHIBITS

2. Plan of Acquisition, Reorganization, Arrangement, Liquidation or Succession
2.1  
Asset Purchase Agreement dated December 14, 1999 between Indiana Energy, Inc. and The Dayton Power and Light Company and Number-3CHK with a commitment letter for a 364-Day Credit Facility dated December 16,1999. (Filed and designated in Current Report on Form 8-K dated December 28, 1999, File No. 1-9091, as Exhibit 2 and 99.1)

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  
Amended and Restated Code of By-Laws of Vectren Corporation as of February 1, 2007. (Filed and designated in Current Report on Form 8-K filed February 5, 2007, File No. 1-15467, as Exhibit 3.2.)
3.3  
Shareholders Rights Agreement dated as of October 21, 1999 between Vectren Corporation and Equiserve Trust Company, N.A., as Rights Agent. (Filed and designated in Form S-4 (No. 333-90763), filed November 12. 1999, File No. 1-15467, as Exhibit 4.)


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 designated in Form 10-K for the year ended December 31, 2004, File No. 1-15467, as Exhibit 4.1.) October 1, 2004. (Filed designated in Form 10-K for the year ended December 31, 2004, File No. 1-15467, as Exhibit 4.2.)

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

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

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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.)


10. Material Contracts

10.1  
Summary description of Southern Indiana Gas and Electric Company's nonqualified Supplemental Retirement Plan (Filed and designated in Form 10-K for the fiscal year 1992, File No. 1-3553, as Exhibit 10-A-17.) First Amendment, effective April 16, 1997 (Filed and designated in Form 10-K for the fiscal year 1997, File No. 1-3553, as Exhibit 10.29.).
10.2  
Southern Indiana Gas and Electric Company 1994 Stock Option Plan (Filed and designated in Southern Indiana Gas and Electric Company's Proxy Statement dated February 22, 1994, File No. 1-3553, as Exhibit A.)
10.3  
Indiana Energy, Inc. Unfunded Supplemental Retirement Plan for a Select Group of Management Employees as amended and restated effective December 1, 1998. (Filed and designated in Form 10-Q for the quarterly period ended December 31, 1998, File No. 1-9091, as Exhibit 10-G.)
10.4  
Vectren Corporation At Risk Compensation Plan effective May 1, 2001,(as amended and restated s of May 1, 2006). (Filed and designated in Vectren Corporation’s Proxy Statement dated March 15, 2006, File No. 1-15467, as Appendix H.)
10.5  
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.)
10.6  
Vectren Corporation Change in Control Agreement between Vectren Corporation and Niel C. Ellerbrook dated as of March 1, 2005. (Filed and designated in Form 8-K dated March 1, 2005, File No. 1-15467, as Exhibit 99.1.)
10.7  
Vectren Corporation At Risk Compensation Plan specimen Restricted Stock 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 99.1.)
10.8  
Vectren Corporation At Risk Compensation Plan specimen restricted stock grant agreement for officers, effective January 1, 2006. (Filed and designated in Form 8-K, dated February 27, 2006, File No. 1-15467, as Exhibit 99.1.)
10.9  
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.)
10.10  
Vectren Corporation specimen employment agreement dated February 1, 2005. (Filed and designated in Form 8-K, dated February 1, 2005, File No. 1-15467, as Exhibit 99.1.)
10.11  
Life Insurance Replacement Agreement between Vectren Corporation and certain named officers, effective December 31, 2006. (Filed and designated in Form 8-K, dated December 31, 2006, File No. 1-15467 as Exhibit 99.1.)
10.12  
Gas Sales and Portfolio Administration Agreement between Indiana Gas Company, Inc. and ProLiance Energy, LLC, effective August 30, 2003. (Filed and designated in Form 10-K, for the year ended December 31, 2003, File No. 1-15467, as Exhibit 10.15.)
10.13  
Gas Sales and Portfolio Administration Agreement between Southern Indiana Gas and Electric Company and ProLiance Energy, LLC, effective September 1, 2002. (Filed and designated in Form 10-K, for the year ended December 31, 2003, File No. 1-15467, as Exhibit 10.16.)
10.14  
Coal Supply Agreement for F.B. Culley Generating Station between Southern Indiana Gas and Electric Company and Vectren Fuels, Inc., dated December 17, 1997 and effective January 1, 1998. (Filed and designated in Form 10-K, for the year ended December 31, 2003, File No. 1-15467, as Exhibit 10.18.) Portions of the document have been omitted pursuant to a request to a request for confidential treatment. Amendment 1, effective January 1, 2003, to Coal Supply Agreement between Southern Indiana Gas and Electric Company and Vectren Fuels, Inc originally dated December 17, 1997. (Filed and designated in Form 10-K, for the year ended December 31, 2003, File No. 1-15467, as Exhibit 10.19.)
10.15  
Coal Supply Agreement for Generating Stations at Yankeetown, Warrick County, Indiana, and West Franklin, Posey County, Indiana between Southern Indiana Gas and Electric Company and Vectren Fuels, Inc., dated January 19, 2000. (Filed and designated in Form 10-K, for the year ended December 31, 2003, File No. 1-15467, as Exhibit 10.20.) Amendment 1, effective January 1, 2004, to Coal Supply Agreement between Southern Indiana Gas and Electric Company and Vectren Fuels, Inc originally dated January 19, 2000. (Filed and designated in Form 10-K, for the year ended December 31, 2003, File No. 1-15467, as Exhibit 10.21.)
10.16  
Formation Agreement among Indiana Energy, Inc., Indiana Gas Company, Inc., IGC Energy, Inc., Indiana Energy Services, Inc., Citizens Gas & Coke Utility, 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.)
 

10.17  
Revolving Credit Agreement (5 year facility), dated November 10, 2005, among Vectren Utility Holdings, Inc., and each of the purchasers named therein. (Filed and designated in Form 10-K, for the year ended December 31, 2005, File No. 1-15467, as Exhibit 10.24.)
10.18  
Revolving Credit Agreement (5 year facility), dated November 10, 2005, among Vectren Capital Corp., and each of the purchasers named therein. (Filed and designated in Form 10-K, for the year ended December 31, 2005, File No. 1-15467, as Exhibit 10.25.)
 
21. Subsidiaries of the Company
The list of the Company's significant subsidiaries is attached hereto as Exhibit 21.1.
 
23. Consents of Experts and Counsel
The consents of Deloitte & Touche LLP are attached hereto as Exhibits 23.1 and 23.2.

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

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

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

99.1 ProLiance Energy, LLC Consolidated Financial Statements for the Fiscal Years Ended September 30, 2006, 2005, and 2004. (Filed herewith.)

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SIGNATURES

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


Dated February 16, 2007                      /s/ Niel C. Ellerbrook                                                      
Niel C. Ellerbrook,
Chairman, President, Chief Executive Officer, and Director

Pursuant to the requirements of the Securities and Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in capacities and on the dates indicated.
 
Signature
 
Title
 
Date
         
 
/s/ Niel C. Ellerbrook
 
Chairman, President, Chief
Executive Officer, &
 
 
February 16, 2007
Niel C. Ellerbrook
 
 
Director (Principal Executive
Officer)
 
   
/s/ Jerome A. Benkert, Jr.
 
Executive Vice President &
 
February 16, 2007
Jerome A. Benkert, Jr.
 
 
Chief Financial Officer
(Principal Financial Officer)
 
   
 
/s/ M. Susan Hardwick
 
Vice President, Controller &
Assistant Treasurer
 
 
February 16, 2007
M. Susan Hardwick
 
 
(Principal Accounting Officer)
   
/s/ John M. Dunn
 
Director
 
February 16, 2007
John M. Dunn
 
       
/s/ John D. Engelbrecht
 
Director
 
February 16, 2007
John D. Engelbrecht
 
       
/s/ Anton H. George
 
Director
 
February 16, 2007
Anton H. George
 
       
         
/s/ Robert L. Koch II
 
Director
 
February 16, 2007
Robert L. Koch II
 
       
/s/ William G Mays
 
Director
 
February 16, 2007
William G. Mays
 
       
/s/ J. Timothy McGinley
 
Director
 
February 16, 2007
J. Timothy McGinley
 
       
/s/ Richard P. Rechter
 
Director
 
February 16, 2007
Richard P. Rechter
 
       
/s/ R. Daniel Sadlier
 
Director
 
February 16, 2007
R. Daniel Sadlier
 
       
/s/ Richard W. Shymanski
 
Director
 
February 16, 2007
Richard W. Shymanski
 
       
/s/ Michael L Smith
 
Director
 
February 16, 2007
Michael L Smith
 
       
/s/ Jean L Wojtowicz
 
Director
 
February 16, 2007
Jean L.Wojtowicz
       
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