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: **1-16739**





**VECTREN
                UTILITY HOLDINGS, INC.**


(Exact
      name of registrant as specified in its charter)









**INDIANA**
            
            **35-2104850**(State
                or other jurisdiction of incorporation or organization)
            
            (IRS
                Employer Identification No.)**One
                Vectren Square, Evansville, Indiana**
            
            **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





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





Title
                of each class
            
            Name
                of each exchange on which registered**Common
                - Without Par**
            
            **None**


Table
          of Contents


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 □


* Utility
      Holdings is a majority owned subsidiary of a well-known seasoned issuer, and
      well-known seasoned issuer status depends in part on the type of security being
      registered by the majority-owned subsidiary.





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





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





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





Indicate
      by check mark whether the registrant is a large accelerated filer, an
      accelerated filer, 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 □  Accelerated
      filer □  Non-accelerated
      filer ý





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 zero. All shares outstanding of the Registrant’s common stock were
      held by Vectren Corporation.





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**
            **10**
            **January
                31, 2007**Class
            Number
                of Shares
            Date





**Omission
      of Information by Certain Wholly Owned Subsidiaries**





The
      Registrant is a wholly owned subsidiary of Vectren Corporation and meets the
      conditions set forth in General Instructions (I)(1)(a) and (b) of Form 10-K
      and
      is therefore filing with the reduced disclosure format contemplated
      thereby.





**Access
      to Information**





Vectren
      Corporation makes available all SEC filings and recent annual reports, including
      those of Vectren Utility Holdings, Inc., 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


-2-
 Table
          of Contents


**Table
      of Contents**





Item
            
            
            PageNumber
            
            NumberPart
                I1
            
            Business
            
            41A
            
            Risk
                Factors
            
            81B
            
            Unresolved
                Staff Comments
            
            112
            
            Properties
            
            113
            
            Legal
                Proceedings
            
            124
            
            Submission
                of Matters to Vote of Security
                Holders
            
            12Part
                II5
            
            Market
                for the Company’s Common Equity, Related Stockholder
                Matters, and Issuer Purchases of Equity Securities
            
            136
            
            Selected
                Financial Data
            
            147
            
            Management's
                Discussion and Analysis of Results of Operations
                and Financial Condition
            
            147A
            
            Quantitative
                andQualitative Disclosures About Market
                Risk
            
            328
            
            Financial
                Statements and Supplementary Data
            
            349
            
            Changes
                in and Disagreements with Accountants on Accounting and
                Financial Disclosure
            
            689A
            
            Controls
                and ProceduresControls
                and Procedures
            
            689B
            
            Other
                Information
            
            68Part
                III10
            
            Directors,
                Executive Officers and Corporate Governance(A)
            
            6811
            
            Executive
                Compensation(A)
            
            6812
            
            Security
                Ownership of Certain Beneficial Owners and Management and Related
                Stockholder Matters(A).
            
            6813
            
            Certain
                Relationships and Related Transactions(A)
            
            6814
            
            Principal
                Accountant Fees and Services
            
            69Part
                IV15
            
            Exhibits
                and Financial Statement Schedules
            
            70Signatures
            
            75





(A)
            -Omitted
                or amended as the Registrant is a wholly owned subsidiary of Vectren
                Corporation and meets the conditions set forth in General Instructions
                (I)(1)(a) and (b) of Form 10-K and is therefore filing with the reduced
                disclosure format contemplated
                thereby.





**Definitions**


AFUDC:
                allowance for funds used during construction
            MMBTU:
                millions of British thermal unitsAPB:
                Accounting Principles Board
            MW:
                megawattsEITF:
                Emerging Issues Task Force
            MWh
                / GWh: megawatt hours / thousands of megawatt hours (gigawatt
                hours)FASB:
                Financial Accounting Standards Board
            NOx:
                nitrogen oxideFERC:
                Federal Energy Regulatory Commission
            OUCC:
                Indiana Office of the Utility Consumer CounselorIDEM:
                Indiana Department of Environmental Management
            PUCO:
                Public Utilities Commission of OhioIURC:
                Indiana Utility Regulatory Commission
            SFAS:
                Statement of Financial Accounting StandardsMCF
                / BCF: thousands / billions of cubic feet
            USEPA:
                United States Environmental Protection AgencyMDth
                / MMDth: thousands / millions of dekatherms
            Throughput:
                combined gas sales and gas transportation
                volumes







-3-
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          of Contents


**PART
      I**





**ITEM
      1. BUSINESS**





**Description
      of the Business**





Vectren
      Utility Holdings, Inc. (Utility Holdings or the Company), an Indiana
      corporation, was formed on March 31, 2000, to serve as the intermediate holding
      company for Vectren Corporation’s (Vectren) 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 assets
      that
      provide information technology and other services to the utilities.




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 natural 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, (53% ownership) and Indiana Gas (47% ownership). The
      Ohio operations generally do business as Vectren Energy Delivery of Ohio.





Vectren,
      an Indiana corporation, is an energy holding company headquartered in
      Evansville, Indiana, and organized on June 10, 1999. 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.








**Narrative
      Description of the Business**





The
      Company segregates its businesses into three operating segments: Gas Utility
      Services, Electric Utility Services, and Other Operations. 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 marketing operations. The Company
      collectively refers to its gas and electric operating segments as its regulated
      operations. In total, these regulated operations supply natural gas and/or
      electricity to over one million customers. Other Operations primarily provide
      information technology and other support services to those utility operations.





At
      December 31, 2006, the Company had $3.4 billion in total assets, with $2.0
      billion (57%) attributed to the Gas Utility Services, $1.3 billion (37%)
      attributed to the Electric Utility Services, and $0.2 billion (6%) attributed
      to
      Other Operations. Net income for the year ended December 31, 2006, was $91.4
      million with $83.1 million attributed to regulated operations and $8.3 million
      attributed to other operations. Net income for the year ended 2005 was $95.1
      million.





For
      further information, refer to Note 12 regarding the activities and assets of
      the
      Company’s operating segments in the Company’s consolidated financial statements
      included under “Item 8 Financial Statements and Supplementary
      Data”.





Following
      is a more detailed description of the Gas Utility Services and Electric Utility
      Services operating segments. The Company’s Other Operations are not
      significant.





-4-
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          of Contents


**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, and
      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 Note 4 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 addition, the Company prepays ProLiance
      for natural gas delivery services during the seven months prior to the peak
      heating season. The volume of gas per day that can be delivered during peak
      demand periods for each utility is 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.





**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.





-5-
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The
      principal industries served include polycarbonate resin (Lexan®) and plastic
      products, aluminum smelting and recycling, aluminum sheet products, automotive
      assembly, steel finishing, 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 1,301 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
              
              8/5/2002Total
                  load at peak(1)
              
              
              1,325
              
              
              1,315
              
              
              1,222
              
              
              1,272
              
              
              1,258Generating
                  capability
              
              
              1,351
              
              
              1,351
              
              
              1,351
              
              
              1,351
              
              
              1,351Firm
                  purchase supply
              
              
              107
              
              
              107
              
              
              105
              
              
              32
              
              
              82Interruptible
                  contracts
              
              
              62
              
              
              76
              
              
              51
              
              
              95
              
              
              95Total
                  power supply capacity
              
              
              1,520
              
              
              1,534
              
              
              1,507
              
              
              1,478
              
              
              1,528Reserve
                  margin at peak
              
              
              15
              %
              
              17
              %
              
              23
              %
              
              16
              %
              
              21
              %


(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.




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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, in addition to its generating 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
              
              2002Ton
              
              $
              37.51
              
              $
              30.27
              
              $
              27.06
              
              $
              24.91
              
              $
              23.50MWh
              
              
              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, approximately 72,000 customers in Utility Holdings’ 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.





**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.


-7-
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**Personnel**





As
      of
      December 31, 2006, the Company and its consolidated subsidiaries had 1,599
      employees, of which 828 are subject to collective bargaining arrangements.





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.





No
      contracts subject to collective
      bargaining expired
      in 2006. The next negotiation will be with the International Brotherhood of
      Electrical Workers Local 702,
      whose contract expires in June of 2007.





**ITEM
      1A. RISK FACTORS**





The
      following factors 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.





**The
      Company is a holding company, and its assets consist primarily of investments
      in
      its subsidiaries.**





Dividends
      on the Company’s common stock depend on the earnings, financial condition,
      capital requirements and cash flow of its subsidiaries, Indiana Gas, SIGECO
      and
      VEDO, and the distribution or other payment of earnings from those entities
      to
      the Company. Should the earnings, financial condition, or capital requirements
      of, or legal requirements applicable to, them restrict their ability to pay
      dividends or make other payments to Utility Holdings, the Company’s ability to
      pay dividends to its parent could be adversely affected. Utility Holdings'
      results of operations, future growth and earnings and dividend goals also will
      depend on the performance of its subsidiaries.





**The
      Company 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 the Company’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. The Company cannot provide any assurance
      that
      increased competition or other changes in legislation, regulation or policies
      will not have a material adverse effect on its business, financial condition
      or
      results of operations.





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





The
      Company’s gas and electric utility sales are sensitive to variations in weather
      conditions. Utility Holdings' forecasts utility sales on the basis of normal
      weather, which represents a long-term historical average. Since the Company
      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 its Indiana territories has been significantly mitigated
      through the implementation on October 15, 2005, of a normal temperature
      adjustment mechanism.


-8-
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**The
      Company’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 the Company’s businesses, including environmental
      regulation, could affect the rates the Company charges its customers, its costs
      and its profitability.**





Utility
      Holdings’ businesses are subject to regulation by federal, state and local
      regulatory authorities. In particular, the Company 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 its 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 Utility Holdings will be able to obtain rate increases or rate supplements
      or earn its current authorized rate of return.





In
      addition, Utility Holdings’ 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 (SO 2 ),
      nitrogen oxide (NOx), and mercury, among others.





Environmental
      legislation also requires that facilities, sites and other properties associated
      with Utility Holdings’ 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 Utility Holdings 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 (CO 2 )
      and
      other greenhouse gases. Any future legislative or regulatory actions taken
      to
      address global climate change could adversely affect Utility Holdings’ business
      and results of operations by, for example, requiring changes in, and increased
      costs related to, the Company’s fossil fuel generating plants.





**From
      time to time, Utility Holdings is subject to material litigation and regulatory
      proceedings.**





The
      Company 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 its business, results of operations or
      financial condition.





**The
      Company’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.


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**Utility
      Holdings 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, Utility Holdings’ 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, the Company’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 Utility Holdings’ 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, Utility Holdings 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 Utility Holdings’ 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 Utility Holdings’ 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.**





Utility
      Holdings’ 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.





**Catastrophic
      events could adversely affect the Company’s facilities and
      operations.**





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





**Workforce
      risks could affect Utility Holdings’ 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.





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**A
      downgrade in the Company’s credit rating 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
                RatingStandardMoody’s
            &
                Poor’sUtility
                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.





Utility
      Holdings 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 its ratings,
      it
      may significantly limit Utility Holdings’ access to the debt capital markets and
      the commercial paper market, and the Company’s borrowing costs would increase.
      In addition, Utility Holdings 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.





**ITEM
      1B. UNRESOLVED STAFF COMMENTS**





None.





**ITEM2. 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.





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.





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**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.





**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, and rate and regulatory matters. 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.


-12-
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**PART
      II**





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





**Common
      Stock**





Market
      Price


All
      of
      the outstanding shares of Utility Holdings’ common stock are owned by Vectren.
      Utility Holdings’ common stock is not traded. There
      are
      no outstanding options or warrants to purchase Utility
      Holdings’ common
      equity or securities convertible into Utility
      Holdings’ common
      equity. Additionally, Utility
      Holdings has
      no
      plans to publicly offer its common equity securities.





Dividends
      Paid to Parent


During
      2006, Utility Holdings paid dividends to its parent company of $18.7 million
      in
      each of the first, second and third quarters, and $19.4 million in the fourth
      quarter.





During
      2005, Utility Holdings paid dividends to its parent company of $20.0 million
      in
      each of the first, second and third quarters, and $20.7 million in the fourth
      quarter.





On
      January 31, 2007, the board of directors declared a $19.1 million dividend,
      payable to Vectren on February 28, 2007.





Dividends
      on shares of common stock are payable at the discretion of the board of
      directors out of legally available funds. Future payments of dividends, and
      the
      amounts of these dividends, will depend on the Company’s financial condition,
      results of operations, capital requirements, and other factors.





**Debt
      Security**





The
      Company’s 7 1⁄4% Senior Notes, due October 15, 2031, which were called in October
      2006, previously traded on the New York Stock Exchange under the symbol “AVU.”
The high and low sales prices for the Company’s publicly traded debt security as
      reported on the New York Stock Exchange are shown in the following table for
      the
      periods indicated.


Price
                  Range
              
              
              
              Price
                  Range**2006**
              
              High
              
              Low
              
              **2005**
              
              High
              
              LowFirst Quarter
              
              $
              25.59
              
              $
              25.00
              
              
              First
                  Quarter
              
              $
              26.74
              
              $
              25.44Second Quarter
              
              
              26.00
              
              
              24.72
              
              
              Second
                  Quarter
              
              
              26.30
              
              
              25.40Third Quarter
              
              
              25.40
              
              
              24.81
              
              
              Third
                  Quarter
              
              
              26.35
              
              
              25.05Fourth Quarter
              
              
              -
              
              
              -
              
              
              Fourth
                  Quarter
              
              
              25.80
              
              
              25.00
  -13-
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            of Contents





**ITEM
      6. SELECTEDFINANCIAL 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)*
              
              2006
              
              2005
              
              2004
              
              2003
              
              2002**Operating
                  Data:**Operating
                  revenues
              
              $
              1,656.5
              
              $
              1,781.8
              
              $
              1,498.0
              
              $
              1,448.8
              
              $
              1,236.9Operating
                  income
              
              
              209.0
              
              
              216.6
              
              
              196.3
              
              
              197.2
              
              
              207.7Net
                  income
              
              
              91.4
              
              
              95.1
              
              
              83.1
              
              
              85.6
              
              
              97.1**Balance
                  Sheet Data:**Total
                  assets
              
              $
              3,440.8
              
              $
              3,391.2
              
              $
              3,147.7
              
              $
              2,925.1
              
              $
              2,780.4Redeemable
                  preferred stock
              
              
              -
              
              
              -
              
              
              0.1
              
              
              0.2
              
              
              0.3Long-term
                  debt - net of current maturities& debt subject to tender
              
              
              1,025.3
              
              
              997.8
              
              
              941.3
              
              
              960.5
              
              
              841.2Common
                  shareholder's equity
              
              
              1,056.7
              
              
              1,023.8
              
              
              985.4
              
              
              979.8
              
              
              768.6





**ITEM7.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**





For
      the
      year ended December 31, 2006, earnings were $91.4 million as compared to $95.1
      million in 2005 and $83.1 million in 2004. The decline in 2006 results compared
      to 2005 is primarily due to continued declines in customer usage. 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
addition
      to customer usage declines, the decrease in earnings in2006 was
      also
      impacted byhigher 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 $12 million 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.





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In
      2006,
      2005, and 2004 weather across all utilities was unfavorable compared to 30-year
      normal temperatures. Management estimates the after tax effect of weather
      compared to normal was unfavorable $4 million in 2006, unfavorable $3 million
      in
      2005, and unfavorable $7 million 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.





Utility
      Holdings generates revenue primarily from the delivery of natural gas and
      electric service to its customers. The primary source of cash flow results
      from
      the collection of customer bills and the payment for goods and services procured
      for the delivery of gas and electric services. Results are impacted by weather
      patterns in its service territory and general economic conditions both in its
      service territory as well as nationally.





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.





**Significant
      Fluctuations**





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.





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
              
              2004Gas
                  utility revenues
              
              $
              1,232.5
              
              $
              1,359.7
              
              $
              1,126.2Cost
                  of gas sold
              
              
              841.5
              
              
              973.3
              
              
              778.5**Total
                  gas utility margin**
              
              $
              391.0
              
              $
              386.4
              
              $
              347.7Margin
                  attributed to:Residential
                  & commercial customers
              
              $
              330.2
              
              $
              333.2
              
              $
              297.7Industrial
                  customers
              
              
              48.0
              
              
              48.3
              
              
              45.7Other
                  customers
              
              
              12.8
              
              
              4.9
              
              
              4.3Sold
                  & transported volumes in MMDth attributed to:Residential
                  & commercial customers
              
              
              97.7
              
              
              112.9
              
              
              114.5Industrial
                  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
      authorizations 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.





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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.





Electric
      Utility Margin (Electric utility
      revenues less Cost of fuel & purchased power)


Electric
      Utility margin by revenue type follows:


Year
                  Ended December 31,*(In
                  millions)*
              
              2006
              
              2005
              
              2004Electric
                  utility revenues
              
              $
              422.2
              
              $
              421.4
              
              $
              371.3Cost
                  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
              
              $
              157.3Industrial
                  customers
              
              
              70.2
              
              
              66.9
              
              
              63.7Municipal
                  & other customers
              
              
              24.0
              
              
              19.8
              
              
              18.6**Subtotal:
                  Retail & firm wholesale**
              
              **$**
              **257.1**
              
              **$**
              **257.5**
              
              **$**
              **239.6**Asset
                  optimization
              
              $
              13.6
              
              $
              19.8
              
              $
              14.9Electric
                  volumes sold in GWh attributed to:Residential
                  & commercial customers
              
              
              2,789.7
              
              
              2,933.2
              
              
              2,830.9Industrial
                  customers
              
              
              2,570.4
              
              
              2,575.9
              
              
              2,511.2Municipal
                  & 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.





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          of Contents


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.





Following
      is a reconciliation of asset optimization activity:


Year
                  Ended December 31,*(In
                  millions)*
              
              2006
              
              2005
              
              2004Off-system
                  sales
              
              $
              14.2
              
              $
              15.3
              
              $
              8.7Transmission
                  system sales
              
              
              3.5
              
              
              4.5
              
              
              4.6Other
              
              
              (4.1
              )
              
              0.0
              
              
              1.6Total asset optimization
              
              $
              13.6
              
              $
              19.8
              
              $
              14.9




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.





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.





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*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.





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.





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.





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.





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 (SO 2 ),
      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 (SO 2 )
      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.





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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 SO 2 ,
      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.





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.





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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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          of Contents


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.




**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.


-21-
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          of Contents





*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.





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.





Integrated
        Gasification Combined Cycle (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 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.





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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.





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.





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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.





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 .





**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 impairments tests. The Company makes other
      estimates in the course of accounting for unbilled revenue, the effects of
      regulation, and intercompany allocations 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 depreciation of utility and
      non-utility plant, the valuation of derivative contracts, and the allowance
      for
      doubtful accounts, among others. Actual results could differ from these
      estimates.





-24-
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**Goodwill**





Pursuant
      to SFAS No. 142, the Company performs an annual impairment analysis of its
      goodwill, all 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
      12
      to the consolidated financial statements to be the reporting unit. 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.





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.





**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.





**Intercompany
      Allocations**





Support
      Services





Vectren
      provides corporate, general, and administrative services to the Company and
      allocates costs to the Company, including costs forshare-based
      compensation and for pension and other postretirement benefits that are not
      directly charged to subsidiaries. These costs have been allocated using various
      allocators, including number of employees, number of customers, and/or
the
      level of payroll, revenue contribution, and capital expenditures.
      Allocations are based on cost. Management believes that the allocation
      methodology is reasonable and approximates the costs that would have been
      incurred had the Company secured those services on a stand-alone basis. The
      allocation methodology is not subject to near term changes.





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Pension
      and Other Postretirement Obligations





Vectren
      satisfies the future funding requirements of its pension and other
      postretirement plans and the payment of benefits from general corporate assets.
      An allocation of expense is determined by Vectren’s actuaries, comprised of only
      service cost and interest on that service cost, by subsidiary based on headcount
      at each measurement date, which occurs on September 30. These costs are directly
      charged to individual subsidiaries. Other components of costs (such as interest
      cost and asset returns) are charged to individual subsidiaries through the
      corporate allocation process discussed above. Neither plan assets nor the ending
      liability is allocated to individual subsidiaries since these assets and
      obligations are derived from corporate level decisions. Management believes
      these direct charges when combined with benefit-related corporate charges
      discussed in “support services” above approximate costs that would have been
      incurred if the Company accounted for benefit plans on a stand-alone basis.





Vectren
      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 pension and postretirement plans. Vectren annually
      measures its obligations on September 30, and 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, Vectren 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.





**Impact
      of Recently Issued Accounting Guidance**





**SFAS
      No. 158**





On
      December 31, 2006 *,* and
      after
      calculating the balance sheet impact of Vectren'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 required Vectren 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. The impacts of adopting this standard were
      recorded at Vectren and are not reflected at the Utility Holdings level.





**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.




-26-
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**Financial
      Condition**





Utility
      Holdings, the parent company, funds the short-term and long-term financing
      needs
      of its consolidated operations. Vectren does not guarantee Utility Holdings’
debt. Utility Holdings’ currently outstanding long-term and short-term borrowing
      arrangements are jointly and severally guaranteed by Indiana Gas, SIGECO, and
      VEDO. The guarantees are full and unconditional and joint and several, and
      Utility Holdings has no subsidiaries other than the subsidiary guarantors.
      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. Utility Holdings’ operations have historically
      funded the significant portion of Vectren’s common stock dividends.





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.





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 50% and 49% of long-term
      capitalization at 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 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 $286.1
      million in 2006 compared to $265.8 million in 2005 and $232.9 million in 2004.
      The $20.3 million increase in cash flow in 2006 compared to 2005 is primarily
      attributable to favorable changes in working capital accounts, which offset
      increases in regulatory assets and plant removal costs and a
      $39.5
      million decrease to cash related todeferred taxes.





Cash
      flow
      from operating activities increased $32.9 million in 2005 compared to 2004.
      Increased cash flow from operating activities is due to increased earnings
      before noncash charges and less cash utilized to support working capital
      increases. Earnings before noncash charges were $289.2 million in 2005 compared
      to $269.2 million in 2004, and cash utilized for working capital increases
      was
      $13.0 million in 2005 compared to $24.4 million in 2004.





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.





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          of Contents


Cash
      flow
      required for financing activities reflects the impact of long-term financing
      arrangements executed in 2006 and 2005. 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 2006 and 2005, Utility Holdings received an additional
      capital contribution from Vectren totaling $20.0 million in
      both
      years.  Utility Holdings used proceeds from
      these capital contributionsto retire higher coupon long-term 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 guaranty insurance policy issued 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.





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.


-28-
 Table
          of Contents


*Additional
      Capital Contributions*


During
      the years ended December 31, 2006, 2005, and 2004, the Company has cumulatively
      received additional capital of $43.1 million from Vectren. Of that total, $40.0
      million was funded by Vectren’s nonregulated operations, and $3.1 million was
      funded by new share issues from Vectren’s dividend reinvestment
      plan.





*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 re-marketed. During 2006 and 2005, no debt was put to the
      Company. During 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.





*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.





Other
      Company debt totaling $15.0 million in 2004 was retired as
      scheduled.





Investing
      Cash Flow





Cash
      flow
      required for investing activities was $249.9 million in 2006, $217.7 million
      in
      2005, and $242.7 million in 2004. Capital expenditures are the primary component
      of investing activities. Capital expenditures were $250.0 in 2006 compared
      to
      $217.8 million in 2005 and $246.2 million in 2004. Expenditures in 2006 and
      2004
      include higher levels of expenditures for environmental compliance equipment.





**Available
      Sources of Liquidity**





At
      December 31, 2006, the Company has $520 million of short-term borrowing
      capacity, of which approximately $250 million is available.





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
      periodically issues new shares to satisfy dividend reinvestment plan and stock
      option plan requirements and contributes those proceeds to Utility Holdings.
      During 2004, these new issuances added additional liquidity of $3.1 million.


-29-
 Table
          of Contents


**Potential
      & Future Uses of Liquidity**





Contractual
      Obligations





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


*(In
                  millions)*
              
              Total
              
              2007
              
              2008
              
              2009
              
              2010
              
              2011
              
              ThereafterLong-term
                  debt(1)
              
              $
              1,055.7
              
              $
              6.5
              
              $
              -
              
              $
              -
              
              $
              -
              
              $
              250.0
              
              $
              799.2Short-term
                  debt
              
              
              270.1
              
              
              270.1
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -Long-term
                  debt interest commitments
              
              
              919.6
              
              
              62.7
              
              
              62.5
              
              
              62.5
              
              
              62.5
              
              
              61.1
              
              
              608.3Plant
                  purchase commitments(2)
              
              
              390.5
              
              
              64.5
              
              
              113.0
              
              
              115.0
              
              
              70.0
              
              
              28.0
              
              
              -Total
              
              $
              2,635.9
              
              $
              403.8
              
              $
              175.5
              
              $
              177.5
              
              $
              132.5
              
              $
              339.1
              
              $
              1,407.5


(1)
            Certain
                long-term debt issues contain put and call provisions that can be
                exercised on various dates before maturity. These provisions allow
                holders
                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 million in 2010, $30.0 in 2011 and zero
                thereafter.





(2)
            The
                settlement period of these 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.





Planned
      Capital Expenditures





The
      timing and amount of capital expenditures, including contractual purchase
      commitments discussed above, for the five-year period 2007 - 2011 are estimated
      as follows (in millions): $297.4 in 2007, $323.6 in 2008, $351.8 in 2009, $281.7
      in 2010, and $222.7 in 2011.





Pension
      and Postretirement Funding Obligations





Vectren
      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 Utility Holdings to contribute approximately $3 million
      in
      2007 and approximately $7 million in 2008. During 2006, Vectren made
      contributions of $8.3 million, all of which were funded by Utility
      Holdings.


-30-
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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.*


*·*
            *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.*


-31-
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**ITEM
      7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
      RISK**





The
      Company is exposed to various business risks associated with commodity prices,
      interest rates, and counter-party credit. These financial exposures are
      monitored and managed by the Company as an integral part of its overall risk
      management program. The Company’s risk management program includes, among other
      things, the use of derivatives. The Company 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.





Sales
      to Municipalities and Other Industrial Customers


The
      Company purchases and sells electricity to meet the demands of certain
      municipalities and large industrial customers. Price risk from forward positions
      obligating the Company to deliver commodities is mitigated with generating
      capability and offsetting forward purchase contracts. These contracts are
      expected to be settled by physical receipt or delivery of the
      commodity.


-32-
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          of Contents


**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 27% 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 $263.6 million and $225.9 million,
      respectively. At December 31, 2006, and 2005, combined borrowings under these
      arrangements were $351.7 million and $259.3 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 $2.6 million and $2.3 million,
      respectively.





**Other
      Risks**





By
      using
      forward purchase contracts and derivative financial instruments to manage risk,
      the Company 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.


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          of Contents





**ITEM8.**  **FINANCIAL
      STATEMENTS AND SUPPLEMENTARY DATA**





**MANAGEMENT’S
      RESPONSIBILITY FOR THE FINANCIAL STATEMENTS**





Vectren
      Utility Holdings, Inc.’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 shareholder’s 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.


-34-
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          of Contents








**REPORT
      OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM**







To
      the
      Shareholder and Board of Directors of Vectren Utility Holdings,
      Inc.:




We
      have
      audited the accompanying consolidated balance sheets of Vectren Utility
      Holdings, Inc. and subsidiaries (the “Company”) as of December 31, 2006 and
      2005, and the related consolidated statements of income, shareholder’s 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. These financial statements and financial statement schedule
      are the responsibility of the Company's management. Our responsibility is to
      express an opinion on the financial statements and financial statement schedule
      based on our audits.





We
      conducted our audits in accordance with the standards of the Public Company
      Accounting Oversight Board (United States). Those standards require that we
      plan
      and perform the audit to obtain reasonable assurance about whether the financial
      statements are free of material misstatement. The Company is not required to
      have, nor were we engaged to perform, an audit of its internal control over
      financial reporting. Our audits included consideration of internal control
      over
      financial reporting as a basis for designing audit procedures that are
      appropriate in the circumstances, but not for the purpose of expressing an
      opinion on the effectiveness of the Company's internal control over financial
      reporting. Accordingly, we express no such opinion. An audit also includes
      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, as well as evaluating the overall
      financial statement presentation. We believe that our audits provide a
      reasonable basis for our opinion.





In
      our
      opinion, such consolidated financial statements present fairly, in all material
      respects, the financial position of Vectren Utility Holdings, Inc. and
      subsidiaries 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, present fairly in all material respects the
      information set forth therein.























DELOITTE
                & TOUCHE LLPIndianapolis,
                IndianaFebruary
                16, 2007


-35-
 Table
          of Contents





**VECTREN
      UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES**


**CONSOLIDATED
      BALANCE SHEETS**


***(In
      millions)***








At
                  December 31,2006
              
              2005**ASSETS**Current
                  AssetsCash
                  & cash equivalents
              
              $
              28.5
              
              $
              11.7Accounts
                  receivable - less reserves of $2.5 &$2.6,
                  respectively
              
              
              134.8
              
              
              170.7Receivables
                  due from other Vectren companies
              
              
              0.3
              
              
              2.2Accrued
                  unbilled revenues
              
              
              121.4
              
              
              212.5Inventories
              
              
              141.9
              
              
              126.2Recoverable
                  fuel & natural gas costs
              
              
              1.8
              
              
              15.4Prepayments
                  & other current assets
              
              
              103.2
              
              
              117.2**Total
                  current assets**
              
              
              **531.9**
              
              
              **655.9**Utility
                  PlantOriginal cost
              
              
              3,820.2
              
              
              3,632.0Less: accumulated depreciation & amortization
              
              
              1,434.7
              
              
              1,380.1**Net utility plant**
              
              
              **2,385.5**
              
              
              **2,251.9**Investments
                  in unconsolidated affiliates
              
              
              0.2
              
              
              0.2Other
                  investments
              
              
              21.4
              
              
              21.0Nonutility
                  property - net
              
              
              163.1
              
              
              160.0Goodwill
                  - net
              
              
              205.0
              
              
              205.0Regulatory
                  assets
              
              
              116.8
              
              
              89.9Other
                  assets
              
              
              16.9
              
              
              7.3**TOTAL
                  ASSETS**
              
              **$**
              **3,440.8**
              
              **$**
              **3,391.2**


















































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


-36-
 Table
          of Contents


**VECTREN
      UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES**


**CONSOLIDATED
      BALANCE SHEETS**


***(In
      millions)***








At
                  December 31,2006
              
              2005**LIABILITIES
                  & SHAREHOLDER'S EQUITY**Current
                  LiabilitiesAccounts
                  payable
              
              $
              136.2
              
              $
              131.9Accounts
                  payable to affiliated companies
              
              
              68.2
              
              
              140.6Payables
                  to other Vectren companies
              
              
              25.3
              
              
              29.2Refundable
                  fuel & natural gas costs
              
              
              35.3
              
              
              7.6Accrued
                  liabilities
              
              
              115.8
              
              
              130.4Short-term
                  borrowings
              
              
              270.1
              
              
              226.9Current
                  maturities of long-term debt
              
              
              6.5
              
              
              -Long-term
                  debt subject to tender
              
              
              20.0
              
              
              53.7**Total
                  current liabilities**
              
              
              **677.4**
              
              
              **720.3**Long-Term
                  Debt - Net of Current Maturities &Debt
                  Subject to Tender
              
              
              1,025.3
              
              
              997.8Deferred
                  Income Taxes & Other LiabilitiesDeferred
                  income taxes
              
              
              282.2
              
              
              275.5Regulatory
                  liabilities
              
              
              291.1
              
              
              272.9Deferred
                  credits & other liabilities
              
              
              108.1
              
              
              100.9**Total
                  deferred credits & other liabilities**
              
              
              **681.4**
              
              
              **649.3**Commitments
                  & Contingencies (Notes 7 - 10)Common
                  Shareholder's EquityCommon
                  stock (no par value)
              
              
              632.9
              
              
              612.9Retained
                  earnings
              
              
              422.9
              
              
              406.9Accumulated
                  other comprehensive income
              
              
              0.9
              
              
              4.0**Total
                  common shareholder's equity**
              
              
              **1,056.7**
              
              
              **1,023.8****TOTAL
                  LIABILITIES & SHAREHOLDER'S EQUITY**
              
              **$**
              **3,440.8**
              
              **$**
              **3,391.2**



































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


-37-
 Table
          of Contents


**VECTREN
      UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES**


**CONSOLIDATED
      STATEMENTS OF INCOME**


***(In
      millions)***











Year
                  Ended December 31,2006
              
              2005
              
              2004OPERATING
                  REVENUESGas
                  utility
              
              $
              1,232.5
              
              $
              1,359.7
              
              $
              1,126.2Electric
                  utility
              
              
              422.2
              
              
              421.4
              
              
              371.3Other
              
              
              1.8
              
              
              0.7
              
              
              0.5**Total
                  operating revenues**
              
              
              **1,656.5**
              
              
              **1,781.8**
              
              
              **1,498.0**OPERATING
                  EXPENSESCost
                  of gas sold
              
              
              841.5
              
              
              973.3
              
              
              778.5Cost
                  of fuel & purchased power
              
              
              151.5
              
              
              144.1
              
              
              116.8Other
                  operating
              
              
              239.0
              
              
              241.3
              
              
              220.4Depreciation
                  & amortization
              
              
              151.3
              
              
              141.3
              
              
              127.8Taxes
                  other than income taxes
              
              
              64.2
              
              
              65.2
              
              
              58.2Total
                  operating expenses
              
              
              1,447.5
              
              
              1,565.2
              
              
              1,301.7**OPERATING
                  INCOME**
              
              
              **209.0**
              
              
              **216.6**
              
              
              **196.3**OTHER
                  INCOMEOther
                  - net
              
              
              7.6
              
              
              5.9
              
              
              7.1Equity
                  in earnings of unconsolidated affiliates
              
              
              -
              
              
              -
              
              
              0.2Total
                  other income
              
              
              7.6
              
              
              5.9
              
              
              7.3Interest
                  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**


















































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


-38-
 Table
          of Contents


**VECTREN
      UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES**


**CONSOLIDATED
      STATEMENTS OF CASH FLOWS**


***(In
      millions)***





Year
                  Ended December 31,2006
              
              2005
              
              2004CASH
                  FLOWS FROM OPERATING ACTIVITIESNet
                  income
              
              $
              91.4
              
              $
              95.1
              
              $
              83.1Adjustments
                  to reconcile net income to cash from operating activities:Depreciation
                  & amortization
              
              
              151.3
              
              
              141.3
              
              
              127.8Deferred
                  income taxes & investment tax credits
              
              
              (6.4
              )
              
              33.1
              
              
              43.0Expense
                  portion of pension & postretirement periodic benefit cost
              
              
              4.2
              
              
              4.0
              
              
              4.1Provision
                  for uncollectible accounts
              
              
              13.6
              
              
              14.4
              
              
              10.7Other
                  non-cash (income) expense - net
              
              
              (2.4
              )
              
              1.3
              
              
              0.5Changes
                  in working capital accounts:Accounts
                  receivable, including to Vectren companies&
                  accrued unbilled revenue
              
              
              115.3
              
              
              (88.1
              )
              
              (78.0
              )Inventories
              
              
              (15.7
              )
              
              (68.2
              )
              
              (3.5
              )Recoverable
                  fuel & natural gas costs
              
              
              41.3
              
              
              3.6
              
              
              8.9Prepayments
                  & other current assets
              
              
              16.7
              
              
              23.3
              
              
              (2.9
              )Accounts
                  payable, including to Vectren companies&
                  affiliated companies
              
              
              (74.7
              )
              
              100.7
              
              
              37.9Accrued
                  liabilities
              
              
              (14.2
              )
              
              15.7
              
              
              13.2Changes
                  in noncurrent assets
              
              
              (27.2
              )
              
              (8.4
              )
              
              (1.9
              )Changes
                  in noncurrent liabilities
              
              
              (7.1
              )
              
              (2.0
              )
              
              (10.0
              )**Net
                  cash flows from operating activities**
              
              
              **286.1**
              
              
              **265.8**
              
              
              **232.9**CASH
                  FLOWS FROM FINANCING ACTIVITIESProceeds
                  from:Long-term
                  debt - net of issuance costs & hedging proceeds
              
              
              92.8
              
              
              150.0
              
              
              32.4Additional
                  capital contribution
              
              
              20.0
              
              
              20.0
              
              
              3.1Requirements
                  for:Dividends
                  to parent
              
              
              (75.4
              )
              
              (80.7
              )
              
              (80.6
              )Retirement
                  of long-term debt, including premiums paid
              
              
              (100.0
              )
              
              (49.9
              )
              
              (70.5
              )Redemption
                  of preferred stock of subsidiary
              
              
              -
              
              
              (0.1
              )
              
              (0.1
              )Net
                  change in short-term borrowings, including from otherVectren
                  companies
              
              
              43.2
              
              
              (81.4
              )
              
              123.1**Net
                  cash flows from financing activities**
              
              
              **(19.4**
              **)**
              
              **(42.1**
              **)**
              
              **7.4**CASH
                  FLOWS FROM INVESTING ACTIVITIESProceeds
                  from other investing activities
              
              
              0.1
              
              
              0.1
              
              
              3.5Requirements
                  for capital expenditures, excluding AFUDC equity
              
              
              (250.0
              )
              
              (217.8
              )
              
              (246.2
              )**Net
                  cash flows from investing activities**
              
              
              **(249.9**
              **)**
              
              **(217.7**
              **)**
              
              **(242.7**
              **)**Net
                  (decrease) increase in cash & cash equivalents
              
              
              16.8
              
              
              6.0
              
              
              (2.4
              )Cash
                  & cash equivalents at beginning of period
              
              
              11.7
              
              
              5.7
              
              
              8.1Cash
                  & cash equivalents at end of period
              
              $
              28.5
              
              $
              11.7
              
              $
              5.7Cash
                  paid during the year for:Interest
              
              $
              75.2
              
              $
              65.9
              
              $
              65.0Income
                  taxes
              
              
              49.8
              
              
              43.3
              
              
              6.1





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


-39-
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          of Contents


**VECTREN
      UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES**


**CONSOLIDATED
      STATEMENTS OF COMMON SHAREHOLDER’S EQUITY**


***(In
      millions)***





AccumulatedOtherCommon
              
              Retained
              
              ComprehensiveStock
              
              Earnings
              
              Income
                  (Loss)
              
              TotalBalance
                  at January 1, 2004
              
              **$**
              589.8
              
              **$**
              390.0
              
              **$**
              -
              
              **$**
              979.8Net
                  income and comprehensive income
              
              
              
              
              
              83.1
              
              
              
              
              
              83.1Common
                  stock:Additional
                  capital contribution
              
              
              3.1
              
              
              
              
              
              
              
              
              3.1Dividends
              
              
              
              
              
              (80.6
              )
              
              
              
              
              (80.6
              )**Balance
                  at December 31, 2004**
              
              **$**
              **592.9**
              
              **$**
              **392.5**
              
              **$**
              **-**
              
              **$**
              **985.4**Comprehensive
                  income:Net
                  income
              
              
              
              
              
              95.1
              
              
              
              
              
              95.1Cash
                  flow hedgeUnrealized
                  gains  - net of $2.9 million in tax
              
              
              
              
              
              
              
              
              4.2
              
              
              4.2Reclassification
                  to net income - net of $0.2 million in tax
              
              
              
              
              
              
              
              
              (0.2
              )
              
              (0.2
              )Total
                  comprehensive income
              
              
              
              
              
              
              
              
              
              
              
              99.1Common
                  stock:Additional
                  capital contribution
              
              
              20.0
              
              
              
              
              
              
              
              
              20.0Dividends
              
              
              
              
              
              (80.7
              )
              
              
              
              
              (80.7
              )**Balance
                  at December 31, 2005**
              
              **$**
              **612.9**
              
              **$**
              **406.9**
              
              **$**
              **4.0**
              
              **$**
              **1,023.8**Comprehensive
                  income:Net
                  income
              
              
              
              
              
              91.4
              
              
              
              
              
              91.4Cash
                  flow hedgeUnrealized losses
                  - net of $1.5 million in tax
              
              
              
              
              
              
              
              
              (2.1
              )
              
              (2.1
              )Reclassification
                  to net income - net of $0.7 million in tax
              
              
              
              
              
              
              
              
              (1.0
              )
              
              (1.0
              )Total
                  comprehensive income
              
              
              
              
              
              
              
              
              
              
              
              88.3Common
                  stock:Additional
                  capital contribution
              
              
              20.0
              
              
              
              
              
              
              
              
              20.0Dividends
              
              
              
              
              
              (75.4
              )
              
              
              
              
              (75.4
              )**Balance
                  at December 31, 2006**
              
              **$**
              **632.9**
              
              **$**
              **422.9**
              
              **$**
              **0.9**
              
              **$**
              **1,056.7**



































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








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**VECTREN
      UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES**


**NOTES
      TO THE CONSOLIDATED FINANCIAL STATEMENTS**





**1.**
            **Organization
                and Nature of Operations**





Vectren
      Utility Holdings, Inc. (Utility Holdings or the Company), an Indiana
      corporation, serves as the intermediate holding company for Vectren
      Corporation’s (Vectren) 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 assets that provide information
      technology and other services to the utilities. Vectren is an energy holding
      company headquartered in Evansville, Indiana. 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, (53% ownership) and Indiana Gas (47% ownership). The Ohio
      operations generally do business as Vectren Energy Delivery of Ohio.





**2.**
            **Summary
                of Significant Accounting
                Policies**





A.
            Principles
                of Consolidation


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





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.





C.
            Inventories


*Inventories* consist
      of the following:


At
                  December 31,*(In
                  millions)*
              
              2006
              
              2005Gas
                  in storage – at average cost
              
              $
                  61.3
              
              $
                  63.3Materials
                  & supplies
              
              28.0
              
              29.9Gas
                  in storage – at LIFO cost
              
              26.5
              
              18.8Fuel
                  (coal & oil) for electric generation
              
              26.0
              
              14.1Other
              
              
              0.1
              
              0.1**Total
                  inventories**
              
              **$
                  141.9**
              
              **$
                  126.2**
  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.





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D.
            Utility
                Plant & Depreciation


*Utility
      plant* is
      stated at historical cost, including AFUDC. Depreciation rates, which include
      a
      cost of removal component, 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
                  and For the Year Ended December 31,*(In
                  millions)*
              
              2006
              
              
              2005Original
                  Cost
              Depreciation
                Rates
                  as a
                Percent
                  of
                Original
                  Cost
              
              Original
                  Cost
              Depreciation
                Rates
                  as a
                Percent
                  of
                Original
                  CostGas
                  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 used for construction purposes,
      and is 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
              
              2004AFUDC
                  – borrowed funds
              
              $
              2.6
              
              $
              1.6
              
              $
              1.6AFUDC
                  – equity funds
              
              
              1.5
              
              
              0.3
              
              
              1.6**Total
                  AFUDC capitalized**
              
              **$**
              **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 charged against *Regulatory
      liabilities* ,
      where
      the cost of removal obligation is classified in these financial
      statements.





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
              
              2005Computer
                  hardware & software
              
              $
              105.4
              
              $
              103.3Land
                  & buildings
              
              
              44.9
              
              
              43.5All
                  other
              
              
              12.8
              
              
              13.2**Nonutility
                  property - net**
              
              **$**
              **163.1**
              
              **$**
              **160.0**




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. 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 $113.7 million and $92.7 million as
      of
      December 31, 2006, and 2005, respectively. For the years ended December 31,
      2006, 2005 and 2004, the Company capitalized interest totaling $0.7 million,
      $0.6 million, and $1.4 million, respectively, on nonutility plant construction
      projects.





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F.
            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.





G.
            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. All of the Company’s goodwill is
      included in the Gas Utility Services operating segment.





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 $18.3 million at December 31, 2006 and $17.3
      million at December 31, 2005, and are included in *Other
      Liabilities* .
      During
      2006, the Company recorded accretion of $1.0 million. In 2005, the Company
      recorded accretion of $0.1 million and recorded additional liabilities of $16.0
      million, related to the adoption of FASB Interpretation No. 47.





I.
            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.





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*Regulatory
      assets* consist
      of the following:


At
                  December 31,*(In
                  millions)*
              
              2006
              
              2005Future
                  amounts recoverable from ratepayers:Income
                  taxes
              
              $
              13.3
              
              $
              11.1Asset
                  retirement obligations & other
              
              
              5.2
              
              
              1.718.5
              
              
              12.8Amounts
                  deferred for future recovery:Demand
                  side management programs
              
              
              27.7
              
              
              26.7MISO-related
                  costs
              
              
              17.1
              
              
              9.4Cost
                  recovery riders & other
              
              
              4.7
              
              
              2.549.5
              
              
              38.6Amounts
                  currently recovered through base rates:Unamortized
                  debt issue costs
              
              
              23.1
              
              
              20.2Premiums
                  paid to reacquire debt
              
              
              6.0
              
              
              6.5Demand
                  side management programs & other
              
              
              3.3
              
              
              4.532.4
              
              
              31.2Amounts
                  currently recovered through tracking mechanisms:Ohio
                  authorized trackers
              
              
              10.3
              
              
              5.6Indiana
                  authorized trackers
              
              
              6.1
              
              
              1.716.4
              
              
              7.3**Total
                  regulatory assets**
              
              **$**
              **116.8**
              
              **$**
              **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
            
            2005Advances
                from rate-payers related to:Cost
                of removal
            
            $
            270.6
            
            $
            251.4Asset
                retirement obligations
            
            
            11.3
            
            
            11.6281.9
            
            
            263.0Amounts
                currently amortizing related to:Interest
                rate hedging proceeds
            
            
            6.1
            
            
            6.8Amounts
                deferred for future settlement related to:MISO-related
                costs
            
            
            3.1
            
            
            3.1**Total
                regulatory liabilities**
            
            **$**
            **291.1**
            
            **$**
            **272.9**




*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).





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*Asset
      Retirement Obligations*


A
      portion
      of removal costs related to interim retirements of gas utility pipeline and
      utility poles, certain asbestos-related issues, and reclamation activities
      meet
      the definition of an asset retirement obligation (ARO). The regulatory liability
      above represents a timing difference between cost recognition described in
      SFAS
      143, and cost recognition established in regulatory proceedings for these
      obligations.





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
              
              2006Beginning
              
              Changes
              
              End
              
              Changes
              
              End
              
              Changes
              
              Endof
                  Year
              
              During
              
              of
                  Year
              
              During
              
              of
                  Year
              
              During
              
              of
                  Year*(In
                  millions)*
              
              Balance
              
              Year
              
              Balance
              
              Year
              
              Balance
              
              Year
              
              BalanceCash
                  flow hedges
              
              
              -
              
              
              -
              
              
              -
              
              
              6.7
              
              
              6.7
              
              
              (5.3
              )
              
              1.4Deferred
                  income taxes
              
              
              -
              
              
              -
              
              
              -
              
              
              (2.7
              )
              
              (2.7
              )
              
              2.2
              
              
              (0.5
              )**Accumulated
                  other comprehensive income (loss)**
              
              **$**
              **-**
              
              **$**
              **-**
              
              **$**
              **-**
              
              **$**
              **4.0**
              
              **$**
              **4.0**
              
              **$**
              **(3.1**
              **)**
              **$**
              **0.9**





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. Excise and utility receipts taxes paid are
      recorded as a component of *Taxes
      other than income taxes* .





M.
            Earnings
                Per Share


Earnings
      per share are not presented as Utility Holdings’ common stock is wholly owned by
      Vectren.





N.
            Other
                Significant Policies


Included
      elsewhere in these notes are significant accounting policies related to
      intercompany allocations and income taxes (Note 3) and derivatives (Note
      10).





O.
            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.





**3.**
            **Transactions
                with Other Vectren
                Companies**





Support
      Services and Purchases


Vectren
      provides corporate and general and administrative services to the Company and
      allocates costs to the Company, including costs for share-basedcompensation and for pension and other postretirement benefits
      that are not directly charged to subsidiaries. These costs have been allocated
      using various allocators, including number of employees, number of customers
      and/or the
      level
      of payroll, revenue contribution and capital expenditures. Allocations are based on cost. Utility Holdings received corporate
      allocations totaling $43.7 million, $48.0 million, and $44.5 million for the
      years ended December 31, 2006, 2005, and 2004, respectively.





Vectren
      Fuels, Inc., a wholly owned subsidiary of Vectren, owns and operates coal mines
      from which SIGECO purchases fuel used for electric generation. Amounts paid
      for
      such purchases for the years ended December 31, 2006, 2005, and 2004, totaled
      $116.8 million, $96.4 million, and $79.0 million, respectively.





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Miller
      Pipeline Corporation


Effective
        July 1, 2006, Vectren purchased the remaining 50% ownership in Miller Pipeline
        Corporation (Miller), making Miller a wholly owned subsidiary of Vectren.
        Prior
        to the transaction, Miller was 50% owned by Vectren and was accounted for
        by
        Vectren using the equity method of accounting. Miller 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 Utility
        Holdings’ utilities. Fees paid by Utility Holdings and its subsidiaries totaled
        17.1 million in 2006, $13.6 million in 2005 and $22.6 million in 2004. Amounts
        owed to Miller at December 31, 2006 are included in *Payables
        to other Vectren companies* and at
        December 31, 2005 are included in *Accounts
        payable to affiliated companies* .
  Retirement
      Plans and Other Postretirement Benefits


Vectren
      has multiple defined benefit pension plans and postretirement plans that require
      accounting as described in 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), which it
      adopted on December 31, 2006. An allocation of expense is determined by
      Vectren’s actuaries, comprised of only service cost and interest on that service
      cost, by subsidiary based on headcount at each measurement date. These costs
      are
      directly charged to individual subsidiaries. Other components of costs (such
      as
      interest cost and asset returns) are charged to individual subsidiaries through
      the corporate allocation process discussed above. Neither plan assets nor the
      ending liability is allocated to individual subsidiaries since these assets
      and
      obligations are derived from corporate level decisions. Further, Vectren
      satisfies the future funding requirements of plans and the payment of benefits
      from general corporate assets. This allocation methodology is consistent with
      “multiemployer” benefit accounting as described in SFAS 87 and 106.





For
      the
      years ended December 31, 2006, 2005, and 2004, periodic pension costs totaling
      $5.3 million, $4.8 million, and $4.8 million, respectively, were directly
      charged by Vectren to the Company. For the years ended December 31, 2006, 2005,
      and 2004, other periodic postretirement benefit costs totaling $0.6 million,
      $0.8 million, and $0.9 million, respectively, were directly charged by Vectren
      to the Company. As of December 31, 2006 and 2005, $44.2 million and $49.5
      million, respectively, is included in *Deferred
      credits & other liabilities* and
      represents expense directly charged to the Company that is yet to be funded
      to
      Vectren, and $5.9 million and $3.0 million, respectively, is included in *Other
      assets* for
      amounts funded in advance to Vectren.





Cash
      Management Arrangements


The
      Company participates in a centralized cash management program with Vectren,
      other wholly owned subsidiaries, and banks.





Share-Based
      Incentive Plans


In
      December 2004, the FASB issued Statement 123 (revised 2004), “Share-Based
      Payments” (SFAS 123R) that required compensation costs related to all
      share-based payment transactions to be recognized in the financial statements.
      With limited exceptions, the amount of compensation cost is measured based
      on
      the grant-date fair value of the equity or liability instruments issued.
      Compensation cost is recognized over the period that an employee provides
      service in exchange for the award. SFAS 123R replaced SFAS 123 and superseded
      APB 25. The Company adopted SFAS 123R using the modified prospective method
      on
      January 1, 2006. The adoption of this standard, and subsequent interpretations
      of the standard, did not have a material effect on the Company’s operating
      results or financial condition. Utility Holdings does not have share-based
      compensation plans separate from Vectren. An insignificant number of Utility
      Holdings’ employees participate in Vectren’s share-based compensation plans.





Income
      Taxes


Vectren
      files a consolidated federal income tax return. Pursuant to a subsidiary tax
      sharing agreement and for financial reporting purposes, Utility Holdings’
current and deferred tax expense is computed on a separate company basis.
      Current taxes payable/receivable are settled with Vectren in
      cash.


-46-
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The
      components of income tax expense and utilization of investment tax credits
      follow:


Year
                  Ended December 31,*(In
                  millions)*
              
              2006
              
              2005
              
              2004Current:Federal
              
              $
              43.3
              
              $
              15.7
              
              $
              3.7State
              
              
              10.8
              
              
              8.7
              
              
              6.4**Total
                  current taxes**
              
              
              **54.1**
              
              
              **24.4**
              
              
              **10.1**Deferred:Federal
              
              
              (0.9
              )
              
              32.2
              
              
              40.6State
              
              
              (3.5
              )
              
              3.3
              
              
              4.6**Total
                  deferred taxes**
              
              
              **(4.4**
              **)**
              
              **35.5**
              
              
              **45.2**Amortization
                  of investment tax credits
              
              
              (2.0
              )
              
              (2.4
              )
              
              (2.2
              )**Total
                  income tax expense**
              
              **$**
              **47.7**
              
              **$**
              **57.5**
              
              **$**
              **53.1**
  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
              
              2005Noncurrent
                  deferred tax liabilities (assets):Depreciation
                  & cost recovery timing differences
              
              $
              271.8
              
              $
              277.5Regulatory
                  assets recoverable through future rates
              
              
              21.0
              
              
              19.2Demand
                  side management programs
              
              
              8.4
              
              
              7.7Other
                  comprehensive income
              
              
              0.5
              
              
              2.7Employee
                  benefit obligations
              
              
              (24.4
              )
              
              (20.7
              )Regulatory
                  liabilities to be settled through future rates
              
              
              (7.7
              )
              
              (8.1
              )Other
                  – net
              
              
              12.6
              
              
              (2.8
              )Net
                  noncurrent deferred tax liability
              
              
              282.2
              
              
              275.5Current
                  deferred tax liabilities:Deferred
                  fuel costs - net
              
              
              (1.9
              )
              
              7.6Other
                  net
              
              
              (1.6
              )
              
              -**Net
                  deferred tax liability**
              
              **$**
              **278.7**
              
              **$**
              **283.1**





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.





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


Year
                  Ended December 31,2006
              
              2005
              
              2004Statutory
                  rate
              
              
              35.0
              %
              
              35.0
              %
              
              35.0
              %State
                  and local taxes-net of federal benefit
              
              
              5.5
              
              
              5.2
              
              
              5.2Tax
                  law change
              
              
              (2.2
              )
              
              -
              
              
              -Amortization
                  of investment tax credit
              
              
              (1.4
              )
              
              (1.5
              )
              
              (1.6
              )Adjustment
                  to income tax accruals
              
              
              (2.8
              )
              
              (2.2
              )
              
              (0.2
              )All
                  other - net
              
              
              0.2
              
              
              1.2
              
              
              0.6**Effective
                  tax rate**
              
              
              34.3
              %
              
              37.7
              %
              
              39.0
              %






-47-
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**4.**
            **Transactions
                with Vectren Affiliates**





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
      natural gas and related services to the Company’s utilities, Citizens Gas, and
      others. ProLiance’s primary businesses include gas marketing, gas portfolio
      optimization, and other portfolio and energy management services.





*Transactions
      with ProLiance*


Purchases
      from ProLiance for resale and for injections into storage for the years ended
      December 31, 2006, 2005, and 2004, totaled $610.2 million, $908.9 million,
      and
      $789.8 million, respectively. Amounts owed to ProLiance at December 31, 2006
      and
      2005, for those purchases were $68.2 million and $137.4 million, respectively,
      and are included in *Accounts
      payable to affiliated companies* in the
      Consolidated Balance Sheets. The Company purchased approximately 72% of its
      gas
      through ProLiance in 2006, compared to 95% in 2005 and 100% in 2004. 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.





Other
      Affiliate Transactions


Vectren
        has ownership interests in other affiliated companies accounted for using
        the
        equity method of accounting that performed facilities locating and meter
        reading
        services for the Company. For the years ended December 31, 2006, 2005, and
        2004,
        fees for these services paid by the Company to Vectren affiliates totaled
        $7.4
        million, $7.7 million, and $8.6 million, respectively. Amounts charged were
        market based. Amounts owed to unconsolidated affiliates other than ProLiance
        totaled less than $0.1 million and $1.2 million at December 31, 2006, and
        2005,
        respectively, and are included in *Accounts
        payable to affiliated companies* in the
        Consolidated Balance Sheets.


**5.**
            **Borrowing
                Arrangements**





Short-Term
      Borrowings


At
      December 31, 2005, Utility Holdings has $520 million of short-term borrowing
      capacity, of which approximately $250 million is available. The Company
      increased its short-term credit facility in November 2005, by approximately
      $165
      million in response to increased natural gas costs. Utility Holdings’ credit
      facilities are primarily used to support its access to the commercial paper
      market. See the table below for interest rates and outstanding
      balances.


Year
                  Ended December 31,*(In
                  millions)*
              
              2006
              
              2005
              
              2004Weighted
                  average commercial paper and bank loansoutstanding
                  during the year
              
              $
              177.5
              
              $
              193.5
              
              $
              133.2Weighted
                  average interest rates during the yearCommercial
                  paper
              
              
              5.16
              %
              
              3.42
              %
              
              1.78
              %Bank
                  loans
              
              
              -
              
              
              -
              
              
              2.19
              %At
                  December 31,*(In
                  millions)*
              
              
              2006
              
              
              2005Commercial
                  paper
              
              $
              270.1
              
              $
              226.9**Total
                  short-term borrowings**
              
              **$**
              **270.1**
              
              **$**
              **226.9**


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 Table
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Long-Term
      Debt


Senior
      unsecured obligations and first mortgage bonds outstanding and classified as
      long-term by subsidiary follow:


At
                    December 31,*(In
                    millions)*
                
                
                
                2006
                
                2005**UTILITY
                    HOLDINGS**Senior
                  Unsecured Notes2011,
                    6.625%
                
                
                
                
                $
                250.0
                
                $
                250.02013,
                    5.25%
                
                
                
                
                
                100.0
                
                
                100.02015,
                    5.45%
                
                
                
                
                
                75.0
                
                
                75.02018,
                    5.75%
                
                
                
                
                
                100.0
                
                
                100.02031,
                    7.25%
                
                
                
                
                
                -
                
                
                100.02035,
                    6.10%
                
                
                
                
                
                75.0
                
                
                75.02036,
                    5.95%
                
                
                
                
                
                100.0
                
                
                -**Total
                    VUHI**
                
                
                
                
                
                **700.0**
                
                
                **700.0****SIGECO**First
                    Mortgage Bonds2016,
                    1986 Series, 8.875%
                
                
                
                
                
                13.0
                
                
                13.02020,
                    1998 Pollution Control Series B, 4.50%, tax exempt
                
                
                
                
                
                4.6
                
                
                4.62024,
                    2000 Environmental Improvement Series A, 4.65%, tax exempt
                
                
                
                
                
                22.5
                
                
                22.52029,
                    1999 Senior Notes, 6.72%
                
                
                
                
                
                80.0
                
                
                80.02030,
                    1998 Pollution Control Series B, 5.00%, tax exempt
                
                
                
                
                
                22.0
                
                
                22.02015,
                    1985 Pollution Control Series A, current adjustable rate 4.06%,
                    tax
                    exempt,auction
                    rate mode, 2006 weighted average: 3.53%
                
                
                
                
                
                9.8
                
                
                9.82023,
                    1993 Environmental Improvement Series B, current adjustable rate
                    4.11%,tax
                    exempt, auction rate mode, 2006 weighted average: 3.74%
                
                
                
                
                
                22.6
                
                
                22.62025,
                    1998 Pollution Control Series A, current adjustable rate 4.11%,
                    tax
                    exempt,auction
                    rate mode, 2006 weighted average: 3.08%
                
                
                
                
                
                31.5
                
                
                31.52030,
                    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****Indiana
                    Gas**Senior
                    Unsecured Notes2007,
                    Series E, 6.54%
                
                
                
                
                
                6.5
                
                
                6.52013,
                    Series E, 6.69%
                
                
                
                
                
                5.0
                
                
                5.02015,
                    Series E, 7.15%
                
                
                
                
                
                5.0
                
                
                5.02015,
                    Series E, 6.69%
                
                
                
                
                
                5.0
                
                
                5.02015,
                    Series E, 6.69%
                
                
                
                
                
                10.0
                
                
                10.02025,
                    Series E, 6.53%
                
                
                
                
                
                10.0
                
                
                10.02027,
                    Series E, 6.42%
                
                
                
                
                
                5.0
                
                
                5.02027,
                    Series E, 6.68%
                
                
                
                
                
                1.0
                
                
                1.02027,
                    Series F, 6.34%
                
                
                
                
                
                20.0
                
                
                20.02028,
                    Series F, 6.36%
                
                
                
                
                
                10.0
                
                
                10.02028,
                    Series F, 6.55%
                
                
                
                
                
                20.0
                
                
                20.02029,
                    Series G, 7.08%
                
                
                
                
                
                30.0
                
                
                30.0**Total
                    Indiana Gas**
                
                
                
                
                
                **127.5**
                
                
                **127.5**


**Total
                  long-term debt outstanding**
              
              
              **1,055.7**
              
              
              **1,055.7**Current
                  maturities of long-term debt
              
              
              (6.5
              )
              
              -Debt
                  subject to tender
              
              
              (20.0
              )
              
              (53.7
              )Unamortized
                  debt premium & discount - net
              
              
              (3.9
              )
              
              (4.2
              )**Total
                  long-term debt-net**
              
              **$**
              **1,025.3**
              
              **$**
              **997.8**


-49-
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              of Contents


*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 issued 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).





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.





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.





-50-
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          of Contents


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.*





Other
      Company debt totaling $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 and sinking fund requirements on long-term debt during the five
      years
      following 2006 (in millions) are $6.5 in 2007, zero in 2008 and 2009, and 2010
      and $250.0 in 2011.





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.





**6.**
            **Additional
                Capital Contributions**





During
      the years ended December 31, 2006, 2005, and 2004, the Company has cumulatively
      received additional capital of $43.1 million from Vectren. Of that total, $40.0
      million was funded by Vectren’s nonregulated operations, and $3.1 million was
      funded by new share issues from Vectren’s dividend reinvestment
      plan.





**7.**
            **Commitments
                & Contingencies**





Commitments


Firm
      purchase commitments for utility and non-utility plant total $64.5 million
      in
      2007, $113.0 million in 2008, $115.0 million in 2009, $70.0 million in 2010
      and
      $28.0 million in 2011.





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 or results of operations.





**8.**
            **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 (SO 2 )
      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.





-51-
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          of Contents


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 SO 2 ,
      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.





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.





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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.





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.


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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.





**9.**
            **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.





*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.





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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.





Integrated
        Gasification Combined Cycle (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 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.





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 .





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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.





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.





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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 .





**10.**
            **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, SO 2 emission
      allowance risk management, natural gas procurement, and interest rate
      management.





*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.


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*SO* *2* *Emission Allowance Risk Management*


The
      Company’s wholesale power marketing operations are exposed to price risk
      associated with SO 2 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
      other comprehensive income* 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 SO 2 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.





At
      December 31, 2006 and 2005, the market values of these 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 $0.4 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
            
            2005In
                millions
            
            Carrying
              Amount
            
            Est.
                Fair
              Value
            
            Carrying
              Amount
            
            Est.
                Fair
              ValueLong-term
                debt
            
            $
            1,055.7
            
            $
            1,072.6
            
            $
            1,055.7
            
            $
            1,105.2Short-term
                borrowings
            
            
            270.1
            
            
            270.1
            
            
            226.9
            
            
            226.9




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.





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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.





**11.**
            **Additional
                Balance Sheet & Operational
                Information**





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


At
                  December 31,*(In
                  millions)*
              
              2006
              
              2005Prepaid
                  gas delivery service
              
              $
              66.2
              
              $
              69.3Prepaid
                  taxes
              
              
              20.7
              
              
              27.1Deferred
                  income taxes
              
              
              3.5
              
              
              -Other
                  prepayments & current assets
              
              
              12.8
              
              
              20.8**Total
                  prepayments & other current assets**
              
              **$**
              **103.2**
              
              **$**
              **117.2**




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


At
                  December 31,*(In
                  millions)*
              
              2006
              
              2005Refunds
                  to customers & customer deposits
              
              $
              42.3
              
              $
              36.4Accrued
                  taxes
              
              
              28.3
              
              
              31.5Accrued
                  interest
              
              
              15.5
              
              
              16.2Deferred
                  income taxes
              
              
              -
              
              
              7.6Accrued
                  salaries & other
              
              
              29.7
              
              
              38.7**Total
                  accrued liabilities**
              
              **$**
              **115.8**
              
              **$**
              **130.4**
  *Other
      - net* in the
      Consolidated Statements of Income consists of the following:


Year
                  Ended December 31,*(In
                  millions)*
              
              2006
              
              2005
              
              2004AFUDC
                  & capitalized interest
              
              $
              4.8
              
              $
              2.5
              
              $
              4.6Interest
                  income
              
              
              0.7
              
              
              0.6
              
              
              0.5Other
                  income
              
              
              2.1
              
              
              2.8
              
              
              2.0**Total
                  other – net**
              
              **$**
              **7.6**
              
              **$**
              **5.9**
              
              **$**
              **7.1**




**12.**
            **Segment
                Reporting**





The
      Company’s operations consist of 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.
      Net income is the measure of profitability used by management for all
      operations. In total, the Utility Holdings has three operating segments of
      as
      defined by SFAS 131 “Disclosure About Segments of an Enterprise and Related
      Information” (SFAS 131).





-59-
 Table
          of Contents


Information
      related to the Company’s business segments is summarized below:


Year
                  Ended December 31,*(In
                  millions)*
              
              2006
              
              2005
              
              2004**Revenues**Gas
                  Utility Services
              
              $
              1,232.5
              
              $
              1,359.7
              
              $
              1,126.2Electric
                  Utility Services
              
              
              422.2
              
              
              421.4
              
              
              371.3Other
                  Operations
              
              
              36.6
              
              
              36.1
              
              
              32.9Eliminations
              
              
              (34.8
              )
              
              (35.4
              )
              
              (32.4
              )Total
                  revenues
              
              $
              1,656.5
              
              $
              1,781.8
              
              $
              1,498.0**Profitability
                  Measure - Net Income**Gas
                  Utility Services
              
              $
              41.5
              
              $
              34.7
              
              $
              28.1Electric
                  Utility Services
              
              
              41.6
              
              
              50.4
              
              
              47.9Other
                  Operations
              
              
              8.3
              
              
              10.0
              
              
              7.1Total
                  net income
              
              $
              91.4
              
              $
              95.1
              
              $
              83.1




**Amounts
                  Included in Profitability Measures****Depreciation
                & Amortization**Gas
                  Utility Services
              
              
              
              
              $
              67.6
              
              $
              64.9
              
              $
              57.0Electric
                  Utility Services
              
              
              
              
              
              61.8
              
              
              56.9
              
              
              53.3Other
                  Operations
              
              
              
              
              
              21.9
              
              
              19.5
              
              
              17.5Total
                  depreciation & amortization
              
              
              
              
              $
              151.3
              
              $
              141.3
              
              $
              127.8**Interest
                  Expense**Gas
                  Utility Services
              
              
              
              
              $
              40.7
              
              $
              40.2
              
              $
              41.4Electric
                  Utility Services
              
              
              
              
              
              28.6
              
              
              23.7
              
              
              21.3Other
                  Operations
              
              
              
              
              
              8.2
              
              
              6.0
              
              
              4.7Total
                  interest expense
              
              
              
              
              $
              77.5
              
              $
              69.9
              
              $
              67.4**Equity
                  in Earnings of Unconsolidated Affiliates**Other
                  Operations
              
              
              
              
              $
              -
              
              $
              -
              
              $
              0.2**Income
                  Taxes**Gas
                  Utility Services
              
              
              
              
              $
              22.6
              
              $
              22.3
              
              $
              17.5Electric
                  Utility Services
              
              
              
              
              
              25.3
              
              
              33.5
              
              
              30.8Other
                  Operations
              
              
              
              
              
              (0.2
              )
              
              1.7
              
              
              4.8Total
                  income taxes
              
              
              
              
              $
              47.7
              
              $
              57.5
              
              $
              53.1**Capital
                  Expenditures**Gas
                  Utility Services
              
              
              
              
              $
              76.8
              
              $
              81.0
              
              $
              89.1Electric
                  Utility Services
              
              
              
              
              
              156.8
              
              
              100.0
              
              
              150.6Other
                  Operations
              
              
              
              
              
              24.8
              
              
              29.9
              
              
              27.9Non-cash
                  costs & changes in accruals
              
              
              
              
              
              (8.4
              )
              
              6.9
              
              
              (21.4
              )Total
                  capital expenditures
              
              
              
              
              $
              250.0
              
              $
              217.8
              
              $
              246.2







-60-
 Table
          of Contents


At
                  December 31,*(In
                  millions)*
              
              
              
              2006
              
              2005**Assets**Utility
                GroupGas
                  Utility Services
              
              
              
              
              $
              1,953.6
              
              $
              2,030.8Electric
                  Utility Services
              
              
              
              
              
              1,277.6
              
              
              1,176.0Other
                  Operations
              
              
              
              
              
              225.9
              
              
              188.9Eliminations
              
              
              
              
              
              (16.3
              )
              
              (4.5
              )Total
                  assets
              
              
              
              
              $
              3,440.8
              
              $
              3,391.2


**13.**
            **Subsidiary
                Guarantor and Consolidating
                Information**





The
      Company’s three operating utility companies, SIGECO, Indiana Gas, and VEDO are
      guarantors of Utility Holdings’ $520 million in short-term credit facilities, of
      which $270.1 million is outstanding at December 31, 2006, and Utility Holdings’
$700.0 million unsecured senior notes outstanding at December 31, 2006. The
      guarantees are full and unconditional and joint and several, and Utility
      Holdings has no subsidiaries other than the subsidiary guarantors. However,
      Utility Holdings does have operations other than those of the subsidiary
      guarantors.  Pursuant
      to a tax sharing agreement, consolidating tax effects are reflected at the
      parent level.Pursuant to Item 3-10 of Regulation S-X, disclosure of
      the results of operations and balance sheets of the subsidiary guarantors
      separate from the parent company’s operations is required. Following are
      consolidating financial statements including information on the combined
      operations of the subsidiary guarantors separate from the other operations
      of
      the parent company.





Consolidating
      Statement of Income for the year ended December 31, 2006 (in
      millions):


Subsidiary
              
              ParentGuarantors
              
              Company
              
              Eliminations
              
              ConsolidatedOPERATING
                  REVENUESGas
                  utility
              
              $
              1,232.5
              
              $
              -
              
              $
              -
              
              $
              1,232.5Electric
                  utility
              
              
              422.2
              
              
              -
              
              
              -
              
              
              422.2Other
              
              
              -
              
              
              36.6
              
              
              (34.8
              )
              
              1.8**Total
                  operating revenues**
              
              
              **1,654.7**
              
              
              **36.6**
              
              
              **(34.8**
              **)**
              
              **1,656.5**OPERATING
                  EXPENSESCost
                  of gas sold
              
              
              841.5
              
              
              -
              
              
              -
              
              
              841.5Cost
                  of fuel & purchased power
              
              
              151.5
              
              
              -
              
              
              -
              
              
              151.5Other
                  operating
              
              
              275.5
              
              
              (4.4
              )
              
              (32.1
              )
              
              239.0Depreciation
                  & amortization
              
              
              129.4
              
              
              21.5
              
              
              0.4
              
              
              151.3Taxes
                  other than income taxes
              
              
              63.0
              
              
              1.1
              
              
              0.1
              
              
              64.2Total
                  operating expenses
              
              
              1,460.9
              
              
              18.2
              
              
              (31.6
              )
              
              1,447.5**OPERATING
                  INCOME**
              
              
              **193.8**
              
              
              **18.4**
              
              
              **(3.2**
              **)**
              
              **209.0**OTHER
                  INCOME (EXPENSE)Equity
                  in earnings of consolidated companies
              
              
              -
              
              
              83.2
              
              
              (83.2
              )
              
              -Other
                  – net
              
              
              3.7
              
              
              42.6
              
              
              (38.7
              )
              
              7.6Total
                  other income (expense)
              
              
              3.7
              
              
              125.8
              
              
              (121.9
              )
              
              7.6Interest
                  expense
              
              
              66.4
              
              
              53.0
              
              
              (41.9
              )
              
              77.5**INCOME
                  BEFORE INCOME TAXES**
              
              
              **131.1**
              
              
              **91.2**
              
              
              **(83.2**
              **)**
              
              **139.1**Income
                  taxes
              
              
              47.9
              
              
              (0.2
              )
              
              -
              
              
              47.7**NET
                  INCOME**
              
              **$**
              **83.2**
              
              **$**
              **91.4**
              
              **$**
              **(83.2**
              **)**
              **$**
              **91.4**
  -61-
 Table
            of Contents


Consolidating
      Statement of Income for the year ended December 31, 2005 (in
      millions):


Subsidiary
              
              ParentGuarantors
              
              Company
              
              Eliminations
              
              ConsolidatedOPERATING
                  REVENUESGas
                  utility
              
              $
              1,359.7
              
              $
              -
              
              $
              -
              
              $
              1,359.7Electric
                  utility
              
              
              421.4
              
              
              -
              
              
              -
              
              
              421.4Other
              
              
              -
              
              
              36.1
              
              
              (35.4
              )
              
              0.7**Total
                  operating revenues**
              
              
              **1,781.1**
              
              
              **36.1**
              
              
              **(35.4**
              **)**
              
              **1,781.8**OPERATING
                  EXPENSESCost
                  of gas sold
              
              
              973.3
              
              
              -
              
              
              -
              
              
              973.3Cost
                  of fuel & purchased power
              
              
              144.1
              
              
              -
              
              
              -
              
              
              144.1Purchased
                  electric energy
              
              
              
              
              
              -Other
                  operating
              
              
              274.4
              
              
              0.1
              
              
              (33.2
              )
              
              241.3Depreciation
                  & amortization
              
              
              121.7
              
              
              19.3
              
              
              0.3
              
              
              141.3Taxes
                  other than income taxes
              
              
              64.7
              
              
              0.4
              
              
              0.1
              
              
              65.2Total
                  operating expenses
              
              
              1,578.2
              
              
              19.8
              
              
              (32.8
              )
              
              1,565.2**OPERATING
                  INCOME**
              
              
              **202.9**
              
              
              **16.3**
              
              
              **(2.6**
              **)**
              
              **216.6**OTHER
                  INCOME (EXPENSE)Equity
                  in earnings of consolidated companies
              
              
              -
              
              
              85.3
              
              
              (85.3
              )
              
              -Other
                  – net
              
              
              4.3
              
              
              37.8
              
              
              (36.2
              )
              
              5.9Total
                  other income (expense)
              
              
              4.3
              
              
              123.1
              
              
              (121.5
              )
              
              5.9Interest
                  expense
              
              
              64.4
              
              
              42.9
              
              
              (37.4
              )
              
              69.9**INCOME
                  BEFORE INCOME TAXES**
              
              
              **142.8**
              
              
              **96.5**
              
              
              **(86.7**
              **)**
              
              **152.6**Income
                  taxes
              
              
              57.5
              
              
              1.4
              
              
              (1.4
              )
              
              57.5**NET
                  INCOME**
              
              **$**
              **85.3**
              
              **$**
              **95.1**
              
              **$**
              **(85.3**
              **)**
              **$**
              **95.1**




Consolidating
      Statement of Income for the year ended December 31, 2004 (in
      millions):


Subsidiary
              
              ParentGuarantors
              
              Company
              
              Eliminations
              
              ConsolidatedOPERATING
                  REVENUESGas
                  utility
              
              $
              1,126.2
              
              $
              -
              
              $
              -
              
              $
              1,126.2Electric
                  utility
              
              
              371.3
              
              
              -
              
              
              -
              
              
              371.3Other
              
              
              -
              
              
              32.9
              
              
              (32.4
              )
              
              0.5**Total
                  operating revenues**
              
              
              **1,497.5**
              
              
              **32.9**
              
              
              **(32.4**
              **)**
              
              **1,498.0**OPERATING
                  EXPENSESCost
                  of gas sold
              
              
              778.5
              
              
              -
              
              
              -
              
              
              778.5Cost
                  of fuel & purchased power
              
              
              116.8
              
              
              -
              
              
              -
              
              
              116.8Purchased
                  electric energy
              
              
              
              
              
              -Other
                  operating
              
              
              249.8
              
              
              1.1
              
              
              (30.5
              )
              
              220.4Depreciation
                  & amortization
              
              
              110.1
              
              
              17.5
              
              
              0.2
              
              
              127.8Taxes
                  other than income taxes
              
              
              57.5
              
              
              0.6
              
              
              0.1
              
              
              58.2Total
                  operating expenses
              
              
              1,312.7
              
              
              19.2
              
              
              (30.2
              )
              
              1,301.7**OPERATING
                  INCOME**
              
              
              **184.8**
              
              
              **13.7**
              
              
              **(2.2**
              **)**
              
              **196.3**OTHER
                  INCOME (EXPENSE)Equity
                  in earnings of consolidated companies
              
              
              -
              
              
              75.9
              
              
              (75.9
              )
              
              -Equity
                  in earnings/losses of unconsolidated affiliates
              
              
              -
              
              
              0.2
              
              
              -
              
              
              0.2Other
                  – net
              
              
              5.8
              
              
              35.4
              
              
              (34.1
              )
              
              7.1Total
                  other income (expense)
              
              
              5.8
              
              
              111.5
              
              
              (110.0
              )
              
              7.3Interest
                  expense
              
              
              62.9
              
              
              37.5
              
              
              (33.0
              )
              
              67.4**INCOME
                  BEFORE INCOME TAXES**
              
              
              **127.7**
              
              
              **87.7**
              
              
              **(79.2**
              **)**
              
              **136.2**Income
                  taxes
              
              
              51.8
              
              
              4.6
              
              
              (3.3
              )
              
              53.1**NET
                  INCOME**
              
              **$**
              **75.9**
              
              **$**
              **83.1**
              
              **$**
              **(75.9**
              **)**
              **$**
              **83.1**
 -62-
 Table
            of Contents


Consolidating
      Statement of Cash Flows for the year ended December 31, 2006 (in
      millions): Subsidiary
              
              ParentGuarantors
              
              Company
              
              Eliminations
              
              Consolidated**NET
                  CASH FLOWS FROM OPERATING ACTIVITIES**
              
              **$**
              **279.9**
              
              **$**
              **6.2**
              
              **$**
              **-**
              
              **$**
              **286.1**CASH
                  FLOWS FROM FINANCING ACTIVITIESProceeds
                  from:Additional
                  capital contribution
              
              
              40.0
              
              
              20.0
              
              
              (40.0
              )
              
              20.0Long-term
                  debt - net of issuance costs & hedging proceeds
              
              
              228.9
              
              
              92.8
              
              
              (228.9
              )
              
              92.8Requirements
                  for:Retirement
                  of long-term debt, including premiums paid
              
              
              (96.7
              )
              
              (100.0
              )
              
              96.7
              
              
              (100.0
              )Dividends
                  to parent
              
              
              (75.4
              )
              
              (75.4
              )
              
              75.4
              
              
              (75.4
              )Redemption
                  of preferred stock of subsidiary
              
              
              -
              
              
              -
              
              
              -
              
              
              -Net
                  change in short-term borrowings, including from otherVectren
                  companies
              
              
              (156.5
              )
              
              43.2
              
              
              156.5
              
              
              43.2**Net
                  cash flows from financing activities**
              
              
              **(59.7**
              **)**
              
              **(19.4**
              **)**
              
              **59.7**
              
              
              **(19.4**
              **)**CASH
                  FLOWS FROM INVESTING ACTIVITIESProceeds
                  from:Consolidated
                  subsidiary distributions
              
              
              -
              
              
              75.4
              
              
              (75.4
              )
              
              -Other
                  investing activities
              
              
              -
              
              
              0.1
              
              
              -
              
              
              0.1Requirements
                  for:Capital
                  expenditures, excluding AFUDC equity
              
              
              (225.5
              )
              
              (24.5
              )
              
              -
              
              
              (250.0
              )Consolidated
                  subsidiary investments
              
              
              -
              
              
              (172.2
              )
              
              172.2
              
              
              -Net
                  change in notes receivable from other Vectren companies
              
              
              -
              
              
              156.5
              
              
              (156.5
              )
              
              -**Net
                  cash flows from investing activities**
              
              
              **(225.5**
              **)**
              
              **35.3**
              
              
              **(59.7**
              **)**
              
              **(249.9**
              **)**Net
                  (decrease) increase in cash & cash equivalents
              
              
              (5.3
              )
              
              22.1
              
              
              -
              
              
              16.8Cash
                  & cash equivalents at beginning of period
              
              
              11.0
              
              
              0.7
              
              
              -
              
              
              11.7Cash
                  & cash equivalents at end of period
              
              $
              5.7
              
              $
              22.8
              
              $
              -
              
              $
              28.5




Consolidating
      Statement of Cash Flows for the year ended December 31, 2005 (in
      millions):


Subsidiary
            
            ParentGuarantors
            
            Company
            
            Eliminations
            
            Consolidated**NET
                CASH FLOWS FROM OPERATING ACTIVITIES**
            
            **$**
            **224.0**
            
            **$**
            **41.8**
            
            **$**
            **-**
            
            **$**
            **265.8**CASH
                FLOWS FROM FINANCING ACTIVITIESProceeds
                from:Additional
                capital contribution
            
            
            125.0
            
            
            20.0
            
            
            (125.0
            )
            
            20.0Long-term
                debt - net of issuance costs & hedging proceeds
            
            
            -
            
            
            150.0
            
            
            -
            
            
            150.0Requirements
                for:Retirement
                of long-term debt, including premiums paid
            
            
            (49.9
            )
            
            -
            
            
            -
            
            
            (49.9
            )Dividends
                to parent
            
            
            (80.7
            )
            
            (80.7
            )
            
            80.7
            
            
            (80.7
            )Redemption
                of preferred stock of subsidiary
            
            
            (0.1
            )
            
            -
            
            
            -
            
            
            (0.1
            )Net
                change in short-term borrowings, including from otherVectren
                companies
            
            
            (24.6
            )
            
            (81.1
            )
            
            24.3
            
            
            (81.4
            )**Net
                cash flows from financing activities**
            
            
            **(30.3**
            **)**
            
            **8.2**
            
            
            **(20.0**
            **)**
            
            **(42.1**
            **)**CASH
                FLOWS FROM INVESTING ACTIVITIESProceeds
                from:Consolidated
                subsidiary distributions
            
            
            -
            
            
            80.7
            
            
            (80.7
            )
            
            -Other
                investing activities
            
            
            0.1
            
            
            -
            
            
            -
            
            
            0.1Requirements
                for:Capital
                expenditures, excluding AFUDC equity
            
            
            (187.5
            )
            
            (30.3
            )
            
            -
            
            
            (217.8
            )Consolidated
                subsidiary investments
            
            
            -
            
            
            (125.0
            )
            
            125.0
            
            
            -Net
                change in notes receivable from other Vectren companies
            
            
            -
            
            
            24.3
            
            
            (24.3
            )
            
            -**Net
                cash flows from investing activities**
            
            
            **(187.4**
            **)**
            
            **(50.3**
            **)**
            
            **20.0**
            
            
            **(217.7**
            **)**Net
                (decrease) increase in cash & cash equivalents
            
            
            6.3
            
            
            (0.3
            )
            
            -
            
            
            6.0Cash
                & cash equivalents at beginning of period
            
            
            4.7
            
            
            1.0
            
            
            -
            
            
            5.7Cash
                & cash equivalents at end of period
            
            $
            11.0
            
            $
            0.7
            
            $
            -
            
            $
            11.7




-63-
 Table
          of Contents


Consolidating
      Statement of Cash Flows for the year ended December 31, 2004 (in
      millions):


Subsidiary
              
              ParentGuarantors
              
              Company
              
              Eliminations
              
              Consolidated**NET
                  CASH FLOWS FROM OPERATING ACTIVITIES**
              
              **$**
              **197.6**
              
              **$**
              **35.3**
              
              **$**
              **-**
              
              **$**
              **232.9**CASH
                  FLOWS FROM FINANCING ACTIVITIESProceeds
                  from:Additional
                  capital contribution
              
              
              -
              
              
              3.1
              
              
              -
              
              
              3.1Long-term
                  debt - net of issuance costs & hedging proceeds
              
              
              32.4
              
              
              -
              
              
              -
              
              
              32.4Requirements
                  for:Retirement
                  of long-term debt, including premiums paid
              
              
              (70.5
              )
              
              -
              
              
              -
              
              
              (70.5
              )Dividends
                  to parent
              
              
              (80.6
              )
              
              (80.6
              )
              
              80.6
              
              
              (80.6
              )Redemption
                  of preferred stock of subsidiary
              
              
              (0.1
              )
              
              -
              
              
              -
              
              
              (0.1
              )Net
                  change in short-term borrowings, including from other
              
              
              
              
              
              
              
              
              -Vectren
                  companies
              
              
              135.7
              
              
              123.6
              
              
              (136.2
              )
              
              123.1**Net
                  cash flows from financing activities**
              
              
              **16.9**
              
              
              **46.1**
              
              
              **(55.6**
              **)**
              
              **7.4**CASH
                  FLOWS FROM INVESTING ACTIVITIESProceeds
                  from:Consolidated
                  subsidiary distributions
              
              
              -
              
              
              80.6
              
              
              (80.6
              )
              
              -Other
                  investing activities
              
              
              1.1
              
              
              2.4
              
              
              -
              
              
              3.5Requirements
                  for:Capital
                  expenditures, excluding AFUDC equity
              
              
              (218.3
              )
              
              (27.9
              )
              
              -
              
              
              (246.2
              )Net
                  change in notes receivable from other Vectren companies
              
              
              -
              
              
              (136.2
              )
              
              136.2
              
              
              -**Net
                  cash flows from investing activities**
              
              
              **(217.2**
              **)**
              
              **(81.1**
              **)**
              
              **55.6**
              
              
              **(242.7**
              **)**Net
                  (decrease) increase in cash & cash equivalents
              
              
              (2.7
              )
              
              0.3
              
              
              -
              
              
              (2.4
              )Cash
                  & cash equivalents at beginning of period
              
              
              7.4
              
              
              0.7
              
              
              -
              
              
              8.1Cash
                  & cash equivalents at end of period
              
              $
              4.7
              
              $
              1.0
              
              $
              -
              
              $
              5.7




Consolidating
      Balance Sheet as of December 31, 2006 (in millions):


**ASSETS**
            
            Subsidiary
            
            ParentGuarantors
            
            Company
            
            Eliminations
            
            ConsolidatedCurrent
                AssetsCash
                & cash equivalents
            
            $
            5.7
            
            $
            22.8
            
            $
            -
            
            $
            28.5Accounts
                receivable - less reserves
            
            
            134.8
            
            
            -
            
            
            -
            
            
            134.8Receivables
                due from other Vectren companies
            
            
            6.1
            
            
            146.0
            
            
            (151.8
            )
            
            0.3Accrued
                unbilled revenues
            
            
            121.4
            
            
            -
            
            
            -
            
            
            121.4Inventories
            
            
            139.6
            
            
            2.3
            
            
            -
            
            
            141.9Recoverable
                fuel & natural gas costs
            
            
            1.8
            
            
            -
            
            
            -
            
            
            1.8Prepayments
                & other current assets
            
            
            91.2
            
            
            14.7
            
            
            (2.7
            )
            
            103.2**Total
                current assets**
            
            
            **500.6**
            
            
            **185.8**
            
            
            **(154.5**
            **)**
            
            **531.9**Utility
                PlantOriginal
                cost
            
            
            3,820.2
            
            
            -
            
            
            -
            
            
            3,820.2Less:
                accumulated depreciation & amortization
            
            
            1,434.7
            
            
            -
            
            
            -
            
            
            1,434.7**Net
                utility plant**
            
            
            **2,385.5**
            
            
            **-**
            
            
            **-**
            
            
            **2,385.5**Investments
                in consolidated subsidiaries
            
            
            -
            
            
            1,129.7
            
            
            (1,129.7
            )
            
            -Notes
                receivable from consolidated subsidiaries
            
            
            -
            
            
            575.3
            
            
            (575.3
            )
            
            -Investments
                in unconsolidated affiliates
            
            
            0.2
            
            
            -
            
            
            -
            
            
            0.2Other
                investments
            
            
            15.4
            
            
            6.0
            
            
            -
            
            
            21.4Non-utility
                property - net
            
            
            5.2
            
            
            157.9
            
            
            -
            
            
            163.1Goodwill
                - net
            
            
            205.0
            
            
            -
            
            
            -
            
            
            205.0Regulatory
                assets
            
            
            103.3
            
            
            13.5
            
            
            -
            
            
            116.8Other
                assets
            
            
            16.1
            
            
            0.8
            
            
            -
            
            
            16.9**TOTAL
                ASSETS**
            
            **$**
            **3,231.3**
            
            **$**
            **2,069.0**
            
            **$**
            **(1,859.5**
            **)**
            **$**
            **3,440.8**


-64-
 Table
            of Contents


**LIABILITIES
                & SHAREHOLDER'S EQUITY**
            
            Subsidiary
            
            ParentGuarantors
            
            Company
            
            Eliminations
            
            ConsolidatedCurrent
                LiabilitiesAccounts
                payable
            
            $
            131.5
            
            $
            4.7
            
            $
            -
            
            $
            136.2Accounts
                payable to affiliated companies
            
            
            68.1
            
            
            0.1
            
            
            -
            
            
            68.2Payables
                to other Vectren companies
            
            
            44.0
            
            
            0.1
            
            
            (18.8
            )
            
            25.3Refundable
                fuel & natural gas costs
            
            
            35.3
            
            
            -
            
            
            -
            
            
            35.3Accrued
                liabilities
            
            
            107.3
            
            
            11.2
            
            
            (2.7
            )
            
            115.8Short-term
                borrowings
            
            
            -
            
            
            270.1
            
            
            -
            
            
            270.1Short-term
                borrowings from other Vectren companies
            
            
            133.0
            
            
            -
            
            
            (133.0
            )
            
            -Current
                maturities of long-term debt
            
            
            6.5
            
            
            -
            
            
            -
            
            
            6.5Long-term
                debt subject to tender
            
            
            20.0
            
            
            -
            
            
            -
            
            
            20.0**Total
                current liabilities**
            
            
            **545.7**
            
            
            **286.2**
            
            
            **(154.5**
            **)**
            
            **677.4**Long-Term
                DebtLong-term
                debt - net of current maturities & debt subject to
                tender
            
            
            327.3
            
            
            698.0
            
            
            -
            
            
            1,025.3Long-term
                debt due to VUHI
            
            
            575.3
            
            
            -
            
            
            (575.3
            )
            
            -Total
                long-term debt - net
            
            
            902.6
            
            
            698.0
            
            
            (575.3
            )
            
            1,025.3Deferred
                Income Taxes & Other LiabilitiesDeferred
                income taxes
            
            
            265.9
            
            
            16.3
            
            
            -
            
            
            282.2Regulatory
                liabilities
            
            
            285.0
            
            
            6.1
            
            
            -
            
            
            291.1Deferred
                credits & other liabilities
            
            
            102.4
            
            
            5.7
            
            
            -
            
            
            108.1Total
                deferred credits & other liabilities
            
            
            653.3
            
            
            28.1
            
            
            -
            
            
            681.4Common
                Shareholder's EquityCommon
                stock (no par value)
            
            
            776.3
            
            
            632.9
            
            
            (776.3
            )
            
            632.9Retained
                earnings
            
            
            352.5
            
            
            422.9
            
            
            (352.5
            )
            
            422.9Accumulated
                other comprehensive income
            
            
            0.9
            
            
            0.9
            
            
            (0.9
            )
            
            0.9**Total
                common shareholder's equity**
            
            
            **1,129.7**
            
            
            **1,056.7**
            
            
            **(1,129.7**
            **)**
            
            **1,056.7****TOTAL
                LIABILITIES & SHAREHOLDER'S EQUITY**
            
            **$**
            **3,231.3**
            
            **$**
            **2,069.0**
            
            **$**
            **(1,859.5**
            **)**
            **$**
            **3,440.8**




Consolidating
      Balance Sheet as of December 31, 2005 (in millions):


**ASSETS**
              
              Subsidiary
              
              ParentGuarantors
              
              Company
              
              Eliminations
              
              ConsolidatedCurrent
                  AssetsCash
                  & cash equivalents
              
              $
              11.0
              
              $
              0.7
              
              $
              -
              
              $
              11.7Accounts
                  receivable - less reserves
              
              
              170.6
              
              
              0.1
              
              
              -
              
              
              170.7Receivables
                  due from other Vectren companies
              
              
              0.9
              
              
              294.7
              
              
              (293.4
              )
              
              2.2Accrued
                  unbilled revenues
              
              
              212.5
              
              
              -
              
              
              -
              
              
              212.5Inventories
              
              
              126.2
              
              
              -
              
              
              -
              
              
              126.2Recoverable
                  fuel & natural gas costs
              
              
              15.4
              
              
              -
              
              
              -
              
              
              15.4Prepayments
                  & other current assets
              
              
              104.1
              
              
              13.7
              
              
              (0.6
              )
              
              117.2**Total
                  current assets**
              
              
              **640.7**
              
              
              **309.2**
              
              
              **(294.0**
              **)**
              
              **655.9**Utility
                  PlantOriginal
                  cost
              
              
              3,631.6
              
              
              0.4
              
              
              -
              
              
              3,632.0Less:
                  accumulated depreciation & amortization
              
              
              1,380.1
              
              
              -
              
              
              -
              
              
              1,380.1**Net utility plant**
              
              
              **2,251.5**
              
              
              **0.4**
              
              
              **-**
              
              
              **2,251.9**Investments
                  in consolidated subsidiaries
              
              
              -
              
              
              1,085.0
              
              
              (1,085.0
              )
              
              -Notes
                  receivable from consolidated subsidiaries
              
              
              -
              
              
              443.1
              
              
              (443.1
              )
              
              -Investments
                  in unconsolidated affiliates
              
              
              0.2
              
              
              -
              
              
              -
              
              
              0.2Other
                  investments
              
              
              14.9
              
              
              6.1
              
              
              -
              
              
              21.0Non-utility
                  property - net
              
              
              5.1
              
              
              154.9
              
              
              -
              
              
              160.0Goodwill
                  - net
              
              
              205.0
              
              
              -
              
              
              -
              
              
              205.0Regulatory
                  assets
              
              
              83.1
              
              
              6.8
              
              
              -
              
              
              89.9Other
                  assets
              
              
              6.3
              
              
              1.0
              
              
              -
              
              
              7.3**TOTAL
                  ASSETS**
              
              **$**
              **3,206.8**
              
              **$**
              **2,006.5**
              
              **$**
              **(1,822.1**
              **)**
              **$**
              **3,391.2**
 -65-
 Table
            of Contents


**LIABILITIES
                  & SHAREHOLDER'S EQUITY**
              
              Subsidiary
              
              ParentGuarantors
              
              Company
              
              Eliminations
              
              ConsolidatedCurrent
                  LiabilitiesAccounts
                  payable
              
              $
              125.7
              
              $
              6.2
              
              $
              -
              
              $
              131.9Accounts
                  payable to affiliated companies
              
              
              140.0
              
              
              0.6
              
              
              -
              
              
              140.6Payables
                  to other Vectren companies
              
              
              27.8
              
              
              5.2
              
              
              (3.8
              )
              
              29.2Refundable
                  fuel & natural gas costs
              
              
              7.6
              
              
              -
              
              
              -
              
              
              7.6Accrued
                  liabilities
              
              
              120.7
              
              
              10.3
              
              
              (0.7
              )
              
              130.4Short-term
                  borrowings
              
              
              -
              
              
              226.9
              
              
              -
              
              
              226.9Short-term
                  borrowings from other Vectren companies
              
              
              289.5
              
              
              -
              
              
              (289.5
              )
              
              -Current
                  maturities of long-term debt
              
              
              -
              
              
              -
              
              
              -
              
              
              -Long-term
                  debt subject to tender
              
              
              53.7
              
              
              -
              
              
              -
              
              
              53.7**Total
                  current liabilities**
              
              
              **765.0**
              
              
              **249.2**
              
              
              **(294.0**
              **)**
              
              **720.3**Long-Term
                  DebtLong-term
                  debt - net of current maturities & debt subject to tender
              
              
              299.9
              
              
              697.9
              
              
              -
              
              
              997.8Long-term
                  debt due to VUHI
              
              
              443.1
              
              
              -
              
              
              (443.1
              )
              
              -Total
                  long-term debt - net
              
              
              743.0
              
              
              697.9
              
              
              (443.1
              )
              
              997.8Deferred
                  Income Taxes & Other LiabilitiesDeferred
                  income taxes
              
              
              251.6
              
              
              23.9
              
              
              -
              
              
              275.5Regulatory
                  liabilities
              
              
              266.2
              
              
              6.8
              
              
              -
              
              
              272.9Deferred
                  credits & other liabilities
              
              
              96.0
              
              
              4.9
              
              
              -
              
              
              100.9Total
                  deferred credits & other liabilities
              
              
              613.8
              
              
              35.6
              
              
              -
              
              
              649.3Common
                  Shareholder's EquityCommon
                  stock (no par value)
              
              
              736.3
              
              
              612.9
              
              
              (736.3
              )
              
              612.9Retained
                  earnings
              
              
              344.7
              
              
              406.9
              
              
              (344.7
              )
              
              406.9Accumulated
                  other comprehensive income
              
              
              4.0
              
              
              4.0
              
              
              (4.0
              )
              
              4.0**Total
                  common shareholder's equity**
              
              
              **1,085.0**
              
              
              **1,023.8**
              
              
              **(1,085.0**
              **)**
              
              **1,023.8****TOTAL
                  LIABILITIES & SHAREHOLDER'S EQUITY**
              
              **$**
              **3,206.8**
              
              **$**
              **2,006.5**
              
              **$**
              **(1,822.1**
              **)**
              **$**
              **3,391.2**


**14.**
            **Adoption
                of Other Accounting
                Standards**





SFAS
      No. 158


On
      December 31, 2006, and after calculating the balance sheet impact
      of Vectren’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 required
      Vectren 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. The impacts of adopting
      this standard were recorded at Vectren and are not reflected at the Utility
      Holdings level.





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.





-66-
 Table
          of Contents


**15.**
            **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)*
              
              
              
              Q1
              
              Q2
              
              Q3
              
              Q4**2006****Results
                of Operations**:Operating
                  revenues
              
              
              
              
              $
              678.3
              
              $
              159.1
              
              $
              240.5
              
              $
              578.6Operating
                  income
              
              
              
              
              
              89.7
              
              
              27.3
              
              
              23.7
              
              
              68.3Net
                  income
              
              
              
              
              
              43.4
              
              
              7.1
              
              
              6.5
              
              
              34.4**2005****Results
                  of Operations:**Operating
                  revenues
              
              
              
              
              $
              611.6
              
              $
              283.0
              
              $
              265.7
              
              $
              621.5Operating
                  income
              
              
              
              
              
              94.7
              
              
              28.3
              
              
              30.7
              
              
              62.9Net
                  income
              
              
              
              
              
              48.1
              
              
              7.8
              
              
              8.9
              
              
              30.3





-67-
 Table
          of Contents





**ITEM9. CHANGE IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
      FINANCIAL DISCLOSURE**


None.





**ITEM9A.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.





**ITEM9B. OTHER INFORMATION**





None.


**PART
      III**





**ITEM10.** **DIRECTORS,
      EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE**





Intentionally
      omitted. See the table of contents of this Annual Report on Form 10-K for
      explanation.





Vectren’s
      Corporate Governance Guidelines, its charters for each of its Audit,
      Compensation 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.





**ITEM
      11. EXECUTIVE COMPENSATION**





Intentionally
      omitted. See the table of contents of this Annual Report on Form 10-K for
      explanation.





**ITEM
      12.** **SECURITYOWNERSHIP
      OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
      RELATED STOCKHOLDER MATTERS**





Intentionally
      omitted. See the table of contents of this Annual Report on Form 10-K for
      explanation.





**ITEM
      13.** **CERTAIN
      RELATIONSHIPS AND RELATED TRANSACTIONS**


Intentionally
      omitted. See the table of contents of this Annual Report on Form 10-K for
      explanation.





-68-
 Table
          of Contents


**ITEM14. PRINCIPAL ACCOUNTANT FEES AND SERVICES**





The
      following tabulation shows the audit and non-audit fees incurred and payable
      to
      Deloitte & Touche, LLP (Deloitte) for the years ending December 31, 2006 and
      2005. The fees presented below represent total Vectren fees, the majority of
      which are allocated to Utility Holdings.


2006
            
            2005Audit
                Fees(1)
            
            $
            1,524,008
            
            $
            1,409,862Audit-Related
                Fees(2)
            
            
            63,250
            
            
            50,000Tax
                Fees(3)
            
            
            144,879
            
            
            128,208All
                Other Fees(4)
            
            
            -
            
            
            -Total
                Fees Paid to Deloitte(5)
            
            $
            1,732,137
            
            $
            1,588,070




(1)  Aggregate
      fees incurred and payable to Deloitte for professional services rendered for
      the
      audits of Vectren’s
      and Utility Holdings’2006 and 2005 fiscal year annual financial
      statements and the review of financial statements included in their Forms
      10-K or 10-Q filed during the Company’s 2006 and 2005 fiscal years. This
      includes fees incurred for audit services related to regulatory filings and
      certain of Vectren’s subsidiaries in connection with the audit of the Company’s
      financial statements. The amount also includes fees related to the attestation
      to the Company’s assertion pursuant to Section 404 of the Sarbanes Oxley Act of
      2002. In addition, this amount includes the reimbursement of out-of-pocket
      costs
      incurred related to the provision of these services totaling $91,008 and
      $100,262 in 2006 and 2005, respectively.





(2)  Audit
      related fees consisted principally of reviews related to various financing
      transactions and consultation on various accounting issues.





(3)  Tax
      fees
      consisted of fees paid to Deloitte for the review of tax returns, consultation
      on other tax matters of Vectren,
      and tax technical training. In addition, this amount includes the reimbursement
      of out-of-pocket costs incurred related to the provision of these services
      totaling $13,971 and $9,896 in 2006 and 2005, respectively.





(4)  Pursuant
      to its charter, the Audit committee of Vectren Corporation is responsible for
      selecting, approving professional fees and overseeing the independence,
      qualifications and performance of the independent registered public accounting
      firm. The Audit committee has adopted a formal policy with respect to the
      pre-approval of audit and permissible non-audit services provided by the
      independent registered public accounting firm. Pre-approval is assessed on
      a
      case-by-case basis. In assessing requests for services to be provided by the
      independent registered public accounting firm, the Audit committee considers
      whether such services are consistent with the auditors’ independence, whether
      the independent registered public accounting firm is likely to provide the
      most
      effective and efficient service based upon the firm’s familiarity with Vectren
      and Utility Holdings, and whether the service could enhance the Company’s
      ability to manage or control risk or improve audit quality. The audit-related,
      tax and other services provided by Deloitte in the last year and related
      fees were approved by the Audit committee of
      Vectren Corporationin accordance with this policy.





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          of Contents


**PART
      IV**





**ITEM
      15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM
      8-K**





**List
      of Documents Filed as Part of This Report**





Consolidated
      Financial Statements





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





Supplemental
      Schedules





For
      the
      years ended December 31, 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 is
      included 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
      Utility Holdings, Inc. and Subsidiary Companies**


**VALUATION
      AND QUALIFYING ACCOUNTS AND RESERVES**





Column
                  A
              
              Column
                  B
              
              Column
                  C
              
              
              
              Column
                  D
              
              Column
                  EAdditionsBalance
                  at
              
              Charged
              
              Charged
              
              Deductions
              
              Balance
                  atBeginning
              
              to
              
              to
                  Other
              
              from
              
              End
                  ofDescription
              
              Of
                  Year
              
              Expenses
              
              Accounts
              
              Reserves,
                  Net
              
              Year(In
                  millions)VALUATION
                  AND QUALIFYING ACCOUNTS:Year
                  2006 – Accumulated provision foruncollectible
                  accounts
              
              $
              2.6
              
              $
              13.6
              
              $
              -
              
              $
              13.7
              
              $
              2.5Year
                  2005 – Accumulated provision foruncollectible
                  accounts
              
              $
              1.9
              
              $
              14.4
              
              $
              -
              
              $
              13.7
              
              $
              2.6Year
                  2004 – Accumulated provision foruncollectible
                  accounts
              
              $
              3.1
              
              $
              10.7
              
              $
              -
              
              $
              11.9
              
              $
              1.9OTHER
                  RESERVES:Year
                  2006 – Restructuring costs
              
              $
              2.4
              
              $
              -
              
              $
              -
              
              $
              0.7
              
              $
              1.7Year
                  2005 – Restructuring costs
              
              $
              2.7
              
              $
              -
              
              $
              -
              
              $
              0.3
              
              $
              2.4Year
                  2004 – Restructuring costs
              
              $
              3.2
              
              $
              -
              
              $
              -
              
              $
              0.5
              
              $
              2.7


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List
      of Exhibits





The
      Company has incorporated by reference herein certain exhibits as specified
      below
      pursuant to Rule 12b-32 under the Exchange Act. Exhibits for the Company
      attached to this filing filed electronically with the SEC are listed below.
      Exhibits for the Company are listed in the Index to Exhibits beginning on page
      72.








**Vectren
      Utility Holdings, Inc.**


**2006
      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******





12
            Ratio
                of Earnings to Fixed Charges21.1
            List
                of Company’s Significant
                Subsidiaries23
            Consent
                of Independent Registered Public Accounting
                Firm


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          of Contents





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
            Articles
                of Incorporation of Vectren Utility Holdings, Inc. (Filed and designated
                in Registration Statement on Amendment 3 to Form 10, File No. 1-16739,
                as
                Exhibit 3.1)


3.2
            Bylaws
                of Vectren Utility Holdings, Inc. (Filed and designated in Registration
                Statement on Amendment 3 to Form 10, File No. 1-16739, as Exhibit
                3.2)





**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).





-72-
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          of Contents


**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 as of May 1, 2006). (Filed and designated in Vectren
                Corporation’s Proxy Statement dated March 15, 2006, File No. 1-15467, as
                Appendix H.)


10.5
            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 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.)


10.8
            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.)


10.9
              
              10.10
            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.)
              Vectren
                Corporation At Risk Compensation Plan specimen Stock Option Grant
                Agreement for officers, effective January 1, 2005. (Filed and designated
                in Form 8-K, dated January 1, 2005, File No. 1-15467, as Exhibit
                99-2.)


10.11
            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.)


10.12
            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.)


10.13
            Agreement
                for the Supply of Coal to F.B. Culley Generating Station between
                Southern
                Indiana Gas and Electric Company and Sigcorp Fuels, Inc., dated December
                17, 1997 and effective January 1, 1998. Portions of the document
                have been
                omitted pursuant to a request for confidential treatment in accordance
                with Exchange Act Rule 24b-2. . (Filed and designated in Form 10-K,
                for
                the year ended December 31, 2005, File No. 1-15467, as Exhibit 10-21.)
                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.)


10.14
            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.)


10.15
            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.)


10.16
            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.)


-73-
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**12.
      Ratio of Earnings to Fixed Charges**


The
      Company’s Ratio of Earnings to Fixed Charges is attached hereto as Exhibit
      12.





**21.
      Subsidiaries of the Company**


The
      list
      of the Company's significant subsidiaries is attached hereto as Exhibit 21.





**23.
      Consents of Experts and Counsel**


The
      consent of Deloitte & Touche LLP is attached hereto as Exhibit 23.




**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 32.1.





**99.
      Additional Exhibits**


99.1
            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.)





99.2
            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.)





99.3
            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.)


-74-
 Table
          of Contents


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
      UTILITY HOLDINGS, INC.








Dated
      February 27,
      2007                                                                                     /s/
      Niel C.
      Ellerbrook


Niel
      C.
      Ellerbrook,


Chairman,
      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,
                Chief Executive
            
            February
                27, 2007Niel
                C. Ellerbrook
            
            Officer,
                & Director (Principal
              Executive
                Officer)/s/
                Jerome A. Benkert, Jr.
            
            Executive
                Vice President,
            
            February
                27, 2007Jerome
                A. Benkert, Jr.
            
            Chief
                Financial Officer, &
              Director
                (Principal Financial
              Officer)/s/
                M. Susan Hardwick
            
            Vice
                President, Controller &
            
            February
                27, 2007M.
                Susan Hardwick
            
            Assistant
                Treasurer (Principal
              Accounting
                Officer)/s/
                Ronald E. Christian
            
            Director
            
            February
                27, 2007Ronald
                E. Christian/s/
                William S. Doty
            
            Director
            
            February
                27, 2007William
                S. Doty