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, 2005**
 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**7
                  1/4% Senior Notes, due 10/15/2031**
              
              **New
                  York Stock Exchange**
 
 
 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 Contecnts
 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
          ___.
 
 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, 2005, 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**
                **February
                    28, 2006**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 Contecnts
 **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
                
                157A
                
                Qualitative
                    and Quantitative Disclosures About Market
                    Risk
                
                338
                
                Financial
                    Statements and Supplementary Data
                
                359
                
                Changes
                    in and Disagreements with Accountants on Accounting and
                    Financial Disclosure
                
                719A
                
                Controls
                    and Procedures
                
                719B
                
                Other
                    Information
                
                71Part
                    III10
                
                Directors
                    and Executive Officers of the Registrant(A)
                
                7111
                
                Executive
                    Compensation(A)
                
                7112
                
                Security
                    Ownership of Certain Beneficial Owners and Management and Related
                    Stockholder Matters(A).
                
                7113
                
                Certain
                    Relationships and Related Transactions(A)
                
                7114
                
                Principal
                    Accountant Fees and Services
                
                72Part
                    IV15
                
                Exhibits and Financial Statement
                    Schedules
                
                73Signatures
                
                78
 
 (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 duringconstruction
              MMBTU:
                  millions of British thermal unitsAPB:
                  Accounting Principles Board
              MW:
                  megawattsEITF:
                  Emerging Issues Task Force
              MWh
                  / GWh: megawatt hours / thousands ofmegawatt
                  hours (gigawatt hours)FASB:
                  Financial Accounting Standards Board
              NOx:
                  nitrogen oxideFERC:
                  Federal Energy Regulatory Commission
              OUCC:
                  Indiana Office of the Utility ConsumerCounselorIDEM:
                  Indiana Department of EnvironmentalManagement
              PUCO:
                  Public Utilities Commission of OhioIURC:
                  Indiana Utility Regulatory Commission
              SFAS:
                  Statement of Financial AccountingStandardsMCF
                  / BCF: thousands / billions of cubic feet
              USEPA:
                  United States Environmental ProtectionAgencyMDth
                  / MMDth: thousands / millions of dekatherms
              Throughput:
                  combined gas sales and gastransportation
                  volumes
 
 3
 Table
            of Contecnts
  **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), formerly a wholly owned subsidiary
          of
          Indiana Energy, Inc. (Indiana Energy), Southern Indiana Gas and Electric
          Company
          (SIGECO), formerly a wholly owned subsidiary of SIGCORP, Inc. (SIGCORP),
          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 562,000 natural
          gas
          customers located in central and southern Indiana. SIGECO provides energy
          delivery services to approximately 140,000 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 were acquired from The Dayton Power and Light Company on
          October
          31, 2000. The Ohio operations generally do business as Vectren Energy Delivery
          of Ohio.
 
 Vectren,
          an Indiana corporation, is an energy and applied technology holding company
          headquartered in Evansville, Indiana. The Company organized on June 10,
          1999, to
          effect the merger of Indiana Energy and SIGCORP. On March 31, 2000, Indiana
          Energy merged with SIGCORP and into Vectren. The transaction involved a
          tax-free
          exchange of shares that was accounted for as a pooling-of-interests.
 
 Both
          Vectren and Utility Holdings are 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, 2005, the Company had $3.4 billion in total assets, with $2.0
          billion (60%) attributed to the Gas Utility Services, $1.2 billion (35%)
          attributed to the Electric Utility Services, and $0.2 billion (5%) attributed
          to
          Other Operations. Net income for the year ended December 31, 2005, was
          $95.1
          million with $85.3 million attributed to regulated operations and $9.8
          million
          attributed to other operations. Net income for the year ended 2004 was
          $83.1
          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
 Table
              of Contecnts
 **Gas
          Utility Services**
 
 At
          December 31, 2005, the Company supplied natural gas service to approximately
          992,000 Indiana and Ohio customers, including 906,000 residential, 84,000
          commercial, and 2,000 industrial and other contract customers. This represents
          customer base growth of 1.3% compared to 2004.
 
 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. The largest community served outside of Indiana is Dayton,
          Ohio.
 
 **Revenues**
 
 For
          the
          year ended December 31, 2005, gas utility revenues were approximately $1,359.7
          million, of which residential customers accounted for 66%, commercial 28%,
          and
          industrial and other contract customers 6%, respectively.
 
 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 200.1 MMDth for the year ended December 31,
          2005.
          Gas transported or sold to residential and commercial customers was 112.9
          MMDth
          representing 56% of throughput. Gas transported or sold to industrial and
          other
          contract customers was 87.2 MMDth representing 44% of throughput. Rates
          for
          transporting gas provide for the same margins generally 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, six liquefied petroleum air-gas manufacturing
          plants, and a propane cavern. 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,
          nonregulated, 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
          2005,
          the Company purchased 106,449 MDth volumes of gas at an average cost of
          $9.05
          per Dth, of which approximately 95% was purchased from ProLiance and 5%
          was
          purchased from other third party providers. As required by a June 2005,
          PUCO
          order, VEDO solicited bids for its gas supply/portfolio administration
          services
          and selected a third party provider under a one year contract. ProLiance’s
          obligation to supply these services to VEDO ended October 31, 2005. Prior
          to
          October 31, 2005, ProLiance supplied natural gas to all of the Company’s
          regulated gas utilities.
 
 As
          part
          of a settlement agreement approved by the IURC during July 2002, the gas
          supply
          agreements with Indiana Gas and SIGECO, were approved and extended through
          March
          31, 2007. On February 1, 2006, the Company, Citizens Gas, and three consumer
          representatives, including the OUCC, filed a settlement agreement with
          the IURC
          providing for ProLiance to be the continued supplier of gas supply services
          to
          the Company’s Indiana utilities through March 2011. The settlement is subject to
          approval by the IURC. The average cost of gas per Dth purchased for the
          last
          five years was: $9.05 in 2005; $6.92 in 2004; $6.36 in 2003; $4.57 in 2002;
          and
          $5.83 in 2001.
 
 **Electric
          Utility Services**
 
 At
          December 31, 2005, the Company supplied electric service to approximately
          140,000 Indiana customers, including 121,000 residential, and 19,000 commercial,
          and 150 industrial and other customers. This represents customer base growth
          of
          0.6% compared to 2004. In addition, the Company has firm power commitments
          to
          four municipalities and has contingency reserve requirements consistent
          with
          Reliability First Corp. standards.
 
 The
          principal industries served include polycarbonate resin (Lexan®) and plastic
          products, aluminum smelting and recycling, aluminum sheet products, automotive
          assembly, steel finishing, appliance manufacturing, pharmaceutical and
          nutritional products, automotive glass, gasoline and oil products, and
          coal
          mining.
 
 **Revenues**
 
 For
          the
          year ended December 31, 2005, retail and firm wholesale electricity sales
          totaled 6,199.0 GWh, resulting in revenues of approximately $383.4 million.
          Residential customers accounted for 35% of 2005 revenues; commercial 25%;
          industrial 31%; and municipal and other 9%. In addition, the Company sold
          3,049.2 GWh through wholesale contracts in 2005, generating revenue, net
          of
          purchased power costs, of $38.0 million.
 
 **Generating
          Capacity**
 
 Installed
          generating capacity as of December 31, 2005, was rated at 1,351 MW. Coal-fired
          generating units provide 1,056 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 2005, the Company had 34 MW available
          under firm contracts and 61 MW available under interruptible contracts.
          The
          Company also had a firm purchase supply contract for a maximum of 73 MW
          for the
          peak cooling season months during 2005.
 
 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. Utility Holdings also had an interconnection agreement
          with Wabash Valley Power Association, which was cancelled effective August
          31,
          2005. However, the ability of the Company to effectively utilize the electric
          transmission grid in order to achieve import/export capability has been,
          and may
          continue to be, impacted. 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 2001 through 2005 at the time of the system
          summer
          peak, and the related reserve margin, is presented below in
          MW.
 Date
                    of summer peak load
                
                7/25/2005
                
                7/13/2004
                
                8/27/2003
                
                8/5/2002
                
                7/31/2001Total
                    load at peak(1)
                
                1,315
                
                1,222
                
                1,272
                
                1,258
                
                1,234Generating
                    capability
                
                1,351
                
                1,351
                
                1,351
                
                1,351
                
                1,271Firm
                    purchase supply
                
                107
                
                105
                
                32
                
                82
                
                82Interruptible
                    contracts
                
                76
                
                51
                
                95
                
                95
                
                95Total
                    power supply capacity
                
                1,534
                
                1,507
                
                1,478
                
                1,528
                
                1,448Reserve
                    margin at peak
                
                17%
                
                23%
                
                16%
                
                21%
                
                17%
 
 5
 Table
            of Contecnts
 (1)
              The
                  total load at peak is increased 25 MW in 2005, 2003, 2002, and
                  2001 from
                  the total load actually experienced. The additional 25 MW represents
                  load
                  that would have been incurred if summer cycler programs 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 programs were not
                  activated.
  The
        winter peak load for the 2004-2005 season of approximately 932 MW occurred
        on
        January 18, 2005. The prior year winter peak load was approximately 928 MW,
        occurring on January 20, 2004.
 
 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 2005 was fueled by coal (98.3%) and natural gas (1.7%). 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 3.6 million tons of coal were purchased for
        generating electricity during 2005, of which substantially all 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
        2001
        through 2005 follows:
 Year
                    Ended December 31,Avg.
                    Cost Per
                
                2005
                
                2004
                
                2003
                
                2002
                
                2001Ton
                
                $   
                    30.27
                
                $   
                    27.06
                
                $   
                    24.91
                
                $    23.50
                
                $    22.48MWh
                
                14.94
                
                13.06
                
                11.93
                
                11.00
                
                10.53
 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 2005 totaled
        2,253,502 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, 2005, approximately 71,000 customers in Vectren’s Ohio service
        territory purchase natural gas from a supplier other than the regulated 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.
  6
 Table
            of Contecnts
 
 **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.
 
 **Personnel**
 
 As
        of
        December 31, 2005, the Company and its consolidated subsidiaries had 1,612
        employees, of which 858 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. The agreement
        includes annual wage increases of 3.5% and market adjustments to healthcare
        and
        pensions. The agreement also provides increased flexibility in job assignments
        and work rules.
 
 In
        September 2005, the Company reached a four year agreement with Local 135
        of the
        Teamsters, Chauffeurs, Warehousemen, and Helpers Union, ending September
        2009.
        The agreement provides for annual wage increases of 3.4%, modifications to
        the
        pension and insurance plans, and increased flexibility in
        operations.
 
 In
        July
        2004, the Company reached a three year labor agreement with Local 702 of
        the
        International Brotherhood of Electrical Workers, ending June 2007.  The
        agreement provides a 3% wage increase in the first two years and a 3.5% increase
        in the third year of the agreement.  The agreement also provides for
        improvements in pension benefits and a multi-tiered health plan in which
        the
        employees pay 16% of the cost.
 
 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. The agreement provides
        for
        annual wage increases of 3%, a multi-tiered health care plan in which the
        employees pay 12% to 16% of the premium, and pension enhancements for early
        retirees.
 
 **ITEM
        1A. RISKFACTORS**
 
 Investors
          should consider carefully the following factors that could cause the Company’s
          operating results and financial condition to be materially adversely affected.
          New risks may emerge at any time, and the Company cannot predict those
          risks or
          estimate the extent to which they may affect the Company’s businesses or
          financial performance.
  **Utility
            Holdings 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, and
            capital requirements of its subsidiaries, Indiana Gas, SIGECO and VEDO,
            and the
            distribution or other payment of earnings from those subsidiaries to
            the
            Company. Should the earnings, financial condition, or capital requirements
            of,
            or legal requirements applicable to, the Company’s subsidiaries restrict the
            ability of these subsidiaries to pay dividends or make other payments
            to Utility
            Holdings, the Company’s ability to pay dividends to its parent could be
            adversely affected.
  **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.
 
 7
 Table
            of Contecnts
 **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.
 
 **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 charged, 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 Federal Energy Regulatory Commission (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 it can charge customers and the rate of return
        that
        it is allowed to realize. The Company’s ability to obtain rate increases to
        maintain its current authorized rate of return depends upon regulatory
        discretion, and there can be no assurance that Vectren will be able to obtain
        rate increases or rate supplements or earn its current authorized rate of
        return.
 
 In
        addition, its 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 ),
        and
        nitrogen oxide (NOx), among others.
 
 Environmental
        legislation also requires that facilities, sites and other properties associated
        with the Company’s operations be operated, maintained, abandoned and reclaimed
        to the satisfaction of applicable regulatory authorities. Utility Holding’
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 the Company subject to environmental regulation, its
        investment in environmentally compliant equipment has increased and is expected
        to increase in the future.
 
 From
        time
        to time, the Company 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.
 
 8
 Table
            of Contecnts
 **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.
 
 **The
        Company may experience significantly increased gas costs.**
 
 Recently,
        commodity prices for natural gas purchases have increased and have become
        more
        volatile. Subject to regulatory approval, the Company’s 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, it is possible regulators may disallow
        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.
 
 **The
        impact of MISO participation is uncertain.**
 
 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.
 
 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.
 
 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, 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.
 
 **Wholesale
        power marketing activities may add volatility to earnings.**
  The
        Company’s regulated electric utility engages in wholesale power marketing
        activities that primarily involve asset optimization strategies. These
        optimization strategies manage the utilization of available electric generating
        capacity and include the execution of energy contracts that are integrated
        with
        portfolio requirements around power supply and delivery. As part of these
        strategies, the Company will execute forward contracts and option contracts
        that
        may not result in the physical flow of electricity, but hedge, other
        commitments. While most physical forward positions to sell electricity are
        hedged with these contracts or with planned unutilized generation capability,
        the Company does not hedge its entire portfolio from market price volatility.
        To
        the extent the Company has unhedged positions or its hedging procedures do
        not
        work as planned, fluctuating prices for electricity are likely to cause its
        net
        income to be volatile and may lower its net income. Beginning in April 2005,
        substantially all physically delivered off-system sales occur into the MISO
        day-ahead market.
 
 9
 Table
            of Contecnts
 **Catastrophic
        events could adversely affect the Company’s facilities and
        operations.**
 
 Catastrophic
        events such as fires, explosions, floods, terrorist acts or other similar
        occurrences could adversely affect the Company’s facilities and operations.
  **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.
 
 The
          Company 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 the Company’s 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.
 **ITEM1B.UNRESOLVED STAFF COMMENTS**
 
 None.
  **ITEM
        2. 
PROPERTIES**
 **Gas
        Utility Services**
 
 Indiana
        Gas owns and operates four active gas storage fields located in Indiana covering
        58,130 acres of land with an estimated ready delivery from storage capability
        of
        5.6 BCF of gas with maximum peak day delivery capabilities of 145,000 MCF
        per
        day. Indiana Gas also owns and operates three liquefied petroleum (propane)
        air-gas manufacturing plants located in Indiana with the ability to store
        1.5
        million gallons of propane and manufacture for delivery 33,000 MCF of
        manufactured gas per day. In addition to its company owned storage and propane
        capabilities, Indiana Gas has contracted for 17.8 BCF of storage with a maximum
        peak day delivery capability of 299,717 MMBTU per day. Indiana Gas’ gas delivery
        system includes 12,118 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 3,079 miles of distribution and transmission mains, all of which
        are
        located in Indiana.
 
 10
 Table
            of Contecnts
 The
        Ohio
        operations own and operate three liquefied petroleum (propane) air-gas
        manufacturing plants and a cavern for propane storage, all of which are located
        in Ohio. The plants and cavern can store 7.8 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
        5,300 miles of distribution and transmission mains, all of which are located
        in
        Ohio.
  Electric
        Utility Services
 
 SIGECO's
        installed generating capacity as of December 31, 2005, was rated at 1,351
        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 three
        units of 406 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 will shut down Culley Unit
        1,
        with generating capacity of 50 MW, effective December 31, 2006.
 
 SIGECO's
        transmission system consists of 832 circuit miles of 138,000 and 69,000 volt
        lines. The transmission system also includes 28 substations with an installed
        capacity of 4,622.3 megavolt amperes (Mva). The electric distribution system
        includes 3,226 pole miles of lower voltage overhead lines and 305 trench
        miles
        of conduit containing 1,710 miles of underground distribution cable. The
        distribution system also includes 95 distribution substations with an installed
        capacity of 1,964.9 Mva and 52,211 distribution transformers with an installed
        capacity of 2,418.5 Mva.
 
 SIGECO
        owns utility property outside of Indiana approximating eight 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. LEGALPROCEEDINGS**
 
 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 investments in unconsolidated
        affiliates, 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. SUBMISSIONOF MATTERS TO VOTE OF SECURITY
        HOLDERS**
 
 No
        matters were submitted during the fourth quarter to a vote of security
        holders.
 
 11
 Table
            of Contecnts
 **PART
        II**
 
 **ITEM5. 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
        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.
 
 During
        2004, Utility Holdings paid dividends to its parent company of $20.0 million
        in
        the first quarter, $19.9 million in the second quarter, $21.1 million in
        the
        third quarter, and $19.6 million in the fourth quarter.
 
 On
        January 25, 2006, the board of directors declared an $18.7 million dividend,
        payable to Vectren on February 28, 2006.
 
 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, trade on the New York Stock
        Exchange under the symbol “AVU.” The high and low sales prices for the Company’s
        publicly traded debt security since issuance in October 2001 as reported
        on the
        New York Stock Exchange are shown in the following table for the periods
        indicated.
  Price
                  Range
              
              
              
              Price
                  Range**2005**
              
              High
              
              Low
              
              **2004**
              
              High
              
              LowFirst
                  Quarter
              
              $
              26.74
              
              $
              25.44
              
              
              First
                  Quarter
              
              $
              27.44
              
              $
              26.25Second
                  Quarter
              
              
              26.30
              
              
              25.40
              
              
              Second
                  Quarter
              
              
              27.03
              
              
              24.05Third
                  Quarter
              
              
              26.35
              
              
              25.05
              
              
              Third
                  Quarter
              
              
              26.81
              
              
              23.03Fourth
                  Quarter
              
              
              25.80
              
              
              25.00
              
              
              Fourth
                  Quarter
              
              
              27.00
              
              
              26.06
 12
 Table
            of Contecnts
  **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)*
                  
                  2005
                  
                  2004
                  
                  2003
                  
                  2002
                  
                  2001(1)**Operating
                      Data:**Operating
                      revenues
                  
                  $
                  1,781.8
                  
                  $
                  1,498.0
                  
                  $
                  1,448.8
                  
                  $
                  1,236.9
                  
                  $
                  1,328.3Operating
                      income
                  
                  
                  216.6
                  
                  
                  196.3
                  
                  
                  197.2
                  
                  
                  207.7
                  
                  
                  131.4Income
                      before cumulative effect of changein accounting principle
                  
                  
                  95.1
                  
                  
                  83.1
                  
                  
                  85.6
                  
                  
                  97.1
                  
                  
                  43.7Net
                      income
                  
                  
                  95.1
                  
                  
                  83.1
                  
                  
                  85.6
                  
                  
                  97.1
                  
                  
                  44.8**Balance
                      Sheet Data:**Total
                      assets
                  
                  $
                  3,391.2
                  
                  $
                  3,147.7
                  
                  $
                  2,925.1
                  
                  $
                  2,780.4
                  
                  $
                  2,489.3Redeemable
                      preferred stock
                  
                  
                  -
                  
                  
                  0.1
                  
                  
                  0.2
                  
                  
                  0.3
                  
                  
                  0.5Long-term
                      debt - net of current maturities& debt subject to tender
                  
                  
                  997.8
                  
                  
                  941.3
                  
                  
                  960.5
                  
                  
                  841.2
                  
                  
                  900.9Common
                      shareholder's equity
                  
                  
                  1,023.8
                  
                  
                  985.4
                  
                  
                  979.8
                  
                  
                  768.6
                  
                  
                  738.9
 (1)
              Merger
                  and integration related costs incurred for the year ended December
                  31,
                  2001 were $2.8 million. These costs relate primarily to transaction
                  costs,
                  severance and other merger and acquisition and integration activities.
                  As
                  a result of merger integration activities, management retired certain
                  information systems in 2001. Accordingly, the useful lives of these
                  assets
                  were shortened to reflect this decision, resulting in additional
                  depreciation expense of approximately $9.6 million for the year
                  ended
                  December 31, 2001. In total, merger and integration related costs
                  incurred
                  for the year ended December 31, 2001, were $12.4 million ($7.7
                  million
                  after tax).
                
                The
                  Company incurred restructuring charges of $15.0 million, ($9.3
                  million
                  after tax) relating to employee severance, related benefits and
                  other
                  employee related costs, lease termination fees related to duplicate
                  facilities, and consulting and other
                  fees.
  13
 Table
            of Contecnts
 ITEM
        7. MANAGMENTDISCUSSION 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, 2005, earnings were $95.1 million as compared to
          $83.1
          million in 2004. The 2005 results reflect the impact of a regulatory strategy
          that includes gas utility base rate increases, the recovery of pollution
          control
          investments, and a normal temperature adjustment mechanism implemented
          in its
          Indiana gas territories in October 2005, among other initiatives. Gas utility
          base rate increases added revenues of approximately $33.8 million, or $20.1
          million after tax, in 2005 compared to 2004 and $4.7 million, or $2.8 million
          after tax, in 2004 compared to 2003. Increased revenues associated with
          recovery
          of pollution control investments, net of related operating and depreciation
          expenses, increased operating income $8.7 million, or $5.2 million after
          tax, in
          2005 compared to 2004 and $6.0 million, or $3.6 million after tax, in 2004
          compared to 2003. Results for the year ended December 31 2005, also reflect
          increased margins from generation asset optimization activities. In addition
          to
          higher operating costs, depreciation expense, and unfavorable weather,
          Utility
          Holdings’ results were impacted by a $4.2 million ($2.5 million after tax)
          charge recorded pursuant to the disallowance of Ohio gas costs in 2005.
          In 2003,
          $1.1 million ($0.7 million after tax) was recorded related to this
          matter.
 
 Management
          estimates that the after tax impact of weather on the electric and gas
          utility
          businesses, including the effects of the recently implemented normal temperature
          adjustment mechanism, was unfavorable $3.2 million after tax in 2005,
          unfavorable $7.1 million after tax in 2004, and unfavorable $2.1 million
          after
          tax in 2003.
 
 The
          $2.5
          million decrease in earnings occurring in 2004 compared to 2003 was primarily
          due to the impact of unfavorable weather, estimated at $5.0 million after
          tax.
          Margin growth, offsetting the weather impact, results from the recovery
          of NOx
          related environmental expenditures, gas base rate increases implemented
          in 2004,
          and customer growth. The primary expense changes were higher depreciation
          and
          lower bad debt expense in 2003. Bad debt expense in 2003 associated with
          the
          Ohio service territory was reversed and deferred for later recovery under
          an
          uncollectible accounts expense rider.
 
 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* .
          Electric Utility margin is calculated as *Electric
          utility revenues* less *Fuel
          for electric generation* and *Purchased
          electric energy* .
          These
          measures exclude *Other
          operating expenses, Depreciation and amortization,* and *Taxes other than income taxes* ,
          which
          are included in the calculation of operating income. 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.
 
 **Margin**
 
 Margin
          generated from the sale of natural gas and electricity to residential and
          commercial customers is seasonal and impacted by weather patterns in the
          Company’s service territories. The weather impact in the Company’s Indiana gas
          utility service territories is mitigated somewhat 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. 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.
 
 14
 Table
              of Contecnts
 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)*
              
              
              
              2005
              
              2004
              
              2003Gas
                  utility revenues
              
              
              
              $  
                              1,359.7
              
              $    
                       1,126.2
              
              $                1,112.3Cost
                  of gas sold
              
              
              
              973.3
              
              778.5
              
              762.5**Total gas utility margin**
              
              
              
              $   
                     
                             386.4
              
              $ 
                         
                           347.7
              
              $                  
                  349.8Margin
                  attributed to:Residential
                  & commercial customers
              
              
              
              
              $
              333.2
              
              $
              297.7
              
              $
              302.1Industrial customers
              
              
              
              
              
              48.3
              
              
              45.7
              
              
              43.0Other customers
              
              
              
              
              
              4.9
              
              
              4.3
              
              
              4.7Sold
                  & transported volumes in MMDth attributed to:Residential
                  & commercial customers
              
              
              
              
              
              112.9
              
              
              114.5
              
              
              122.6Industrial
                  customers
              
              
              
              
              
              87.2
              
              
              85.8
              
              
              86.7**Total
                  sold & transported volumes**
              
              
              
              
              
              **200.1**
              
              
              **200.3**
              
              
              **209.3**


Gas
      utility margins were $386.4 million for the year ended December 31, 2005, an
      increase of $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 last year. Results for the year ended December 31, 2005, reflect a $4.2
      million charge for the impact of the disallowance of Ohio gas costs ordered
      by
      the PUCO. 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 of the effects of the normal temperature adjustment mechanism,
      increased margin an estimated $2.5 million compared to 2004. Though estimated
      to
      be modest to date and net of customer growth, management has seen evidence
      of
      gas customer usage declines in 2005, assumed to be driven primarily by price
      sensitivity. With the current outlook for continued high gas commodity prices,
      management expects that trend to continue and/or accelerate in 2006. The average
      cost per dekatherm of gas purchased was $9.05 in 2005, $6.92 in 2004; and $6.36
      in 2003.





Gas
        utility margins were $347.7 and $349.8 million, respectively, for the years
        ended December 31, 2004 and 2003. This represents a decrease in gas utility
        margin of $2.1 million compared to 2003. Heating weather for the year ended
        December 31, 2004, was 8% warmer than normal and 8% warmer than 2003. The
        estimated unfavorable impact on gas utility margin caused by weather was
        approximately $9.8 million compared to 2003. Indiana base rate increases
        added
        $4.7 million compared to the prior year. Also offsetting the effects of weather
        were increased late and reconnect fees, expense recovery pursuant to Ohio
        regulatory trackers, and higher revenue taxes collected from rate payers.
        Gas
        sold and transported volumes were 4% less in 2004, compared to the prior
        year.
        The decreased throughput was primarily attributable to weather.





15
 Table
          of Contecnts


Electric
      Utility Margin (Electric Utility Revenues less Fuel for Electric Generation
      and
      Purchased Electric Energy)




Electric
        Utility margin by revenue type follows:


Year
                  Ended December 31,*(In
                  millions)*
              
              2005
              
              2004
              
              2003Electric
                  utility revenues
              
              $
              421.4
              
              $
              371.3
              
              $
              335.7Fuel
                  for electric generation
              
              
              126.3
              
              
              96.1
              
              
              86.5Purchased
                  electric energy
              
              
              17.8
              
              
              20.7
              
              
              16.2**Total
                  electric utility margin**
              
              **$**
              **277.3**
              
              **$**
              **254.5**
              
              **$**
              **233.0**Margin
                  attributed to:Residential
                  & commercial customers
              
              $
              170.8
              
              $
              157.3
              
              $
              141.1Industrial
                  customers
              
              
              66.9
              
              
              63.7
              
              
              53.5Municipalities
                  & other customers
              
              
              19.8
              
              
              18.6
              
              
              20.1**Subtotal:
                  Retail & firm wholesale**
              
              **$**
              **257.5**
              
              **$**
              **239.6**
              
              **$**
              **214.7**Asset
                  optimization
              
              $
              19.8
              
              $
              14.9
              
              $
              18.3Electric
                  volumes sold in GWh attributed to:Residential
                  & commercial customers
              
              
              2,933.2
              
              
              2,830.9
              
              
              2,715.8Industrial
                  customers
              
              
              2,575.9
              
              
              2,511.2
              
              
              2,369.6Municipal
                  & other customers
              
              
              689.9
              
              
              645.9
              
              
              624.7**Total
                  retail & firm wholesale volumes sold**
              
              
              **6,199.0**
              
              
              **5,988.0**
              
              
              **5,710.1**





*Retail
      & Firm Wholesale Margin*




Electric
      retail and firm wholesale utility margin was $257.5 million for the year ended
      December 31, 2005, an increase over the prior year of $17.9 million. 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 last year.
      The estimated increase in electric margin related to weather was $4.0 million
      compared to the prior year ($3.8 million related to cooling weather and $0.2
      million related to heating weather).





Electric
      retail and firm wholesale margin was $239.6 million for the year ended December
      31, 2004. This represents a $24.9 million increase over 2003. Additional NOx
      recoveries increased margin $14.6 million in 2004. Cooling weather for the
      year
      was 12% warmer than 2003, increasing margin an estimated $2.0 million. The
      remaining increase in margin was attributable to increased small customer usage
      and increased sales to industrial customers.





*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. Substantially all of the margin
      from
      these activities is generated from 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. Beginning
      in
      April 2005, substantially all off-system sales occur into the MISO day-ahead
      market.


16
 Table
          of Contecnts





Following
      is a reconciliation of asset optimization activity:


Year
                  Ended December 31,*(In
                  millions)*
              
              2005
              
              2004
              
              2003Beginning
                  of Year Net Balance Sheet Position
              
              $
              (0.6
              )
              $
              (0.4
              )
              $
              (0.7
              )Statement
                  of Income ActivityMark-to-market
                  gains (losses) recognized
              
              
              0.5
              
              
              (1.4
              )
              
              0.7Realized
                  gains
              
              
              19.3
              
              
              16.3
              
              
              17.6**Net
                  activity in electric utility margin**
              
              
              **19.8**
              
              
              **14.9**
              
              
              **18.3**Net
                  cash received & other adjustments
              
              
              (17.9
              )
              
              (15.1
              )
              
              (18.0
              )End
                  of Year Net Balance Sheet Position
              
              $
              1.3
              
              $
              (0.6
              )
              $
              (0.4
              )


For
      the
      year ended December 31, 2005, net asset optimization margins were $19.8 million,
      which represents an increase of $4.9 million, as compared to 2004. The increase
      in margin results primarily from the timing of available capacity and mark
      to
      market gains. Net asset optimization margins decreased $3.4 million in 2004
      as
      compared to 2003 due to reduced available capacity.





In
      2005,
      the Company experienced increased availability of the generating units. The
      availability of excess capacity was reduced in 2004 by scheduled outages of
      owned generation related to the installation of environmental compliance
      equipment. Off system sales totaled 1,208.1 GWh in 2005, compared to 670.4
      GWh
      in 2004 and 739.0 GWh in 2003.





**Operating
      Expenses**





Other
      Operating





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.





Other
      operating expenses increased $8.4 million for the year ended December 31, 2004,
      compared to 2003. Expense in 2003 reflects the deferral of $4.0 million relating
      to the Ohio order allowing the Company to defer for future recovery its actual
      bad debt expense in excess of the amount provided in base rates (See Rate and
      Regulatory Matters below). Other factors contributing to the increase were
      an
      increase in environmental compliance-related expenses of $2.8 million recovered
      in rates and planned turbine maintenance of $1.9 million.





Depreciation
      & Amortization




Depreciation
      expense increased $13.5 million in 2005
      compared to 2004 and increased $9.9 million in 2004 compared to 2003.  In
      addition to depreciation on additions to plant in service, the increases were
      primarily due to incremental depreciation expense associated with environmental
      compliance equiptment additions.  Depreciation expense associated with
      environmental compliance equiptment, which is recovered in *Electric Utility
      margins*, totaled $12.1 million in 2005, $6.2 million in 2004, and $0.7
      million in 2003.  Results for 2004 include $1.8 million of lower
      depreciation due to adjustments of Ohio depreciation rates and amortization
      of
      Indiana regulatory assets.




Taxes
      Other Than Income Taxes


Taxes
      other than income taxes increased $7.0 million in 2005 compared to 2004, and
      $1.6 million in 2004 compared to 2003. These increases are primarily
      attributable to increased collections of utility receipts and excise taxes
      due
      to higher revenues.





17
 Table
          of Contecnts


**Other
      Income (Expense)**





Total
      other income (expense)-net decreased $1.4 million in 2005 compared to 2004,
      and
      increased $1.3 million during 2004 compared to 2003. Lower amounts of AFUDC
      were
      recorded in 2005 compared to 2004 and in 2004 compared to 2003 as environmental
      compliance expenditures were placed in service. Fiscal year 2003 includes
      operating losses and the write-off of investments in an entity that processed
      fly ash, totaling $4.2 million.





**Interest
      Expense**





Interest
      expense increased $2.5 million in 2005 compared to 2004. The increase was 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.





In
      November 2005, the Company completed permanent financing transactions in which
      approximately $150 million in debt and interest rate swap settlement proceeds
      were received and used to retire higher coupon long-term debt and other short
      term borrowings.





In
      the
      second half of 2003, the Company completed permanent financing transactions
      in
      which approximately $366 million in equity, debt, and hedging net proceeds
      were
      received and used to retire higher coupon long-term debt and other short term
      borrowings. The changes in interest expense in 2004 and 2003 reflect the full
      impact of that transaction.





**Income
      Taxes**





Federal
      and state income taxes increased $4.4 million in 2005 compared to 2004 due
      primarily to increased pre-tax income as compared to the prior year and
      adjustments to accruals resulting from the conclusion of state tax audits and
      other adjustments. Income taxes in 2004 were relatively consistent with 2003
      with decreased earnings offset by a slightly higher effective rate.





**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 ),
      and
      nitrogen oxide (NOx). 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.
      The Company intends to comply with all applicable governmental regulations,
      but
      will contest any regulation it deems to be unreasonable or impossible with
      which
      to comply.





Clean
      Air Act





*NOx
      SIP Call Matter*


The
      Company has taken steps to comply with Indiana’s State Implementation Plan (SIP)
      of the Clean Air Act (the Act). These steps include installing 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
      has issued orders that approve:


·
            the
                Company’s project to achieve environmental compliance by investing in
                clean coal technology;


·
            a
                total capital cost investment for this project up to $250 million
                (excluding AFUDC and administrative overheads), subject to periodic
                review
                of the actual costs incurred;


·
            a
                mechanism whereby, prior to an electric base rate case, the Company
                may
                recover 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 once the facility
                is
                placed into service.





18
 Table
          of Contecnts


Through
      December 31, 2005, capital investments approximating the level approved by
      the
      IURC have been made. The last SCR was placed into service in May, 2005. 
Related annual operating expenses, including depreciation expense, were $15.4
      million in 2005, $9.7 million in 2004 and $1.2 million in 2003. Such operating
      expenses could approximate $24 to $27 million once all installed equipment
      is
      operational for an entire year.





The
      Company has achieved timely compliance through the reduction of the Company’s
      overall NOx emissions to levels compliant with Indiana’s NOx emissions budget
      allotted by the USEPA. Therefore, the Company has recorded no accrual for
      potential penalties that may result from noncompliance.





*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.




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 its
        capital investments, which are expected to approximate $110 million, and
        related
        operating expenses through a rider mechanism. This rider mechanism will operate
        similar to the rider used to recover NOx-related capital investments and
        operating expenses. 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.
  *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.


19
 Table
          of Contecnts





Under
      the
      agreement, SIGECO committed to:


·
            either
                repower Culley Unit 1 (50 MW) with natural gas and equip it with
                SCR
                control technology for further reduction of nitrogen oxide, or cease
                operation of the unit by December 31,
                2006;


·
            operate
                the existing SCR control technology recently installed on Culley
                Unit 3
                (287 MW) year round at a lower emission rate than that currently
                required
                under the NOx SIP Call, resulting in further nitrogen oxide
                reductions;


·
            enhance
                the efficiency of the existing scrubber at Culley Units 2 and 3 for
                additional removal of sulphur dioxide
                emissions;


·
            install
                a baghouse for further particulate matter reductions at Culley Unit
                3 by
                June 30, 2007;


·
            conduct
                a Sulphuric Acid Reduction Demonstration Project as an environmental
                mitigation project designed to demonstrate an advance in pollution
                control
                technology for the reduction of sulfate emissions; and


·
            pay
                a $600,000 civil penalty.





The
      Company notified the USEPA of its intention to shut down Culley Unit 1 effective
      December 31, 2006. The Company does not believe that implementation of the
      settlement will have a material effect to its results from operations or
      financial condition. The $600,000 civil penalty was expensed and paid during
      2003 and is reflected in *Other-net* .





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, Indiana Gas, SIGECO, and others may now
      be
      required to take remedial action if certain byproducts are found above the
      regulatory thresholds at these sites.





Indiana
      Gas has 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 has 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 has
      accrued the estimated costs for further investigation, remediation, groundwater
      monitoring, and related costs for the sites. While the total costs that may
      be
      incurred in connection with addressing these sites cannot be determined at
      this
      time, 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.





Environmental
      matters related to manufactured gas plants have had no material impact on
      earnings since costs recorded to date approximate PRP and insurance settlement
      recoveries. While Indiana Gas has recorded all costs which it presently expects
      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.





In
      October 2002, the Company received a formal information request letter from
      the
      IDEM regarding five manufactured gas plants owned and/or operated by SIGECO
      and
      not currently 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 risk to human health or the environment. Follow up
      reviews have been initiated by the Company to confirm that the sites continue
      to
      pose no such risk.




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. Costs
      of remediation at the four SIGECO sites, as well as the amount of any PRP or
      insurance recoveries, cannot be determined at this time. The total costs accrued
      to date, including investigative costs, have been immaterial.





20
 Table
          of Contecnts


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.





**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 .





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.





21
 Table
          of Contecnts


Gas
      Utility Base Rate Settlements





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 new rate designs in all three territories include a larger service
      charge, which is intended to address to some extent earnings volatility related
      to weather. 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 on-going costs to comply with the Pipeline Safety
      Improvement Act of 2002 as well as the funding of conservation
      programs .





Indiana
      and Ohio Decoupling/Conservation Filings





On
      October 25, 2005, Vectren Energy Delivery of Indiana filed with the IURC for
      approval of a conservation program and a conservation adjustment rider in its
      two Indiana gas service territories. If approved, the plan outlined in the
      petition will better align the interests of the Company with its customers
      through the promotion of natural gas conservation. The petition requests the
      use
      of a tracker mechanism to recover the costs of funding the design and
      implementation of conservation efforts, such as consumer education programs
      and
      rebates for high efficiency equipment. The conservation tracker works in tandem
      with a decoupling mechanism. The decoupling mechanism would allow the Company
      to
      recover the distribution portion of its rates from residential and commercial
      customers based on the level of customer usage established in each utility’s
      last general rate case. The Company will file its evidence in March 2006 and
      a
      hearing is set for June 2006.





Similarly,
      on November 28, 2005, Vectren Energy Delivery of Ohio filed with the PUCO for
      approval of a conservation program and a conservation adjustment rider that
      would accomplish the same objectives. Discussions with interested parties are
      ongoing in both states.





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.




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, the Company, 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 the
      Company’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.





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.





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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 $4.2 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.
      That appeal is pending with briefing scheduled to be completed in February,
      2006. In addition, the Company solicited and received bids for VEDO’s gas supply
      and portfolio administration services and has selected a third party provider,
      who began providing services to VEDO on November 1, 2005, under a one year
      contract. 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 is considering whether to appeal
      that decision.





Ohio
      Uncollectible Accounts Expense Tracker





On
      December 17, 2003, the PUCO approved a request by VEDO and several other
      regulated Ohio gas utilities to establish a mechanism to recover uncollectible
      account expense outside of base rates. The tariff mechanism establishes an
      automatic adjustment procedure to track and recover these costs instead of
      providing the recovery of the historic amount in base rates. Through this order,
      VEDO received authority to defer its 2003 uncollectible accounts expense to
      the
      extent it differs from the level included in base rates. The Company estimated
      the difference to approximate $4.0 million in excess of that included in base
      rates, and reversed and deferred that amount for future recovery in 2003. In
      2005 and 2004, the Company recorded revenues of $5.1 million and $3.3 million,
      respectively, which is equal to the level of uncollectible accounts expense
      recognized for Ohio residential customers.





**United
        States Securities and Exchange Commission Inquiry into PUHCA
        Exemption**




In
      July
      2004, the Company received a letter from the SEC regarding its exempt status
      under the Public Utility Holding Company Act of 1935 (PUHCA).  The Company
      has responded fully to the SEC's letter and believes that it and its utility
      holding company subsidiary, Utility Holdings, remain entitled to exemption
      under
      Section 3(a)(1) of PUHCA.  The question of the PUHCA exemptions was mooted
      by the Energy Policy Act of 2005 (Energy Act), which repealed the Public Utility
      Holding Company Act of 1935 effective February 8, 2006.




The
      Energy Act enacts a new Public Utility Holding Company Act of 2005 (PUHCA 2005).
      Vectren and Utility Holdings, are holding companies under PUHCA 2005. Under
      PUHCA 2005, the FERC is granted authority to require holding companies and
      their
      subsidiaries to maintain certain books and records and make them available
      for
      review by FERC and state regulatory authorities to the extent relevant to the
      rates of FERC-jurisdictional public utilities and natural gas companies that
      are
      part of the holding company system. FERC has issued rules implementing PUHCA
      2005 that allow companies to seek an exemption or waiver from all or some of
      FERC’s books and records requirements. Under PUHCA 2005, the Company will be
      required to notify FERC of its status as a holding company, and, unless an
      exemption or waiver is obtained, file an annual report, maintain certain books
      and records and make them available to the FERC. Compliance with these
      requirements is not expected to materially affect the Company’s financial
      position or operations.




23
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          of Contecnts


**Critical
        Accounting Policies**
 
 Management
        is required to make judgments, assumptions, and estimates that affect the
        amounts reported in the consolidated financial statements and the related
        disclosures that conform to accounting principles generally accepted in the
        United States. Note 2 to the consolidated financial statements describes
        the
        significant accounting policies and methods used in the preparation of the
        consolidated financial statements. Certain estimates used in the financial
        statements are subjective and use variables that require judgment. These
        include
        the estimates to perform goodwill and other asset impairments tests. 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.
 
 **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 the year, and more frequently if events or circumstances
        indicate that an impairment loss has been incurred. Impairment tests are
        performed at the reporting unit level which the Company has determined to
        be
        consistent with its Gas Utility Services operating segment as identified
        in Note
        12 to the consolidated financial statements. 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 2005, 2004, and 2003 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.
 
 **Impairment
        Review of Investments**
 
 The
        Company will occasionally make equity investments in companies and notes
        receivable convertible into equity interests. When events occur that may
        cause
        one of these investments to be impaired, the Company performs an impairment
        analysis. An impairment analysis of notes receivable usually involves the
        comparison of the investment’s estimated free cash flows to the stated terms of
        the note. An impairment analysis of equity method investments involves
        comparison of the investment’s estimated fair value to its carrying amount. Fair
        value is estimated using primarily discounted cash flow analyses. Calculating
        free cash flows and fair value is subjective and requires judgment concerning
        growth assumptions, longevity of cash flows, and discount rates (for fair
        value
        calculations). As a result of such tests, a $3.9 million dollar write-off
        of
        investments in an entity that processed fly ash resulted in 2003. No impairments
        were recorded in 2005 or 2004. At December 31, 2005, the book value of any
        remaining investments is not significant.
 
 24
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            of Contecnts
 **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. 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
        these estimates are derived from 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
        including legal, finance, tax, risk management, and human resources, which
        includes charges for share-based compensation and for pension and other
        postretirement benefits not directly charged to subsidiaries. These costs
        have
        been allocated using various allocators, primarily number of employees, number
        of customers and/or revenues. 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.
 
 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
        SFAS
        87/106 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 things,
        and
        relies on actuarial estimates to assess the future potential liability and
        funding requirements of pension and postretirement plans. Vectren used the
        following weighted average assumptions to develop 2005 periodic benefit cost:
        a
        discount rate of 5.75%, an expected return on plan assets of 8.25%, a rate
        of
        compensation increase of 3.5%, and an inflation assumption of 3.5%. During
        2005,
        Vectren reduced the discount rate by 25 basis points to value the 2005 ending
        pension and postretirement obligations due to a decline in benchmark interest
        rates. In January 2005, Vectren announced the amendment of certain
        postretirement benefit plans, effective January 1, 2006. The amendment resulted
        in a decrease to both allocated and direct charge costs of approximately
        $4.0
        million, of which $3.1 million was recognized by Vectren, and almost all
        of
        which was passed through to Utility Holdings through reduced allocations
        in
        2005. Two of the unions that represent bargaining employees at the Company’s
        regulated subsidiaries have advised Vectren that it is their position that
        these
        changes are not permitted under the existing collective bargaining agreements
        which govern the relationship between the employees and the affected
        subsidiaries. With assistance from legal counsel, management has analyzed
        the
        unions’ position and continues to believe that the Company has reserved the
        right to amend the affected plans and that changing these benefits for retirees
        is not a mandatory subject of bargaining. Future changes in health care costs,
        work force demographics, interest rates, or plan changes could significantly
        affect the estimated cost of these future benefits.


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 Table
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**Impact
      of Recently Issued Accounting Guidance**


**SFAS
      No. 154**





In
      May
      2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections -
      a Replacement of APB Opinion No. 20 and FASB Statement No. 3” (SFAS 154). This
      statement changes the requirements for the accounting for and reporting of
      a
      change in accounting principle and applies to all voluntary changes in
      accounting principle and to changes required by an accounting pronouncement
      in
      the instance that the pronouncement does not include specific transition
      provisions. SFAS 154 requires retrospective application to prior periods’
financial statements of the direct effects caused by a change in accounting
      principle, unless it is impracticable to determine either the period-specific
      effects or the cumulative effect of the change. Further, changes in
      depreciation, amortization or depletion methods for long-lived, nonfinancial
      assets are to be accounted for as a change in accounting estimate affected
      by a
      change in accounting principle. SFAS 154 is effective for accounting changes
      and
      corrections made in fiscal years beginning after December 15, 2005, with early
      adoption permitted. The adoption of this standard, beginning in fiscal year
      2006, is not expected to have any material effect on the Company’s operating
      results or financial condition.





**FIN
      47**





In
      March
      2005, the FASB issued FASB Interpretation No. 47, “Accounting for Conditional
      Asset Retirement Obligations — an interpretation of FASB Statement No. 143” (FIN
      47). FIN 47 clarifies that a legal obligation to perform an asset retirement
      activity that is conditional on a future event is within SFAS 143’s scope. It
      also clarifies the meaning of the term “conditional asset retirement obligation”
as a legal obligation to perform an asset retirement activity in which the
      timing and (or) method of settlement are conditional on a future event that
      may
      or may not be within the control of the entity. Accordingly, an entity is
      required to recognize a liability for the fair value of an asset retirement
      obligation (ARO) that is conditional on a future event if the liability’s fair
      value can be estimated reasonably. The interpretation also clarifies when an
      entity would have sufficient information to reasonably estimate the fair value
      of an asset retirement obligation.





The
      Company adopted this interpretation on December 31, 2005. The primary issue
      resulting from FIN 47’s adoption was the reassessment of whether a portion of
      removal costs accrued through depreciation rates established in regulatory
      proceedings should be recharacterized as an ARO. The adoption of this
      interpretation established an approximate $16 million ARO for interim
      retirements of gas utility pipeline and utility poles and certain
      asbestos-related issues, the majority of which was already accrued as a cost
      of
      removal regulatory liability. The ARO is included in *Other
      liabilities and deferred credits* .
      Adoption also resulted in an increase to *Utility
      plant* of
      approximately $12 million. Because of the effects of regulation, the difference
      was recorded to *Regulatory
      assets and liabilities.*




**SFAS
      123 (revised 2004) and related interpretations**





In
      December 2004, the FASB issued Statement 123 (revised 2004), “Share-Based
      Payments” (SFAS 123R) that will require compensation costs related to all
      share-based payment transactions to be recognized in the financial statements.
      With limited exceptions, the amount of compensation cost will be measured based
      on the grant-date fair value of the equity or liability instruments issued.
      Compensation cost will be recognized over the period that an employee provides
      service in exchange for the award. SFAS 123R replaces SFAS 123 and supersedes
      APB 25. In April 2005, the SEC extended the effective date of SFAS 123R to
      January 1, 2006 for calendar year companies like Utility Holdings. The Company
      intends to adopt SFAS 123R using the modified prospective method. The adoption
      of this standard, and subsequent interpretations of this standard, is not
      expected to 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.





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 Table
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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, 2005, totaled $700.0 million and $226.9 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,
        SIGECO
        and Indiana Gas, at December 31, 2005, 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. Standard and
        Poor’s revised its current outlook to stable from negative in January 2005 and
        in March 2005 revised SIGECO’s secured debt rating to A from A- and its
        unsecured debt to A- from BBB+. 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 49% and 51% of long-term
        capitalization at December 31, 2005, and 2004, respectively. Long-term
        capitalization includes long-term debt, including current maturities and
        debt
        subject to tender, as well as common shareholder’s equity and any outstanding
        preferred stock.
 
 In
        the
        fourth quarter of 2005, the Company issued $150 million of long-term debt,
        taking advantage of favorable long-term debt capital markets. Proceeds from
        the
        issuance, net of those used to retire called debt, converted approximately
        $100
        million of short-term debt to long-term. This short-term debt had been incurred
        primarily to support the Company’s capital expenditure programs. In addition to
        permanently financing these long-lived assets, the issuance of new long-term
        debt improved the Company’s liquidity position allowing additional capacity on
        its credit lines to meet expected working capital requirements for 2006 and
        beyond. Resulting primarily from this issuance, the equity component of
        long-term capitalization decreased 2% at December 31, 2005, compared to
        2004.
 
 The
        Company expects the majority of its capital expenditures, investments, and
        debt
        security redemptions to be provided by internally generated funds. However,
        due
        to significant capital expenditures, the Company may require additional
        long-term financing.




**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. Cash flow from operating
        activities increased $32.9 million during 2005 as compared to 2004 and $63.5
        million during 2004, compared to 2003.  Increased cash flow from operating
        activities is due to both increased earnings before noncash charges and less
        cash utilized to support working capital increases.  Earnings before
        noncash charges was $289.2 million in 2005, $269.2 million in 2004, and
        $242.3 milion in 2003.  Cash utilized for working capital increases was
        $13.0 million in 2005, $24.4 million in 2004, and $64.0 million in
        2003.


27
 Table
          of Contecnts


Financing
      Cash Flow





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




Cash
        flow
        required for financing activities reflects the impact of long-term financing
        arrangements executed in 2005 and 2003. In 2005, Utility Holdings issued
        $150
        million of senior unsecured securities and received an additional capital
        contribution from Vectren totaling $20.0 million. Utility Holdings used those
        proceeds to retire higher coupon long-term debt and refinance certain capital
        projects originally financed with short-term borrowings. Cash flow provided
        by
        financing activities in 2003 includes the effects of long-term financing
        in
        which approximately $407 million in capital contributions from Vectren, third
        party debt proceeds, and hedging net proceeds were received and used to retire
        higher coupon long-term debt and other short term borrowings.


*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. In addition, they 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 on 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.





*Utility
      Holdings 2003 Debt Issuance*


In
      July
      2003, Utility Holdings issued senior unsecured notes with an aggregate principal
      amount of $200 million in two $100 million tranches. The first tranche was
      10-year notes due August 2013, with an interest rate of 5.25% priced at 99.746%
      to yield 5.28% to maturity (2013 Notes). The second tranche was 15-year notes
      due August 2018 with an interest rate of 5.75% priced at 99.177% to yield 5.80%
      to maturity (2018 Notes).





The
      notes
      are guaranteed by the Utility Holdings’ three public utilities: SIGECO, Indiana
      Gas, and VEDO. These guarantees are full and unconditional and joint and
      several. In addition, they 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 2013 Notes and 25
      basis points for the 2018 Notes.





Shortly
      before these issues, Utility Holdings entered into several treasury locks with
      a
      total notional amount of $150 million. Upon issuance of the debt, the treasury
      locks were settled resulting in the receipt of $5.7 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 issues.





28
 Table
          of Contecnts


The
      net
      proceeds from the sale of the senior notes and settlement of related hedging
      arrangements approximated $203 million and were used refinance certain capital
      projects originally financed with short-term borrowings and to retire long-term
      debt with higher interest rates.





*Additional
        Capital Contributions*
 During
        the years ended December 31, 2005, 2004, and 2003, the Company has cumulatively
        received additional capital of $227.2 million from Vectren. Of that total,
        Vectren generated $163.2 million from issuances of its common stock, $55.0
        million was funded by Vectren’s nonregulated operations, and $9.0 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 remarketed. During 2005, no debt was put to the Company. In
      2004,
      and 2003, debt totaling $2.5 million, and $0.1 million, respectively, 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.





*SIGECO
      and Indiana Gas Debt Calls*


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 2005 and 2004 had stated interest rates of 7.45% and 7.15%,
      respectively.




During
      2003, the Company called two first mortgage bonds outstanding at SIGECO and
      two
      senior unsecured notes outstanding at Indiana Gas. The first SIGECO bond had
      a
      principal amount of $45.0 million, an interest rate of 7.60%, was originally
      due
      in 2023, and was redeemed at 103.745% of its stated principal amount. The second
      SIGECO bond had a principal amount of $20.0 million, an interest rate of 7.625%,
      was originally due in 2025, and was redeemed at 103.763% of the stated principal
      amount.





The
      first
      Indiana Gas note had a remaining principal amount of $21.3 million, an interest
      rate of 9.375%, was originally due in 2021, and was redeemed at 105.525% of
      the
      stated principal amount. The second Indiana Gas note had a principal amount
      of
      $13.5 million, an interest rate of 6.75%, was originally due in 2028, and was
      redeemed at the principal amount.





Pursuant
      to regulatory authority, the premiums paid to retire these notes totaling $3.6
      million were deferred as a *Regulatory
      asset* .





*Other
      Financing Transactions*





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 and reissuance
      of
      debt at generally the same par value.





Other
      Company debt totaling $15.0 million in 2004 and $18.5 million in 2003 was
      retired as scheduled.





Investing
      Cash Flow





Cash
        flow
        required for investing activities was $217.7 million in 2005, $242.7 million
        in
        2004, and $236.3 million in 2003. Capital expenditures are the primary component
        of investing activities. Capital expenditures were $217.8 million in 2005
        compared to $246.2 million in 2004, and $235.2 million in 2003. Expenditures
        in
        2005, 2004 and 2003 include approximately $250.0 million in expenditures
        for
        environmental compliance equipment. These expenditures are the primary reason
        for the changes in capital expenditures over the years
        presented.


29
 Table
          of Contecnts


**Available
      Sources of Liquidity**





At
      December 31, 2005, the Company has $520.0 million of short-term borrowing
      capacity, of which approximately $293.0 million is available.




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 common shares to satisfy dividend reinvestment plan and stock option
      plan requirements and contributes these proceeds to Utility Holdings. 
During 2004 and 2003, these new issuances added additional liquidity of $3.1
      million and $5.9 million, respectively.




**Potential
      & Future Uses of Liquidity**




Contractual
        Obligations


The
      following is a summary of contractual obligations at December 31,
      2005:


*(In
                  millions)*
              
              2006
              
              2007
              
              2008
              
              2009
              
              2010
              
              ThereafterLong-term
                  debt(1)
              
              $
              -
              
              $
              6.5
              
              $
              -
              
              $
              -
              
              $
              -
              
              $
              1049.2Short-term
                  debt
              
              
              226.9
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -Long-term
                  debt interest commitments
              
              
              64.9
              
              
              64.8
              
              
              64.5
              
              
              64.5
              
              
              64.5
              
              
              668.2Utility
                  & nonutility plant purchase commitments(2)
              
              
              13.0
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -Total
              
              $
              304.8
              
              $
              71.3
              
              $
              64.5
              
              $
              64.5
              
              $
              64.5
              
              $
              1717.4


(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 2005 (in millions) is $53.7 in 2006, $20.0 in 2007,
                zero
                in 2008, $80.0 in 2009, $10.0 in 2010 and $30.0
                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 implications 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 2006 - 2010 are estimated
        as follows (in millions): $245.8 in 2006, $292.1 in 2007, $358.4 in 2008,
        $319.1
        in 2009, and $244.5 in 2010.
 
 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 Company contributions of approximately $5 million in 2006
        and
        approximately $15 million in 2007. Utility Holdings may be called upon to
        fund a
        portion of these contributions. During 2005, Vectren made contributions of
        $3.7
        million, of which $2.5 million was 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
                or regulatory accounting principles or policies imposed by the Financial
                Accounting Standards Board; the Securities and Exchange Commission;
                the
                Federal Energy Regulatory Commission; state public utility commissions;
                state entities which regulate electric and natural gas transmission
                and
                distribution, natural gas gathering and processing, electric power
                supply;
                and similar entities with regulatory
                oversight.*


*·*
            *Economic
                conditions including the effects of an economic downturn, inflation
                rates,
                commodity prices, and monetary fluctuations.*


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


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


*·*
            *The
                performance of projects undertaken by the Company’s nonregulated
                businesses and the success of efforts to invest in and develop new
                opportunities, including but not limited to, the realization of Section
                29
                income tax credits and the Company’s coal mining, gas marketing, and
                broadband strategies.*


*·*
            *Direct
                or indirect effects on the Company’s business, financial condition or
                liquidity resulting from a****change
                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, 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 legislature 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
 Table
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**ITEM7A. QUALITATIVEAND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK**





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





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





**Commodity
      Price Risk**





Regulated
      Operations


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





Recently,
      commodity prices for natural gas purchases have increased and have become 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
      and Other Operations


The
      Company’s wholesale power marketing activities include asset optimization
      strategies that manage the utilization of available electric generating
      capacity. Execution of asset optimization strategies require entering into
      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.
      In
      addition, the Company may purchase tailored products to mitigate unique risks
      involving SO 2 emission
      allowances, as an example.


Sales
        to
        certain municipalities and large industrial customers are executed pursuant
        to
        customer demand. Price risk from forward positions obligating the Company
        to
        deliver electricity 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.
 
 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 years ended December 31, 2005, and
        2004,
        a 10% adverse change in forward commodity prices would have decreased earnings
        by $0.3 million and $0.7 million, respectively, based upon open positions
        existing on the last day of those years.




32
 Table
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**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
        short-term interest 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, 2005,
        debt
        subject to short-term interest rate volatility as affected by seasonal increases
        in short-term debt outstanding, represented 20% 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 2005 and 2004, the weighted average combined
        borrowings under these arrangements were $225.9 million and $142.7 million,
        respectively. At December 31, 2005, and 2004, combined borrowings under these
        arrangements were $259.3 million and $340.7 million, respectively. Based
        upon
        average borrowing rates under these facilities during the years ended December
        31, 2005 and 2004, an increase of 100 basis points (one percentage point)
        in the
        rates would have increased interest expense by $2.3 million and $1.4 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.
  33
 Table
            of Contecnts


**ITEM8.**  **FINANCIALSTATEMENTS
        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, 2005. Management certified this fact in its
        Sarbanes Oxley Section 302 certifications, which are attached as exhibits
        to
        this 2005 Form 10-K.
  34
 Table
            of Contecnts
 **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, 2005 and
        2004, 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,
        2005. Our audits also included the financial statement schedules listed in
        the
        Index at Item 15. These financial statements and financial statement schedules
        are the responsibility of the Company's management. Our responsibility is
        to
        express an opinion on the financial statements and financial statement schedules
        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, 2005 and 2004, and the results of their
        operations and their cash flows for each of the three years in the period
        ended
        December 31, 2005, in conformity with accounting principles generally accepted
        in the United States of America. Also, in our opinion, such financial statement
        schedules, 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, 2006





35
 Table
            of Contecnts


**VECTREN
        UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES**
 **CONSOLIDATED
        BALANCE SHEETS**
 ***(In
        millions)***
 
 
 At
                    December 31,2005
                
                2004**ASSETS**Current
                    AssetsCash
                    & cash equivalents
                
                $
                11.7
                
                $
                5.7Accounts
                    receivable - less reserves of $2.6 &$1.9,
                    respectively
                
                
                170.7
                
                
                146.5Receivables
                    due from other Vectren companies
                
                
                2.2
                
                
                4.0Accrued
                    unbilled revenues
                
                
                212.5
                
                
                161.2Inventories
                
                
                126.2
                
                
                58.1Recoverable
                    fuel & natural gas costs
                
                
                15.4
                
                
                17.7Prepayments
                    & other current assets
                
                
                117.2
                
                
                134.1**Total
                    current assets**
                
                
                **655.9**
                
                
                **527.3**Utility
                    PlantOriginal cost
                
                
                3,632.0
                
                
                3,465.2Less: accumulated depreciation & amortization
                
                
                1,380.1
                
                
                1,309.0**Net
                    utility plant**
                
                
                **2,251.9**
                
                
                **2,156.2**Investments
                    in unconsolidated affiliates
                
                
                0.2
                
                
                0.2Other
                    investments
                
                
                21.0
                
                
                19.6Non-utility
                    property - net
                
                
                160.0
                
                
                149.6Goodwill
                    - net
                
                
                205.0
                
                
                205.0Regulatory
                    assets
                
                
                89.9
                
                
                82.5Other
                    assets
                
                
                7.3
                
                
                7.3**TOTAL
                    ASSETS**
                
                **$**
                **3,391.2**
                
                **$**
                **3,147.7**
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 *The
        accompanying notes are an integral part of these consolidated financial
        statements.*
  36
 Table
            of Contecnts
  **VECTREN
        UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES**
 **CONSOLIDATED
        BALANCE SHEETS**
 ***(In
        millions)***
 
 
 At
                    December 31,2005
                
                2004**LIABILITIES
                    & SHAREHOLDER'S EQUITY**Current
                    LiabilitiesAccounts
                    payable
                
                $
                131.9
                
                $
                97.3Accounts
                    payable to affiliated companies
                
                
                140.6
                
                
                98.8Payables
                    to other Vectren companies
                
                
                29.2
                
                
                15.8Refundable
                    fuel & natural gas costs
                
                
                7.6
                
                
                6.3Accrued
                    liabilities
                
                
                130.4
                
                
                110.0Short-term
                    borrowings
                
                
                226.9
                
                
                308.3Long-term
                    debt subject to tender
                
                
                53.7
                
                
                10.0**Total
                    current liabilities**
                
                
                **720.3**
                
                
                **646.5**Long-Term
                    Debt - Net of Current Maturities &Debt
                    Subject to Tender
                
                
                997.8
                
                
                941.3Deferred
                    Income Taxes & Other LiabilitiesDeferred
                    income taxes
                
                
                275.5
                
                
                240.8Regulatory
                    liabilities
                
                
                272.9
                
                
                251.7Deferred
                    credits & other liabilities
                
                
                100.9
                
                
                81.9**Total
                    deferred credits & other liabilities**
                
                
                **649.3**
                
                
                **574.4**Commitments
                    & Contingencies (Notes 8 - 10)Cumulative,
                    Redeemable Preferred Stock of a Subsidiary
                
                
                -
                
                
                0.1Common
                    Shareholder's EquityCommon
                    stock (no par value)
                
                
                612.9
                
                
                592.9Retained
                    earnings
                
                
                406.9
                
                
                392.5Accumulated
                    other comprehensive income
                
                
                4.0
                
                
                -**Total
                    common shareholder's equity**
                
                
                **1,023.8**
                
                
                **985.4****TOTAL
                    LIABILITIES & SHAREHOLDER'S EQUITY**
                
                **$**
                **3,391.2**
                
                **$**
                **3,147.7**
 
 
 
 
 
 
 
 
 
 
 
 
 *The
        accompanying notes are an integral part of these consolidated financial
        statements.*
 37
 Table
            of Contecnts
  **VECTREN
        UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES**
 **CONSOLIDATED
        STATEMENTS OF INCOME**
 ***(In
        millions)***
 
 
 
 Year
                    Ended December 31,2005
                
                2004
                
                2003OPERATING
                    REVENUESGas
                    utility
                
                $
                1,359.7
                
                $
                1,126.2
                
                $
                1,112.3Electric
                    utility
                
                
                421.4
                
                
                371.3
                
                
                335.7Other
                
                
                0.7
                
                
                0.5
                
                
                0.8**Total
                    operating revenues**
                
                
                **1,781.8**
                
                
                **1,498.0**
                
                
                **1,448.8**OPERATING
                    EXPENSESCost
                    of gas sold
                
                
                973.3
                
                
                778.5
                
                
                762.5Fuel
                    for electric generation
                
                
                126.3
                
                
                96.1
                
                
                86.5Purchased
                    electric energy
                
                
                17.8
                
                
                20.7
                
                
                16.2Other
                    operating
                
                
                241.3
                
                
                220.4
                
                
                211.9Depreciation
                    & amortization
                
                
                141.3
                
                
                127.8
                
                
                117.9Taxes
                    other than income taxes
                
                
                65.2
                
                
                58.2
                
                
                56.6Total
                    operating expenses
                
                
                1,565.2
                
                
                1,301.7
                
                
                1,251.6**OPERATING
                    INCOME**
                
                
                **216.6**
                
                
                **196.3**
                
                
                **197.2**OTHER
                    INCOME (EXPENSE)Other
                    - net
                
                
                5.9
                
                
                7.1
                
                
                6.6Equity
                    in earnings (losses) of unconsolidated affiliates
                
                
                -
                
                
                0.2
                
                
                (0.5
                )Total
                    other income
                
                
                5.9
                
                
                7.3
                
                
                6.1Interest
                    expense
                
                
                69.9
                
                
                67.4
                
                
                66.1**INCOME
                    BEFORE INCOME TAXES**
                
                
                **152.6**
                
                
                **136.2**
                
                
                **137.2**Income
                    taxes
                
                
                57.5
                
                
                53.1
                
                
                51.6**NET
                    INCOME**
                
                **$**
                **95.1**
                
                **$**
                **83.1**
                
                **$**
                **85.6**
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 *The
        accompanying notes are an integral part of these consolidated financial
        statements.*
  38
 Table
            of Contecnts
   **VECTREN
        UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES**
 **CONSOLIDATED
        STATEMENTS OF CASH FLOWS**
 ***(In
        millions)***
 
 Year
                    Ended December 31,2005
                
                2004
                
                2003CASH
                    FLOWS FROM OPERATING ACTIVITIESNet
                    income
                
                $
                95.1
                
                $
                83.1
                
                $
                85.6Adjustments
                    to reconcile net income to cash from operating activities:Depreciation
                    & amortization
                
                
                141.3
                
                
                127.8
                
                
                117.9Deferred
                    income taxes & investment tax credits
                
                
                33.1
                
                
                43.0
                
                
                24.1Expense
                    portion of pension & postretirement periodic benefit cost
                
                
                4.0
                
                
                4.1
                
                
                4.2Provision
                    for uncollectible accounts
                
                
                14.4
                
                
                10.7
                
                
                12.2Other
                    non-cash charges - net
                
                
                1.3
                
                
                0.5
                
                
                (1.7
                )Changes
                    in working capital accounts:Accounts
                    receivable, including to Vectren companies&
                    accrued unbilled revenue
                
                
                (88.1
                )
                
                (78.0
                )
                
                44.3Inventories
                
                
                (68.2
                )
                
                (3.5
                )
                
                0.9Recoverable
                    fuel & natural gas costs
                
                
                3.6
                
                
                8.9
                
                
                (1.0
                )Prepayments
                    & other current assets
                
                
                23.3
                
                
                (2.9
                )
                
                (49.1
                )Accounts
                    payable, including to Vectren companies&
                    affiliated companies
                
                
                100.7
                
                
                37.9
                
                
                (69.1
                )Accrued
                    liabilities
                
                
                15.7
                
                
                13.2
                
                
                10.0Changes
                    in noncurrent assets
                
                
                (8.4
                )
                
                (1.9
                )
                
                (5.9
                )Changes
                    in noncurrent liabilities
                
                
                (2.0
                )
                
                (10.0
                )
                
                (3.0
                )**Net
                    cash flows from operating activities**
                
                
                **265.8**
                
                
                **232.9**
                
                
                **169.4**CASH
                    FLOWS FROM FINANCING ACTIVITIESProceeds
                    from:Long-term
                    debt - net of issuance costs & hedging proceeds
                
                
                150.0
                
                
                32.4
                
                
                202.9Additional
                    capital contribution
                
                
                20.0
                
                
                3.1
                
                
                204.1Requirements
                    for:Dividends
                    to parent
                
                
                (80.7
                )
                
                (80.6
                )
                
                (78.0
                )Retirement
                    of long-term debt, including premiums paid
                
                
                (49.9
                )
                
                (70.5
                )
                
                (121.9
                )Redemption
                    of preferred stock of subsidiary
                
                
                (0.1
                )
                
                (0.1
                )
                
                (0.1
                )Net
                    change in short-term borrowings, including from otherVectren
                    companies
                
                
                (81.4
                )
                
                123.1
                
                
                (140.8
                )Other
                    activity
                
                
                -
                
                
                -
                
                
                (1.7
                )**Net
                    cash flows from financing activities**
                
                
                **(42.1**
                **)**
                
                **7.4**
                
                
                **64.5**CASH
                    FLOWS FROM INVESTING ACTIVITIESProceeds
                    from other investing activities
                
                
                0.1
                
                
                3.5
                
                
                -Requirements
                    for:Capital
                    expenditures, excluding AFUDC equity
                
                
                (217.8
                )
                
                (246.2
                )
                
                (235.2
                )Unconsolidated
                    affiliate & other investments
                
                
                -
                
                
                -
                
                
                (1.1
                )**Net
                    cash flows from investing activities**
                
                
                **(217.7**
                **)**
                
                **(242.7**
                **)**
                
                **(236.3**
                **)**Net
                    (decrease) increase in cash & cash equivalents
                
                
                6.0
                
                
                (2.4
                )
                
                (2.4
                )Cash
                    & cash equivalents at beginning of period
                
                
                5.7
                
                
                8.1
                
                
                10.5Cash
                    & cash equivalents at end of period
                
                $
                11.7
                
                $
                5.7
                
                $
                8.1Cash
                    paid during the year for:Interest
                
                $
                65.9
                
                $
                65.0
                
                $
                60.7Income
                    taxes
                
                
                43.3
                
                
                6.1
                
                
                52.2
 
 
 *The
        accompanying notes are an integral part of these consolidated financial
        statements.*
  39
 Table
            of Contecnts
   **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, 2003
                
                $
                385.7
                
                $
                382.4
                
                $
                0.5
                
                $
                768.6Comprehensive
                    income:Net
                    income
                
                
                
                
                
                85.6
                
                
                
                
                
                85.6Cash
                    flow hedges - net of tax
                
                
                
                
                
                
                
                
                (0.5
                )
                
                (0.5
                )Total
                    comprehensive income
                
                
                
                
                
                
                
                
                
                
                
                85.1Common
                    stock:Additional
                    capital contribution
                
                
                204.1
                
                
                
                
                
                
                
                
                204.1Dividends
                
                
                
                
                
                (78.0
                )
                
                
                
                
                (78.0
                )**Balance
                    at December 31, 2003**
                
                
                **589.8**
                
                
                **390.0**
                
                
                **-**
                
                
                **979.8**Net
                    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 hedges - net of tax
                
                
                
                
                
                
                
                
                4.0
                
                
                4.0Total
                    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**
 
 
 
 
 
 
 
 
 
 
 
 
 
 *The
        accompanying notes are an integral part of these consolidated financial
        statements.*


40
 Table
          of Contecnts


**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 and
        applied
        technology holding company headquartered in Evansville, Indiana. Both Vectren
        and Utility Holdings are 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 562,000 natural gas
        customers located in central and southern Indiana. SIGECO provides energy
        delivery services to approximately 140,000 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)*
                
                2005
                
                2004Gas
                    in storage – at average cost (See Note 4)
                
                $
                63.3
                
                $
                -Materials
                    & supplies
                
                
                29.9
                
                
                27.3Gas
                    in storage – at LIFO cost
                
                
                18.8
                
                
                18.9Fuel
                    (coal & oil) for electric generation
                
                
                14.1
                
                
                8.8Other
                
                
                0.1
                
                
                3.1**Total
                    inventories**
                
                **$**
                **126.2**
                
                **$**
                **58.1**
  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, 2005, and 2004,
      by approximately $117.0 million and $56.4 million, respectively. Gas in storage
      of the Indiana regulated operations is stated at LIFO. All other inventories
      are
      carried at average cost.





41
 Table
          of Contecnts


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
                  December 31,*(In
                  millions)*
              20052004Original
                  Cost
              
              Depreciation
                Rates
                  as a
                Percent
                  of
                Original
                  Cost
              
              Original
                  Cost
              
              Depreciation
                Rates
                  as a
                Percent
                  of
                Original
                  CostGas
                  utility plant
              
              $
              1,879.1
              
              
              3.5
              %
              $
              1,793.6
              
              
              3.5
              %Electric
                  utility plant
              
              
              1,611.4
              
              
              3.7
              %
              
              1,458.1
              
              
              3.6
              %Common
                  utility plant
              
              
              44.2
              
              
              2.6
              %
              
              44.2
              
              
              2.7
              %Construction
                  work in progress
              
              
              97.3
              
              
              -
              
              
              169.3
              
              
              -**Total
                  original cost**
              
              **$**
              **3,632.0**
              
              
              
              
              **$**
              **3,465.2**





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)*
              
              2005
              
              2004
              
              2003AFUDC
                  – borrowed funds
              
              $
              1.6
              
              $
              1.6
              
              $
              2.1AFUDC
                  – equity funds
              
              
              0.3
              
              
              1.6
              
              
              2.9**Total
                  AFUDC**
              
              **$**
              **1.9**
              
              **$**
              **3.2**
              
              **$**
              **5.0**


Maintenance
      and repairs, including the cost of removal of minor items of property and
      planned major maintenance projects, are charged to expense as incurred. When
      property that represents a retirement unit is replaced or removed, the remaining
      historical value of such property is charged to *Utility
      plant* ,
      with an
      offsetting charge to *Accumulated
      depreciation* .
      Costs
      to dismantle and remove retired property are recovered through the depreciation
      rates identified above.





Jointly
      Owned Plant


SIGECO
      and Alcoa Generating Corporation (AGC), a subsidiary of ALCOA, own the 270
      MW
      Unit 4 at the Warrick Power Plant as tenants in common. SIGECO's share of the
      cost of this unit at December 31, 2005 is $63.2 million with accumulated
      depreciation totaling $40.2 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.
            Non-utility
                Property


*Non-utility
      property* ,
      net of
      accumulated depreciation and amortization follows:




At
                    December 31,*(In
                    millions)*
                
                2005
                
                2004Computer
                    hardware and software
                
                $
                103.3
                
                $
                102.1Land
                    & buildings
                
                
                43.5
                
                
                37.2All
                    other
                
                
                13.2
                
                
                10.3**Non-utility
                    property - net**
                
                **$**
                **160.0**
                
                **$**
                **149.6**


42
 Table
          of Contecnts


The
      depreciation of non-utility property is charged against income over its
      estimated useful life (ranging from 5 to 40 years), using the straight-line
      method of depreciation or units-of-production method of amortization. Repairs
      and maintenance, which are not considered improvements and do not extend the
      useful life of the non-utility property, are charged to expense as incurred.
      When non-utility property is retired, or otherwise disposed of, the asset and
      accumulated depreciation are removed, and the resulting gain or loss is
      reflected in income. Non-utility property is presented net of accumulated
      depreciation and amortization totaling $92.7 million and $73.3 million as of
      December 31, 2005, and 2004, respectively. For the years ended December 31,
      2005, 2004, and 2003, the Company capitalized interest totaling $0.4 million,
      $1.4 million, and $0.9 million, respectively, on non-utility plant construction
      projects.


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),
        which the Company adopted on January 1, 2002. 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 the evaluation for
        impairment involve the comparison of an asset’s carrying value to the estimated
        future cash flows 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). The Company adopted SFAS
        142 on January 1, 2002. 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, 2005, 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, “Accounting for Asset Retirement Obligations” (SFAS 143) requires entities
        to record the fair value of a liability for a legal asset retirement obligation
        (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. The Company adopted this statement on
        January
        1, 2003. The adoption was not material to the Company’s results of
        operations.
 
 In
        March
        2005, the FASB issued FASB Interpretation No. 47, “Accounting for Conditional
        Asset Retirement Obligations — an interpretation of FASB Statement No. 143” (FIN
        47). FIN 47 clarifies that a legal obligation to perform an asset retirement
        activity that is conditional on a future event is within SFAS 143’s scope. It
        also clarifies the meaning of the term “conditional asset retirement obligation”
as a legal obligation to perform an asset retirement activity in which the
        timing and (or) method of settlement are conditional on a future event that
        may
        or may not be within the control of the entity. Accordingly, an entity is
        required to recognize a liability for the fair value of an ARO that is
        conditional on a future event if the liability’s fair value can be estimated
        reasonably. The interpretation also clarifies when an entity would have
        sufficient information to reasonably estimate the fair value of an asset
        retirement obligation.
 
 The
        Company adopted this interpretation on December 31, 2005. The primary issue
        resulting from FIN 47’s adoption was the reassessment of whether a portion of
        removal costs accrued through depreciation rates established in regulatory
        proceedings should be recharacterized as an ARO. The adoption of this
        interpretation established an approximate $16 million ARO for interim
        retirements of gas utility pipeline and utility poles and certain
        asbestos-related issues. The ARO is included in *Other
        liabilities and deferred credits* .
        Adoption also resulted in an increase to *Utility
        plant* of
        approximately $12 million. Because of the effects of regulation, the difference
        was recorded to *Regulatory
        assets and liabilities.*
 
 43
 Table
            of Contecnts
 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).


*Regulatory
      Assets and Liabilities*


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 rate-making process. Regulatory assets represent probable
      future revenues associated with certain incurred costs, which will be recovered
      from customers through the rate-making process. The Company assesses the
      recoverability of costs recognized as regulatory assets 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.





*Regulatory
      liabilities* consist
      of the following:





At
                  December 31,*(In
                  millions)*
              
              2005
              
              2004Future
                  amounts recoverable from ratepayers:Income
                  taxes
              
              $
              11.1
              
              $
              11.5Asset
                  retirement obligations & other
              
              
              1.7
              
              
              1.012.8
              
              
              12.5Amounts
                  deferred for future recovery:Demand
                  side management programs
              
              
              26.7
              
              
              25.9MISO-related
                  costs
              
              
              9.4
              
              
              3.1Other
              
              
              3.0
              
              
              4.239.1
              
              
              33.2Amounts
                  currently recovered through base rates:Unamortized
                  debt issue costs
              
              
              20.2
              
              
              20.4Premiums
                  paid to reacquire debt
              
              
              6.5
              
              
              7.0Demand
                  side management programs & other
              
              
              3.7
              
              
              3.530.4
              
              
              30.9Amounts
                  currently recovered through tracking mechanisms:Ohio
                  authorized trackers
              
              
              5.6
              
              
              6.3Indiana
                  authorized trackers
              
              
              2.0
              
              
              (0.4
              )7.6
              
              
              5.9**Total
                  regulatory assets**
              
              **$**
              **89.9**
              
              **$**
              **82.5**




Of
        the
        $30.4 million currently being recovered through base rates charged to customers,
        $28.6 million is earning a return. The weighted average recovery period of
        regulatory assets currently being recovered is 13.6 years. The Company has
        rate
        orders for all deferred costs not yet in rates and therefore believes that
        future recovery is probable.





44
 Table
          of Contecnts


*Regulatory
        liabilities* consist
        of the following:


At
                  December 31,*(In
                  millions)*
              
              2005
              
              2004Cost
                  of removal
              
              $
              251.4
              
              $
              246.2Asset
                  retirement obligation timing difference
              
              
              11.6
              
              
              -Interest
                  rate hedging proceeds (See Note 10)
              
              
              6.8
              
              
              5.5MISO-related
                  costs
              
              
              3.1
              
              
              -**Total
                  regulatory liabilities**
              
              **$**
              **272.9**
              
              **$**
              **251.7**




*Cost
        of Removal*
 The
        Company collects an estimated cost of removal of its utility plant through
        depreciation rates established by regulatory proceedings. The Company records
        amounts expensed in advance of payments as a regulatory liability because
        the
        liability does not meet the threshold of a legal asset retirement obligation
        (ARO) as defined by SFAS No. 143




*Refundable
      or Recoverable Gas Costs, Fuel for Electric Production & 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.


J.
            Comprehensive
                Income


Comprehensive
        income is a measure of all changes in equity that result from the transactions
        or other economic events during the period from non-shareholder transactions.
        This information is reported in the Consolidated Statements of Common
        Shareholder’s Equity. A summary of the components of and changes in *Accumulated
        other comprehensive income* for the
        past three years follows:


2003
              
              2004
              
              2005Beginning
              
              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
              
              
              0.8
              
              
              (0.8
              )
              
              -
              
              
              -
              
              
              -
              
              
              6.7
              
              
              6.7Deferred
                  income taxes
              
              
              (0.3
              )
              
              0.3
              
              
              -
              
              
              -
              
              
              -
              
              
              (2.7
              )
              
              (2.7
              )**Accumulated
                  other**
                **comprehensive
                  income (loss)**
              
              **$**
              **0.5**
              
              **$**
              **(0.5**
              **)**
              **$**
              **-**
              
              **$**
              **-**
              
              **$**
              **-**
              
              **$**
              **4.0**
              
              **$**
              **4.0**




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.




45
 Table
          of Contecnts


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 $42.6 million in 2005, $38.3 million in
      2004, and $37.1 million in 2003. Excise and utility receipts taxes expensed
      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.
 
 P.
            Reclassifications Certain
        amounts included in prior years’ consolidated balance sheet and the consolidated
        statements of income and cash flows have been reclassified to conform to
        the
        current year presentation. These reclassifications had no effect on reported
        total assets, liabilities, shareholders’ equity, or net income.




**3.**
            **Transactions
                with Other Vectren Companies** 
 Support
        Services and Purchases
 Vectren
        provides corporate and general and administrative services to the Company
        including legal, finance, tax, risk management, human resources, which includes
        charges for restricted stock compensation and for pension and other
        postretirement benefits not directly charged to subsidiaries. These costs
        have
        been allocated using various allocators, primarily number of employees, number
        of customers and/or revenues. Allocations are based on cost. Utility Holdings
        received corporate allocations totaling $48.0 million, $44.5 million, and
        $43.4
        million for the years ended December 31, 2005, 2004, and 2003, 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, 2005, 2004, and 2003, totaled
        $96.4 million, $79.0 million, and $77.0 million, respectively.
 
 Retirement
        Plans and Other Postretirement Benefits
 Vectren
        has multiple defined benefit pension plans and postretirement plans that
        require
        accounting as described in SFAS No. 87 “Employers’ Accounting for Pensions” and
        SFAS No. 106 “Employers’ Accounting for Postretirement Benefits Other Than
        Pensions,” respectively. 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
        SFAS
        87/106 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, 2005, 2004, and 2003, periodic pension costs totaling
        $4.8 million, $4.8 million, and $5.0 million, respectively, were directly
        charged by Vectren to the Company. For the years ended December 31, 2005,
        2004,
        and 2003, other periodic postretirement benefit costs totaling $0.8 million,
        $0.9 million, and $0.9 million, respectively, were directly charged by Vectren
        to the Company. As of December 31, 2005 and 2004, $49.5 million and $49.8
        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 $3.0 million and $2.4 million, respectively, is included in *Other
        assets* for
        amounts funded in advance to Vectren.
 
 46
 Table
            of Contecnts
 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 will require compensation costs related to all
        share-based payment transactions to be recognized in the financial statements.
        With limited exceptions, the amount of compensation cost will be measured
        based
        on the grant-date fair value of the equity or liability instruments issued.
        Compensation cost will be recognized over the period that an employee provides
        service in exchange for the award. SFAS 123R replaces SFAS 123 and supersedes
        APB 25. In April 2005, the SEC extended the effective date of SFAS 123R to
        January 1, 2006 for calendar year companies like Utility Holdings. The Company
        intends to adopt SFAS 123R using the modified prospective method. The adoption
        of this standard, and subsequent interpretations of the standard, is not
        expected to 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.
 
 The
        components of income tax expense and utilization of investment tax credits
        follow:
 
 Year
                    Ended December 31,*(In
                    millions)*
                
                2005
                
                2004
                
                2003Current:Federal
                
                $
                15.7
                
                $
                3.7
                
                $
                15.0State
                
                
                8.7
                
                
                6.4
                
                
                12.5**Total
                    current taxes**
                
                
                **24.4**
                
                
                **10.1**
                
                
                **27.5**Deferred:Federal
                
                
                32.2
                
                
                40.6
                
                
                27.4State
                
                
                3.3
                
                
                4.6
                
                
                (1.1
                )**Total
                    deferred taxes**
                
                
                **35.5**
                
                
                **45.2**
                
                
                **26.3**Amortization
                    of investment tax credits
                
                
                (2.4
                )
                
                (2.2
                )
                
                (2.2
                )**Total
                    income tax expense**
                
                **$**
                **57.5**
                
                **$**
                **53.1**
                
                **$**
                **51.6**
  47
 Table
              of Contecnts
 A
        reconciliation of the federal statutory rate to the effective income tax
        rate
        follows:
 Year
                    Ended December 31,2005
                
                2004
                
                2003Statutory
                    rate
                
                
                35.0
                %
                
                35.0
                %
                
                35.0
                %State
                    and local taxes-net of federal benefit
                
                
                5.2
                
                
                5.2
                
                
                5.4Amortization
                    of investment tax credit
                
                
                (1.5
                )
                
                (1.6
                )
                
                (1.6
                )Adjustment
                    to income tax accruals
                
                
                (2.2
                )
                
                (0.2
                )
                
                (0.1
                )All
                    other - net
                
                
                1.2
                
                
                0.6
                
                
                (1.1
                )**Effective
                    tax rate**
                
                
                37.7
                %
                
                39.0
                %
                
                37.6
                %
 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)*
                
                2005
                
                2004Noncurrent
                    deferred tax liabilities (assets):Depreciation
                    & cost recovery timing differences
                
                $
                277.5
                
                $
                240.9Regulatory
                    assets recoverable through future rates
                
                
                19.2
                
                
                19.2Demand
                    side management programs
                
                
                7.7
                
                
                12.5Other
                    comprehensive income
                
                
                2.7
                
                
                -Employee
                    benefit obligations
                
                
                (20.7
                )
                
                (21.5
                )Regulatory
                    liabilities to be settled through future rates
                
                
                (8.1
                )
                
                (7.7
                )Other
                    – net
                
                
                (2.8
                )
                
                (2.6
                )Net
                    noncurrent deferred tax liability
                
                
                275.5
                
                
                240.8Current
                    deferred tax liabilities:Deferred
                    fuel costs - net
                
                
                7.6
                
                
                4.5**Net
                    deferred tax liability**
                
                **$**
                **283.1**
                
                **$**
                **245.3**
 
 At
        December 31, 2005 and 2004, investment tax credits totaling $11.8 million
        and
        $14.2 million, respectively, are included in *Deferred
        credits and other liabilities* .
        These
        investment tax credits are amortized over the lives of the related investments.
  **4.**
              **Transactions
                  with Vectren
                  Affiliates**


ProLiance
        Energy, LLC
 ProLiance
        Energy, LLC (ProLiance), a nonregulated energy marketing 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 business is optimizing the gas portfolios of utilities and
        providing services to large end use customers.
 
 *Transactions
        with ProLiance*
 Purchases
        from ProLiance for resale and for injections into storage for the years ended
        December 31, 2005, 2004, and 2003, totaled $908.9 million, $789.8 million,
        and
        $770.7 million, respectively. Amounts owed to ProLiance at December 31, 2005
        and
        2004, for those purchases were $137.4 million and $97.7 million, respectively,
        and are included in *Accounts
        payable to affiliated companies* in the
        Consolidated Balance Sheets. The Company purchased approximately 95% of its
        gas
        through ProLiance in 2005. In 2004 and 2003, all purchases were made through
        ProLiance. Amounts charged by ProLiance for gas supply services are established
        by supply agreements with each utility.
 
 48
 Table
            of Contecnts
 As
        required by a June 2005, PUCO order, VEDO solicited bids for its gas
        supply/portfolio administration services and selected a third party provider
        under a one year contract. ProLiance’s obligation to supply these services to
        VEDO ended October 31, 2005. As a result, delivery services that in the past
        were paid to ProLiance were used to purchase inventory; therefore, natural
        gas
        held in inventory has increased, while *Prepaid
        gas delivery services* in *Prepayments
        and other current assets* have
        decreased. See Notes 2-C and 11, respectively.
 
 As
        part
        of a settlement agreement approved by the IURC during July 2002, the gas
        supply
        agreements with Indiana Gas and SIGECO, were approved and extended through
        March
        31, 2007. On February 1, 2006, the Company, Citizens Gas, and three consumer
        representatives, including the OUCC, filed a settlement agreement with the
        IURC
        providing for ProLiance to be the continued supplier of gas supply services
        to
        the Company’s Indiana utilities through March 2011. The settlement is subject to
        approval by the IURC.
 
 Other
        Affiliate Transactions
 Vectren
        has ownership interests in other affiliated companies accounted for using
        the
        equity method of accounting that perform underground construction and repair,
        facilities locating, and meter reading services for the Company. For the
        years
        ended December 31, 2005, 2004, and 2003, fees for these services and
        construction-related expenditures paid by the Company to Vectren affiliates
        totaled $21.3 million, $31.2 million, and $37.2 million, respectively. Amounts
        charged by these affiliates are market based. Amounts owed to unconsolidated
        affiliates other than ProLiance totaled $3.2 million and $1.1 million at
        December 31, 2005, and 2004, 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 $293 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)*
                
                2005
                
                2004
                
                2003Weighted
                    average commercial paper and bank loansoutstanding
                    during the year
                
                $
                193.5
                
                $
                133.2
                
                $
                219.5Weighted
                    average interest rates during the yearCommercial
                    paper
                
                
                3.42
                %
                
                1.78
                %
                
                1.36
                %Bank
                    loans
                
                
                -
                
                
                2.19
                %
                
                1.86
                %At
                    December 31,*(In
                    millions)*
                
                
                2005
                
                
                2004Commercial
                    paper
                
                $
                226.9
                
                $
                308.0Bank
                    loans
                
                
                -
                
                
                0.3**Total
                    short-term borrowings**
                
                **$**
                **226.9**
                
                **$**
                **308.3**
  49
 Table
              of Contecnts
 Long-Term
        Debt
 Senior
        unsecured obligations and first mortgage bonds outstanding and classified
        as
        long-term by subsidiary follow:
 At
                    December 31,*(In
                    millions)*
                
                
                
                2005
                
                2004**UTILITY
                    HOLDINGS**Senior
                  Unsecured Notes2011,
                    6.625%
                
                
                
                
                $
                250.0
                
                $
                250.02013,
                    5.25%
                
                
                
                
                
                100.0
                
                
                100.02015,
                    5.45%
                
                
                
                
                
                75.0
                
                
                -2018,
                    5.75%
                
                
                
                
                
                100.0
                
                
                100.02031,
                    7.25%
                
                
                
                
                
                100.0
                
                
                100.02035,
                    6.10%
                
                
                
                
                
                75.0
                
                
                -**Total
                    VUHI**
                
                
                
                
                
                **700.0**
                
                
                **550.0****SIGECO**First
                    Mortgage Bonds2016,
                    1986 Series, 8.875%
                
                
                
                
                
                13.0
                
                
                13.02023,
                    1993 Environmental Improvement Series B, current adjustable rate
                    3.70%,tax
                    exempt, auction rate mode, 2005 weighted average: 2.66%
                
                
                
                
                
                22.6
                
                
                22.62029,
                    1999 Senior Notes, 6.72%
                
                
                
                
                
                80.0
                
                
                80.02015,
                    1985 Pollution Control Series A, current adjustable rate 3.35%,
                    taxexempt,
                    auction rate mode, 2005 weighted average: 2.46%
                
                
                
                
                
                9.8
                
                
                9.82020,
                    1998 Pollution Control Series B, 4.50%, tax exempt
                
                
                
                
                
                4.6
                
                
                4.62030,
                    1998 Pollution Control Series B, 5.00%, tax exempt
                
                
                
                
                
                22.0
                
                
                22.02024,
                    2000 Environmental Improvement Series A, 4.65%, tax exempt
                
                
                
                
                
                22.5
                
                
                22.5Total
                    first mortgage bonds
                
                
                
                
                
                174.5
                
                
                174.5Senior
                    Secured Bonds to Third Parties:2025,
                    1998 Pollution Control Series A, current adjustable rate 4.75%,
                    taxexempt,
                    next rate adjustment: 2006
                
                
                
                
                
                31.5
                
                
                31.5Senior
                    Unsecured Bonds to Third Parties:2030,
                    1998 Pollution Control Series C, current adjustable rate 5.00%,
                    taxexempt,
                    next rate adjustment: 2006
                
                
                
                
                
                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
                
                
                30.02030,
                    Insured Quarterly, 7.45%
                
                
                
                
                
                -
                
                
                49.9**Total
                    Indiana Gas**
                
                
                
                
                
                **127.5**
                
                
                **177.4**
  50
 Table
            of Contecnts
  At
                    December 31,*(In
                    millions)*
                
                2005
                
                2004**Total
                    long-term debt outstanding**
                
                
                **1,055.7**
                
                
                **955.6**Current
                    maturities of long-term debt
                
                
                -
                
                
                -Debt
                    subject to tender
                
                
                (53.7
                )
                
                (10.0
                )Unamortized
                    debt premium & discount - net
                
                
                (4.2
                )
                
                (4.6
                )Other
                
                
                -
                
                
                0.3**Total
                    long-term debt-net**
                
                **$**
                **997.8**
                
                **$**
                **941.3**
 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 in December 2035.
 
 The
        net
        proceeds from the sale of the senior notes and settlement of related hedging
        arrangements approximated $150 million.
 
 Utility
        Holdings 2003 Issuance
 In
        July
        2003, Utility Holdings issued senior unsecured notes with an aggregate principal
        amount of $200 million in two $100 million tranches. The first tranche was
        10-year notes due August 2013, with an interest rate of 5.25% priced at 99.746%
        to yield 5.28% to maturity (2013 Notes). The second tranche was 15-year notes
        due August 2018 with an interest rate of 5.75% priced at 99.177% to yield
        5.80%
        to maturity (2018 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 2013 Notes and 25 basis points for the 2018
        Notes.
 
 Shortly
        before these issues, Utility Holdings entered into several treasury locks
        with a
        total notional amount of $150.0 million. Upon issuance of the debt, the treasury
        locks were settled resulting in the receipt of $5.7 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 issues.
 
 The
        net
        proceeds from the sale of the senior notes and settlement of related hedging
        arrangements approximated $203 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 re-marketed. No debt was put to the Company in 2005. During
        2004
        and 2003, debt totaling $2.5 million and $0.1 million, respectively, was
        put to
        the Company. Debt which may be put to the Company during the years following
        2005 (in millions) is $53.7 in 2006, $20.0 in 2007, zero in 2008, $80.0 in
        2009,
        $10.0 in 2010, and $30.0 thereafter. Debt that may be put to the Company
        within
        one year is classified as *Long-term
        debt subject to tender* in
        current liabilities.
 
 51
 Table
            of Contecnts
 SIGECO
        and Indiana Gas Debt Call
 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 2005 and 2004 had stated interest rates of 7.45% and
        7.15%,
        respectively.
 
 During
        2003, the Company called two first mortgage bonds outstanding at SIGECO and
        two
        senior unsecured notes outstanding at Indiana Gas. The first SIGECO bond
        had a
        principal amount of $45.0 million, an interest rate of 7.60%, was originally
        due
        in 2023, and was redeemed at 103.745% of its stated principal amount. The
        second
        SIGECO bond had a principal amount of $20.0 million, an interest rate of
        7.625%,
        was originally due in 2025, and was redeemed at 103.763% of the stated principal
        amount.
 
 The
        first
        Indiana Gas note had a remaining principal amount of $21.3 million, an interest
        rate of 9.375%, was originally due in 2021, and was redeemed at 105.525%
        of the
        stated principal amount. The second Indiana Gas note had a principal amount
        of
        $13.5 million, an interest rate of 6.75%, was originally due in 2028, and
        was
        redeemed at the principal amount.
 
 Pursuant
        to regulatory authority, the premiums paid to retire the net carrying value
        of
        these notes totaling $3.6 million were deferred in *Regulatory
        assets* .
 
 Other
        Financing Transactions
 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 and $18.5 million in 2003 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 2006 sinking fund requirement by this
        means and, accordingly, the sinking fund requirement for 2006 is excluded
        from *Current
        liabilities* in the
        Consolidated Balance Sheets. At December 31, 2005, $549.4 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
        $1.9
        billion at December 31, 2005.
 
 Consolidated
        maturities and sinking fund requirements on long-term debt during the five
        years
        following 2005 (in millions) are zero in 2006, $6.5 in 2007, and zero in
        2008,
        2009, and 2010.
 
 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, 2005, the Company
        was in
        compliance with all financial covenants.
 
 **6.**
            **Additional
                Capital Contributions** 
 During
        the years ended December 31, 2005, 2004, and 2003, the Company has cumulatively
        received additional capital of $227.2 million from Vectren. Of that total,
        Vectren generated $163.2 million from issuances of its common stock, $55.0
        million was funded by Vectren’s nonregulated operations, and $9.0 million was
        funded by new share issues from Vectren’s dividend reinvestment
        plan.
 
 52
 Table
            of Contecnts
 **7.**
            **Commitments
                & Contingencies** 
 Commitments
 Firm
        purchase commitments for utility and non-utility plant total $13.0 million.
 
 Securities
        & Exchange Commission Inquiry into PUHCA Exemption
  In
        July
        2004, the Company received a letter from the SEC regarding its exempt status
        under the Public Utility Holding Company Act of 1935 (PUHCA).  The Company
        has responded fully to the SEC's letter and believes that it and its utility
        holding company subsidiary, Utility Holdings, remain entitled to exemption
        under
        Section 3(a)(1) of PUHCA.  The question of the PUHCA exemptions was mooted
        by the Energy Policy Act of 2005 (Energy Act), which repealed the Public
        Utility
        Holding Company Act of 1935 effective February 8, 2006.
  The
        Energy Act enacts a new Public Utility Holding Company Act of 2005 (PUHCA
        2005).
        Vectren and Utility Holdings, are holding companies under PUHCA 2005. Under
        PUHCA 2005, the FERC is granted authority to require holding companies and
        their
        subsidiaries to maintain certain books and records and make them available
        for
        review by FERC and state regulatory authorities to the extent relevant to
        the
        rates of FERC-jurisdictional public utilities and natural gas companies that
        are
        part of the holding company system. FERC has issued rules implementing PUHCA
        2005 that allow companies to seek an exemption or waiver from all or some
        of
        FERC’s books and records requirements. Under PUHCA 2005, the Company will be
        required to notify FERC of its status as a holding company, and, unless an
        exemption or waiver is obtained, file an annual report, maintain certain
        books
        and records and make them available to the FERC. Compliance with these
        requirements is not expected to materially affect the Company’s financial
        position or operations.
 
 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
 
 *NOx
        SIP Call Matter*
 The
        Company has taken steps to comply with Indiana’s State Implementation Plan (SIP)
        of the Clean Air Act (the Act). These steps include installing 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
        has issued orders that approve:
 ·
            the
                Company’s project to achieve environmental compliance by investing in
                clean coal technology; ·
            a
                total capital cost investment for this project up to $250 million
                (excluding AFUDC and administrative overheads), subject to periodic
                review
                of the actual costs incurred; ·
            a
                mechanism whereby, prior to an electric base rate case, the Company
                may
                recover 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 once the facility
                is
                placed into service. 
 Through
        December 31, 2005, capital investments approximating the level approved by
        the
        IURC have been made. The last SCR was placed into service in May, 2005. 
Related annual operating expenses, including depreciation expense, were $15.4
        million in 2005, $9.7 million in 2004 and $1.2 million in 2003. Such operating
        expenses could approximate $24 to $27 million once all installed equipment
        is
        operational for an entire year.
 
 53
 Table
            of Contecnts
 The
        Company has achieved timely compliance through the reduction of the Company’s
        overall NOx emissions to levels compliant with Indiana’s NOx emissions budget
        allotted by the USEPA. Therefore, the Company has recorded no accrual for
        potential penalties that may result from noncompliance.
 
 *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.
  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
        its capital investments, which are expected to approximate $110 million,
        and
        related operating expenses through a rider mechanism. This rider mechanism
        will
        operate similar to the rider used to recover NOx-related capital investments
        and
        operating expenses. 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.
 
 *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 generating station without obtaining
        required permits, (2) making major modifications to the generating station
        without installing the best available emission control technology, and (3)
        failing to notify the USEPA of the modifications.
 
 Under
        the
        terms of the agreement, the DOJ and USEPA agreed to drop all challenges of
        past
        maintenance and repair activities at the Culley Generating Station. In reaching
        the agreement, SIGECO did not admit to any allegations in the government’s
        complaint, and SIGECO continues to believe that it acted in accordance with
        applicable regulations and conducted only routine maintenance on the units.
        SIGECO entered into this agreement to further its continued commitment to
        improve air quality and avoid the cost and uncertainties of litigation.
 
 Under
        the
        agreement, SIGECO committed to:
 ·
            either
                repower Culley Unit 1 (50 MW) with natural gas and equip it with
                SCR
                control technology for further reduction of nitrogen oxide, or cease
                operation of the unit by December 31,
                2006; ·
            operate
                the existing SCR control technology recently installed on Culley
                Unit 3
                (287 MW) year round at a lower emission rate than that currently
                required
                under the NOx SIP Call, resulting in further nitrogen oxide
                reductions; ·
            enhance
                the efficiency of the existing scrubber at Culley Units 2 and 3 for
                additional removal of sulphur dioxide
                emissions; ·
            install
                a baghouse for further particulate matter reductions at Culley Unit
                3 by
                June 30, 2007; ·
            conduct
                a Sulphuric Acid Reduction Demonstration Project as an environmental
                mitigation project designed to demonstrate an advance in pollution
                control
                technology for the reduction of sulfate emissions; and ·
            pay
                a $600,000 civil penalty. 
 The
        Company notified the USEPA of its intention to shut down Culley Unit 1 effective
        December 31, 2006. The Company does not believe that implementation of the
        settlement will have a material effect to its results from operations or
        financial condition. The $600,000 civil penalty was accrued during 2003 and
        is
        reflected in *Other-net* .
 
 54
 Table
            of Contecnts
 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, Indiana Gas, SIGECO, and others may now
        be
        required to take remedial action if certain byproducts are found above the
        regulatory thresholds at these sites.
 
 Indiana
        Gas has 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 has 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
        has
        accrued the estimated costs for further investigation, remediation, groundwater
        monitoring, and related costs for the sites. While the total costs that may
        be
        incurred in connection with addressing these sites cannot be determined at
        this
        time, 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.
 
 Environmental
        matters related to manufactured gas plants have had no material impact on
        earnings since costs recorded to date approximate PRP and insurance settlement
        recoveries. While Indiana Gas has recorded all costs which it presently expects
        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.
 
 In
        October 2002, the Company received a formal information request letter from
        the
        IDEM regarding five manufactured gas plants owned and/or operated by SIGECO
        and
        not currently 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 risk to human health or the environment. Follow
        up
        reviews have been initiated by the Company to confirm that the sites continue
        to
        pose no such risk.
 
 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.
        Costs
        of remediation at the four SIGECO sites, as well as the amount of any PRP
        or
        insurance recoveries, cannot be determined at this time. The total costs
        accrued
        to date, including investigative costs, have been immaterial.
  55
 Table
            of Contecnts
  
 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.
 
 **9.**
            **Rate
                & Regulatory Matters** 
 Gas
        Utility Base Rate Settlements
 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 new rate
        designs in all three territories include a larger service charge, which is
        intended to address to some extent earnings volatility related to
        weather. 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 on-going
        costs to comply with the Pipeline Safety Improvement Act of 2002 as well
        as the funding
        of conservation programs.
 
 Indiana
        and Ohio Decoupling/Conservation Filing
 On
        October 25, 2005, Vectren Energy Delivery of Indiana filed with the IURC
        for
        approval of a conservation program and a conservation adjustment rider in
        its
        two Indiana service territories. If approved, the plan outlined in the petition
        will better align the interests of the Company with its customers through
        the
        promotion of natural gas conservation. The petition requests the use of a
        tracker mechanism to recover the costs of funding the design and implementation
        of conservation efforts, such as consumer education programs and rebates
        for
        high efficiency equipment. The conservation tracker works in tandem with
        a
        decoupling mechanism. The decoupling mechanism would allow the Company to
        recover the distribution portion of its rates from residential and commercial
        customers based on the level of customer usage established in each utility’s
        last general rate case. The Company will file its evidence in March 2006
        and a
        hearing is set for June 2006.
 
 Similarly,
        on November 28, 2005, Vectren Energy Delivery of Ohio filed with the PUCO
        for
        approval of a conservation program and a conservation adjustment rider that
        would accomplish the same objectives. Discussions with interested parties
        are
        ongoing in both states.
 
 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.
 
 56
 Table
            of Contecnts
 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 the fourth quarter of 2003, the Company
        recorded a reserve of $1.1 million for this matter. An additional pretax
        charge
        of $4.2 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.
        That appeal is pending with briefing scheduled to be completed in February,
        2006. In addition, the Company solicited and received bids for VEDO’s gas supply
        and portfolio administration services and has selected a third party provider,
        who began providing services to VEDO on November 1, 2005, under a one year
        contract. 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 is considering whether to appeal
        that decision.
 
 Commodity
        Prices
 Recently,
        commodity prices for natural gas purchases have increased and have become
        more
        volatile. Subject
        to compliance with applicable state laws, the Company's utility
        subsidiaries are
        allowed recovery of such changes in purchased gas costs from their retail
        customers through commission-approved gas cost adjustment mechanisms, and
        margin
        on gas sales are not expected to be impacted. Nevertheless, it is possible
        regulators may disallow recovery of a portion of gas costs for a variety
        of
        reasons, including, but not limited to, a finding by the regulator that natural
        gas was not prudently procured. In addition, it is reasonably
        possible that as a result of this near term change in the natural gas commodity
        price, the
        Company’s utility 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. In response to higher gas prices, the Company increased
        its
        utility-related credit facilities (See Note 5).
 
 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.
 
 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, Utility Holdings, 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 the
        Company’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.
 
 57
 Table
            of Contecnts
 Ohio
        Uncollectible Accounts Expense Tracker
 On
        December 17, 2003, the PUCO approved a request by VEDO and several other
        regulated Ohio gas utilities to establish a mechanism to recover uncollectible
        account expense outside of base rates. The tariff mechanism establishes an
        automatic adjustment procedure to track and recover these costs instead of
        providing the recovery of the historic amount in base rates. Through this
        order,
        VEDO received authority to defer its 2003 uncollectible accounts expense
        to the
        extent it differs from the level included in base rates. The Company estimated
        the difference to approximate $4 million in excess of that included in base
        rates, and reversed and deferred that amount for future recovery in 2003.
        In
        2005 and 2004, the Company recorded revenues of $5.1 and $3.3 million,
        respectively, which is equal to the level of uncollectible accounts expense
        recognized for Ohio residential customers.
 
 **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 four 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. Substantially all of the income
        from
        these activities is generated from 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 are recorded at
        market
        value. Beginning in April 2005, substantially all off-system sales occur
        into
        the MISO day-ahead market.
 
 At
        December 31, 2005, asset optimization contracts recorded at market value
        in *Prepayments
        & other current assets* were
        $1.3 million and were zero in *Accrued
        liabilities.* At
        December 31, 2004, asset optimization contracts recorded at market value
        approximated $2.5 million in *Prepayments
        & other current assets* and $3.1
        million in *Accrued
        liabilities* .
 
 The
        proceeds received and paid upon settlement of both purchase and sale contracts
        along with changes in market value of open contracts are recorded in *Electric
        utility revenues* .
        The
        change in market value is a function of the normal decline in market value
        as
        earnings are realized and the fluctuation in market value resulting from
        price
        volatility. Net revenues from asset optimization activities totaled $38.0
        million in 2005, $23.8 million in 2004, and $26.5 million in 2003.
 
 58
 Table
            of Contecnts
 *SO* *2* *Emission Allowance Risk Management*
 The
        Company’s wholesale power marketing operations are exposed to price risk
        associated with SO 2 emission
        allowances. During 2004 and 2005, emission allowances became more volatile
        and
        prices increased. To hedge this risk, the Company executed call options to
        hedge
        wholesale emission allowance utilization in future periods. The Company
        designated and documented these derivatives as cash flow hedges. At December
        31,
        2005, a deferred gain of approximately $3.2 million remains in *Accumulated
        comprehensive income* which
        will be recognized in earnings as emission allowances are utilized. At December
        31, 2005, outstanding call options hedging a forecasted 2006 transaction,
        have a
        fair value of $3.9 million and are recorded in *Prepayments
        and other current assets* .
        Hedge
        ineffectiveness totaling $0.8 million of expense is included in 2005’s earnings,
        and the effective portion of outstanding hedges totaling $3.6 million resides
        in *Accumulated
        comprehensive income* .
 
 *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 Utility Holdings’ 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, 2005 and 2004, 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.
 
 At
        December 31, 2005, approximately $6.8 million remains in *Regulatory
        liabilities* related
        to future interest payments. Of the existing regulatory liability, $0.7 million
        will be reclassified to earnings in 2006, $0.6 million was reclassified to
        earnings in 2005, and $0.6 million was reclassified to earnings during
        2004.
 
 Fair
        Value of Other Financial Instruments
 The
        carrying values and estimated fair values of the Company's other financial
        instruments follow:
 
 
 At
                  December 31,2005
              
              2004In
                  millions
              
              Carrying
                Amount
              
              Est.
                  Fair
                Value
              
              Carrying
                Amount
              
              Est.
                Fair
                  ValueLong-term
                  debt
              
              $
              1,055.7
              
              $
              1,105.2
              
              $
              955.6
              
              $
              1,108.9Short-term
                  borrowings
              
              
              226.9
              
              
              226.9
              
              
              308.3
              
              
              308.3
  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.
 
 59
 Table
            of Contecnts
 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)*
                
                2005
                
                2004Prepaid
                    gas delivery service (See Note 4)
                
                $
                69.3
                
                $
                116.9Prepaid
                    taxes
                
                
                27.1
                
                
                12.3Other
                    prepayments & current assets
                
                
                20.8
                
                
                4.9**Total
                    prepayments & other current assets**
                
                **$**
                **117.2**
                
                **$**
                **134.1**
 
 *Accrued
        liabilities* in the
        Consolidated Balance Sheets consist of the following:
 
 At
                    December 31,*(In
                    millions)*
                
                2005
                
                2004Refunds
                    to customers & customer deposits
                
                $
                36.4
                
                $
                31.0Accrued
                    taxes
                
                
                31.5
                
                
                27.6Accrued
                    interest
                
                
                16.2
                
                
                15.1Deferred
                    income taxes
                
                
                7.6
                
                
                4.5Accrued
                    salaries & other
                
                
                38.7
                
                
                31.8**Total
                    accrued liabilities**
                
                **$**
                **130.4**
                
                **$**
                **110.0**
 *Other
        - net* in the
        Consolidated Statements of Income consists of the following:
 
 Year
                    Ended December 31,*(In
                    millions)*
                
                2005
                
                2004
                
                2003AFUDC
                    & capitalized interest
                
                $
                2.5
                
                $
                4.6
                
                $
                5.9Interest
                    income
                
                
                0.6
                
                
                0.5
                
                
                0.6Gains
                    on sale of investments & assets
                
                
                -
                
                
                0.6
                
                
                -Other
                    income
                
                
                2.8
                
                
                0.8
                
                
                3.3Other
                    expense
                
                
                -
                
                
                0.6
                
                
                (3.2
                )**Total
                    other – net**
                
                **$**
                **5.9**
                
                **$**
                **7.1**
                
                **$**
                **6.6**
 **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.
        For these regulated operations the Company uses after tax operating income
        as a
        measure of profitability, consistent with regulatory reporting requirements.
        For
        Utility Holdings’ other operations, net income is used as the measure of
        profitability. In total, there are three operating segments as defined by
        SFAS
        131 “Disclosure About Segments of an Enterprise and Related Information” (SFAS
        131).
 
 60
 Table
            of Contecnts
 Information
        related to the Company’s business segments is summarized below:
 
 Year
                    Ended December 31,*(In
                    millions)*
                
                2005
                
                2004
                
                2003**Revenues**Gas
                    Utility Services
                
                $
                1,359.7
                
                $
                1,126.2
                
                $
                1,112.3Electric
                    Utility Services
                
                
                421.4
                
                
                371.3
                
                
                335.7Other
                    Operations
                
                
                36.1
                
                
                32.9
                
                
                26.5Eliminations
                
                
                (35.4
                )
                
                (32.4
                )
                
                (25.7
                )Total
                    revenues
                
                $
                1,781.8
                
                $
                1,498.0
                
                $
                1,448.8**Profitability
                    Measure**Regulated
                    Operating Income(Operating
                    Income Less Applicable Income Taxes)Gas
                    Utility Services
                
                $
                74.8
                
                $
                70.9
                
                $
                74.9Electric
                    Utility Services
                
                
                72.4
                
                
                65.6
                
                
                63.8Total
                    regulated operating income
                
                
                147.2
                
                
                136.5
                
                
                138.7Regulated
                    other income - net
                
                
                2.0
                
                
                2.1
                
                
                5.1Regulated
                    interest expense & preferred dividends
                
                
                (63.9
                )
                
                (62.7
                )
                
                (62.0
                )Regulated
                    Net Income
                
                
                85.3
                
                
                75.9
                
                
                81.8Other
                    Operations Net Income
                
                
                9.8
                
                
                7.2
                
                
                3.8Net
                    Income
                
                $
                95.1
                
                $
                83.1
                
                $
                85.6
 61
 Table
            of Contecnts
 Year
                    Ended December 31,*(In
                    millions)*
                
                
                
                2005
                
                2004
                
                2003**Amounts
                    Included in Profitability Measures****Depreciation
                  & Amortization**Gas
                    Utility Services
                
                
                
                
                $
                64.9
                
                $
                57.0
                
                $
                61.1Electric
                    Utility Services
                
                
                
                
                
                56.9
                
                
                53.3
                
                
                42.6Other
                    Operations
                
                
                
                
                
                19.5
                
                
                17.5
                
                
                14.2Total
                    depreciation & amortization
                
                
                
                
                $
                141.3
                
                $
                127.8
                
                $
                117.9**Interest
                    Expense**Regulated
                    Operations
                
                
                
                
                $
                63.9
                
                $
                62.7
                
                $
                62.0Other
                    Operations
                
                
                
                
                
                6.0
                
                
                4.7
                
                
                4.1Total
                    interest expense
                
                
                
                
                $
                69.9
                
                $
                67.4
                
                $
                66.1**Equity
                    in (Earnings )Losses of Unconsolidated Affiliates**Other
                    Operations
                
                
                
                
                $
                -
                
                $
                0.2
                
                $
                (0.5
                )**Income
                    Taxes**Gas
                    Utility Services
                
                
                
                
                $
                22.3
                
                $
                17.5
                
                $
                19.5Electric
                    Utility Services
                
                
                
                
                
                33.5
                
                
                30.8
                
                
                29.8Other
                    Operations
                
                
                
                
                
                1.7
                
                
                4.8
                
                
                2.3Total
                    income taxes
                
                
                
                
                $
                57.5
                
                $
                53.1
                
                $
                51.6**Capital
                    Expenditures**Gas
                    Utility Services
                
                
                
                
                $
                81.0
                
                $
                89.1
                
                $
                95.0Electric
                    Utility Services
                
                
                
                
                
                100.0
                
                
                150.6
                
                
                124.1Other
                    Operations
                
                
                
                
                
                29.9
                
                
                27.9
                
                
                15.9Non-cash
                    costs & changes in accruals
                
                
                
                
                
                6.9
                
                
                (21.4
                )
                
                0.2Total
                    capital expenditures
                
                
                
                
                $
                217.8
                
                $
                246.2
                
                $
                235.2
 At
                    December 31,*(In
                    millions)*
                
                
                
                2005
                
                2004**Assets**Utility
                  GroupGas
                    Utility Services
                
                
                
                
                $
                2,030.8
                
                $
                1,892.8Electric
                    Utility Services
                
                
                
                
                
                1,176.0
                
                
                1,090.1Other
                    Operations
                
                
                
                
                
                188.9
                
                
                175.0Eliminations
                
                
                
                
                
                (4.5
                )
                
                (10.2
                )Total
                    assets
                
                
                
                
                $
                3,391.2
                
                $
                3,147.7
  **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 $226.9 million is outstanding at December 31, 2005, and Utility Holdings’
$700.0 million unsecured senior notes outstanding at December 31, 2005. 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 Article 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.
 
  62
 Table
            of Contecnts
  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****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 fromother
                    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
                
                
                -
                
                
                649.3Cumulative,
                    Redeemable Preferred Stock of a Subsidiary
                
                
                -
                
                
                -
                
                
                -
                
                
                -Common
                    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**
  63
 Table
            of Contecnts
  Consolidating
        Balance Sheet as of December 31, 2004 (in millions):
 
 **ASSETS**
                  
                  Subsidiary
                  
                  ParentGuarantors
                  
                  Company
                  
                  Eliminations
                  
                  ConsolidatedCurrent
                      AssetsCash
                      & cash equivalents
                  
                  $
                  4.7
                  
                  $
                  1.0
                  
                  $
                  -
                  
                  $
                  5.7Accounts
                      receivable - less reserves
                  
                  
                  146.5
                  
                  
                  -
                  
                  
                  -
                  
                  
                  146.5Receivables
                      due from other Vectren companies
                  
                  
                  1.7
                  
                  
                  327.0
                  
                  
                  (324.7
                  )
                  
                  4.0Accrued
                      unbilled revenues
                  
                  
                  161.2
                  
                  
                  -
                  
                  
                  -
                  
                  
                  161.2Inventories
                  
                  
                  58.1
                  
                  
                  -
                  
                  
                  -
                  
                  
                  58.1Recoverable
                      fuel & natural gas costs
                  
                  
                  17.7
                  
                  
                  -
                  
                  
                  -
                  
                  
                  17.7Prepayments
                      & other current assets
                  
                  
                  132.2
                  
                  
                  4.2
                  
                  
                  (2.3
                  )
                  
                  134.1**Total
                      current assets**
                  
                  
                  **522.1**
                  
                  
                  **332.2**
                  
                  
                  **(327.0**
                  **)**
                  
                  **527.3**Utility
                      PlantOriginal
                      cost
                  
                  
                  3,465.2
                  
                  
                  -
                  
                  
                  -
                  
                  
                  3,465.2Less:
                      accumulated depreciation & amortization
                  
                  
                  1,309.0
                  
                  
                  -
                  
                  
                  -
                  
                  
                  1,309.0**Net
                      utility plant**
                  
                  
                  **2,156.2**
                  
                  
                  **-**
                  
                  
                  **-**
                  
                  
                  **2,156.2**Investments
                      in consolidated subsidiaries
                  
                  
                  -
                  
                  
                  951.6
                  
                  
                  (951.6
                  )
                  
                  -Notes
                      receivable from consolidated subsidiaries
                  
                  
                  -
                  
                  
                  443.1
                  
                  
                  (443.1
                  )
                  
                  -Investments
                      in unconsolidated affiliates
                  
                  
                  0.2
                  
                  
                  -
                  
                  
                  -
                  
                  
                  0.2Other
                      investments
                  
                  
                  13.5
                  
                  
                  6.1
                  
                  
                  -
                  
                  
                  19.6Non-utility
                      property - net
                  
                  
                  5.3
                  
                  
                  144.3
                  
                  
                  -
                  
                  
                  149.6Goodwill
                      - net
                  
                  
                  205.0
                  
                  
                  -
                  
                  
                  -
                  
                  
                  205.0Regulatory
                      assets
                  
                  
                  76.8
                  
                  
                  5.7
                  
                  
                  -
                  
                  
                  82.5Other
                      assets
                  
                  
                  3.8
                  
                  
                  3.5
                  
                  
                  -
                  
                  
                  7.3**TOTAL
                      ASSETS**
                  
                  **$**
                  **2,982.9**
                  
                  **$**
                  **1,886.5**
                  
                  **$**
                  **(1,721.7**
                  **)**
                  **$**
                  **3,147.7****LIABILITIES
                      & SHAREHOLDER'S EQUITY**
                  
                  
                  Subsidiary
                  
                  
                  ParentGuarantors
                  
                  
                  Company
                  
                  
                  Eliminations
                  
                  
                  ConsolidatedCurrent
                      LiabilitiesAccounts
                      payable
                  
                  $
                  87.9
                  
                  $
                  9.4
                  
                  $
                  -
                  
                  $
                  97.3Accounts
                      payable to affiliated companies
                  
                  
                  98.6
                  
                  
                  0.2
                  
                  
                  -
                  
                  
                  98.8Payables
                      to other Vectren companies
                  
                  
                  26.0
                  
                  
                  0.6
                  
                  
                  (10.8
                  )
                  
                  15.8Refundable
                      fuel & natural gas costs
                  
                  
                  6.3
                  
                  
                  -
                  
                  
                  -
                  
                  
                  6.3Accrued
                      liabilities
                  
                  
                  100.8
                  
                  
                  11.6
                  
                  
                  (2.4
                  )
                  
                  110.0Short-term
                      borrowings
                  
                  
                  0.3
                  
                  
                  308.0
                  
                  
                  -
                  
                  
                  308.3Short-term
                      borrowings fromother
                      Vectren companies
                  
                  
                  313.8
                  
                  
                  -
                  
                  
                  (313.8
                  )
                  
                  -Current
                      maturities of long-term debt
                  
                  
                  -
                  
                  
                  -
                  
                  
                  -
                  
                  
                  -Long-term
                      debt subject to tender
                  
                  
                  10.0
                  
                  
                  -
                  
                  
                  -
                  
                  
                  10.0**Total
                      current liabilities**
                  
                  
                  **643.7**
                  
                  
                  **329.8**
                  
                  
                  **(327.0**
                  **)**
                  
                  **646.5**Long-Term
                      DebtLong-term
                      debt - net of current maturities &debt
                      subject to tender
                  
                  
                  393.4
                  
                  
                  547.9
                  
                  
                  -
                  
                  
                  941.3Long-term
                      debt due to VUHI
                  
                  
                  443.1
                  
                  
                  -
                  
                  
                  (443.1
                  )
                  
                  -Total
                      long-term debt - net
                  
                  
                  836.5
                  
                  
                  547.9
                  
                  
                  (443.1
                  )
                  
                  941.3Deferred
                      Income Taxes & Other LiabilitiesDeferred
                      income taxes
                  
                  
                  226.8
                  
                  
                  14.0
                  
                  
                  -
                  
                  
                  240.8Regulatory
                      liabilities
                  
                  
                  246.2
                  
                  
                  5.5
                  
                  
                  -
                  
                  
                  251.7Deferred
                      credits & other liabilities
                  
                  
                  78.0
                  
                  
                  3.9
                  
                  
                  -
                  
                  
                  81.9Total
                      deferred credits & other liabilities
                  
                  
                  551.0
                  
                  
                  23.4
                  
                  
                  -
                  
                  
                  574.4Cumulative,
                      Redeemable Preferred Stock of a Subsidiary
                  
                  
                  0.1
                  
                  
                  -
                  
                  
                  -
                  
                  
                  0.1Common
                      Shareholder's EquityCommon
                      stock (no par value)
                  
                  
                  611.3
                  
                  
                  592.9
                  
                  
                  (611.3
                  )
                  
                  592.9Retained
                      earnings
                  
                  
                  340.3
                  
                  
                  392.5
                  
                  
                  (340.3
                  )
                  
                  392.5**Total
                      common shareholder's equity**
                  
                  
                  **951.6**
                  
                  
                  **985.4**
                  
                  
                  **(951.6**
                  **)**
                  
                  **985.4****TOTAL
                      LIABILITIES & SHAREHOLDER'S EQUITY**
                  
                  **$**
                  **2,982.9**
                  
                  **$**
                  **1,886.5**
                  
                  **$**
                  **(1,721.7**
                  **)**
                  **$**
                  **3,147.7**
  64
 Table
              of Contecnts
 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
                
                
                -
                
                
                -
                
                
                973.3Fuel
                    for electric generation
                
                
                126.3
                
                
                -
                
                
                -
                
                
                126.3Purchased
                    electric energy
                
                
                17.8
                
                
                -
                
                
                -
                
                
                17.8Other
                    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
                )
                
                -Equity
                    in losses of unconsolidated affiliates
                
                
                -
                
                
                -
                
                
                -
                
                
                -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
                
                
                -
                
                
                -
                
                
                778.5Fuel
                    for electric generation
                
                
                96.1
                
                
                -
                
                
                -
                
                
                96.1Purchased
                    electric energy
                
                
                20.7
                
                
                -
                
                
                -
                
                
                20.7Other
                    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
                
                
                -
                
                
                67.2
                
                
                (67.2
                )
                
                -Equity
                    in earnings/losses of unconsolidated affiliates
                
                
                -
                
                
                0.2
                
                
                -
                
                
                0.2Other
                    – net
                
                
                (2.9
                )
                
                35.4
                
                
                (25.4
                )
                
                7.1Total
                    other income (expense)
                
                
                (2.9
                )
                
                102.8
                
                
                (92.6
                )
                
                7.3Interest
                    expense
                
                
                62.9
                
                
                37.5
                
                
                (33.0
                )
                
                67.4**INCOME
                    BEFORE INCOME TAXES**
                
                
                **119.0**
                
                
                **79.0**
                
                
                **(61.8**
                **)**
                
                **136.2**Income
                    taxes
                
                
                51.8
                
                
                4.7
                
                
                (3.4
                )
                
                53.1**NET
                    INCOME**
                
                **$**
                **67.2**
                
                **$**
                **74.3**
                
                **$**
                **(58.4**
                **)**
                **$**
                **83.1**
 65
 Table
            of Contecnts
 Consolidating
        Statement of Income for the year ended December 31, 2003 (in
        millions):
  Subsidiary
                
                ParentGuarantors
                
                Company
                
                Eliminations
                
                ConsolidatedOPERATING
                    REVENUESGas
                    utility
                
                $
                1,112.3
                
                $
                -
                
                $
                -
                
                $
                1,112.3Electric
                    utility
                
                
                335.7
                
                
                -
                
                
                -
                
                
                335.7Other
                
                
                -
                
                
                26.5
                
                
                (25.7
                )
                
                0.8**Total
                    operating revenues**
                
                
                **1,448.0**
                
                
                **26.5**
                
                
                **(25.7**
                **)**
                
                **1,448.8**OPERATING
                    EXPENSESCost
                    of gas sold
                
                
                762.5
                
                
                -
                
                
                -
                
                
                762.5Fuel
                    for electric generation
                
                
                86.5
                
                
                -
                
                
                -
                
                
                86.5Purchased
                    electric energy
                
                
                16.2
                
                
                -
                
                
                -
                
                
                16.2Other
                    operating
                
                
                235.3
                
                
                0.5
                
                
                (23.9
                )
                
                211.9Depreciation
                    & amortization
                
                
                103.7
                
                
                14.2
                
                
                -
                
                
                117.9Taxes
                    other than income taxes
                
                
                55.9
                
                
                0.7
                
                
                -
                
                
                56.6Total
                    operating expenses
                
                
                1,260.1
                
                
                15.4
                
                
                (23.9
                )
                
                1,251.6**OPERATING
                    INCOME**
                
                
                **187.9**
                
                
                **11.1**
                
                
                **(1.8**
                **)**
                
                **197.2**OTHER
                    INCOME (EXPENSE)Equity
                    in earnings of consolidated companies
                
                
                -
                
                
                81.8
                
                
                (81.8
                )
                
                -Equity
                    in losses of unconsolidated affiliates
                
                
                -
                
                
                (0.5
                )
                
                -
                
                
                (0.5
                )Other
                    – net
                
                
                5.1
                
                
                27.9
                
                
                (26.4
                )
                
                6.6Total
                    other income (expense)
                
                
                5.1
                
                
                109.2
                
                
                (108.2
                )
                
                6.1Interest
                    expense
                
                
                62.0
                
                
                32.3
                
                
                (28.2
                )
                
                66.1**INCOME
                    BEFORE INCOME TAXES**
                
                
                **131.0**
                
                
                **88.0**
                
                
                **(81.8**
                **)**
                
                **137.2**Income
                    taxes
                
                
                49.2
                
                
                2.4
                
                
                -
                
                
                51.6**NET
                    INCOME**
                
                **$**
                **81.8**
                
                **$**
                **85.6**
                
                **$**
                **(81.8**
                **)**
                **$**
                **85.6**
 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
  66
 Table
              of Contecnts
 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
                )
                
                123.1Other
                    activity
                
                
                -
                
                
                -
                
                
                -
                
                
                -**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
                )Consolidated
                    subsidiary investments
                
                
                -
                
                
                -
                
                
                -
                
                
                -Unconsolidated
                    affiliate & other investments
                
                
                -
                
                
                -
                
                
                -
                
                
                -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
  67
 Table
              of Contecnts
 Consolidating
        Statement of Cash Flows for the year ended December 31, 2003 (in
        millions):
 
 Subsidiary
                
                ParentGuarantors
                
                Company
                
                Eliminations
                
                Consolidated**NET
                    CASH FLOWS FROM OPERATING ACTIVITIES**
                
                **$**
                **129.6**
                
                **$**
                **39.8**
                
                **$**
                **-**
                
                **$**
                **169.4**CASH
                    FLOWS FROM FINANCING ACTIVITIESProceeds
                    from:Additional
                    capital contribution
                
                
                150.0
                
                
                204.1
                
                
                (150.0
                )
                
                204.1Long-term
                    debt - net of issuance costs & hedging proceeds
                
                
                99.0
                
                
                202.9
                
                
                (99.0
                )
                
                202.9Requirements
                    for:Retirement
                    of long-term debt, including premiums paid
                
                
                (121.9
                )
                
                -
                
                
                -
                
                
                (121.9
                )Dividends
                    to parent
                
                
                (77.9
                )
                
                (78.0
                )
                
                77.9
                
                
                (78.0
                )Redemption
                    of preferred stock of subsidiary
                
                
                (0.1
                )
                
                -
                
                
                -
                
                
                (0.1
                )Net
                    change in short-term borrowings, including from otherVectren
                    companies
                
                
                30.9
                
                
                (150.1
                )
                
                (21.6
                )
                
                (140.8
                )Other
                    activity
                
                
                (1.7
                )
                
                -
                
                
                -
                
                
                (1.7
                )**Net
                    cash flows from financing activities**
                
                
                **78.3**
                
                
                **178.9**
                
                
                **(192.7**
                **)**
                
                **64.5**CASH
                    FLOWS FROM INVESTING ACTIVITIESProceeds
                    from:Consolidated
                    subsidiary distributions
                
                
                -
                
                
                77.9
                
                
                (77.9
                )
                
                -Requirements
                    for:Capital
                    expenditures, excluding AFUDC equity
                
                
                (219.2
                )
                
                (16.0
                )
                
                -
                
                
                (235.2
                )Consolidated
                    subsidiary investments
                
                
                -
                
                
                (150.0
                )
                
                150.0
                
                
                -Unconsolidated
                    affiliate & other investments
                
                
                -
                
                
                (1.1
                )
                
                -
                
                
                (1.1
                )Net
                    change in notes receivable from other Vectren companies
                
                
                8.5
                
                
                (129.1
                )
                
                120.6
                
                
                -**Net
                    cash flows from investing activities**
                
                
                **(210.7**
                **)**
                
                **(218.3**
                **)**
                
                **192.7**
                
                
                **(236.3**
                **)**Net
                    (decrease) increase in cash & cash equivalents
                
                
                (2.8
                )
                
                0.4
                
                
                -
                
                
                (2.4
                )Cash
                    & cash equivalents at beginning of period
                
                
                10.2
                
                
                0.3
                
                
                -
                
                
                10.5Cash
                    & cash equivalents at end of period
                
                $
                7.4
                
                $
                0.7
                
                $
                -
                
                $
                8.1
 **14.**
            **Adoption
                of Other Accounting Standards** 
 **SFAS
        No. 154**
 
 In
        May
        2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections -
        a Replacement of APB Opinion No. 20 and FASB Statement No. 3” (SFAS 154). This
        statement changes the requirements for the accounting for and reporting of
        a
        change in accounting principle and applies to all voluntary changes in
        accounting principle and to changes required by an accounting pronouncement
        in
        the instance that the pronouncement does not include specific transition
        provisions. SFAS 154 requires retrospective application to prior periods’
financial statements of the direct effects caused by a change in accounting
        principle, unless it is impracticable to determine either the period-specific
        effects or the cumulative effect of the change. Further, changes in
        depreciation, amortization or depletion methods for long-lived, nonfinancial
        assets are to be accounted for as a change in accounting estimate affected
        by a
        change in accounting principle. SFAS 154 is effective for accounting changes
        and
        corrections made in fiscal years beginning after December 15, 2005, with
        early
        adoption permitted. The adoption of this standard, beginning in fiscal year
        2006, is not expected to have any material effect on the Company’s operating
        results or financial condition.
 
  68
 Table
            of Contecnts
  
 **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 2005 and 2004 follows:
 
 *(In
                    millions)*
                
                
                
                Q1
                
                Q2
                
                Q3
                
                Q4**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**2004****Results
                    of Operations:**Operating
                    revenues
                
                
                
                
                $
                594.2
                
                $
                243.4
                
                $
                214.7
                
                $
                445.7Operating
                    income
                
                
                
                
                
                87.3
                
                
                19.9
                
                
                21.7
                
                
                67.4Net
                    income
                
                
                
                
                
                44.7
                
                
                2.8
                
                
                4.5
                
                
                31.1
 
  69
 Table
            of Contecnts
  **ITEM9.CHANGE IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
        FINANCIAL DISCLOSURE**
 None.
 
 **ITEM
        9A.CONTROLS AND PROCEDURES**
 
 **Changes
        in Internal Controls over Financial Reporting**
 
 During
        the quarter ended December 31, 2005, 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, 2005, 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,
        2005, 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.
 
 **ITEM
        9B. OTHERINFORMATION**
 
 None.
 **PART
        III**
 
 **ITEM
        10. DIRECTORSAND EXECUTIVE OFFICERS OF THE REGISTRANT**
 
 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. EXECUTIVECOMPENSATION**
 
 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. CERTAINRELATIONSHIPS AND RELATED TRANSACTIONS**
 
 Intentionally
        omitted. See the table of contents of this Annual Report on Form 10-K for
        explanation.
 
  70
 Table
            of Contecnts
  **ITEM
        14. 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, 2005,
        and December 31, 2004. The fees presented below represent total Vectren fees,
        the majority of which are allocated to Utility Holdings.
 
 
 2005
              
              2004Audit
                  Fees(1)
              
              $
              1,409,862
              
              $
              1,424,910Audit-Related
                  Fees(2)
              
              
              50,000
              
              
              13,650Tax
                  Fees(3)
              
              
              128,208
              
              
              103,663All
                  Other Fees(4)
              
              
              -
              
              
              -Total
                  Fees Paid to Deloitte(5)
              
              $
              1,588,070
              
              $
              1,542,223
 (1)
                  Aggregate
                      fees incurred and payable to Deloitte for professional services
                      rendered
                      for the audits of the Company’s 2005 and 2004 fiscal year annual financial
                      statements and the review of financial statements included
                      in Company’s
                      Forms 10-K or 10-Q filed during the Company’s 2005 and 2004 fiscal years.
                      This includes fees incurred for audit services related to regulatory
                      filings and certain of the Company’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 $100,262 and $74,185 in 2005 and
                      2004,
                      respectively.
 
 (2)
                  Audit
                      related fees consisted principally of reviews related to various
                      financing
                      transactions and consultation on various accounting issues.
                      In addition,
                      this amount includes the reimbursement of out-of-pocket costs
                      incurred
                      related to the provision of these services totaling $0 and
                      $650 in 2005
                      and 2004, respectively.
 
 (3)
                  Tax
                      fees consisted of fees paid to Deloitte for the review of tax
                      returns,
                      consultation on other tax matters of the Company, 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 $9,896 and $2,788 in 2005 and 2004,
                      respectively.
 
 (4)
                  All
                      Other Fees—None.
 
 (5)
                  Pursuant
                      to its charter, the Audit committee 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 the Company,
                      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 fiscal year and related
                      fees
                      were approved by the Audit committee in accordance with this
                      policy.
 71
 Table
              of Contecnts
 
 **PART
        IV**
 
 **ITEM15. 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, 2005, 2004, and 2003, 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**
 
 AdditionsBalance
                    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
                    2005 – Accumulated provision foruncollectible
                    accounts
                
                $
                1.9
                
                $
                14.4
                
                $
                -
                
                $
                13.7
                
                $
                2.6Year
                    2004 – Accumulated provision foruncollectible
                    accounts
                
                $
                3.1
                
                $
                10.7
                
                $
                -
                
                $
                11.9
                
                $
                1.9Year
                    2003 – Accumulated provision foruncollectible
                    accounts
                
                $
                5.5
                
                $
                12.2
                
                $
                -
                
                $
                14.6
                
                $
                3.1OTHER
                    RESERVES:Year
                    2005 – Restructuring costs
                
                $
                2.7
                
                $
                -
                
                $
                -
                
                $
                0.3
                
                $
                2.4Year
                    2004 – Restructuring costs
                
                $
                3.2
                
                $
                -
                
                $
                -
                
                $
                0.5
                
                $
                2.7Year
                    2003 – Restructuring costs
                
                $
                3.6
                
                $
                -
                
                $
                -
                
                $
                0.4
                
                $
                3.2
  72
 Table
            of Contecnts
  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
        74.
 
 
 **Vectren
        Utility Holdings, Inc.**
 **2005
        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 2002.32.1
              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
              List
                  of Company’s Significant
                  Subsidiaries23
              Consent
                  of Registered Public Accounting
                  Firm
 
 73
 Table
              of Contecnts
 
 
 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.)
                  March 1,
                  2000. (Filed and designated in Form 10-K for the year ended December
                  31,
                  2001, File No. 1-15467, as Exhibit 4.1.) August 1, 2004. (Filed
                  and
                  designated in Form 10-K for the year ended December 31, 2004, File
                  No.
                  1-15467, as Exhibit 4.1.) October 1, 2004. (Filed and designated
                  in Form
                  10-K for the year ended December 31, 2004, File No. 1-15467, as
                  Exhibit
                  4.2.)
 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, 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 4.1); 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, 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
                  November 29, 2001, File No. 1-16739, as Exhibit 4.1); Third Supplemental
                  Indenture, among Vectren Utility Holdings, Inc., Indiana Gas Company,
                  Inc., Southern Indianan 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).
 
 74
 Table
            of Contecnts
 **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
              Indiana
                  Energy, Inc. Nonqualified Deferred Compensation Plan effective
                  January 1,
                  1999. (Filed and designated in Form 10-Q for the quarterly period
                  ended
                  December 31, 1998, File No. 1-9091, as Exhibit
                  10-H.)
 10.5
              Indiana
                  Energy, Inc. Executive Restricted Stock Plan as amended and restated
                  effective October 1, 1998. (Filed and designated in Form 10-K for
                  the
                  fiscal year ended September 30, 1998, File No. 1-9091, as Exhibit
                  10-O.)
                  First Amendment, 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-I.).
 10.6
              Indiana
                  Energy, Inc. Director's Restricted Stock Plan as amended and restated
                  effective May 1, 1997. (Filed and designated in Form 10-Q for the
                  quarterly period ended June 30, 1997, File No. 1-9091, as Exhibit
                  10-B.)
                  First Amendment, 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-J.) Second Amendment, Plan renamed the Vectren Corporation
                  Directors Restricted Stock Plan effective October 1, 2000. (Filed
                  and
                  designated in Form 10-K for the year ended December 31, 2000, File
                  No.
                  1-15467, as Exhibit 10-34.) Third Amendment, effective March 28,
                  2001.
                  (Filed and designated in Form 10-K for the year ended December
                  31, 2000,
                  File No. 1-15467, as Exhibit
                  10-35.)
 10.7
              Vectren
                  Corporation At Risk Compensation Plan effective May 1, 2001. (Filed
                  and
                  designated in Vectren Corporation’s Proxy Statement dated March 16, 2001,
                  File No. 1-15467, as Appendix B.)
 10.8
              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.)
 10.9
              Vectren
                  Corporation Employment Agreement between Vectren Corporation and
                  Niel C.
                  Ellerbrook dated as of March 31, 2000. (Filed and designated in
                  Form 10-Q
                  for the quarterly period ended June 30, 2000, File No. 1-15467,
                  as Exhibit
                  99.1.)
 10.10
              Vectren
                  Corporation Employment Agreement between Vectren Corporation and
                  Jerome A.
                  Benkert, Jr. dated as of March 31, 2000. (Filed and designated
                  in Form
                  10-Q for the quarterly period ended June 30, 2000, File No. 1-15467,
                  as
                  Exhibit 99.3.)
 10.11
              Vectren
                  Corporation Employment Agreement between Vectren Corporation and
                  Carl L.
                  Chapman dated as of March 31, 2000. (Filed and designated in Form
                  10-Q for
                  the quarterly period ended June 30, 2000, File No. 1-15467, as
                  Exhibit
                  99.4.)
 10.12
              Vectren
                  Corporation Employment Agreement between Vectren Corporation and
                  Ronald E.
                  Christian dated as of March 31, 2000. (Filed and designated in
                  Form 10-Q
                  for the quarterly period ended June 30, 2000, File No. 1-15467,
                  as Exhibit
                  99.5.)
 10.13
              Vectren
                  Corporation Employment Agreement between Vectren Corporation and
                  Richard
                  G. Lynch dated as of March 31, 2000. (Filed and designated in Form
                  10-Q
                  for the quarterly period ended June 30, 2000, File No. 1-15467,
                  as Exhibit
                  99.8.)
 10.14
              Vectren
                  Corporation Employment Agreement between Vectren Corporation and
                  William
                  S. Doty dated as of April 30, 2001. (Filed and designated in Form
                  10-K,
                  for the year ended December 31, 2001, File No. 1-15467, as Exhibit
                  10.43.)
 10.15
              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.)
 10.16
              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.)
 10.17
              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.)
  75
 Table
            of Contecnts
 10.18
              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.)
 10.19
              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.)
 10.20
              Gas
                  Sales and Portfolio Administration Agreement between Vectren Energy
                  Delivery of Ohio and ProLiance Energy, LLC, effective October 31,
                  2000.
                  (Filed and designated in Form 10-K, for the year ended December
                  31, 2001,
                  File No. 1-15467, as Exhibit 10-24.)
 10.21
              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.)
 10.22
              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.)
 10.23
              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.)
 10.24
              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.)
 
 **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 October
                  29,
                  2003. (Filed and designated in Quarterly Report on Form 10-Q filed
                  November 13, 2003, File No. 1-15467, as Exhibit 3.1.)
 
 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.)
 
 76
 Table
              of Contecnts
 
 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
        March 1, 2006   /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
                Officer,
                  & Director
                (Principal
                  Executive Officer)
              
              March
                  1, 2006Niel
                  C. Ellerbrook/s/
                  Jerome A. Benkert, Jr.
              
              Executive
                  Vice President,
              
              March
                  1, 2006Jerome
                  A. Benkert, Jr.
              
              Chief
                  Financial Officer, &
                Director
                  (Principal Financial
                Officer)/s/
                  M. Susan Hardwick
              
              Vice
                  President & Controller
              
              March
                  1, 2006M.
                  Susan Hardwick
              
              (Principal
                  Accounting Officer)/s/
                  Ronald E. Christian
              
              Director
              
              March
                  1, 2006Ronald
                  E. Christian/s/
                  William S. Doty
              
              Director
              
              March
                  1, 2006William
                  S. Doty