UNITED STATES
                       SECURITIES AND EXCHANGE COMMISSION
                             Washington, D.C. 20549

                                    FORM 10-K
(Mark One)

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

For the fiscal year ended December 31, 2002
                                       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           (IRS Employer Identification No.)
 incorporation or organization)

  20 N.W. Fourth Street, 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 Stock - Without Par                          None


<PAGE>


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 |X|. 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. |X|

Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act). Yes ___. No |X|.

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
28, 2002 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                  March 15, 2003
 --------------------------------     ----------------           --------------
            Class                     Number of Shares                 Date

                       Documents Incorporated by Reference

Certain information in Vectren Corporation's definitive Proxy Statement for the
2003 Annual Meeting of Stockholders, which was filed with the Securities and
Exchange Commission pursuant to Regulation 14A, on March 27, 2003, is
incorporated by reference in Part III of this Form 10-K.


                                   Definitions

AFUDC:  allowance for funds used     MMBTU:  millions of British thermal units
        during construction
APB:    Accounting Principles Board  MW:  megawatts

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

<PAGE>

                                Table of Contents

 Item                                                                    Page
 Number                                                                 Number
                                Part I

   1    Business .....................................................     1
   2    Properties ...................................................     5
   3    Legal Proceedings.............................................     6
   4    Submission of Matters to Vote of Security Holders.............     6
..
                                Part II

   5    Market for the Company's Common Equity and Related
        Stockholder Matters ..........................................     7
   6    Selected Financial Data.......................................     8
   7    Management's Discussion and Analysis of Results of
        Operations and Financial Condition............................     9
   7A   Qualitative and Quantitative Disclosures About Market Risk....    28
   8    Financial Statements and Supplementary Data...................    30
   9    Change in and Disagreements with Accountants on
        Accounting and Financial Disclosure...........................    65

                               Part III

  10    Directors and Executive Officers of the Company...............    65
  11    Executive Compensation........................................    66
  12    Security Ownership of Certain Beneficial Owners and
        Management and Related Stockholder Matters....................    68
  13    Certain Relationships and Related Transactions................    70

                                Part IV

  14    Controls and Procedures.......................................    71
  15    Exhibits, Financial Statement Schedules, and
        Reports on Form 8-K...........................................    71
        Signatures....................................................    74
        Certifications................................................    75

                              Access to Information

Vectren Corporation makes available all SEC filings and recent annual reports
free of charge, including those of its wholly owned subsidiaries, 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:                   Phone Number:   Investor Relations Contact:
P.O. Box 209                      (812) 491-4000   Steven M. Schein
Evansville, Indiana  47702-0209                    Vice President, Investor
                                                      Relations
                                                   sschein@vectren.com





<PAGE>


                                     PART I

ITEM 1. BUSINESS

                           Description of the Business

Vectren Utility Holdings, Inc. (VUHI 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.

Indiana Gas provides natural gas distribution and transportation services to a
diversified customer base in 49 of Indiana's 92 counties. SIGECO provides
electric generation, transmission, and distribution services to 8 counties in
southwestern Indiana, including counties surrounding Evansville, and
participates in the wholesale power market. SIGECO also provides natural gas
distribution and transportation services to 10 counties in southwestern Indiana,
including counties surrounding Evansville. The Ohio operations provide natural
gas distribution and transportation services to 17 counties in west central
Ohio, including counties surrounding Dayton.

Vectren is an energy and applied technology holding company headquartered in
Evansville, Indiana. The Company was organized on June 10, 1999 solely for the
purpose of effecting the merger of Indiana Energy and SIGCORP. On March 31,
2000, the merger of Indiana Energy with SIGCORP and into Vectren was consummated
with a tax-free exchange of shares and has been accounted for as a
pooling-of-interests in accordance with APB Opinion No. 16 "Business
Combinations" (APB 16).

Both Vectren and VUHI are exempt from registration pursuant to Section 3(a)(1)
and 3(c) of the Public Utility Holding Company Act of 1935.

Acquisition of the Gas Distribution Assets of The Dayton Power and Light Company

On October 31, 2000, the Company acquired the natural gas distribution assets of
The Dayton Power and Light Company for $471 million, including transaction
costs. The acquisition has been accounted for as a purchase transaction in
accordance with APB 16, and accordingly, the results of operations of the
acquired assets are included in the Company's financial results since the date
of acquisition.

The Company acquired the natural gas distribution assets as a tenancy in common
through two separate wholly owned subsidiaries. Vectren Energy Delivery of Ohio,
Inc. (VEDO) holds a 53% undivided ownership interest in the assets, and Indiana
Gas holds a 47% undivided ownership interest. VEDO is the operator of the
assets, and these operations are referred to as "the Ohio operations."

                      Narrative Description of the Business

The Company segregates its businesses into gas utility services and electric
utility services. 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 west central Ohio. The Electric Utility Services
segment includes the operations of SIGECO's electric transmission and
distribution services, which provides electricity primarily to southwestern
Indiana, and SIGECO's power generating and power marketing operations.

At December 31, 2002, the Company had $2.4 billion in total assets, with $1.6
billion (67%) attributed to the gas utility operations and $0.8 billion (33%)
attributed to the electric utility operations. Net income for the year ended
2002 was $93.6 million with $39.0 million attributed to gas utility operations
and $54.6 million attributed to electric utility operations. Net income, as
restated, for the year ended 2001 was $40.1 million. The year ending December
31, 2001 included nonrecurring charges with an after tax impact of $15.9
million. Nonrecurring items net of tax in 2001 included $7.7 million of merger
and integration costs, $9.3 million of restructuring costs, and a $1.1 million
gain resulting from a cumulative effect of change in accounting principle.

For further information refer to Note 3 regarding the restatement of previously
reported information, Note 14 regarding the segments' activities and assets,
Note 15 regarding special charges in 2001 and 2000, and Note 12 regarding the
cumulative effect of change in accounting principle included under Item 8
Financial Statements and Supplementary Data. Following is a more detailed
description of the gas and electric utility operations.

                              Gas Utility Services

At December 31, 2002, the Company supplied natural gas service to 966,761
Indiana and Ohio customers, including 882,151 residential, 80,483 commercial,
and 4,127 industrial and other customers. This represents customer base growth
of 1.4% compared to 2001.

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, 2002, natural gas revenues were approximately
$909.0 million of which residential customers accounted for 67%, commercial 23%,
and industrial and other 10%, respectively.

The Company receives gas revenues by selling gas directly to residential,
commercial, and industrial customers at approved rates or by transporting gas
through its pipelines at approved rates to commercial and industrial customers
that have purchased gas directly from other producers, brokers, or marketers.
Total volumes of gas provided to both sales and transportation customers
(throughput) was 207,693 MDth for the year ended December 31, 2002. Transported
gas represented 44% of total 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 owns and operates seven
underground gas storage fields and six liquefied petroleum air-gas manufacturing
plants. The Company also contracts with ProLiance and other parties to ensure
availability of gas. Natural gas purchased from suppliers is injected into
storage during periods of light demand which are typically periods of lower
prices. The injected gas is then available to supplement contracted and
manufactured volumes during periods of peak requirements. Approximately 909,500
MCF of gas per day can be withdrawn during peak demand periods from all sources
and for all utilities.

Gas Purchases

In 2002, the Company purchased natural gas from multiple suppliers including
ProLiance Energy, LLC (ProLiance). ProLiance is an unconsolidated, nonregulated,
energy marketing affiliate of Vectren and Citizens Gas and Coke Utility. (See
Note 5 in the Company's consolidated financial statements included in Item 8
Financial Statements and Supplementary Data regarding transactions with
ProLiance ). The Company purchased 120,764 MDth volumes of gas in 2002 at an
average cost of $4.57 per Dth, of which 94% was purchased from ProLiance. The
average cost of gas per Dth purchased for the last five years was; $4.57 in
2002; $5.83 in 2001; $5.60 in 2000; $3.58 in 1999; and $3.53 in 1998.

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 issues
involving manufactured gas plants.

                            Electric Utility Services

At December 31, 2002, the Company supplied electric service to 134,057 Indiana
customers, including 116,979 residential, 16,881 commercial, and 197 industrial
and other customers. This represents customer base growth of 0.6% compared to
2001. In addition, the Company is obligated to provide for firm power
commitments to several municipalities and to maintain spinning reserve margin
requirements under an agreement with the East Central Area Reliability Group.

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, 2002, retail and firm wholesale electricity
sales totaled 6,187,132 MWh, resulting in revenues of approximately $305.3
million. Residential customers accounted for 35% of 2002 revenues; commercial
26%; industrial and municipalities 37%; and other 2%. In addition, the Company
sold 10,711,614 MWh through non-firm wholesale contracts in 2002 generating
revenue of $302.8 million.

Generating Capacity

Installed generating capacity as of December 31, 2002 was rated at 1,351 MW.
Coal-fired generating units provide 1,056 MW of capacity, and gas or oil-fired
turbines used for peaking or emergency conditions provide 295 MW. New peaking
capacity of 80 MW fueled by natural gas was added during 2002 and was available
for the summer peaking season.

In addition to its generating capacity, throughout 2002 the Company had 82MW
available under firm contracts and 95 MW available under interruptible
contracts. On January 1, 2003, a 50 MW firm contract expired and was no longer
required and therefore not renewed.

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, Wabash Valley Power
Association, and the City of Jasper, Indiana, providing the historic ability to
simultaneously interchange approximately 500 MW. However, the ability of the
Company to effectively utilize the electric transmission grid in order to
achieve import/export capability may be impacted because the Company, as a
member of the Midwest Independent System Operator (MISO), has turned over
operational control over the interchange facilities and its own transmission
assets like many other Midwestern electric utilities to the MISO. See Item 7
Management's Discussion and Analysis of Results of Operations and Financial
Condition regarding the Company's participation in MISO.



<PAGE>


Total load for each of the years 1998 through 2002 at the time of the system
summer peak, and the related reserve margin, is presented below in MW.


Date of summer peak load        8/5/02   7/31/01   8/17/00   7/6/99   7/21/98
                                ------   -------   -------   ------   -------
Total load at peak (1)          1,258     1,234     1,212    1,255     1,154

Generating capability           1,351     1,271     1,256    1,256     1,256
Firm purchase supply               82        82        75        -         -
Interruptible contracts            95        95        95       95        85
-----------------------------------------------------------------------------
Total power supply capacity     1,528     1,448     1,426    1,351     1,341
-----------------------------------------------------------------------------

Reserve margin at peak            21%       17%       18%       8%       16%
-----------------------------------------------------------------------------


(1)  The total load at peak is increased 25MW in 2002, 2001, 1999, and 1998 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. On the date of peak in 2000,
     summer cycler programs were not activated.

The winter peak load of the 2001-2002 season of approximately 854 MW occurred on
March 4, 2002 and was 8% lower than the previous winter peak load of
approximately 925 MW which occurred on December 19, 2000.

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 32 MW of
capacity, in addition to its generating capacity, for use in other operations.

Fuel Costs and Purchased Power

Electric generation for 2002 was fueled by coal (97.5%) and natural gas (2.5%).
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 Vectren. Approximately 3.1 million tons of coal was purchased for
generating electricity during 2002. Of this amount, Vectren Fuels, Inc. supplied
2.7 million tons from its mines and third party purchases. The average cost of
coal consumed in generating electrical energy for the years 1998 through 2002
follows:

                                             Year
                    ------------------------------------------------------
Avg. Cost Per         2002       2001        2000        1999        1998
                    -------    -------     -------     -------     -------
Ton                 $ 23.50    $ 22.48     $ 22.49     $ 21.88     $ 21.34
MWh                   11.00      10.53       10.39       10.13        9.97


The Company will also purchase 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 non-firm wholesale customers. Volumes purchased in
2002 totaled 10,362,196 MWh.

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 a
discussion of the Company's Clean Air Act Compliance Plan, and the USEPA's
lawsuit against SIGECO for alleged violations of the Clean Air Act.

Competition

See Item 7 Management's Discussion and Analysis of Results of Operations and
Financial Condition regarding competition within the public utility industry for
the Company's regulated Indiana and Ohio operations.

                                    Personnel

As of December 31, 2002, the Company and its consolidated subsidiaries had 1,581
employees, of which 896 are subject to collective bargaining arrangements.

In August 2001, the Company signed a new four-year labor agreement, ending in
September 2005 with Local 135 of the Teamsters, Chauffeurs, Warehousemen and
Helpers. The new agreement provides for annual wage increases of 3.25%, a new
401(k) savings plan and improvements in the areas of health insurance and
pension benefits.

Concurrent with the Company's purchase of the Ohio operations, VEDO and Local
Union 175, Utility Workers Union of America approved a labor agreement effective
November 2000, through October 2005. The agreement provides a 3.25% wage
increase each year, and the other terms and conditions are substantially the
same as the agreement reached between the Utility Workers Union and Dayton Power
and Light Company in August of 2000.

In July 2000, SIGECO signed a new four-year labor agreement with Local 702 of
the International Brotherhood of Electrical Workers, ending June 2004. The new
agreement provides a 3% wage increase for each year in addition to improvements
in health care coverage, retirement benefits and incentive pay.

ITEM 2. PROPERTIES

Gas Utility Services

Indiana Gas owns and operates four gas storage fields located in Indiana
covering 58,489 acres of land with an estimated ready delivery from storage
capability of 4.2 BCF of gas with delivery capabilities of 119,160 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 31,000 MCF of manufactured gas
per day. In addition to its owned storage and manufacturing and daily delivery
capabilities, Indiana Gas contracts for a maximum of 17.2 BCF of gas
availability across various pipelines with a delivery capability of 283,298 MCF
per day. Indiana Gas' gas delivery system includes 11,590 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 8.7 BCF of gas with delivery capabilities of 124,748 MCF per day.
In addition to its owned storage and daily delivery capabilities, SIGECO
contracts for a maximum of 0.5 BCF of gas availability across various pipelines
with a delivery capability of 18,753 MCF per day. SIGECO's gas delivery system
includes 2,996 miles of distribution and transmission mains, all of which are
located in Indiana.

The Ohio operations owns and operates three liquefied petroleum (propane)
air-gas manufacturing plants and one cavern for propane storage, all of which
are located in Ohio. The plants and cavern can store 3.7 million gallons of
propane, and the plants can manufacture for delivery 51,047 MCF of manufactured
gas per day. In addition to its owned storage and manufacturing and daily
delivery capabilities, the Ohio operations contracts for a maximum of 13.2 BCF
of gas availability across various pipelines with a delivery capability of
281,491 MCF per day. The Ohio operations' gas delivery system includes 5,176
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, 2002, was rated at
1,351 MW. SIGECO's coal-fired generating facilities are: the Brown Station with
500 MW of capacity, located in Posey County approximately eight miles east of
Mt. Vernon, Indiana; the Culley Station with 406 MW of 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: the 80 MW Brown 3 Gas Turbine 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, 50MW and Broadway Avenue Unit 2,
65MW); two Northeast Gas Turbines located northeast of Evansville in Vanderburgh
County, Indiana with a combined capacity of 20 MW; and a new 80MW turbine also
located at the Brown station (Brown Unit 4) placed into service in 2002. 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.

SIGECO's transmission system consists of 829 circuit miles of 138,000 and 69,000
volt lines. The transmission system also includes 27 substations with an
installed capacity of 4,221.2 megavolt amperes (Mva). The electric distribution
system includes 3,212 pole miles of lower voltage overhead lines and 275 trench
miles of conduit containing 1,541 miles of underground distribution cable. The
distribution system also includes 95 distribution substations with an installed
capacity of 1,939.5 Mva and 50,030 distribution transformers with an installed
capacity of 2,352.3 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. 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. See Note 10 of its consolidated
financial statements included in Item 8 Financial Statements and Supplementary
Data regarding the Clean Air Act and related legal proceedings. Legal
proceedings involving transactions with ProLiance were substantially resolved
during 2002. See Note 5 for a discussion of regulatory matters related to
ProLiance.

ITEM 4. Submission of Matters to Vote of Security Holders

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

                                     PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

Common Stock

Market Price

All of the outstanding shares of VUHI's common stock are owned by Vectren.
VUHI's common stock is not traded.

There are no outstanding options or warrants to purchase VUHI's common equity or
securities convertible into VUHI's common equity. Additionally, VUHI has no
plans to publicly offer any of its common equity.

Dividends Paid to Parent

During 2002, VUHI paid dividends to its parent company of $17.9 million in each
of the first three quarters and $18.0 million in the fourth quarter.

During 2001, VUHI paid dividends to its parent company of $16.5 million, $14.3
million, $15.9 million, and $18.2 million in the first, second, third, and
fourth quarters, respectively.

On January 22, 2003, the board of directors declared a dividend $17.9 million,
payable to Vectren on March 3, 2003.

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 dues 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
                                      ---------------------
2002                                    High          Low
----                                  -------       -------
     First Quarter                    $ 25.60       $ 24.50
     Second Quarter                     25.40         24.50
     Third Quarter                      25.95         24.80
     Fourth Quarter                     26.08         25.15

2001
----
     Fourth Quarter                   $ 25.50       $ 24.95





<PAGE>


ITEM 6. SELECTED FINANCIAL DATA

The following selected financial data is derived from the Company's audited
consolidated financial statements and should be read in conjunction with those
financial statements and notes thereto contained in this Form 10-K. The
financial information as of and for the years ended December 31, 2001 and 2000
has been restated. Common shareholder's equity as of January 1, 2000 also
reflects adjustments related to years prior to 2000. See Note 3 to the
consolidated financial statements included under Item 8 Financial Statements and
Supplementary Data for further information on the restatement.
<TABLE>
<CAPTION>
                                                     Year Ended December 31
-----------------------------------------------------------------------------------------
In millions                                2002     2001 (1)  2000(2,3)   1999      1998
-----------------------------------------------------------------------------------------
                                                      (As Restated)
                                                   -------------------
<S>                                      <C>       <C>        <C>        <C>      <C>
Operating Data:
Operating revenues                       $1,517.1  $1,400.8   $1,154.8   $ 807.1  $ 785.1
Operating income                            199.2     123.3      129.9     109.0    104.0
Income before cumulative effect
  of change in accounting principle          93.6      39.0       52.5      75.4     69.3
Net income                                   93.6      40.1       52.5      75.4     69.3

Balance Sheet Data:
Total assets                              2,439.3   2,402.6    2,454.3   1,623.9  1,568.7
Redeemable preferred stock                    0.3       0.5        8.1       8.2      8.3
Long-term debt-net of current
  maturities & debt subject to tender       841.2     900.9      572.6     450.1    351.7
Common shareholder's equity                 728.3     704.1      573.6     583.2    566.1
</TABLE>


(1)  Merger and integration related costs incurred for the year ended December
     31, 2001 totaled $2.8 million. These costs relate primarily to transaction
     costs, severance and other merger and acquisition 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 in 2000 to reflect this decision. These information system
     assets are owned by a wholly owned subsidiary of Vectren, and the fees are
     allocated by the subsidiary for the use of these systems by the Company. As
     a result of the shortened useful lives, additional fees were incurred by
     the Company during 2001, resulting in an increase in other operating
     expenses of $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.

(2)  Merger and integration related costs incurred for the year ended December
     31, 2000 totaled $32.7 million. These costs relate primarily to transaction
     costs, severance and other merger and acquisition integration activities.
     As a result of merger integration activities, management identified certain
     information systems to be retired in 2001. Accordingly, the useful lives of
     these assets were shortened to reflect this decision. These information
     system assets are owned by a wholly owned subsidiary of Vectren, and the
     fees are allocated by the subsidiary for the use of these systems by the
     Company. As a result of the shortened useful lives, additional fees were
     incurred by the Company during 2000, resulting in an increase in other
     operating expenses of $11.4 million for the year ended December 31, 2000.
     In total, merger and integration related costs incurred for the year ended
     December 31, 2000 were $44.1 million ($31.6 million after tax).

(3)  Reflects two months of results of the Ohio operations.


<PAGE>


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

The following discussion and analysis should be read in conjunction with the
consolidated financial statements and notes thereto. As discussed in Note 3 in
the consolidated financial statements, subsequent to the issuance of the
Company's 2001 financial statements, the Company's management determined that
previously issued financial statements should be restated. As a result, the
Company has restated its 2001 and 2000 financial statements and has increased
reported retained earnings as of January 1, 2000 by $1.7 million. The
restatement had the effect of decreasing net income for 2001 by approximately
$10.6 million and increasing net income for 2000 by approximately $100,000. Note
3 in the consolidated financial statements includes a summary of the significant
effects of the restatement. The effect of the restatement on quarterly results,
including previously reported 2002 quarterly information, is discussed in Note
18. The following discussion and analysis gives effect to the restatement.

                       Consolidated Results of Operations

In 2002, consolidated net income was $93.6 million, an increase of $53.5 million
when compared to 2001, as restated. The year ended December 31, 2001 included
nonrecurring merger, integration, and restructuring costs and other nonrecurring
items totaling $15.9 million after tax. In addition to the nonrecurring 2001
items, the increase reflects improved margins and lower operating costs. These
resulted from favorable weather and a return to lower gas prices and the related
reduction in costs incurred in 2001.

In 2001, consolidated net income of $40.1 million decreased $12.4 million when
compared to 2000. The year ended December 31, 2000 included nonrecurring merger
and integration costs totaling $31.6 million after tax. The decrease reflects
lower earnings resulting from extraordinarily high gas costs early in 2001 that
unfavorably impacted margins and operating costs including uncollectible
accounts expense, interest, and excise taxes; heating weather that was 9% warmer
than the prior year; and a weakened national economy.

Restatement of Previously Reported Results

The Company identified adjustments that, in the aggregate, reduced previously
reported 2001 earnings by approximately $10.6 million after tax and other
adjustments, as described below, related to 2000 and prior periods. Adjustments
were also made to previously reported 2002 quarterly results. In addition to
adjustments affecting previously reported net income, other reclassifications
were made to the previously reported 2001 and 2000 results to conform with the
2002 presentation.

Previously Reported 2001 and 2000 Net Income Adjustments

The Company determined that $11.6 million ($7.2 million after tax) of gas costs
were improperly recorded as recoverable gas costs due from customers. The error
related primarily to the accounting for natural gas inventory and resulted in an
overstatement of 2001 earnings.

The Company also identified an accounting error related to certain employee
benefit and other related costs that are routinely accumulated on the balance
sheet and systematically cleared to operating expense and capital projects.
Because of inadequate loading rates, these costs were not fully cleared to
operating expense and capital projects in 2001. As a result, 2001 earnings were
overstated by $5.6 million ($3.5 million after tax).

The accounting for certain wholesale power marketing contracts was modified to
comply with SFAS 133, which became effective on January 1, 2001. The cumulative
effect at adoption was decreased by $2.8 million after tax. This change was
offset substantially by an increase in electric margins throughout 2001.

The Company identified reconciliation errors and other errors related to the
recording of estimates that were not significant, either individually or in the
aggregate. As a result of these additional items, 2001 earnings were reduced by
$2.2 million ($1.4 million after tax). Originally reflected in 2001, the
correction of the year 2000 overstatement of electric revenue totaling $2.4
million ($1.5 million after tax), now reflected in 2000 as discussed below,
significantly offset these additional items.

The Company also determined that certain billings and collections had been
improperly recorded in 2000, resulting in an understatement of gas revenue by
$1.8 million ($1.1 million after tax) and an overstatement of electric revenue
by $2.4 million ($1.5 million after tax). Other errors were identified that
increased 2000 earnings by $0.8 million ($0.5 million after tax). The impact of
the restatement of results for the year ended 2000 is an increase to net income
of approximately $100,000.

Previously Reported 2002 Quarterly Net Income Adjustments

As previously reported, in the second quarter of 2002 the Company recorded $5.2
million ($3.2 million after tax) of carrying costs for DSM programs pursuant to
existing IURC orders and based on an improved regulatory environment. During the
audit of the three years ended December 31, 2002, management determined that the
accrual of such carrying costs was more appropriate in periods prior to 2000
when DSM program expenditures were made. Therefore, such carrying costs
originally reflected in 2002 quarterly results were reversed and reflected in
common shareholders' equity as of January 1, 2000. In addition, the Company
identified other adjustments that were not significant, either individually or
in the aggregate that increased previously reported 2002 quarterly pre-tax and
after tax earnings by approximately $1.8 million and $1.1 million after tax,
respectively. The cumulative impact from of these adjustments reduced previously
reported earnings for the nine months ended September 30, 2002 by approximately
$2.1 million.

Beginning Retained Earnings Adjustments

In addition to the adjustment of DSM costs above, the Company identified other
errors that were not significant, either individually or in the aggregate that
relate to years prior to 2000. As a result of these additional items, beginning
common shareholders' equity was reduced by $1.5 million. Accordingly, retained
earnings as of January 1, 2000 reflects a cumulative net increase of $1.7
million.

Other Balance Sheet Adjustments

Certain reclassifications were made to reflect separate Company prepaid and
accrued taxes that result in the consolidated tax position. This adjustment
added approximately $26.6 million to receivables due from other Vectren
companies and prepaid and other current assets with a corresponding increase in
payables due to other Vectren companies, accrued liabilities, and deferred taxes
as of December 31, 2001. The Company also reclassified all previously recorded
goodwill not included in rates to goodwill on the balance sheet. This adjustment
resulted in a $5.9 million decrease in other assets, a $3.0 million decrease in
prepayments and other current assets and an $8.9 million increase in goodwill.

The Company has restated its financial statements to give effect to the matters
discussed above. A summary of the significant effects of the restatement on
previously reported financial position and results of operations is included in
Note 3 to the consolidated financial statements. The effects of the restatement
on 2001 quarterly results and on 2002 previously reported quarterly information,
is discussed in Note 18. The consolidated financial statements are included
under Item 8 Financial Statements and Supplementary Data.

Nonrecurring Items in 2001 and 2000

Merger & Integration Costs

Merger and integration costs incurred for the years ended December 31, 2001 and
2000 were $2.8 million and $32.7 million, respectively. Merger and integration
activities resulting from the 2000 merger were completed in 2001.

Since March 31, 2000, $35.5 million has been expensed associated with merger and
integration activities. Accruals were established at March 31, 2000 totaling
$19.3 million. Of this amount, $5.5 million related to employee and executive
severance costs, $11.7 million related to transaction costs and regulatory
filing fees incurred prior to the closing of the merger, and the remaining $2.1
million related to employee relocations that occurred prior to or coincident
with the merger closing. The remaining $16.2 million was expensed through
December 31, 2001 ($13.4 million in 2000 and $2.8 million in 2001) for
accounting fees resulting from merger related filing requirements, consulting
fees related to integration activities such as organization structure, employee
travel between company locations as part of integration activities, internal
labor of employees assigned to integration teams, investor relations
communications activities, and certain benefit costs.

The integration activities experienced by the Company included such things as
information system consolidation, process review and definition, organization
design and consolidation, and knowledge sharing.

As a result of merger integration activities, management retired certain
information systems in 2001. Accordingly, the useful lives of these assets were
shortened in 2000 to reflect this decision. These information system assets are
owned by a wholly owned subsidiary of Vectren, and the fees allocated by the
subsidiary for the use of these systems by the Company's subsidiaries are
reflected in other operating expenses. As a result of the shortened useful
lives, additional fees were incurred by the Company, resulting in additional
other operating expense of $9.6 million for the year ended December 31, 2001 and
$11.4 million for the year ended December 31, 2000.

In total, for the year ended December 31, 2001, merger and integration costs
totaled $12.4 million ($7.7 million after tax) compared to $44.1 million ($31.6
million after tax) in 2000.

Restructuring Costs

As part of continued cost saving efforts, in June 2001, the Company's management
and board of directors approved a plan to restructure, primarily, its regulated
operations. The restructuring plan included the elimination of certain
administrative and supervisory positions in its utility operations and corporate
office. Charges of $10.8 million were expensed in June 2001 as a direct result
of the restructuring plan. Additional charges of $4.2 million were incurred
during the remainder of 2001 primarily for consulting fees, employee relocation,
and duplicate facilities costs. In total, the Company incurred restructuring
charges of $15.0 million, ($9.3 million after tax) in 2001. These charges were
comprised of $7.6 million for employee severance, related benefits and other
employee related costs, $4.0 million for lease termination fees related to
duplicate facilities and other facility costs, and $3.4 million for consulting
and other fees incurred through December 31, 2001. The restructuring program was
completed during 2001, except for the departure of certain employees impacted by
the restructuring which occurred during 2002 and the final settlement of the
lease obligation which has yet to occur. (See Note 15 for further information on
restructuring costs.)

Cumulative Effect of Change in Accounting Principle

Resulting from the adoption of SFAS 133, certain contracts in the power
marketing operations that are periodically settled net were required to be
recorded at market value. Previously, the Company accounted for these contracts
on settlement. The cumulative impact of the adoption of SFAS 133 resulting from
marking these contracts to market on January 1, 2001 was an earnings gain of
approximately $1.8 million ($1.1 million after tax) recorded as a cumulative
effect of change in accounting principle in the Consolidated Statements of
Income.

Significant Fluctuations

Utility Margin

Gas Utility Margin
Gas Utility margin for the year ended December 31, 2002 of $337.2 million
increased $26.5 million, or 9%. The increase is primarily due to weather 7%
cooler for the year and 31% cooler in the fourth quarter. Rate recovery of
excise taxes in Ohio effective July 1, 2001, an increase in the Percent of
Income Payment Plan rider affecting Ohio customers, and customer growth of over
1% also contributed. The effects of cooler weather resulted in an overall 4%
increase in total throughput to 207.7 MMDth in 2002 from 199.3 MMDth in 2001.
Total throughput in 2000 was 181.2 MMDth, which includes two months of
throughput from the Ohio operations.

Gas Utility margin for the year ended December 31, 2001 of $310.7 million
increased $42.8 million, compared to 2000. Excluding the Ohio operations, gas
margin decreased by $17.9 million, or 7%. The primary factors contributing to
this decrease were weather that was 9% warmer than the prior year and the
unfavorable impact resulting from extraordinarily high gas costs early in 2001,
coupled with the effects of a weakened economy. These decreases were offset
somewhat by customer growth of nearly 1% compared to 2000.

Cost of gas sold was $571.8 million in 2002, $708.9 million in 2001, and $552.5
million in 2000. Cost of gas sold decreased $137.1 million, or 19%, during 2002
compared to 2001, primarily due to a return to lower gas prices somewhat offset
by an increase in retail volumes sold. Of the change in 2001 compared to 2000,
the Ohio operations contributed $179.4 million of the increase. Excluding the
Ohio operations, cost of gas sold decreased $23.0 million, or 4%, in 2001. The
decrease is primarily due to lower volumes sold due to the warmer weather and a
weakened economy, offset by an increase in gas prices. The total average cost
per dekatherm of gas purchased was $4.57 in 2002, $5.83 in 2001, and $5.60 in
2000. The price changes are due primarily to changing commodity costs in the
marketplace.

Electric Utility Margin
Electric Utility margin by customer type and non-firm wholesale margin separated
between realized margin and mark-to-market gains and losses follows:

                                                    Year ended December 31,
----------------------------------------------------------------------------
In millions                                2002         2001           2000
----------------------------------------------------------------------------
Retail & firm wholesale                  $ 215.3      $ 200.0        $ 201.2
Non-firm wholesale                          14.9         19.9           21.1
----------------------------------------------------------------------------
Total margin                             $ 230.2      $ 219.9        $ 222.3
============================================================================
Non-firm wholesale margin:
Realized margin                          $  18.5      $  18.4        $  21.1
Mark-to-market gains (losses)               (3.6)         1.5              -


Electric Utility margin for the year ended December 31, 2002 increased $10.3
million, or 5%, when compared to 2001. The increases result primarily from the
effect on retail sales of cooling weather considerably warmer than the prior
year. Weather in 2002 was 27% warmer when compared to 2001 and 23% warmer than
normal. In addition to weather, 2002 was positively affected by a cash return on
NOx compliance expenditures as the expenditures are made pursuant to a rate
recovery rider approved by the IURC in August 2001. As a result of warmer
weather, retail and firm wholesale volumes sold increased from 5.8 GWh in 2001
to 6.2 GWh in 2002. Volumes sold in 2000 were 5.9 GWh. The current year increase
in margin from retail sales was partially offset by lower margins earned in the
wholesale energy market.

Electric Utility margin for the year ended December 31, 2001 decreased $2.4
million, or 1%, compared to 2000 primarily from decreased sales to firm
wholesale customers and decreased margin on non-firm wholesale activity. The
decreases were partially offset by a 3% increase in residential and commercial
sales due to cooling weather 7% warmer than the prior year and a 3% increase in
the number of residential and commercial customers.

Periodically, generation capacity is in excess of that needed to serve retail
and firm wholesale customers. The Company markets this unutilized capacity to
optimize the return on its owned generation assets. The contracts entered into
are primarily short-term purchase and sale transactions that expose the Company
to limited market risk. While volumes both sold and purchased in the wholesale
market have increased during 2002, margins softened as a result of reduced price
volatility. As a result of increased activity offset by reduced price
volatility, margin from power marketing activities decreased $5.0 million during
2002 and $1.2 million during 2001. In 2002, volumes sold into the wholesale
market were 10.7 GWh compared to 3.4 GWh in 2001 and 1.6 GWh in 2000. Volumes
purchased from the wholesale market, some of which were utilized to serve retail
and firm wholesale customers, were 10.3 GWh in 2002 compared to 2.9 GWh in 2001
and 1.2 GWh in 2000.

Utility Operating Expenses

Utility Other Operating
Utility other operating expenses decreased $20.5 million for the year ended
December 31, 2002 when compared to 2001. The decrease results primarily from
lower charges for the use of corporate assets which had useful lives shortened
as a result of the merger and a return to lower gas prices and the related
reduction in costs incurred in 2001. Specific expenses affected by increased gas
costs in 2001 were uncollectible accounts expense and contributions to low
income heating assistance programs. Insurance recovery in 2002 of certain
maintenance costs incurred in 2001 also contributed to the decrease.

Excluding $33.2 million in additional expenses related to the Ohio operations,
utility other operating expenses for the year ended December 31, 2001 decreased
$1.1 million compared to 2000. The 2001 decrease results, primarily from prior
merger synergies offset by higher expenses resulting from increased gas costs.

Utility Depreciation & Amortization
Utility depreciation and amortization decreased $0.4 million for the year ended
December 31, 2002 when compared to 2001. The decrease results from the
discontinuance of goodwill amortization as required by SFAS 142, which
approximated $4.9 million in 2001, offset somewhat by depreciation of plant
additions.

Utility depreciation and amortization increased $14.8 million in 2001 when
compared to 2000. The increase is due to the inclusion of the Ohio operations
and depreciation of normal utility plant additions at Indiana Gas and SIGECO.
For the year ended December 31, 2001, the increase in utility depreciation and
amortization related to the Ohio operations was $12.9 million, including
amortization of goodwill of $4.9 million.

Utility Taxes Other Than Income Taxes
Utility taxes other than income taxes decreased $0.4 million in 2002 compared to
2001 as a result of lower revenues subject to gross receipts tax and increased
$15.0 million in 2001 compared to 2000. The year ended December 31, 2001
includes $15.3 million of additional expense related to the Ohio operations,
primarily state excise tax.

Utility Other Income - Net

Other- net
Utility other income, net increased $1.4 million in 2002 when compared to 2001
and amounts in 2001 were comparable to 2000. The increase in 2002 is primarily
attributable to gains recognized from the sale of excess emission allowances.

Equity in Earnings of Unconsolidated Affiliates
Equity in earnings of unconsolidated affiliates decreased $1.3 million in 2002
and $0.5 million in 2001 principally due to increased losses and increased
ownership in a company that manufactures autoclaved aerated concrete products
from fly ash.

Utility Interest Expense

Utility interest expense decreased $4.0 million in 2002 compared to 2001. The
decrease is attributable to lower outstanding borrowings during 2002 and lower
average interest rates on adjustable rate debt.

Utility interest expense increased $24.0 million during the 2001 compared to
2000. The increase is due primarily to interest related to financing the
acquisition of the Ohio operations and increased working capital requirements
resulting from higher natural gas prices.

Utility Income Tax

Federal and state income taxes related to utility operations increased $26.2
million for the year ended December 31, 2002 when compared to 2001. The increase
results principally from higher pre-tax earnings. The effective tax rate
increased in 2002 due to amortization of investment tax credits and higher
pre-tax income.

Federal and state income taxes related to utility operations decreased $16.6
million in 2001 when compared to 2000. The 2001 decrease is due to lower pre-tax
earnings. The effective tax rate decreased in 2001 due primarily to the
nondeductibility of certain merger and integration costs incurred in 2000 and
amortization of investment tax credits.

Competition

The utility industry has been undergoing dramatic structural change for several
years, resulting in increasing competitive pressures faced by electric and gas
utility companies. Increased competition may create greater risks to the
stability of utility earnings generally and may in the future reduce earnings
from retail electric and gas sales. 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. 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.

Other Operating Matters

Midwest Independent System Operator

The FERC approved the Midwest Independent System Operator (MISO) as the nation's
first regional transmission organization. Regional transmission organizations
place public utility transmission facilities in a region under common control.
The FERC has made regional transmission organizations a top priority to boost
competition and to provide more reliable power at lower rates. The Carmel,
Indiana, based MISO began some operations in December 2001 with control of
73,000 miles of transmission lines carrying up to 81,000 MW. More than 20 states
are included in the MISO from the Midwest and Plains states, to Texas, Arkansas,
and part of the Southeast. In December 2001, the IURC approved the Company's
request for authority to transfer operational control over its electric
transmission facilities to the MISO. That transfer occurred on February 1, 2002.

Issues pertaining to certain of MISO's tariff charges for its services remain to
be determined by the FERC. Given the outstanding tariff issues, as well as the
potential for additional growth in MISO participation, the Company is unable to
determine the future impact MISO participation may have on its operations.
Pursuant to an order from the IURC, certain MISO costs are deferred for future
recovery.

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, may be impacted. Given the
nature of MISO's policies regarding use of transmission facilities, as well as
ongoing FERC initiatives, it is difficult to predict the impact on operational
reliability. 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.


<PAGE>


Environmental Matters

The Company is subject to federal, state, and local regulations with respect to
environmental matters, principally air, solid waste, and water quality. Pursuant
to environmental regulations, the Company is required to obtain operating
permits for the electric generating plants that it owns or operates and
construction permits for any new plants it might propose to build. Regulations
concerning air quality establish standards with respect to both ambient air
quality and emissions from electric generating facilities, including particulate
matter, sulfur dioxide (SO2), and nitrogen oxides (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 to comply with.

Clean Air Act

NOx SIP Call Matter
The Clean Air Act (the Act) requires each state to adopt a State Implementation
Plan (SIP) to attain and maintain National Ambient Air Quality Standards (NAAQS)
for a number of pollutants, including ozone. If the USEPA finds a state's SIP
inadequate to achieve the NAAQS, the USEPA can call upon the state to revise its
SIP (a SIP Call).

In October 1998, the USEPA issued a final rule "Finding of Significant
Contribution and Rulemaking for Certain States in the Ozone Transport Assessment
Group Region for Purposes of Reducing Regional Transport of Ozone," (63 Fed.
Reg. 57355). This ruling found that the SIP's of certain states, including
Indiana, were substantially inadequate since they allowed for NOx emissions in
amounts that contributed to non-attainment with the ozone NAAQS in downwind
states. The USEPA required each state to revise its SIP to provide for further
NOx emission reductions. The NOx emissions budget, as stipulated in the USEPA's
final ruling, requires a 31% reduction in total NOx emissions from Indiana.

In June 2001, the Indiana Air Pollution Control Board adopted final rules to
achieve the NOx emission reductions required by the NOx SIP Call. Indiana's SIP
requires the Company to lower its system-wide NOx emissions to .14 lbs./MMBTU by
May 31, 2004 (the compliance date). This is a 65% reduction from emission levels
existing in 1999 and 1998.

The Company has initiated steps toward compliance with the revised regulations.
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 be the most effective method of reducing
NOx emissions where high removal efficiencies are required.

On August 28, 2001, the IURC issued an order that (1) approved the Company's
proposed project to achieve environmental compliance by investing in clean coal
technology, (2) approved the Company's initial cost estimate of $198 million for
the construction, subject to periodic review of the actual costs incurred, and
(3) approved a mechanism whereby, prior to an electric base rate case, the
Company may recover through a rider that is updated every six months a return on
its capital costs for the project, at its overall cost of capital, including a
return on equity. The first rider adjustment for ongoing cost recovery was
approved by the IURC on February 6, 2002. Based on the level of system-wide
emissions reductions required and the control technology utilized to achieve the
reductions, the current estimated clean coal technology construction cost ranges
from $240 million to $250 million and is expected to be expended during the
2001-2006 period. Through December 31, 2002, $70.0 million has been expended.

On June 5, 2002, the Company filed a new proceeding to update the NOx project
cost and to obtain approval of a second rider authorizing ongoing recovery of
depreciation and operating costs related to the clean coal technology. After the
equipment is installed and operational, related annual operating expenses,
including depreciation expense, are estimated to be between $24 million and $27
million. Such expenses would commence in 2004 when the technology becomes
operational. On January 3, 2003, the IURC approved a settlement that authorizes
total capital cost investment for this project up to $244 million (excluding
AFUDC) and recovery on those capital costs, as well as the recovery of future
operating costs, including depreciation and purchased emission allowances,
through a rider mechanism. The settlement establishes a fixed return of 8
percent on the capital investment, which approximates the return authorized in
the Company's last electric rate case in 1995.

The Company expects to achieve timely compliance as a result of the project.
Construction of the first SCR at Culley is nearing completion on schedule, and
installation of SCR technology as planned is expected to reduce 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.

Culley Generating Station Litigation
In the late 1990's, the USEPA initiated an investigation under Section 114 of
the Act of SIGECO's coal-fired electric generating units in commercial operation
by 1977 to determine compliance with environmental permitting requirements
related to repairs, maintenance, modifications, and operations changes. The
focus of the investigation was to determine whether new source review permitting
requirements were triggered by such plant modifications, and whether the best
available control technology was, or should have been used. Numerous electric
utilities were, and are currently, being investigated by the USEPA under an
industry-wide review for compliance. In July 1999, SIGECO received a letter from
the Office of Enforcement and Compliance Assurance of the USEPA discussing the
industry-wide investigation, vaguely referring to an investigation of SIGECO and
inviting SIGECO to participate in a discussion of the issues. No specifics were
noted; furthermore, the letter stated that the communication was not intended to
serve as a notice of violation. Subsequent meetings were conducted in September
and October 1999 with the USEPA and targeted utilities, including SIGECO,
regarding potential remedies to the USEPA's general allegations.

On November 3, 1999, the USEPA filed a lawsuit against seven utilities,
including SIGECO. The USEPA alleges that, beginning in 1992, SIGECO violated the
Act by (1) making modifications to its Culley Generating Station in Yankeetown,
Indiana without obtaining required permits (2) making major modifications to the
Culley Generating Station without installing the best available emission control
technology and (3) failing to notify the USEPA of the modifications. In
addition, the lawsuit alleges that the modifications to the Culley Generating
Station required SIGECO to begin complying with federal new source performance
standards at its Culley Unit 3.

SIGECO believes it performed only maintenance, repair, and replacement
activities at the Culley Generating Station, as allowed under the Act. Because
proper maintenance does not require permits, application of the best available
control technology, notice to the USEPA, or compliance with new source
performance standards, SIGECO believes that the lawsuit is without merit, and
intends to vigorously defend itself. Since the filing of this lawsuit, the USEPA
has voluntarily dismissed a majority of the claims brought in its original
complaint. In its original complaint, USEPA alleged significant emissions
increases of three pollutants for each of four maintenance projects. Currently,
USEPA is alleging only significant emission increases of a single pollutant at
three of the four maintenance projects cited in the original complaint.

The lawsuit seeks fines against SIGECO in the amount of $27,500 per day per
violation. However, on July 29, 2002, the Court ruled that USEPA could not seek
civil penalties for two of the three remaining projects at issue in the
litigation, significantly reducing potential civil penalty exposure. The lawsuit
also seeks a court order requiring SIGECO to install the best available
emissions technology at the Culley Generating Station. If the USEPA were
successful in obtaining an order, SIGECO estimates that in response it could
incur capital costs of approximately $20 million to $40 million to comply with
the order. Trial is currently set to begin July 14, 2003.

The USEPA has also issued an administrative notice of violation to SIGECO making
the same allegations, but alleging that violations began in 1977.

While it is possible that SIGECO could be subjected to criminal penalties if the
Culley Generating Station continues to operate without complying with the
permitting requirements of new source review and the allegations are determined
by a court to be valid, SIGECO believes such penalties are unlikely as the USEPA
and the electric utility industry have a bonafide dispute over the proper
interpretation of the Act. Accordingly, the Company has recorded no accrual, and
the plant continues to operate while the matter is being decided.

Information Request
On January 23, 2001, SIGECO received an information request from the USEPA under
Section 114 of the Act for historical operational information on the Warrick and
A.B. Brown generating stations. SIGECO has provided all information requested,
and no further action has occurred.

Manufactured Gas Plants

In the past, Indiana Gas 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 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 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 Voluntary Remediation Program. 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 recently been initiated
by the Company to confirm that the sites continue to pose no such risk.

<PAGE>

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 IURC. The
retail gas operations of the Ohio operations are subject to regulation by the
PUCO. Changes in prices for fuel for electric generation and purchased power are
determined primarily by energy markets.

Gas Costs Proceedings

Adjustments to rates and charges related to the cost of gas charged to Indiana
customers are made through gas cost adjustment (GCA) procedures established by
Indiana law and administered by the IURC. Similar adjustments to the cost of gas
charged to Ohio customers are made through gas cost recovery (GCR) procedures
established by Ohio law and administered by the PUCO. GCA and GCR procedures
involve scheduled quarterly filings and IURC and PUCO hearings to establish the
amount of price adjustments for a designated future quarter. The procedures also
provide for inclusion in later quarters any variances between the estimated cost
of gas and actual costs incurred. This reconciliation process with regard to
changes in the cost of gas sold closely matches revenues to expenses.

The IURC has also applied the statute authorizing GCA 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. Recovery of gas
costs is not allowed to the extent that net operating income for the longer of
(1) a 60-month period, including the twelve-month period provided in a gas cost
adjustment filing, or (2) the date of the last order establishing base rates and
charges exceeds the total net operating income authorized by the IURC. For the
recent past, the earnings test has not affected the Company's ability to recover
gas costs, and the Company does not anticipate the earnings test will restrict
the recovery of gas costs in the near future.

Rate structures for gas delivery operations do not include weather
normalization-type clauses that authorize the utility to recover gross margin on
sales established in its last general rate case, regardless of actual weather
patterns.

Commodity prices for natural gas purchases were significantly higher during the
2000 - 2001 heating season, primarily due to colder temperatures, increased
demand and tighter supplies. Subject to compliance with applicable state laws,
the Company's utility subsidiaries are allowed full recovery of such changes in
purchased gas costs from their retail customers through these
commission-approved gas cost adjustment mechanisms, and margin on gas sales
should not be impacted. However, in 2001, the Company's utility subsidiaries
experienced 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.

In March 2001, Indiana Gas and SIGECO reached agreement with the OUCC and the
Citizens Action Coalition of Indiana, Inc. (CAC) regarding the matters raised by
an IURC Order that disallowed $3.8 million of Indiana Gas' gas procurement costs
for the 2000 - 2001 heating season which was recognized during the year ended
December 31, 2000. As part of the agreement, the companies agreed to contribute
an additional $1.7 million to assist qualified low income gas customers, and
Indiana Gas agreed to credit $3.3 million of the $3.8 million disallowed amount
to its customers' April 2001 utility bills in exchange for both the OUCC and the
CAC dropping their appeals of the IURC Order. In April 2001, the IURC issued an
order approving the settlement. Substantially all of the financial assistance
for low income gas customers was distributed in 2001.

Fuel & Purchased Power Costs

Adjustments to rates and charges related to the cost of fuel and the net energy
cost of purchased power charged to Indiana customers are made through fuel cost
adjustment procedures established by Indiana law and administered by the IURC.
Fuel cost adjustment procedures involve scheduled quarterly filings and IURC
hearings to establish the amount of price adjustments for future quarters. The
procedures also provide for inclusion in a later quarter of any variances
between the estimated cost of fuel and purchased power and actual costs
incurred. The order provides that any over-or-under-recovery caused by variances
between estimated and actual cost in a given quarter will be included in the
second succeeding quarter's adjustment factor. This continuous reconciliation of
estimated incremental fuel costs billed with actual incremental fuel costs
incurred closely matches revenues to expenses.

An earnings test similar to the test restricting gas cost recovery is the
principal restriction to recovery of fuel cost increases. This earnings test has
not affected the Company's ability to recover fuel costs, and the Company does
not anticipate the earnings test will restrict the recovery of fuel costs in the
near future.

As a result of an appeal of a generic order issued by the IURC in August 1999
regarding guidelines for the recovery of purchased power costs, SIGECO entered
into a settlement agreement with the OUCC that provides certain terms with
respect to the recoverability of such costs. The settlement, originally approved
by the IURC in August 2000, has been extended by agreement through March 2003,
and discussions regarding further extension of the settlement term are ongoing.
Under the settlement, SIGECO can recover the entire cost of purchased power up
to an established benchmark, and during forced outages, SIGECO will bear a
limited share of its purchased power costs regardless of the market costs at
that time. Based on this agreement, SIGECO believes it has limited its exposure
to unrecoverable purchased power costs.

Transactions with ProLiance

The sale of gas and provision of other services to Indiana Gas and SIGECO by
ProLiance is subject to regulatory review through the quarterly gas cost
adjustment (GCA) process administered by the IURC. The sale of gas and provision
of other services to the Ohio operations by ProLiance is subject to regulatory
review through the quarterly gas cost recovery (GCR) and audit process
administered by the PUCO.

Specific to the sale of gas and provision of other services to Indiana Gas by
ProLiance, on September 12, 1997, the IURC issued a decision finding the gas
supply and portfolio administration agreements between ProLiance and Indiana Gas
and ProLiance and Citizens Gas to be consistent with the public interest and
that ProLiance is not subject to regulation by the IURC as a public utility.
However, with respect to the pricing of gas commodity purchased from ProLiance,
the price paid by ProLiance to the utilities for the prospect of using pipeline
entitlements if and when they are not required to serve the utilities' firm
customers, and the pricing of fees paid by the utilities to ProLiance for
portfolio administration services, the IURC concluded that additional review in
the GCA process would be appropriate and directed that these matters be
considered further in a consolidated GCA proceeding involving Indiana Gas and
Citizens Gas.

On June 4, 2002, Indiana Gas and Citizens Gas, together with the OUCC and other
consumer parties, entered into and filed with the IURC a settlement setting
forth the terms for resolution of all pending regulatory issues related to
ProLiance, including the three pricing issues. On July 23, 2002, the IURC
approved the settlement filed by the parties. The GCA proceeding has been
concluded and new supply agreements between Indiana Gas, SIGECO, Citizens Gas,
and ProLiance have been approved and extended through March 31, 2007. ProLiance
will also have the opportunity, if it so elects, to participate in a "request
for proposal" process for service to the utilities after March 31, 2007.

For past services provided to Indiana Gas by ProLiance, Indiana Gas made refunds
to retail customers pursuant to the settlement totaling $6.4 million in the
fourth quarter of 2002. A subsidiary of Vectren's nonregulated operations has
indemnified Indiana Gas for the amount of the refund as well as any other
amounts incurred as a result of the settlement. Accordingly, the refund had no
effect on operating margin or net income.

In addition to the above, the IURC order also provides that:
o    A portion of the utilities' natural gas will be purchased through a gas
     cost incentive mechanism that shares price risk and reward between the
     utilities and customers;
o    Beginning in 2004, ProLiance will provide the utilities with an interstate
     pipeline transport and storage service price discount, thus providing
     additional savings to customers;
o    As ProLiance continues to provide the utilities with its supply services,
     Citizens Gas and Vectren will together annually provide an additional $2
     million per year in customer benefits in 2003, 2004, and 2005.

                          Critical Accounting Policies

Management is required to make judgements, 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 judgement. 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
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 performed an initial impairment analysis
of its goodwill, all of which resides in the Gas Utility Services operating
segment. Also consistent with SFAS 142, goodwill is tested for impairment
annually 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 14 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 and therefore resulted
in no impairment.

Estimating fair value using a discounted cash flow model is subjective and
requires significant judgement 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 results in no impairment charge.

Impairment Review of Investments

The Company has investments in unconsolidated affiliates, including notes
receivable convertible into equity interests. On a periodic basis and 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 investments in
unconsolidated affiliates involves comparison of the investment's estimated fair
value to its carrying amount. Fair value is estimated using primarily using
discounted cash flow analyses. Calculating free cash flows and fair value using
the above methods is subjective and requires significant judgement in growth
assumptions, longevity of cash flows, and discount rates (for fair value
calculations).

During 2002, the Company performed impairment tests on certain investments using
both free cash flows and discounted cash flows. No impairment charges resulted
from these analyses. For these impairment tests, a 100 basis point adverse
change in the discount rate used to estimate discounted cash flow or a 10%
adverse change in the cash flow growth assumption used to estimate free cash
flows would have resulted in no impairment charge.


<PAGE>


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, these
estimates are 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 judgement 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 and certain subsidiaries of Vectren provided corporate, general and
administrative services to the Company including legal, finance, tax, risk
management, and 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. 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. These costs are directly charged to individual
subsidiaries. Other components of costs (such interest cost from prior service
and asset returns) are charged to individual subsidiaries through the corporate
allocation process discussed above. Plan assets nor the FAS 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. 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 annually measures its obligations
on September 30.

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 2002 annual costs and the
ending benefit obligations recognized in the consolidated financial statements:
a discount rate of 6.75%, an expected return on plan assets before expenses of
9.00%, a rate of compensation increase of 4.25%, and a health care cost trend
rate of 10% in 2002 declining to 5% in 2006. During 2002, Vectren reduced the
discount rate and rate of compensation increase by 50 basis points from those
assumptions used in 2001 due to the general decline in interest rates and other
market conditions that occurred in 2002. Future changes in health care costs,
work force demographics, interest rates, or plan changes could significantly
affect the estimated cost of these future benefits that are allocated to VUHI
and its subsidiaries.

       Impact of Recently Issued Accounting Guidance on Future Operations

EITF 02-03

In October 2002, the EITF reached a final consensus in EITF Issue 02-03 "Issues
Involved in Accounting for Derivative Contracts Held for Trading Purposes and
Contracts Involved in Energy Trading and Risk Management Activities" (EITF
02-03) that gains and losses (realized and unrealized) on all derivative
instruments within the scope of SFAS 133 should be shown net in the income
statement, whether or not settled physically, if the derivative instruments are
held for "trading purposes." The consensus rescinded EITF Issue 98-10
"Accounting for Contracts Involved in Energy Trading and Risk Management
Activities" (EITF 98-10) as well as other decisions reached on energy trading
contracts at the EITF's June 2002 meeting.

The Company's non-firm wholesale power marketing operations enter into contracts
that are derivatives as defined by SFAS 133, but these operations do not meet
the definition of energy trading activities based upon the provisions in EITF
98-10. Currently, the Company uses a gross presentation to report the results of
these operations as described in Note 12 of the consolidated financial
statements. The Company has re-evaluated its portfolio of derivative contracts
and has determined gross presentation remains appropriate.

SFAS 143

In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement
Obligations" (SFAS 143). SFAS 143 requires entities to record the fair value of
a liability for an asset retirement obligation 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 to its present value, 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 upon settlement. Any costs of removal recorded in
accumulated depreciation pursuant to regulatory authority will require
disclosure in future periods. The Company adopted this statement on January 1,
2003. The adoption was not material to the Company's results of operations or
financial condition.

FASB Interpretation (FIN) 45

In November 2002, the FASB issued Interpretation 45, "Guarantor's Accounting and
Disclosure Requirements for Guarantees, Including Indirect Guarantees of
Indebtedness of Others" (FIN 45). FIN 45 clarifies the requirements for a
guarantor's accounting for and disclosure of certain guarantees issued and
outstanding and that a guarantor is required to recognize, at the inception of a
guarantee, a liability for the obligations it has undertaken. The objective of
the initial measurement of that liability is the fair value of the guarantee at
its inception. The initial recognition and measurement provisions are applicable
on a prospective basis to guarantees issued or modified after December 31, 2002.
Although management is still evaluating the impact of FIN 45 on its financial
position and results of operations, the adoption is not expected to have a
material effect.

FIN 46

In January 2003, the FASB issued Interpretation 46, "Consolidation of Variable
Interest Entities" (FIN 46). FIN 46 addresses consolidation by business
enterprises of variable interest entities and significantly changes the
consolidation requirements for those entities. FIN 46 is intended to achieve
more consistent application of consolidation policies to variable interest
entities and, thus improves comparability between enterprises engaged in similar
activities when those activities are conducted through variable interest
entities. FIN 46 applies to variable interest entities created after January 31,
2003 and to variable interest entities in which an enterprise obtains an
interest after that date. FIN 46 applies to the Company's third quarter for
variable interest entities in which the Company holds a variable interest
acquired before February 1, 2003. Although management is still evaluating the
impact of FIN 46 on its financial position and results of operations, the
adoption is not expected to have a material effect.

                               Financial Condition

Within Vectren's consolidated group, VUHI funds short-term and long-term
financing needs of the regulated operations. Vectren does not guarantee VUHI's
debt. VUHI's currently outstanding long-term and short-term borrowing
arrangements are jointly and severally guaranteed by Indiana Gas, SIGECO, and
VEDO. Prior to VUHI's formation, Indiana Gas and SIGECO funded their operations
separately, and therefore, have debt outstanding funded solely by their
operations. VUHI's operations have historically funded Vectren's common stock
dividends.

In November 2002, Moody's Investors Service (Moody's) downgraded the senior
unsecured debt of VUHI, Indiana Gas, and SIGECO (from A2 to Baa1) as well as
SIGECO's senior secured debt (from A1 to A3) and SIGECO's pollution control
revenue bonds (from VMIG 1 to VMIG 2). In addition, VUHI's commercial paper
program was also downgraded (from P-1 to P-2). The reasons cited for the
downgrades included weaker credit and fixed charge coverage measures compared to
A2 peers, resulting from the prior integration and restructuring costs and warm
winter of 2001 and 2002; and lack of weather normalization-type clauses that
authorize the utilities to recover gross margin on sales regardless of actual
weather patterns.

VUHI's and Indiana Gas' credit ratings on outstanding senior unsecured debt at
December 31, 2002 are A-/Baa1 as rated by Standard and Poor's Ratings Services
(Standard and Poor's) and Moody's, respectively. SIGECO's credit ratings on
outstanding senior unsecured debt at December 31, 2002 are BBB+/Baa1. SIGECO's
credit ratings on outstanding secured debt at December 31, 2002 are A-/A3.
VUHI's commercial paper has a credit rating of A-2/P-2. Moody's current outlook
is stable while Standard and Poor's current outlook is negative.

The Company's consolidated equity capitalization objective is 40-55% of total
capitalization. This objective may have varied, and will vary, depending on
particular business opportunities, capital spending requirements, and seasonal
factors that affect the Company's operation. The Company's equity component was
45% and 44% of total capitalization, including current maturities of long-term
debt and long-term debt subject to tender, at December 31, 2002 and 2001,
respectively.

The Company expects the majority of its capital expenditures and debt security
redemptions to be provided by internally generated funds. However, additional
permanent financing may be required due to significant capital expenditures for
NOx compliance equipment at SIGECO and plans to further strengthen the Company's
capital structure and the capital structures of its utility subsidiaries. These
plans may include the issuance of new equity to Vectren and debt and the calling
of certain long-term debt at SIGECO and Indiana Gas. Specific to the NOx
compliance project, the Company is authorized an 8 percent return on its capital
investments through approved rider mechanisms.


<PAGE>


Sources & Uses of Liquidity

Operating Cash Flow

The Company's primary and historical source of liquidity to fund working capital
requirements has been cash generated from operations. Cash flow from operations
increased during the year ended December 31, 2002 compared to 2001 by $156.5
million and increased $101.1 million in 2001 compared to 2000. The primary
reasons for the increases are due to favorable changes in working capital due to
a return to lower gas prices and increased earnings before non-cash charges.

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 permanently financed.

Cash flow required for financing activities of $113.5 million for the year ended
December 31, 2002 includes a decrease in borrowings outstanding over 2001 of
$41.6 million and increased dividends paid to Vectren compared to 2001.
Borrowings have decreased due to the use of operating cash flow to pay down
short-term borrowings.

Cash flow from financing activities of $31.6 million for the year ended December
31, 2001 includes $67.1 million of reductions in borrowings and preferred stock
and $64.9 million in dividends paid to Vectren, offset by additional capital
contributions of $164.4 million. During 2001, $508.4 million of net proceeds
from debt issuances and capital contributions were utilized to pay down
short-term borrowings and strengthen VUHI's balance sheet.

Financing the Ohio Operations Purchase
On October 31, 2000, the acquisition of the Ohio operations was completed for a
purchase price of approximately $471 million. Commercial paper and $150.0
million in floating rate notes were issued to fund the purchase. During 2001,
the Company refinanced these interim borrowing arrangements with permanent
financing in the form of new equity and long-term debt.

In January 2001, Vectren filed a registration statement with the Securities and
Exchange Commission with respect to a public offering of 5.5 million shares of
new common stock. In February 2001, the registration became effective, and an
agreement was reached to sell approximately 6.3 million shares (the original 5.5
million shares, plus an over-allotment option of 0.8 million shares) to a group
of underwriters. The net proceeds from the sale of common stock totaled $129.4
million. These proceeds were contributed to VUHI as an additional capital
contribution.

In September 2001, VUHI filed a shelf registration statement with the Securities
and Exchange Commission with respect to a public offering of $350.0 million
aggregate principal amount of unsecured senior notes, guaranteed jointly and
severally by SIGECO, Indiana Gas, and VEDO. In October 2001, VUHI issued senior
unsecured notes with an aggregate principal amount of $100.0 million and an
interest rate of 7.25%, and in December 2001, issued the remaining aggregate
principal amount of $250.0 million at an interest rate of 6.625% (the December
Notes). The December Notes were priced at 99.302% to yield 6.69% to maturity.
The net proceeds from the sale of the senior notes and settlement of hedging
arrangements totaled $344.0 million.

Other Financing Transactions
In December 2001, Vectren contributed additional capital of $35.0 million. The
proceeds were used to repay short-term borrowings.

In September 2001, the Company notified holders of SIGECO's 4.80%, 4.75%, and
6.50% preferred stock of its intention to redeem the shares. The 4.80% preferred
stock was redeemed at $110.00 per share, plus $1.35 per share in accrued and
unpaid dividends. Prior to the redemption, there were 85,519 shares outstanding.
The 4.75% preferred stock was redeemed at $101.00 per share, plus $0.97 per
share in accrued and unpaid dividends. Prior to the redemption, there were 3,000
shares outstanding. The 6.50% preferred stock was redeemed at $104.23 per share,
plus $0.73 per share in accrued and unpaid dividends. Prior to the redemption,
there were 75,000 shares outstanding. The total redemption price was $17.7
million.

In December 2000, Indiana Gas issued $20.0 million of 15-Year Insured Quarterly
(IQ) Notes at an interest rate of 7.15% and $50.0 million of 30-Year IQ Notes at
an interest rate of 7.45%. Indiana Gas has the option to redeem the 15-Year IQ
Notes, in whole or in part, from time to time on or after December 15, 2004 and
the option to redeem the 30-Year IQ Notes in whole or in part, from time to time
on or after December 15, 2005. The IQ notes have no sinking fund requirements.
The net proceeds totaling $67.9 million were used to repay outstanding
commercial paper.

Investing Cash Flow

Cash required for investing activities of $161.0 million for the year ended
December 31, 2002 includes $151.8 million of requirements for capital
expenditures. Investing activities for 2001 were $152.3 million. The $8.7
million increase in requirements occurring in 2002 is principally the result of
additional capital expenditures for NOx compliance and investments in deferred
compensation funding arrangements.

Cash required for investing activities for the year ended December 31, 2001
includes $147.6 million of requirements for capital expenditures. Investing
activities for the year ended December 31, 2000 were $587.0 million. The $434.7
million decrease occurring in 2001 is principally the result of the acquisition
of the Ohio operations in 2000.

Available Sources of Liquidity

At December 31, 2002, the Company has $330.0 million of short-term borrowing
capacity, of which approximately $90.9 million is available. Subsequent to
December 31, 2002, the Company increased its capacity $145.0 million to $475.0
million. Effective January 1, 2003, Vectren transferred certain assets that
primarily support the regulated operations from other wholly owned subsidiaries
to VUHI. This transfer of assets will take advantage of the greater borrowing
capacity available to VUHI.

Prior to 2001, Vectren purchased shares from the open market to satisfy
issuances of common stock pursuant to its dividend reinvestment plan and stock
option plans. In 2001, Vectren began issuing new shares to satisfy exercised
stock options and beginning in 2003 will issue new shares to satisfy dividend
reinvestment plan requirements. Management estimates these new equity issues
will add approximately $5 million per year that may be utilized to support
VUHI's operations.



<PAGE>


Potential & Future Uses of Liquidity

The following is a summary of certain obligations and commitments at December
31, 2002:
<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------
(In millions)                       2003     2004    2005     2006    2007 Thereafter
-------------------------------------------------------------------------------------
<S>                               <C>       <C>      <C>      <C>    <C>     <C>
Short-term debt                   $ 239.1   $    -   $   -    $ -    $   -   $    -
Long-term debt (1)                   16.0     15.0       -      -      6.5    850.6
Long-term debt to be called (2)      23.8        -       -      -        -        -
Firm natural gas purchase
   commitments                       89.5     21.3     3.6      -        -        -
-------------------------------------------------------------------------------------
    Total                         $ 368.4   $ 36.3   $ 3.6    $ -    $ 6.5  $ 850.6
=====================================================================================
</TABLE>

(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 2002 (in millions) is $26.6 in 2003, $13.5 in 2004, $10.0
     in 2005, $53.7 in 2006, $20.0 in 2007 and $120.0 thereafter.

(2)  On January 15, 2003, the Company called the remaining $23.8 million of
     Indiana Gas' 9.375% private placement notes originally due in 2021. Since
     the proceeds to repay the notes were generated from short-term borrowings,
     these notes are classified in current maturities of long-term debt at
     December 31, 2002.

Planned Capital Expenditures & Investments

Capital expenditures for the five-year period 2003 - 2007 will require
significant investments and include expenditures for non-utility plant that will
primarily support utility operations and for NOx compliance. Capital
expenditures are estimated as follows:

-------------------------------------------------------------------------------
In millions                       2003     2004       2005      2006      2007
-------------------------------------------------------------------------------
Capital expenditures
  Utility plant (1)             $ 204.8   $ 236.5   $ 184.9   $ 145.1   $ 135.4
  Non-utility plant (2)            22.3      27.8      10.5      16.4      11.3
-------------------------------------------------------------------------------
    Total capital expenditures  $ 227.1   $ 264.3   $ 195.4   $ 161.5   $ 146.7
===============================================================================


(1)  Includes expenditures for NOx compliance of approximately $83.0 million in
     2003, $79.0 million in 2004, $23.7 million in 2005, and $4.6 million in
     2006.

(2)  On January 1, 2003, Vectren transferred certain information technology
     systems and related assets and buildings from other entities within its
     consolidated group to VUHI. These assets primarily support the operations
     of VUHI's subsidiaries. These non-utility assets will require further
     investment in the coming years and are included above since such future
     investment will be funded by VUHI.

Guarantees

Vectren's three operating utility companies, SIGECO, Indiana Gas, and VEDO are
guarantors of VUHI's $350.0 million commercial paper program, of which $239.1
million is outstanding at December 31, 2002 and VUHI's $350.0 million unsecured
senior notes outstanding at December 31, 2002. VUHI has no independent assets or
operations, the guarantees are full and unconditional and joint and several, and
VUHI has no subsidiaries other than the subsidiary quarantors.

Pension and Postretirement Funding Obligations

Vectren has not made significant contributions to its qualified pension plans in
recent years. Due to poor market performance during 2000-2002, it will be
necessary for Vectren to make contributions to benefits plans in the coming
years. Management currently estimates that the qualified pension plans will
require Company contributions of less than $1 million in 2003 and between $5
million and $10 million in 2004 and 2005. VUHI may be called upon to fund a
portion of these contributions.

                           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 included, among others, the following:

o    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.

o    Increased competition in the energy environment including effects of
     industry restructuring and unbundling.

o    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.

o    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.

o    Economic conditions including the effects of an economic downturn,
     inflation rates, and monetary fluctuations.

o    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.

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

o    Employee workforce factors including changes in key executives, collective
     bargaining agreements with union employees, or work stoppages.

o    Legal and regulatory delays and other obstacles associated with mergers,
     acquisitions, and investments in joint ventures.

o    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.

o    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.

ITEM 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK

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

The Company also executes derivative contracts in the normal course of
operations while buying and selling commodities and other fungible goods to be
used in operations and while optimizing generation assets. The Company does not
execute derivative contracts for speculative or trading purposes.

Commodity Price Risk

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.

Electric sales and purchases in the wholesale power market and other
commodity-related operations are exposed to commodity price risk associated with
fluctuating electric power and other commodity prices. Other commodity
operations include sales of electricity to certain municipalities and large
industrial customers.

The Company's non-firm wholesale power marketing operations manage the
utilization of its available electric generating capacity by entering into
forward and option 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's other commodity-related operations involve the purchase and sale
of commodities, including electricity, to meet customer demands and operational
needs. These operations also enter into forward contracts that commit the
Company to purchase and sell commodities in the future. Price risk from forward
positions that commit the Company to deliver commodities is mitigated using
insurance contracts and offsetting forward purchase contracts.

Open positions in terms of price, volume, and specified delivery points may
occur and are managed using methods described above and frequent management
reporting.

Market risk is measured by management as the potential impact on pre-tax
earnings resulting from a 10% adverse change in the forward price of commodity
prices on outstanding market sensitive financial instruments (all contracts not
expected to be settled by physical receipt or delivery). For the years ended
December 31, 2002 and 2001, a 10% adverse change in commodity forward prices on
market sensitive financial instruments would have decreased pre-tax earnings by
approximately $1.5 million and $2.0 million, respectively.

Interest Rate Risk

The Company is exposed to interest rate risk associated with its adjustable rate
borrowing arrangements. Its risk management program seeks to reduce the
potentially adverse effects that market volatility may have on operations. The
Company tries to limit the amount of adjustable rate borrowing arrangements
exposed to short-term interest rate volatility to a maximum of 25% of total
debt. However, there are times when this targeted level of interest rate
exposure may be exceeded. At December 31, 2002, such obligations represented 23%
of the Company's total debt portfolio. To manage this exposure, the Company may
periodically use derivative financial instruments to reduce earnings
fluctuations caused by interest rate volatility.

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 including bank notes, lines of credit, commercial
paper, and certain adjustable rate long-term debt instruments. At December 31,
2002 and 2001, the combined borrowings under these facilities totaled $261.6
million and $296.7 million, respectively. Based upon average borrowing rates
under these facilities during the years ended December 31, 2002 and 2001, an
increase of 100 basis points (1%) in the rates would have increased interest
expense by $1.8 million and $5.3 million, respectively. Of the 2001 exposure,
approximately $1.5 million would have been offset by an interest rate swap
designated to hedge such exposure.

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.

Although the Company'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.



<PAGE>


ITEM 8. Financial Statements and Supplementary Data

              MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL STATEMENTS

The management of Vectren Utility Holdings, Inc. (VUHI) is responsible for the
preparation of the consolidated financial statements and the related financial
data contained in this report. The financial statements are 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 the data in this report, including required
estimates and judgments, is the responsibility of management. Management
maintains a system of internal control and utilizes an internal auditing program
to provide reasonable assurance of compliance with Company policies and
procedures and the safeguard of assets.

The board of directors of VUHI's parent company, Vectren Corporation, pursues
its responsibility for these financial statements through its audit committee,
which meets periodically with management, the internal auditors and the
independent auditors, to assure that each is carrying out its responsibilities.
Both the internal auditors and the independent auditors meet with the audit
committee of Vectren Corporation's board of directors, with and without
management representatives present, to discuss the scope and results of their
audits, their comments on the adequacy of internal accounting control and the
quality of financial reporting.


/S/ Niel C. Ellerbrook
Niel C. Ellerbrook
Chairman & Chief Executive Officer
February 26, 2003

<PAGE>


                          INDEPENDENT AUDITORS' REPORT

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  as of December  31,  2002 and 2001,  and the
related consolidated  statements of income, common shareholder's equity and cash
flows for each of the three years in the period ended  December  31,  2002.  Our
audits also included the financial  statement  schedules  listed in the Table of
Contents  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 auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all
material respects, the financial position of Vectren Utility Holdings, Inc. and
subsidiaries as of December 31, 2002 and 2001, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2002, 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 financial statements taken
as a whole, present fairly in all material respects the information set forth
therein.

As discussed in Note 2, effective January 1, 2002, the Company adopted Statement
of Financial Accounting Standards ("SFAS") 142, "Goodwill and Other
Intangibles." As discussed in Note 12, effective, January 1, 2001, the Company
adopted SFAS 133, "Accounting for Derivative Instruments and Hedging
Activities," as amended.

As discussed in Note 3, the accompanying 2001 and 2000 financial statements have
been restated.


/S/ DELOITTE & TOUCHE LLP
DELOITTE & TOUCHE LLP
Indianapolis, Indiana
February 26, 2003


<PAGE>


             VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES
                           CONSOLIDATED BALANCE SHEETS
                                  (In millions)


                                                               At December 31,
-------------------------------------------------------------------------------
                                                             2002         2001
-------------------------------------------------------------------------------
             ASSETS                                                (As Restated,
             ------                                                 See Note 3)

Current Assets
   Cash & cash equivalents                              $    10.5    $     5.0
   Accounts receivable-less reserves of $5.5 &
       $5.1, respectively                                   131.8        123.1
   Receivables due from other Vectren companies              56.2         86.3
   Accrued unbilled revenues                                112.7         77.1
   Inventories                                               56.0         54.8
   Recoverable fuel & natural gas costs                      22.1         70.2
   Prepayments & other current assets                        86.5         82.8
-------------------------------------------------------------------------------
       Total current assets                                 475.8        499.3
-------------------------------------------------------------------------------
Utility Plant
  Original cost                                           3,037.2      2,906.1
  Less:  accumulated depreciation & amortization          1,389.0      1,308.2
-------------------------------------------------------------------------------
       Net utility plant                                  1,648.2      1,597.9
-------------------------------------------------------------------------------

Investments in unconsolidated affiliates                      2.4          3.5
Other investments                                            21.9         12.2
Non-utility property-net                                      8.7          6.3
Goodwill-net                                                202.2        201.5
Regulatory assets                                            75.2         67.8
Other assets                                                  4.9         14.1
-------------------------------------------------------------------------------
TOTAL ASSETS                                            $ 2,439.3    $ 2,402.6
===============================================================================


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


<PAGE>


             VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES
                           CONSOLIDATED BALANCE SHEETS
                                  (In millions)

                                                            2002         2001
-------------------------------------------------------------------------------
     LIABILITIES & SHAREHOLDER'S EQUITY                            (As Restated,
     ----------------------------------                              See Note 3)
Current Liabilities
   Accounts payable                                    $    74.3    $    79.4
   Accounts payable to affiliated companies                 85.6         37.4
   Payables due to other Vectren companies                  63.0         29.2
   Accrued liabilities                                      85.2         94.7
   Short-term borrowings                                   239.1        274.2
   Long-term debt subject to tender                         26.6         11.5
   Current maturities of long-term debt                     39.8          1.3
-------------------------------------------------------------------------------
      Total current liabilities                            613.6        527.7
-------------------------------------------------------------------------------

Long-Term Debt-Net of Current Maturities &
   Debt Subject to Tender                                  841.2        900.9

Deferred Income Taxes & Other Liabilities
   Deferred income taxes                                   173.7        176.5
   Deferred credits & other liabilities                     82.2         92.9
-------------------------------------------------------------------------------
      Total deferred credits & other liabilities           255.9        269.4
-------------------------------------------------------------------------------

Commitments & Contingencies (Notes 9-11)

Cumulative, Redeemable Preferred Stock
   of a Subsidiary                                           0.3          0.5

Common Shareholder's Equity
   Common stock (no par value)                             385.7        385.7
   Retained earnings                                       342.1        320.2
   Accumulated other comprehensive income (loss)             0.5         (1.8)
-------------------------------------------------------------------------------
      Total common shareholder's equity                    728.3        704.1
-------------------------------------------------------------------------------
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY               $ 2,439.3    $ 2,402.6
===============================================================================

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

<PAGE>


             VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES
                        CONSOLIDATED STATEMENTS OF INCOME
                                  (In millions)

                                                      Year Ended December 31,
-------------------------------------------------------------------------------
                                                  2002       2001        2000
-------------------------------------------------------------------------------
OPERATING REVENUES                                     (As Restated, See Note 3)
                                                       ------------------------
  Gas utility                                 $  909.0   $1,019.6    $  820.4
  Electric utility                               608.1      381.2       334.4
-------------------------------------------------------------------------------
       Total operating revenues                1,517.1    1,400.8     1,154.8
-------------------------------------------------------------------------------
COST OF OPERATING REVENUES
  Cost of gas sold                               571.8      708.9       552.5
  Fuel for electric generation                    81.6       74.4        75.7
  Purchased electric energy                      296.3       86.9        36.4
-------------------------------------------------------------------------------
       Total cost of operating revenues          949.7      870.2       664.6
-------------------------------------------------------------------------------
TOTAL OPERATING MARGIN                           567.4      530.6       490.2

OPERATING EXPENSES
  Other operating                                220.6      241.1       209.0
  Merger & integration costs                         -        2.8        32.7
  Restructuring costs                                -       15.0           -
  Depreciation & amortization                     96.8       97.2        82.4
  Taxes other than income taxes                   50.8       51.2        36.2
-------------------------------------------------------------------------------
       Total operating expenses                  368.2      407.3       360.3
-------------------------------------------------------------------------------
OPERATING INCOME                                 199.2      123.3       129.9

OTHER INCOME
  Other - net                                      6.9        5.5         4.7
  Equity in earnings of unconsolidated
     affiliates                                   (1.8)      (0.5)          -
-------------------------------------------------------------------------------
       Total other income                          5.1        5.0         4.7
-------------------------------------------------------------------------------
Interest expense                                  66.1       70.1        46.1
-------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES                       138.2       58.2        88.5
-------------------------------------------------------------------------------
Income taxes                                      44.6       18.4        35.0
Preferred dividend requirements of subsidiary        -        0.8         1.0
-------------------------------------------------------------------------------
INCOME BEFORE CUMULATIVE EFFECT
   OF CHANGE IN ACCOUNTING PRINCIPLE              93.6       39.0        52.5
-------------------------------------------------------------------------------

Cumulative effect of change in accounting
principle - net of tax                               -        1.1           -
-------------------------------------------------------------------------------
NET INCOME                                    $   93.6   $   40.1    $   52.5
===============================================================================


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

<PAGE>

<TABLE>
<CAPTION>

             VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES
                      CONSOLIDATED STATEMENTS OF CASH FLOWS
                                  (In millions)
                                                            Year Ended December 31,
----------------------------------------------------------------------------------------
                                                         2002       2001       2000
----------------------------------------------------------------------------------------
CASH FLOWS FROM OPERATING ACTIVITIES                          (As Restated, See Note 3)
                                                               ------------------------
<S>                                                   <C>        <C>        <C>
   Net income                                         $  93.6    $  40.1    $  52.5
   Adjustments to reconcile net income to cash
        from operating activities:
      Depreciation & amortization                        96.8       97.2       82.4
      Deferred income taxes & investment tax credits    (22.0)     (14.9)      12.9
      Equity in earnings of unconsolidated affiliates     1.8        0.5          -
      Net unrealized loss (gain) on derivative
          instruments, including cumulative effect
          of change in accounting principle               3.6       (3.3)         -
      Other non-cash charges- net                        15.1       19.7        7.6
      Changes in working capital accounts:
         Accounts receivable, including to Vectren
            companies & accrued unbilled revenue        (27.9)      66.6     (221.1)
         Inventories                                     (1.2)      38.4       15.9
         Recoverable fuel & natural gas costs            48.1       25.9      (82.3)
         Prepayments & other current assets              (9.4)     (11.3)     (36.8)
         Accounts payable, including to Vectren
            companies & affiliated companies             88.3     (111.7)     186.0
         Accrued liabilities                              2.6      (10.4)       2.1
      Changes in other noncurrent assets
          & liabilities                                  (9.4)     (13.3)       3.2
----------------------------------------------------------------------------------------
         Net cash flows from operating activities       280.0      123.5       22.4
----------------------------------------------------------------------------------------
CASH FLOWS (REQUIRED FOR) FROM FINANCING ACTIVITIES
   Proceeds from:
      Long-term debt - net of issuance costs                -      344.0       67.9
      Additional capital contribution                       -      164.4          -
      Short-term notes payable                              -          -      150.0
      Other proceeds                                        -          -        1.6
   Requirements for:
      Dividends on common stock                         (71.7)     (64.9)     (55.0)
      Retirement of long-term debt                       (6.5)      (7.3)      (0.7)
      Redemption of preferred stock of subsidiary        (0.2)     (17.7)      (2.0)
      Retirement of short-term notes payable                -     (150.0)         -
      Dividends on preferred stock of subsidiary            -       (0.8)      (1.0)
   Net change in short-term borrowings                  (35.1)    (236.1)     405.2
--------------------------------------------------------------------------------------
        Net cash flows (required for) from
         financing activities                          (113.5)      31.6      566.0
----------------------------------------------------------------------------------------
CASH FLOWS (REQUIRED FOR) INVESTING ACTIVITIES
   Proceeds from other investing activities               2.6        1.5          -
   Requirements for:
      Capital expenditures, excluding AFUDC equity     (151.8)    (147.6)    (110.7)
      Acquisition of Ohio operations                        -       (2.2)    (469.2)
      Other investments                                 (11.8)      (4.0)      (7.1)
----------------------------------------------------------------------------------------
         Net cash flows (required for) investing
           activities                                  (161.0)    (152.3)    (587.0)
----------------------------------------------------------------------------------------
Net increase (decrease) in cash & cash equivalents        5.5        2.8        1.4
Cash & cash equivalents at beginning of period            5.0        2.2        0.8
----------------------------------------------------------------------------------------
Cash & cash equivalents at end of period              $  10.5    $   5.0    $   2.2
========================================================================================
</TABLE>


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

<PAGE>

<TABLE>
<CAPTION>
             VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES
             CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER'S EQUITY
                                  (In millions)

                                                                      Accumulated
                                                                          Other
                                                  Common   Retained   Comprehensive
                                                  Stock    Earnings   Income (Loss)       Total
--------------------------------------------------------------------------------------------------
<S>                                              <C>       <C>           <C>         <C>
Balance at January 1, 2000, As Reported          $ 221.3   $ 361.9       $   -       $ 583.2
Restatement adjustment                                 -       1.7           -           1.7
--------------------------------------------------------------------------------------------
Balance at January 1, 2000, As Restated            221.3     363.6           -         584.9
--------------------------------------------------------------------------------------------
Net income & comprehensive income, As Restated         -      52.5           -          52.5

Common stock dividends                                 -     (55.0)          -         (55.0)
Contributions to parent                                -      (9.1)          -          (9.1)
Other                                                  -       0.3           -           0.3
--------------------------------------------------------------------------------------------
Balance at December 31, 2000, As Restated          221.3     352.3           -         573.6
--------------------------------------------------------------------------------------------
Comprehensive income:
Net income, As Restated                                -      40.1           -          40.1
Minimum pension liability adjustment
    & other-net of tax                                 -         -        (1.8)         (1.8)
--------------------------------------------------------------------------------------------
Total comprehensive income, As Restated                -         -           -          38.3
--------------------------------------------------------------------------------------------
Common stock:
    Additional capital contribution                164.4         -           -         164.4
    Dividends                                          -     (64.9)          -         (64.9)
Contributions to parent                                -      (6.1)          -          (6.1)
Loss on extinguishment of preferred stock              -      (1.2)          -          (1.2)
--------------------------------------------------------------------------------------------
Balance at December 31, 2001, As Restated          385.7     320.2        (1.8)        704.1
--------------------------------------------------------------------------------------------
Comprehensive income:
Net income                                             -      93.6           -          93.6
Minimum pension liability adjustments &
    other - net of tax                                 -         -         2.3           2.3
--------------------------------------------------------------------------------------------
Total comprehensive income                             -         -           -          95.9
--------------------------------------------------------------------------------------------
Common stock dividends                                 -     (71.7)          -         (71.7)
--------------------------------------------------------------------------------------------
Balance at December 31, 2002                    $  385.7   $ 342.1       $ 0.5       $ 728.3
============================================================================================
</TABLE>


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


<PAGE>


             VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES
                 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

1.   Organization and Nature of Operations

Overview
Vectren Utility Holdings, Inc. (VUHI 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.

Indiana Gas provides natural gas distribution and transportation services to a
diversified customer base in 49 of Indiana's 92 counties. SIGECO provides
electric generation, transmission, and distribution services to 8 counties in
southwestern Indiana, including counties surrounding Evansville, and
participates in the wholesale power market. SIGECO also provides natural gas
distribution and transportation services to 10 counties in southwestern Indiana,
including counties surrounding Evansville. The Ohio operations provide natural
gas distribution and transportation services to 17 counties in west central
Ohio, including counties surrounding Dayton.

Vectren is an energy and applied technology holding company headquartered in
Evansville, Indiana. The Company was organized on June 10, 1999 solely for the
purpose of effecting the merger of Indiana Energy and SIGCORP. On March 31,
2000, the merger of Indiana Energy with SIGCORP and into Vectren was consummated
with a tax-free exchange of shares and has been accounted for as a
pooling-of-interests in accordance with APB Opinion No. 16 "Business
Combinations" (APB 16).

Both Vectren and VUHI are exempt from registration pursuant to Section 3(a)(1)
and 3(c) of the Public Utility Holding Company Act of 1935.

Acquisition of the Natural Gas Distribution Assets of The Dayton Power and Light
Company
On October 31, 2000, the Company acquired the natural gas distribution assets of
The Dayton Power and Light Company for $471 million, including transaction
costs. The acquisition has been accounted for as a purchase transaction in
accordance with APB 16, and accordingly, the results of operations of the
acquired assets are included in the Company's financial results since the date
of acquisition.

The Company acquired the natural gas distribution assets as a tenancy in common
through two separate wholly owned subsidiaries. Vectren Energy Delivery of Ohio,
Inc. (VEDO) holds a 53% undivided ownership interest in the assets, and Indiana
Gas holds a 47% undivided ownership interest. VEDO is the operator of the
assets, and these operations are referred to as "the Ohio operations."

The purchase price was allocated to the assets and liabilities acquired based on
the fair value of those assets and liabilities as of the acquisition date.
Because of the regulatory environment in which the Ohio operations operate, the
book value of rate-regulated assets and liabilities is generally considered to
be fair value. Goodwill, in the amount of $202.5 million, was recognized for the
excess amount of the purchase price paid over the fair value of the net assets
acquired.

Had the acquisition of the Ohio operations occurred on January 1, 2000, pro
forma operating revenues and net income for the year ended December 31, 2000
would have been $1,339.1 million and $51.1 million, respectively. This pro forma
information is not necessarily indicative of the results that actually would
have occurred if the transaction had been consummated at the beginning of the
periods presented and is not intended to be a projection of future results.

2.   Summary of Significant Accounting Policies

A. Principles of Consolidation
The accompanying consolidated financial statements for the period prior to March
31, 2000 reflect the Company on a historical basis as restated for the effects
of the combination of entities under common control whereby Indiana Gas and
SIGECO became subsidiaries of VUHI. The consolidated financial statements
include the accounts of the Company and its wholly owned and majority owned
subsidiaries, after elimination of intercompany transactions.

For the three months ended March 31, 2000, operating revenues and net income
contributed by the predecessor companies were $171.6 million and $8.8 million,
respectively, by Indiana Gas and $102.2 million and $4.0 million, respectively,
by SIGECO.

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. Cash paid during the
periods reported for interest, income taxes, and acquired assets and liabilities
follows:

                                                     Year Ended December 31,
-----------------------------------------------------------------------------
 In millions                                2002          2001           2000
-----------------------------------------------------------------------------
Cash paid for
      Interest                            $ 55.6        $ 62.9        $  45.2
      Income taxes                          63.3          46.7           44.8
-----------------------------------------------------------------------------

Details of acquisition (Note 1)
      Book value of assets acquired       $    -        $  1.6        $ 275.2
      Liabilities assumed                      -             -            7.9
-----------------------------------------------------------------------------
      Net assets acquired                 $    -        $  1.6        $ 267.3
=============================================================================


C. Inventories Inventories consist of the following:

                                                              At December 31,
-----------------------------------------------------------------------------
In millions                                            2002              2001
-----------------------------------------------------------------------------
Gas in storage - at LIFO cost                        $ 25.4            $ 24.4
Materials & supplies                                   15.8              16.5
Fuel (coal & oil) for electric generation              10.0               9.5
Gas in storage - at average cost                        3.3               0.8
Other                                                   1.5               3.6
-----------------------------------------------------------------------------
       Total inventories                             $ 56.0            $ 54.8
=============================================================================

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,
2002 and 2001 by approximately $32.7 million and $17.9 million, respectively.
Gas in storage of the Indiana regulated operations is stated at LIFO. All other
inventories are carried at average cost.

D. Utility Plant & Depreciation
Utility plant is stated at historical cost, including AFUDC. Depreciation of
utility property is provided using the straight-line method over the estimated
service lives of the depreciable assets.


<PAGE>


The original cost of utility plant, together with depreciation rates expressed
as a percentage of original cost, follows:
<TABLE>
<CAPTION>
                                            At and For the Year Ended December 31,
-----------------------------------------------------------------------------------
In millions                                     2002                       2001
-----------------------------------------------------------------------------------
                                           Depreciation                Depreciation
                                            Rates as a                  Rates as a
                                            Percent of                  Percent of
                                 Original    Original      Original      Original
                                   Cost        Cost          Cost          Cost
-----------------------------------------------------------------------------------
<S>                             <C>            <C>         <C>             <C>
Gas utility plant               $1,622.0       3.8%        $1,523.0        3.6%
Electric utility plant           1,211.1       3.3%         1,148.9        3.3%
Common utility plant                41.6       2.6%            41.3        2.6%
Construction work in progress      162.5         -            192.9          -
-----------------------------------------------------------------------------------
       Total original cost      $3,037.2         -         $2,906.1          -
===================================================================================
</TABLE>


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 and 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                           2002             2001            2000
----------------------------------------------------------------------------
AFUDC - borrowed funds                $ 3.1            $ 2.1           $ 2.4
AFUDC - equity funds                    2.2              2.5             2.6
----------------------------------------------------------------------------
      Total AFUDC capitalized         $ 5.3            $ 4.6           $ 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 cost of such property is credited to utility plant, and such cost,
together with the cost of removal less salvage, is charged to accumulated
depreciation.

E.   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 as required 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 replaced
authoritative guidance in SFAS No. 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to Be Disposed Of" (SFAS 121) and
certain aspects of APB Opinion No. 30, "Reporting Results of
Operations-Reporting the Effects of Disposal of a Segment of a Business." SFAS
144 retains the framework of SFAS 121 and 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.

F.   Goodwill
Goodwill arising from past business combinations, such as the Company's
acquisition of the Ohio operations, is accounted for in accordance with SFAS No.
142, "Goodwill and Other Intangible Assets" (SFAS 142). The Company adopted SFAS
142, as required on January 1, 2002. SFAS 142 changed the accounting for
goodwill from an amortization approach to an impairment-only approach. Thus,
amortization of goodwill that was not included as an allowable cost for
rate-making purposes ceased upon SFAS 142's adoption.

Goodwill is to be tested for impairment at a reporting unit level at least
annually. The impairment review consists 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.
Prior to the adoption of SFAS 142, the Company amortized goodwill on a
straight-line basis over 40 years. SFAS 142 required an initial impairment
review of all goodwill within six months of the adoption date. Results of the
initial impairment review were to be treated as a change in accounting principle
in accordance with APB Opinion No. 20 "Accounting Changes."

As required by SFAS 142, amortization of goodwill relating to the acquisition of
the Ohio operations ceased on January 1, 2002. Amortization approximated $4.9
million ($3.0 million after tax) in 2001 and $0.8 million ($0.5 million after
tax) in 2000. The Company's goodwill is included in the Gas Utility Services
operating segment. Initial impairment reviews to be performed within six months
of adoption of SFAS 142 were completed and resulted in no impairment. The
impairment test is performed at the beginning of each year.

G.   Regulation
Retail public utility operations affecting Indiana customers are subject to
regulation by the IURC, and retail public utility operations affecting Ohio
customers are subject to regulation by the PUCO.

SFAS 71
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 represent probable future revenues associated with certain
incurred costs, which will be recovered from customers through the rate-making
process. Regulatory liabilities represent probable future reductions in revenues
associated with amounts that are to be credited to 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 assets consist of the following:

                                    At December 31,
---------------------------------------------------
 In millions                          2002     2001
---------------------------------------------------
Demand side management programs     $ 32.1   $ 31.7
Unamortized debt issue costs          19.5     21.2
Regulatory income tax asset           15.8     10.3
Other                                  7.8      4.6
---------------------------------------------------
     Total regulatory assets        $ 75.2   $ 67.8
===================================================


As of December 31, 2002, regulatory assets totaling $42.6 million are reflected
in rates charged to customers, of which $17.2 million is earning a return. The
remaining $32.6 million, which is not yet included in rates, represents
primarily electric demand side management (DSM) costs incurred after 1993. The
Company has rate orders for all deferred costs not yet in rates and therefore
believes that future recovery is probable. At December 31, 2002, the weighted
average recovery period of regulatory assets, other than those arising from book
- tax basis differences, included in rates is 16.0 years. Regulatory income tax
assets are recovered as deferred tax assets and liabilities discussed in Note 4
become payable or receivable.

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 typically contain a fuel adjustment clause that allows for adjustment in
charges for electric energy to reflect changes in the cost of fuel and the net
energy cost of purchased power. Metered electric rates also allow recovery,
through a quarterly rate adjustment mechanism, for the margin on electric sales
lost due to the implementation of demand side management programs.

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.

H.   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. The principal transaction resulting in other
comprehensive income relates to a minimum pension liability adjustment which is
a loss of $3.8 million ($2.4 million after tax) in 2001. In 2002, all such
liabilities were transferred to Vectren. The remaining component of accumulated
other comprehensive income relates to a cash flow hedge discussed in Note 12.

I.   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.

J.   Excise and Gross Receipts Taxes
Excise taxes and a portion of gross receipts taxes are included in rates charged
to customers. Accordingly, the Company records these taxes received as a
component of operating revenues, which totaled $32.4 million in 2002, $26.6
million in 2001, and $16.6 million in 2000. Excise and gross receipts taxes paid
are recorded as a component of taxes other than income taxes.

K.   Earnings Per Share Earnings per share are not presented as VUHI's common
stock is wholly owned by Vectren.

L.   Other Significant Policies
Included elsewhere in these notes are significant accounting policies related to
intercompany allocations and income taxes (Note 4) and derivatives (Note 12).

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

3.   Restatement of Previously Reported Results

The Company identified adjustments that, in the aggregate, reduced previously
reported 2001 earnings by approximately $10.6 million after tax and other
adjustments, as described below, related to 2000 and prior periods. Adjustments
were also made to previously reported 2002 quarterly results. In addition to
adjustments affecting previously reported net income, other reclassifications
were made to the previously reported 2001 and 2000 results to conform with the
2002 presentation.

Previously Reported 2001 and 2000 Net Income Adjustments

The Company determined that $11.6 million ($7.2 million after tax) of gas costs
were improperly recorded as recoverable gas costs due from customers. The error
related primarily to the accounting for natural gas inventory and resulted in an
overstatement of 2001 earnings.

The Company also identified an accounting error related to certain employee
benefit and other related costs that are routinely accumulated on the balance
sheet and systematically cleared to operating expense and capital projects.
Because of inadequate loading rates, these costs were not fully cleared to
operating expense and capital projects in 2001. As a result, 2001 earnings were
overstated by $5.6 million ($3.5 million after tax).

The accounting for certain wholesale power marketing contracts was modified to
comply with SFAS 133, which became effective on January 1, 2001. The cumulative
effect at adoption was decreased by $2.8 million after tax. This change was
offset substantially by an increase in electric margins throughout 2001.

The Company identified reconciliation errors and other errors related to the
recording of estimates that were not significant, either individually or in the
aggregate. As a result of these additional items, 2001 earnings were reduced by
$2.2 million ($1.4 million after tax). Originally reflected in 2001, the
correction of the year 2000 overstatement of electric revenue totaling $2.4
million ($1.5 million after tax), now reflected in 2000 as discussed below,
significantly offset these additional items.

The Company also determined that certain billings and collections had been
improperly recorded in 2000, resulting in an understatement of gas revenue by
$1.8 million ($1.1 million after tax) and an overstatement of electric revenue
by $2.4 million ($1.5 million after tax). Other errors were identified that
increased 2000 earnings by $0.8 million ($0.5 million after tax). The impact of
the restatement of results for the year ended 2000 is an increase to net income
of approximately $100,000.

Previously Reported 2002 Quarterly Net Income Adjustments

As previously reported, in the second quarter of 2002 the Company recorded $5.2
million ($3.2 million after tax) of carrying costs for DSM programs pursuant to
existing IURC orders and based on an improved regulatory environment. During the
audit of the three years ended December 31, 2002, management determined that the
accrual of such carrying costs was more appropriate in periods prior to 2000
when DSM program expenditures were made. Therefore, such carrying costs
originally reflected in 2002 quarterly results were reversed and reflected in
common shareholders' equity as of January 1, 2000. In addition, the Company
identified other adjustments that were not significant, either individually or
in the aggregate that increased previously reported 2002 quarterly pre-tax and
after tax earnings by approximately $1.8 million and $1.1 million after tax,
respectively. The cumulative impact from of these adjustments reduced previously
reported earnings for the nine months ended September 30, 2002 by approximately
$2.1 million.

Beginning Retained Earnings Adjustments

In addition to the adjustment of DSM costs above, the Company identified other
errors that were not significant, either individually or in the aggregate that
relate to years prior to 2000. As a result of these additional items, beginning
common shareholders' equity was reduced by $1.5 million. Accordingly, retained
earnings as of January 1, 2000 reflects a cumulative net increase of $1.7
million.

Other Balance Sheet Adjustments

Certain reclassifications were made to reflect separate Company prepaid and
accrued taxes that result in the consolidated tax position. This adjustment
added approximately $26.6 million to receivables due from other Vectren
companies and prepaid and other current assets with a corresponding increase in
payables due to other Vectren companies, accrued liabilities, and deferred taxes
as of December 31, 2001. The Company also reclassified all previously recorded
goodwill not included in rates to goodwill on the balance sheet. This adjustment
resulted in a $5.9 million decrease in other assets, a $3.0 million decrease in
prepayments and other current assets and an $8.9 million increase in goodwill.

The Company has restated its financial statements to give effect to the matters
discussed above. Following is a summary of the significant effects of the
restatement on previously reported financial position and results of operations.
The effects of the restatement on 2001 quarterly results and on 2002 previously
reported quarterly information, is discussed in Note 18. Note 18 is unaudited.

The effects on the income statement for the year ending December 31, 2001
follow:
<TABLE>
<CAPTION>

                                            As Reported  Adjustments As Restated
--------------------------------------------------------------------------------
<S>                                           <C>           <C>        <C>
OPERATING REVENUES
   Gas utility                                $ 1,031.5     $ (11.9)   $ 1,019.6
   Electric utility                               378.9         2.3        381.2
--------------------------------------------------------------------------------
        Total operating revenues                1,410.4        (9.6)     1,400.8
--------------------------------------------------------------------------------

COST OF OPERATING REVENUES
   Cost of gas sold                               708.2         0.7        708.9
   Fuel for electric generation                    74.4           -         74.4
   Purchased electric energy                       91.7        (4.8)        86.9
--------------------------------------------------------------------------------
        Total cost of operating revenues          874.3        (4.1)       870.2
--------------------------------------------------------------------------------

TOTAL OPERATING MARGIN                            536.1        (5.5)       530.6

OPERATING EXPENSES
   Other operating                                234.7         6.4        241.1
   Merger & integration costs                       2.8           -          2.8
   Restructuring costs                             15.0           -         15.0
   Depreciation & amortization                     96.9         0.3         97.2
   Taxes other than income taxes                   51.3        (0.1)        51.2
--------------------------------------------------------------------------------
        Total operating expenses                  400.7         6.6        407.3
--------------------------------------------------------------------------------
OPERATING INCOME                                  135.4       (12.1)       123.3
--------------------------------------------------------------------------------
OTHER INCOME
   Other - net                                      5.0         0.5          5.5
   Equity in earnings of unconsolidated affiliates    -        (0.5)        (0.5)
--------------------------------------------------------------------------------
        Total other income                          5.0           -          5.0
--------------------------------------------------------------------------------
Interest expense                                   70.1           -         70.1
--------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES                         70.3       (12.1)        58.2
--------------------------------------------------------------------------------
Income taxes                                       22.7        (4.3)        18.4
Preferred dividend requirements of a subsidiary     0.8            -         0.8
--------------------------------------------------------------------------------
INCOME BEFORE CUMULATIVE EFFECT OF CHANGE
      IN ACCOUNTING PRINCIPLE                      46.8        (7.8)        39.0
--------------------------------------------------------------------------------
Cumulative effect of change in accounting
   principle - net of tax                           3.9        (2.8)         1.1
--------------------------------------------------------------------------------
NET INCOME                                    $    50.7     $ (10.6)   $    40.1
================================================================================
</TABLE>


<PAGE>


The effects on the income statement for the year ending December 31, 2000
follow:
<TABLE>
<CAPTION>
                                             -----------------------------------
                                             As Reported Adjustments As Restated
--------------------------------------------------------------------------------
<S>                                        <C>              <C>          <C>
OPERATING REVENUES
      Gas utility                          $ 818.8          $ 1.6        $ 820.4
      Electric utility                       336.4           (2.0)         334.4
--------------------------------------------------------------------------------
           Total operating revenues        1,155.2           (0.4)       1,154.8
--------------------------------------------------------------------------------
COST OF OPERATING REVENUES
      Cost of gas sold                       552.5              -          552.5
      Fuel for electric generation            75.7              -           75.7
      Purchased electric energy               36.4              -           36.4
--------------------------------------------------------------------------------
           Total cost of operating revenues  664.6              -          664.6
--------------------------------------------------------------------------------
TOTAL OPERATING MARGIN                       490.6           (0.4)         490.2

OPERATING EXPENSES
      Other operating                        209.9           (0.9)         209.0
      Merger & integration costs              32.7              -           32.7
      Depreciation & amortization             82.4              -           82.4
      Taxes other than income taxes           36.2              -           36.2
--------------------------------------------------------------------------------
           Total operating expenses          361.2           (0.9)         360.3
--------------------------------------------------------------------------------

OPERATING INCOME                             129.4            0.5          129.9

Other income - net                             5.0           (0.3)           4.7
Interest expense                              46.1              -           46.1
--------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES                    88.3            0.2           88.5
--------------------------------------------------------------------------------
Income taxes                                  34.9            0.1           35.0
Preferred dividend requirements of subsidiary  1.0              -            1.0
--------------------------------------------------------------------------------
NET INCOME                                  $ 52.4          $ 0.1         $ 52.5
================================================================================
</TABLE>

<PAGE>


The effects on the balance sheet as of December 31, 2001 follow:

<TABLE>
<CAPTION>

---------------------------------------------------------------------------------------------
    ASSETS
                                                  As Reported    Adjustments    As Restated
                                               -------------- ---------------  --------------
<S>                                                    <C>          <C>              <C>
Current Assets
      Cash & cash equivalents                      $     7.2        $ (2.2)       $     5.0
      Accounts receivable-less reserves                125.3          (2.2)           123.1
      Receivables due from other Vectren companies      26.6          59.7             86.3
      Accrued unbilled revenues                         78.3          (1.2)            77.1
      Inventories                                       55.3          (0.5)            54.8
      Recoverable fuel & natural gas costs              76.5          (6.3)            70.2
      Prepayments & other current assets               127.4         (44.6)            82.8
---------------------------------------------------------------------------------------------
          Total current assets                         496.6           2.7            499.3
---------------------------------------------------------------------------------------------

Utility Plant
     Original cost                                   2,903.2           2.9          2,906.1
     Less:  accumulated depreciation & amortization  1,308.2             -          1,308.2
---------------------------------------------------------------------------------------------
          Net utility plant                          1,595.0           2.9          1,597.9
---------------------------------------------------------------------------------------------

Investments in unconsolidated affiliates                 4.0          (0.5)             3.5
Other investments                                       12.2             -             12.2
Non-utility property-net                                 6.3             -              6.3
Goodwill-net                                           193.1           8.4            201.5
Regulatory assets                                       61.4           6.4             67.8
Other assets                                            22.8          (8.7)            14.1
---------------------------------------------------------------------------------------------
TOTAL ASSETS                                       $ 2,391.4        $ 11.2        $ 2,402.6
=============================================================================================

             LIABILITIES & SHAREHOLDER'S EQUITY

Current Liabilities
      Accounts payable                             $    79.0        $  0.4        $    79.4
      Accounts payable to affiliated companies          36.5           0.9             37.4
      Payables due to other Vectren companies           11.5          17.7             29.2
      Accrued liabilities                               97.5          (2.8)            94.7
      Short-term borrowings                            274.2             -            274.2
      Long-term debt subject to tender                  11.5             -             11.5
      Current maturities of long-term debt               1.3             -              1.3
---------------------------------------------------------------------------------------------
          Total current liabilities                    511.5          16.2            527.7
---------------------------------------------------------------------------------------------

Long-Term Debt-Net of Current Maturities &
      Debt Subject to Tender                           900.9             -            900.9

Deferred Income Taxes & Other Liabilities
      Deferred income taxes                            171.8           4.7            176.5
      Deferred credits & other liabilities              93.7          (0.8)            92.9
---------------------------------------------------------------------------------------------
          Total deferred credits & other liabilities   265.5           3.9            269.4
---------------------------------------------------------------------------------------------

Cumulative, Redeemable Preferred Stock of a Subsidiary   0.5             -              0.5

Common shareholder's equity
      Common stock (no par value)                      385.7             -            385.7
      Retained earnings                                329.0          (8.8)           320.2
      Accumulated other comprehensive loss           (1.7)         (0.1)            (1.8)
---------------------------------------------------------------------------------------------
          Total common shareholder's equity            713.0          (8.9)           704.1
---------------------------------------------------------------------------------------------
---------------------------------------------------------------------------------------------
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY           $ 2,391.4        $ 11.2        $ 2,402.6
=============================================================================================
</TABLE>


<PAGE>

4.   Transactions with Other Vectren Companies

Support Services and Purchases
Vectren and certain subsidiaries of Vectren provided corporate, general and
administrative services to the Company including legal, finance, tax, risk
management, and 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. VUHI received corporate allocations totaling
$133.5 million, $116.8 million, and $65.2 million for the years ended December
31, 2002, 2001, and 2000, 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, 2002, 2001 and
2000, totaled $62.1 million, $58.4 million, and $25.7 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. Subsequent to the merger forming Vectren, 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 interest cost from prior service
and asset returns) are charged to individual subsidiaries through the corporate
allocation process discussed above. Plan assets nor the FAS 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, 2002 and 2001 pension expense totaling $5.5
million and $5.1 million, respectively, were directly charged by Vectren to the
Company. For the years ended December 31, 2002 and 2001other benefit expenses
totaling $1.0 million in both years were directly charged by Vectren to the
Company. In 2000, the Company recognized $8.8 million in charges for
participation in Vectren benefit plans. As of December 31, 2002 and 2001, $51.8
million and $53.3 million is included in other non-current liabilities and
represents expense directly charged to the Company that is yet to be funded to
Vectren, and $3.5 million and $4.8 million is included in other assets for
amounts funded in advance to Vectren.

Cash Management and Borrowing Arrangements
The Company participates in a centralized cash management program with Vectren,
other wholly owned subsidiaries, and banks which permits funding of checks as
they are presented.

Vectren's three operating utility companies, SIGECO, Indiana Gas, and VEDO are
guarantors of VUHI's $350.0 million commercial paper program, of which $239.1
million is outstanding at December 31, 2002 and VUHI's $350.0 million unsecured
senior notes outstanding at December 31, 2002. VUHI has no independent assets or
operations, the guarantees are full and unconditional and joint and several, and
VUHI has no subsidiaries other than the subsidiary quarantors.

Stock-Based Incentive Plans
VUHI does not have stock-based compensation plans separate from Vectren. An
insignificant number of VUHI's employees participate in Vectren's stock-based
compensation plans.

Income Taxes
Vectren and subsidiary companies file a consolidated federal income tax return.
For financial reporting purposes, VUHI's current and deferred tax expense is
computed on a separate company basis. The components of income tax expense and
utilization of investment tax credits follow:

<TABLE>
<CAPTION>
                                                         Year Ended December 31,
----------------------------------------------------------------------------------
 In millions                                       2002         2001          2000
----------------------------------------------------------------------------------
<S>                                              <C>          <C>           <C>
Current:
       Federal                                   $ 59.2       $ 29.5        $ 19.5
       State                                        7.4          3.8           2.6
----------------------------------------------------------------------------------
Total current taxes                                66.6         33.3          22.1
----------------------------------------------------------------------------------
Deferred:
       Federal                                    (14.9)       (12.0)         13.8
       State                                       (4.8)        (0.6)          1.5
----------------------------------------------------------------------------------
Total deferred taxes                              (19.7)       (12.6)         15.3
----------------------------------------------------------------------------------
Amortization of investment tax credits             (2.3)        (2.3)         (2.4)
----------------------------------------------------------------------------------
       Total income tax expense                  $ 44.6       $ 18.4        $ 35.0
==================================================================================
</TABLE>


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

<TABLE>
<CAPTION>
                                                                    Year Ended December 31,
--------------------------------------------------------------------------------------------
                                                             2002          2001        2000
--------------------------------------------------------------------------------------------
<S>                                                          <C>           <C>         <C>
Statutory rate                                               35.0 %        35.0%       35.0%
State and local taxes-net of federal benefit                  1.3           3.3         3.6
Nondeductible merger costs                                      -             -         4.8
Amortization of investment tax credit                        (1.7)         (4.0)       (2.7)
All other-net                                                (2.3)         (2.2)       (0.7)
--------------------------------------------------------------------------------------------
       Effective tax rate                                    32.3%         32.1%       40.0%
============================================================================================
</TABLE>


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:

<TABLE>
<CAPTION>
                                                                           At December 31,
------------------------------------------------------------------------------------------
 In millions                                                            2002          2001
------------------------------------------------------------------------------------------
<S>                                                                   <C>            <C>
Noncurrent deferred tax liabilities (assets):
     Depreciation & cost recovery timing differences                  $ 191.2      $ 197.1
     Regulatory assets recoverable through future rates                  37.5         33.5
     Regulatory liabilities to be settled through future rates          (21.7)       (23.2)
     Employee benefit obligations                                       (30.2)       (24.3)
     Other - net                                                         (3.1)        (6.6)
-------------------------------------------------------------------------------------------
         Net noncurrent deferred tax liability                          173.7        176.5
-------------------------------------------------------------------------------------------

Current deferred tax liabilities (assets):
     Deferred fuel costs-net                                              7.7         21.1
     LIFO inventory                                                         -         (2.0)
-------------------------------------------------------------------------------------------
         Net current deferred tax liability                                7.7         19.1
-------------------------------------------------------------------------------------------
         Net deferred tax liability                                    $ 181.4      $ 195.6
===========================================================================================
</TABLE>


At December 31, 2002 and 2001, investment tax credits totaling $18.6 million and
$20.9 million, respectively, are included in deferred credits and other
liabilities. These investment tax credits are amortized over the lives of the
related investments. The Company has no tax credit carryforwards at December 31,
2002. Alternative Minimum Tax credit carryforwards of approximately $5.2 million
were utilized in 2001.

5. 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 Indiana Gas, the Ohio operations, Citizens Gas and
others. ProLiance also began providing service to SIGECO and Vectren Retail, LLC
(the Company's retail gas marketer) in 2002. ProLiance's primary business is
optimizing the gas portfolios of utilities and providing services to large end
use customers. Vectren continues to account for its investment in ProLiance
using the equity method of accounting.

Regulatory Matters
The sale of gas and provision of other services to Indiana Gas and SIGECO by
ProLiance is subject to regulatory review through the quarterly gas cost
adjustment (GCA) process administered by the IURC. The sale of gas and provision
of other services to the Ohio operations by ProLiance is subject to regulatory
review through the quarterly gas cost recovery (GCR) and audit process
administered by the PUCO.

Specific to the sale of gas and provision of other services to Indiana Gas by
ProLiance, on September 12, 1997, the IURC issued a decision finding the gas
supply and portfolio administration agreements between ProLiance and Indiana Gas
and ProLiance and Citizens Gas to be consistent with the public interest and
that ProLiance is not subject to regulation by the IURC as a public utility.
However, with respect to the pricing of gas commodity purchased from ProLiance,
the price paid by ProLiance to the utilities for the prospect of using pipeline
entitlements if and when they are not required to serve the utilities' firm
customers, and the pricing of fees paid by the utilities to ProLiance for
portfolio administration services, the IURC concluded that additional review in
the GCA process would be appropriate and directed that these matters be
considered further in a consolidated GCA proceeding involving Indiana Gas and
Citizens Gas.

On June 4, 2002, Indiana Gas and Citizens Gas, together with the OUCC and other
consumer parties, entered into and filed with the IURC a settlement setting
forth the terms for resolution of all pending regulatory issues related to
ProLiance, including the three pricing issues. On July 23, 2002, the IURC
approved the settlement filed by the parties. The GCA proceeding has been
concluded and new supply agreements between Indiana Gas, SIGECO, Citizens Gas,
and ProLiance have been approved and extended through March 31, 2007. ProLiance
will also have the opportunity, if it so elects, to participate in a "request
for proposal" process for service to the utilities after March 31, 2007.

For past services provided to Indiana Gas by ProLiance, Indiana Gas made refunds
to retail customers pursuant to the settlement totaling $6.4 million in the
fourth quarter of 2002. A subsidiary of Vectren's nonregulated operations has
indemnified Indiana Gas for the amount of the refund as well as any other
amounts incurred as a result of the settlement. Accordingly, the refund had no
effect on operating margin or net income.

Transactions with ProLiance
Purchases from ProLiance for resale and for injections into storage for the
years ended December 31, 2002, 2001, and 2000 totaled $542.5 million, $610.6
million, and $478.9 million, respectively. Amounts owed to ProLiance at December
31, 2002 and 2001 for those purchases were $83.7 million and $36.1 million,
respectively, and are included in accounts payable to affiliated companies in
the Consolidated Balance Sheets. Amounts charged by ProLiance for gas supply
services are established by supply agreements with each utility.

Other Affiliate Transactions
The Company has ownership interests in other affiliated companies accounted for
using the equity method of accounting that provide materials management,
underground construction and repair, facilities locating, and meter reading
services to the Company. For the years ended December 31, 2002, 2001, and 2000,
fees for these services and construction-related expenditures totaled $38.3
million, $30.4 million, and $6.9 million, respectively. Amounts charged by these
affiliates are market based. Amounts owed to unconsolidated affiliates other
than ProLiance totaled $1.8 million and $1.3 million at December 31, 2002 and
2001, respectively, and are included in accounts payable to affiliated companies
in the Consolidated Balance Sheets.

6. Borrowing Arrangements

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

<TABLE>
<CAPTION>
                                                                       At December 31,
--------------------------------------------------------------------------------------
 In millions                                                      2002            2001
--------------------------------------------------------------------------------------
VUHI
<S>                                                             <C>            <C>
     Fixed Rate Senior Unsecured Notes
         2011, 6.625%                                          $ 250.0         $ 250.0
         2031, 7.25%                                             100.0           100.0
--------------------------------------------------------------------------------------
         Total VUHI                                              350.0           350.0
--------------------------------------------------------------------------------------

SIGECO
  First Mortgage Bonds
      Fixed Rate:
      2003, Series B, 6.25%, tax exempt                            1.0             1.0
      2016, 1986 Series, 8.875%                                   13.0            13.0
      2023, Series, 7.60%                                         45.0            45.0
      2023, Series B, 6.00%, tax exempt                           22.8            22.8
      2025, 1993 Series, 7.625%                                   20.0            20.0
      2029, 1999 Senior Notes, 6.72%                              80.0            80.0
      Adjustable Rate:
      2015, Pollution Control Series A, presently 4.30%, tax
        exempt, next rate adjustment: 2004                        10.0            10.0
      2025, Pollution Control Series A, presently 4.75%, tax
        exempt, next rate adjustment: 2006                        31.5            31.5
      2024, Environmental Improvement Series A, tax exempt,
        adjusts every 35 days, weighted average for year: 1.80%   22.5            22.5
---------------------------------------------------------------------------------------
      Total First Mortgage Bonds                                 245.8           245.8
--------------------------------------------------------------------------------------
  Adjustable Rate Senior Unsecured Bonds
      2020, Pollution Control Series B, presently 4.40%, tax
        exempt, next rate adjustment: 2003                         4.6             4.6
      2030, Pollution Control Series B, presently 4.40%, tax
        exempt, next rate adjustment: 2003                        22.0            22.0
      2030, Pollution Control Series C, presently 5.00%, tax
        exempt, next rate adjustment: 2006                        22.2            22.2
--------------------------------------------------------------------------------------
      Total Adjustable Rate Senior Unsecured Bonds                48.8            48.8
------------------------------------------------------------------------------------------

------------------------------------------------------------------------------------------
      Total SIGECO                                               294.6           294.6
------------------------------------------------------------------------------------------

                                                                       At December 31,
------------------------------------------------------------------------------------------
 In millions                                                         2002         2001
------------------------------------------------------------------------------------------
Indiana Gas
  Fixed Rate Senior Unsecured Notes
      2003, Series F, 5.75%                                          15.0        15.0
      2004, Series F, 6.36%                                          15.0        15.0
      2007, Series E, 6.54%                                           6.5         6.5
      2013, Series E, 6.69%                                           5.0         5.0
      2015, Series E, 7.15%                                           5.0         5.0
      2015, Insured Quarterly, 7.15%                                 20.0        20.0
      2015, Series E, 6.69%                                           5.0         5.0
      2015, Series E, 6.69%                                          10.0        10.0
      2021, Private Placement, 9.375%, $1.3 due annually in 2002     23.8        25.0
      2025, Series E, 6.31%                                             -         5.0
      2025, Series E, 6.53%                                          10.0        10.0
      2027, Series E, 6.42%                                           5.0         5.0
      2027, Series E, 6.68%                                           3.5         3.5
      2027, Series F, 6.34%                                          20.0        20.0
      2028, Series F, 6.75%                                          13.6        13.8
      2028, Series F, 6.36%                                          10.0        10.0
      2028, Series F, 6.55%                                          20.0        20.0
      2029, Series G, 7.08%                                          30.0        30.0
      2030, Insured Quarterly, 7.45%                                 49.9        50.0
------------------------------------------------------------------------------------------
      Total Indiana Gas                                             267.3       273.8
------------------------------------------------------------------------------------------

Total long-term debt outstanding                                    911.9       918.4
Less:    Current maturities of long-term debt                        39.8         1.3
         Debt subject to tender                                      26.6        11.5
         Unamortized debt premium & discount - net                    4.3         4.7
------------------------------------------------------------------------------------------
         Total long-term debt-net                                 $ 841.2     $ 900.9
==========================================================================================
</TABLE>


VUHI
In September 2001, VUHI filed a shelf registration statement with the Securities
and Exchange Commission for $350.0 million aggregate principal amount of
unsecured senior notes. In October 2001, VUHI issued senior unsecured notes with
an aggregate principal amount of $100.0 million and an interest rate of 7.25%
(the October Notes), and in December 2001, issued the remaining aggregate
principal amount of $250.0 million at an interest rate of 6.625% (the December
Notes). The December Notes were priced at 99.302% to yield 6.69% to maturity.

These issues have no sinking fund requirements, and interest payments are due
quarterly for the October Notes and semi-annually for the December Notes. The
October Notes are due October 2031, but may be called by the Company, in whole
or in part, at any time after October 2006 at 100% of the principal amount plus
any accrued interest thereon. The December Notes are due December 2011, but may
be called by the Company, 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 25 basis points.

Both issues are guaranteed by VUHI's three operating utility companies: SIGECO,
Indiana Gas, and VEDO. VUHI has no independent assets or operations, the
guarantees of VUHI's debt are full and unconditional and joint and several, and
VUHI has no subsidiaries other than the subsidiary quarantors.

The net proceeds from the sale of the senior notes and settlement of hedging
arrangements (see Note 12) totaled $344.0 million.

Indiana Gas
In December 2000, $20.0 million of 15-Year Insured Quarterly (IQ) Notes at an
interest rate of 7.15% and $50.0 million of 30-Year IQ Notes at an interest rate
of 7.45% were issued. Indiana Gas may call the 15-Year IQ Notes, in whole or in
part, from time to time on or after December 15, 2004 and has the option to
redeem the 30-Year IQ Notes in whole or in part, from time to time on or after
December 15, 2005. The IQ notes have no sinking fund requirements. The net
proceeds totaled $67.9 million.

Long-Term Debt Put & Call Provisions
On January 15, 2003, the Company called the remaining $23.8 million of Indiana
Gas' 9.375% private placement notes originally due in 2021. Since the proceeds
to repay the notes were generated from short-term borrowings, these notes are
classified in current maturities of long-term debt at December 31, 2002.

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 2002 (in millions) is $26.6 in 2003, $13.5 in 2004, $10.0 in 2005,
$53.7 in 2006, $20.0 in 2007, and $120.0 thereafter.

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 2002 sinking fund requirement by this
means and, accordingly, the sinking fund requirement for 2002 is excluded from
current liabilities in the Consolidated Balance Sheets. At December 31, 2002,
$342.8 million of SIGECO's utility plant remained unfunded under SIGECO's
Mortgage Indenture.

Consolidated maturities and sinking fund requirements on long-term debt,
including debt to be called, during the five years following 2002 (in millions)
are $39.8 in 2003, $15.0 in 2004, zero in 2005, zero in 2006, and $6.5 in 2007.

Short-Term Borrowings
At December 31, 2002, the Company has $330.0 million of short-term borrowing
capacity, of which approximately $90.9 million is available. Subsequent to
December 31, 2002, the Company increased its capacity $145.0 million to $475.0
million. See the table below for interest rates and outstanding balances.

<TABLE>
<CAPTION>
                                                          Year ended December 31,
------------------------------------------------------------------------------------
In millions                                           2002        2001       2000
------------------------------------------------------------------------------------
<S>                                                   <C>          <C>        <C>
Weighted average commercial paper and
    bank loans outstanding during the year           $ 155.7      $ 356.1    $ 190.0

Weighted average interest rates during the year
       Bank loans                                      2.61%        4.39%      6.62%
       Commercial paper                                2.02%        5.77%      6.60%

                                                                 At December 31,
---------------------------------------------------------------------------------
In millions                                           2002          2001
---------------------------------------------------------------------------------
Commercial paper                                     $ 239.1        $ 273.3
Bank loans                                                 -            0.9
---------------------------------------------------------------------------------
       Total short-term borrowings                   $ 239.1        $ 274.2
=================================================================================
</TABLE>


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, 2002, the Company was in
compliance with all financial covenants.

7. Cumulative Preferred Stock of a Subsidiary

Redemption of Preferred Stock of a Subsidiary
Nonredeemable preferred stock of a subsidiary containing call options was
redeemed during September 2001 for a total redemption price of $9.8 million. The
4.80%, $100 par value preferred stock was redeemed at its stated call price of
$110 per share, plus accrued and unpaid dividends totaling $1.35 per share. The
4.75%, $100 par value preferred stock was redeemed at its stated call price of
$101 per share, plus accrued and unpaid dividends totaling $0.97 per share.
Prior to the redemptions, there were 85,519 shares of the 4.80% Series
outstanding and 3,000 shares of the 4.75% Series outstanding.

In September 2001, the 6.50%, $100 par value of redeemable preferred stock of a
subsidiary was redeemed for a total redemption price of $7.9 million at $104.23
per share, plus $0.73 per share in accrued and unpaid dividends. Prior to the
redemption, there were 75,000 shares outstanding.

As both series of preferred stock redeemed was that of a subsidiary, the loss on
redemption of $1.2 million in 2001 is reflected in retained earnings.

Redeemable, Special
This series of redeemable preferred stock has a dividend rate of 8.50% and in
the event of involuntary liquidation the amount payable is $100 per share, plus
accrued dividends. This series may be redeemed at $100 per share, plus accrued
dividends on any of its dividend payment dates and is also callable at the
Company's option at a rate of 1,160 shares per year. As of December 31, 2002 and
2001, there were 3,437 shares and 4,597 shares outstanding, respectively.

8. Common Shareholder's Equity

In February 2001, the Company received $129.4 million from an equity
contribution by Vectren. Vectren funded the contribution with the proceeds from
an offering of its common stock. In December 2001, Vectren made an additional
equity contribution of $35.0 million with proceeds received from dividends paid
by Vectren's nonregulated operations.

9. Commitments & Contingencies

Commitments
Firm commitments to purchase natural gas for years following December 31, 2002
totaled (in millions) $89.5 in 2003, $21.3 in 2004, and $3.6 million in 2005.

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. See Note 10 regarding the Clean
Air Act.

<PAGE>

10.  Environmental Matters

Clean Air Act

NOx SIP Call Matter
The Clean Air Act (the Act) requires each state to adopt a State Implementation
Plan (SIP) to attain and maintain National Ambient Air Quality Standards (NAAQS)
for a number of pollutants, including ozone. If the USEPA finds a state's SIP
inadequate to achieve the NAAQS, the USEPA can call upon the state to revise its
SIP (a SIP Call).

In October 1998, the USEPA issued a final rule "Finding of Significant
Contribution and Rulemaking for Certain States in the Ozone Transport Assessment
Group Region for Purposes of Reducing Regional Transport of Ozone," (63 Fed.
Reg. 57355). This ruling found that the SIP's of certain states, including
Indiana, were substantially inadequate since they allowed for nitrogen oxide
(NOx) emissions in amounts that contributed to non-attainment with the ozone
NAAQS in downwind states. The USEPA required each state to revise its SIP to
provide for further NOx emission reductions. The NOx emissions budget, as
stipulated in the USEPA's final ruling, requires a 31% reduction in total NOx
emissions from Indiana.

In June 2001, the Indiana Air Pollution Control Board adopted final rules to
achieve the NOx emission reductions required by the NOx SIP Call. Indiana's SIP
requires the Company to lower its system-wide NOx emissions to .14 lbs./MMBTU by
May 31, 2004 (the compliance date). This is a 65% reduction from emission levels
existing in 1999 and 1998.

The Company has initiated steps toward compliance with the revised regulations.
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 be the most effective method of reducing
NOx emissions where high removal efficiencies are required.

On August 28, 2001, the IURC issued an order that (1) approved the Company's
proposed project to achieve environmental compliance by investing in clean coal
technology, (2) approved the Company's initial cost estimate of $198 million for
the construction, subject to periodic review of the actual costs incurred, and
(3) approved a mechanism whereby, prior to an electric base rate case, the
Company may recover through a rider that is updated every six months a return on
its capital costs for the project, at its overall cost of capital, including a
return on equity. The first rider adjustment for ongoing cost recovery was
approved by the IURC on February 6, 2002. Based on the level of system-wide
emissions reductions required and the control technology utilized to achieve the
reductions, the current estimated clean coal technology construction cost ranges
from $240 million to $250 million and is expected to be expended during the
2001-2006 period. Through December 31, 2002, $70.0 million has been expended.

On June 5, 2002, the Company filed a new proceeding to update the NOx project
cost and to obtain approval of a second rider authorizing ongoing recovery of
depreciation and operating costs related to the clean coal technology. After the
equipment is installed and operational, related annual operating expenses,
including depreciation expense, are estimated to be between $24 million and $27
million. Such expenses would commence in 2004 when the technology becomes
operational. On January 3, 2003, the IURC approved a settlement that authorizes
total capital cost investment for this project up to $244 million (excluding
AFUDC) and recovery on those capital costs, as well as the recovery of future
operating costs, including depreciation and purchased emission allowances,
through a rider mechanism. The settlement establishes a fixed return of 8
percent on the capital investment, which approximates the return authorized in
the Company's last electric rate case in 1995.

The Company expects to achieve timely compliance as a result of the project.
Construction of the first SCR at Culley is nearing completion on schedule, and
installation of SCR technology as planned is expected to reduce 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.

Culley Generating Station Litigation
In the late 1990's, the USEPA initiated an investigation under Section 114 of
the Act of SIGECO's coal-fired electric generating units in commercial operation
by 1977 to determine compliance with environmental permitting requirements
related to repairs, maintenance, modifications, and operations changes. The
focus of the investigation was to determine whether new source review permitting
requirements were triggered by such plant modifications, and whether the best
available control technology was, or should have been used. Numerous electric
utilities were, and are currently, being investigated by the USEPA under an
industry-wide review for compliance. In July 1999, SIGECO received a letter from
the Office of Enforcement and Compliance Assurance of the USEPA discussing the
industry-wide investigation, vaguely referring to an investigation of SIGECO and
inviting SIGECO to participate in a discussion of the issues. No specifics were
noted; furthermore, the letter stated that the communication was not intended to
serve as a notice of violation. Subsequent meetings were conducted in September
and October 1999 with the USEPA and targeted utilities, including SIGECO,
regarding potential remedies to the USEPA's general allegations.

On November 3, 1999, the USEPA filed a lawsuit against seven utilities,
including SIGECO. The USEPA alleges that, beginning in 1992, SIGECO violated the
Act by (1) making modifications to its Culley Generating Station in Yankeetown,
Indiana without obtaining required permits (2) making major modifications to the
Culley Generating Station without installing the best available emission control
technology and (3) failing to notify the USEPA of the modifications. In
addition, the lawsuit alleges that the modifications to the Culley Generating
Station required SIGECO to begin complying with federal new source performance
standards at its Culley Unit 3.

SIGECO believes it performed only maintenance, repair, and replacement
activities at the Culley Generating Station, as allowed under the Act. Because
proper maintenance does not require permits, application of the best available
control technology, notice to the USEPA, or compliance with new source
performance standards, SIGECO believes that the lawsuit is without merit, and
intends to vigorously defend itself. Since the filing of this lawsuit, the USEPA
has voluntarily dismissed a majority of the claims brought in its original
complaint. In its original complaint, USEPA alleged significant emissions
increases of three pollutants for each of four maintenance projects. Currently,
USEPA is alleging only significant emission increases of a single pollutant at
three of the four maintenance projects cited in the original complaint.

The lawsuit seeks fines against SIGECO in the amount of $27,500 per day per
violation. However, on July 29, 2002, the Court ruled that USEPA could not seek
civil penalties for two of the three remaining projects at issue in the
litigation, significantly reducing potential civil penalty exposure. The lawsuit
also seeks a court order requiring SIGECO to install the best available
emissions technology at the Culley Generating Station. If the USEPA were
successful in obtaining an order, SIGECO estimates that in response it could
incur capital costs of approximately $20 million to $40 million to comply with
the order. Trial is currently set to begin July 14, 2003.

The USEPA has also issued an administrative notice of violation to SIGECO making
the same allegations, but alleging that violations began in 1977.

While it is possible that SIGECO could be subjected to criminal penalties if the
Culley Generating Station continues to operate without complying with the
permitting requirements of new source review and the allegations are determined
by a court to be valid, SIGECO believes such penalties are unlikely as the USEPA
and the electric utility industry have a bonafide dispute over the proper
interpretation of the Act. Accordingly, the Company has recorded no accrual and
the plant continues to operate while the matter is being decided.

Information Request
On January 23, 2001, SIGECO received an information request from the USEPA under
Section 114 of the Act for historical operational information on the Warrick and
A.B. Brown generating stations. SIGECO has provided all information requested,
and no further action has occurred.

Manufactured Gas Plants
In the past, Indiana Gas 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 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 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 the IDEM's Voluntary Remediation Program. 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 recently been initiated by the Company to
confirm that the sites continue to pose no such risk.

11. Rate & Regulatory Matters

Gas Costs Proceedings
Commodity prices for natural gas purchases were significantly higher during the
2000 - 2001 heating season, primarily due to colder temperatures, increased
demand and tighter supplies. Subject to compliance with applicable state laws,
Vectren's utility subsidiaries are allowed full recovery of such changes in
purchased gas costs from their retail customers through commission-approved gas
cost adjustment mechanisms.

In March 2001, Indiana Gas and SIGECO reached agreement with the OUCC and the
Citizens Action Coalition of Indiana, Inc. (CAC) regarding the matters raised by
an IURC Order that disallowed $3.8 million of Indiana Gas' gas procurement costs
for the 2000 - 2001 heating season which was recognized during the year ended
December 31, 2000. As part of the agreement, the companies agreed to contribute
an additional $1.7 million to assist qualified low income gas customers, and
Indiana Gas agreed to credit $3.3 million of the $3.8 million disallowed amount
to its customers' April 2001 utility bills in exchange for both the OUCC and the
CAC dropping their appeals of the IURC Order. In April 2001, the IURC issued an
order approving the settlement. Substantially all of the financial assistance
for low income gas customers was distributed in 2001.

Purchased Power Costs
As a result of an appeal of a generic order issued by the IURC in August 1999
regarding guidelines for the recovery of purchased power costs, SIGECO entered
into a settlement agreement with the OUCC that provides certain terms with
respect to the recoverability of such costs. The settlement, originally approved
by the IURC in August 2000, has been extended by agreement through March 2003,
and discussions regarding further extension of the settlement term are ongoing.
Under the settlement, SIGECO can recover the entire cost of purchased power up
to an established benchmark, and during forced outages, SIGECO will bear a
limited share of its purchased power costs regardless of the market costs at
that time. Based on this agreement, SIGECO believes it has limited its exposure
to unrecoverable purchased power costs.

12. Risk Management, Derivatives, & Other Financial Instruments

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 to mitigate risk.

The Company also executes derivative contracts in the normal course of
operations while buying and selling commodities and other fungible goods to be
used in operations and while optimizing generation assets. The Company does not
execute derivative contracts for speculative or trading purposes.

Commodity Price Risk
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.

Electric sales and purchases in the wholesale power market and other
commodity-related operations are exposed to commodity price risk associated with
fluctuating electric power and other commodity prices. Other commodity
operations include sales of electricity to certain municipalities and large
industrial customers.

The Company's non-firm wholesale power marketing operations manage the
utilization of its available electric generating capacity by entering into
forward and option 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's other commodity-related operations involve the purchase and sale
of commodities, including electricity, to meet customer demands and operational
needs. These operations also enter into forward contracts that commit the
Company to purchase and sell commodities in the future. Price risk from forward
positions that commit the Company to deliver commodities is mitigated using
insurance contracts and offsetting forward purchase contracts.

Open positions in terms of price, volume, and specified delivery points may
occur and are managed using methods described above and frequent management
reporting.

Interest Rate Risk
The Company is exposed to interest rate risk associated with its adjustable rate
borrowing arrangements. Its risk management program seeks to reduce the
potentially adverse effects that market volatility may have on operations. The
Company tries to limit the amount of adjustable rate borrowing arrangements
exposed to short-term interest rate volatility to a maximum of 25% of total
debt. However, there are times when this targeted level of interest rate
exposure may be exceeded. To manage this exposure, the Company may periodically
use derivative financial instruments to reduce earnings fluctuations caused by
interest rate volatility.

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.

Although the Company'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.

Accounting for Derivatives & Other Contracts
When a derivative contract that is entered into in the normal course of
operations is probable of physical settlement, that contract is designated and
documented as a normal purchase or normal sale and is exempted from
mark-to-market accounting. Otherwise, derivative contracts are recorded at
market value as current or noncurrent assets or liabilities depending on their
value and on when the contracts are expected to be settled. Unless the contract
is a cash flow hedge that qualifies for hedge accounting treatment or is subject
to SFAS 71, that contract is marked to market through earnings. When hedge
accounting is appropriate, the Company assesses and documents hedging
relationships between its financial instruments, including commodity contracts
and interest rate swaps, and underlying risks as well as the investment's 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. The ineffective
portion of hedging arrangements is marked to market through earnings. Contracts
affected by SFAS 71 are marked to market as a regulatory asset or liability.
Market value is determined using quoted market prices from independent sources.

Non-Firm Wholesale Power Marketing Contracts
Periodically, generation capacity is in excess of that needed to serve retail
and firm wholesale customers. The Company markets this unutilized capacity to
optimize the return on its owned generation assets. The contracts entered into
are primarily short-term purchase and sale contracts that expose the Company to
limited market risk and are settled both financially and physically. These
operations do not meet the definition of energy trading activities based upon
the provisions in EITF Issue 98-10 "Accounting for Contracts Involved in Energy
Trading and Risk Management Activities" (EITF 98-10).

Asset optimization sale contracts are reflected in electric utility revenues,
and purchase contracts are reflected in purchased electric energy. Contracts
with counter-parties subject to master netting arrangements are presented net in
the Consolidated Balance Sheets. Subsequent to the adoption of SFAS 133 as
described below, certain non-firm power marketing contracts that are
periodically financially settled are recorded at market value. Changes in market
value, which is a function of the normal decline in market value as earnings are
realized and the fluctuation in market value resulting from price volatility,
are recorded in purchased electric energy.

Power marketing contracts recorded at market value at December 31, 2002 totaled
$3.5 million of prepayments and other current assets and $4.2 million of accrued
liabilities, compared to $6.1 million of prepayments and other current assets
and $2.8 million of accrued liabilities at December 31, 2001. The change in the
net value of these contracts includes an unrealized loss of $3.6 million in 2002
and an unrealized gain of $1.5 million in 2001, respectively. Including these
unrealized changes in market value, overall margin (revenue net of purchased
power) from non-firm wholesale power marketing operations for the years ended
December 31, 2002 and 2001 was $14.9 million and $19.9 million, respectively.
Prior to the adoption of SFAS 133 and for the year ended December 31, 2000,
margin was $21.1 million.

Financial Contracts
In September 2001, the Company entered into several forward starting interest
rate swaps with a total notional amount of $200.0 million in anticipation of
VUHI's $250.0 million long-term debt issuance. Upon issuance of the debt in
December 2001, the swaps were settled resulting in the Company receiving $0.9
million. The value received is being amortized from accumulated other
comprehensive income to interest expense over the life of the debt.

In December 2000, the Company entered into an interest rate swap used to hedge
interest rate risk associated with variable rate short-term notes payable
totaling $150.0 million. The swap was entered into concurrently with the
issuance of the floating rate notes on December 28, 2000 and swapped the debt's
variable interest rate of three-month LIBOR plus 0.75% for a fixed rate of
6.64%. The swap expired on December 27, 2001, the date the debt agreement
expired.

Prior to the adoption of SFAS 133, instruments hedging interest rate risk were
accounted for upon settlement in interest expense. After adoption of SFAS 133,
hedging instruments are carried at market value, and changes in market value are
recorded in accumulated other comprehensive income, when effective, and are
recorded to interest expense as settled.

As of December 31, 2002 and 2001, no interest rate swaps are outstanding. At
December 31, 2002, approximately $0.8 million remains in accumulated other
comprehensive income related to future interest payments. Of that amount, $0.1
million will be reclassified to earnings in 2003 and $0.1 million was
reclassified to earnings during 2002.

Other Commodity-Related Operations
Other commodity contracts are generally settled by physical delivery or receipt
and are within the normal operations of the Company. Therefore, these contracts
receive accounting recognition upon settlement. Firm wholesale electric
contracts are recorded in electric utility revenues. Certain contracts that
purchase commodities for operational needs are recorded when settled in other
operating expenses.

Impact of Adoption of SFAS 133
In June 1998, the FASB issued SFAS 133, which required that every derivative
instrument be recorded on the balance sheet as an asset or liability measured at
its market value and that changes in the derivative's market value be recognized
currently in earnings unless specific hedge or regulatory accounting criteria
are met.

SFAS 133, as amended, required that as of the date of initial adoption, the
difference between the market value of derivative instruments recorded on the
balance sheet and the previous carrying amount of those derivatives be reported
in net income, other comprehensive income, or regulatory assets or liabilities,
as appropriate. A change in earnings or other comprehensive income was reported
as a cumulative effect of a change in accounting principle in accordance with
APB Opinion No. 20, "Accounting Changes."

Resulting from the adoption of SFAS 133, certain non-firm wholesale power
marketing contracts that are periodically settled net were required to be
recorded at market value. Previously, the Company accounted for these contracts
on settlement. The cumulative impact of the adoption of SFAS 133 resulting from
marking these contracts to market on January 1, 2001 was an earnings gain of
approximately $1.8 million ($1.1 million net of tax) recorded as a cumulative
effect of accounting change. SFAS 133 did not impact other commodity contracts
because they were normal purchases and sales specifically excluded from the
provisions of SFAS 133 and did not impact the Company's cash flow hedges because
they had no value on the date of adoption.

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

<TABLE>
<CAPTION>
                                                                            At December 31,
-------------------------------------------------------------------------------------------
                                                      2002                   2001
                                            ------------------------ ----------------------
                                              Carrying  Est. Fair  Carrying  Est. Fair
In millions                                    Amount     Value      Amount     Value
------------------------------------------- ------------------------ ----------------------
<S>                                          <C>        <C>         <C>        <C>
   Long-term debt                            $ 911.9    $ 968.9     $ 918.4    $ 912.0
   Short-term borrowings & notes payable       239.1      239.1       274.2      274.2
</TABLE>

Certain methods and assumptions must be used to estimate the fair value of
financial instruments. The fair value of the Company's other financial
instruments was estimated based on the quoted market prices for the same or
similar issues or on the current rates offered to the Company for instruments
with similar characteristics. Because of the maturity dates and variable
interest rates of short-term borrowings, its carrying amount approximates its
fair value.

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

13. Additional Operational & Balance Sheet Information

Other - net in the Consolidated Statements of Income consists of the following:

<TABLE>
<CAPTION>
                                                         Year ended December 31,
--------------------------------------------------------------------------------
 In millions                                 2002            2001          2000
--------------------------------------------------------------------------------
<S>                                         <C>             <C>           <C>
AFUDC & capitalized interest                $ 5.3           $ 4.6         $ 5.0
Interest income                               0.7             0.2           1.2
Other income                                  3.2             8.0           2.1
Other expense                                (2.3)           (7.3)         (3.6)
--------------------------------------------------------------------------------
       Total other - net                    $ 6.9           $ 5.5         $ 4.7
================================================================================
</TABLE>


Other current assets in the Consolidated Balance Sheets consists of the
following:

                                                   At December 31,
------------------------------------------------------------------
 In millions                                    2002       2001
------------------------------------------------------------------
Prepaid gas delivery service                   $ 70.3     $ 67.7
Prepaid taxes                                     4.8        8.7
Other prepayments & current assets               11.4        6.4
------------------------------------------------------------------
      Total prepayments & other current assets $ 86.5     $ 82.8
==================================================================




<PAGE>


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

                                                 At December 31,
------------------------------------------------------------------
 In millions                                   2002        2001
------------------------------------------------------------------
Accrued taxes                                  $ 29.6     $ 34.4
Refunds to customers & customer deposits         21.0       18.7
Accrued interest                                 13.1       12.7
Deferred income taxes                             7.7       19.1
Accrued salaries & other                         13.8        9.8
------------------------------------------------------------------
       Total accrued liabilities               $ 85.2     $ 94.7
==================================================================


14. Segment Reporting

The Company had two operating segments during 2002: 1) Gas Utility Services and
2) Electric Utility Services. The Gas Utility Services segment provides natural
gas distribution and transportation services in nearly two-thirds of Indiana and
west central Ohio. The Electric Utility Services segment includes the operations
of SIGECO's electric transmission and distribution services, which provides
electricity primarily to southwestern Indiana, and SIGECO's power generating and
power marketing operations. The Company makes decisions on finance and dividends
at the corporate level.

                                           Year ended December 31,
------------------------------------------------------------------
 In millions                        2002       2001         2000
------------------------------------------------------------------
Operating Revenues
     Gas Utility Services        $  909.0   $ 1,019.6    $   820.4
     Electric Utility Services      608.1       381.2        334.4
------------------------------------------------------------------
        Total operating revenues $1,517.1   $ 1,400.8    $ 1,154.8
==================================================================

Interest Expense
     Gas Utility Services        $   45.6   $    51.6    $    28.0
     Electric Utility Services       20.5        18.5         18.1
------------------------------------------------------------------
        Total interest expense   $   66.1   $    70.1    $    46.1
==================================================================

Income Taxes
     Gas Utility Services        $   18.0   $    (2.0)   $    11.5
     Electric Utility Services       26.6        20.4         23.5
------------------------------------------------------------------
        Total income taxes       $   44.6   $    18.4    $    35.0
==================================================================

Equity in Earnings of
     Unconsolidated Affiliates
     Gas Utility Services        $    0.1   $     0.7    $       -
     Electric Utility Services       (1.9)       (1.2)           -
------------------------------------------------------------------
        Total equity in earnings of
        unconsolidated afiliates $   (1.8)  $    (0.5)   $       -
==================================================================

Net Income
     Gas Utility Services        $   39.0   $    (2.6)   $    15.7
     Electric Utility Services       54.6        42.7         36.8
------------------------------------------------------------------
        Net income               $   93.6   $    40.1    $    52.5
==================================================================



                                           Year ended December 31,
------------------------------------------------------------------
 In millions                       2002       2001         2000
------------------------------------------------------------------
Depreciation & Amortization
     Gas Utility Services        $   56.8   $    58.5    $    43.8
     Electric Utility Services       40.0        38.7         38.6
------------------------------------------------------------------
        Total depreciation &
        amortization             $   96.8   $    97.2    $    82.4
==================================================================

Capital Expenditures
     Gas Utility Services        $   63.0   $    77.8    $    73.1
     Electric Utility Services       88.8        69.8         37.6
------------------------------------------------------------------
       Total capital
       expenditures              $  151.8   $   147.6    $   110.7
==================================================================

                                     At December 31,
----------------------------------------------------
 In millions                       2002        2001
----------------------------------------------------
Identifiable Assets
     Gas Utility Services      $1,570.1   $ 1,584.1
     Electric Utility Services    869.2       818.5
----------------------------------------------------
        Total identifiable
        assets                 $2,439.3   $ 2,402.6
====================================================


15. Special Charges for 2001 and 2000

Restructuring & Related Charges
As part of continued cost saving efforts, in June 2001, the Company's management
and the board of directors approved a plan to restructure, primarily, its
regulated operations. The restructuring plan included the elimination of certain
administrative and supervisory positions in its utility operations and corporate
office. Charges of $10.8 million were expensed in June 2001 as a direct result
of the restructuring plan. Additional charges of $4.2 million were incurred
during the remainder of 2001 primarily for consulting fees, employee relocation,
and duplicate facilities costs. In total, the Company incurred restructuring
charges of $15.0 million. These charges were comprised of $7.6 million for
employee severance, related benefits and other employee related costs, $4.0
million for lease termination fees related to duplicate facilities and other
facility costs, and $3.4 million for consulting and other fees.

The $7.6 million of severance and related costs includes $1.6 million of
deferred compensation payable at various times through 2016 and $0.8 million of
non-cash pension costs. The $4.0 million of lease termination fees includes $1.0
million of non-cash charges for impaired leasehold improvements. Restructuring
expenses were incurred by the Company's operating segments as follows: $10.2
million by the Gas Utility Services segment and $4.8 million by the Electric
Utility Services segment.

Employee severance and related costs are associated with approximately 100
employees. Employee separation benefits include severance, healthcare, and
outplacement services. As of December 31, 2001, approximately 80 employees had
exited the business. The restructuring program was completed during 2001, except
for the departure of the remaining employees impacted by the restructuring which
occurred during 2002 and the final settlement of the lease obligation which has
yet to occur.

In June 2001, the Company established accruals totaling $8.2 million ($6.2
million for severance and $2.0 million for lease termination fees). Throughout
2001 additional expenses totaling $1.0 million for lease termination fees were
incurred. Cash payments in 2001 totaled $4.9 million, all of which related to
severance payments. As of December 31, 2001, the remaining accrual related to
the restructuring was $4.3 million. Of that amount, $1.3 million remained
accrued for severance, almost all of which relates to deferred compensation
arrangements, and $3.0 million remained for lease termination fees. During 2002,
the accrual for severance did not substantially change, and $1.0 million of
lease costs were paid. At December 31, 2002, the remaining accrual was $3.6
million ($1.6 million for severance and $2.0 million for lease termination
fees). The restructuring accrual is included in accrued liabilities.

Merger & Integration Costs
Merger and integration costs incurred for the years ended December 31, 2001 and
2000 were $2.8 million and $32.7 million, respectively. Merger and integration
activities resulting from the 2000 merger were completed in 2001.

Since March 31, 2000, $35.5 million has been expensed associated with merger and
integration activities. Accruals were established at March 31, 2000 totaling
$19.3 million. Of this amount, $5.5 million related to employee and executive
severance costs, $11.7 million related to transaction costs and regulatory
filing fees incurred prior to the closing of the merger, and the remaining $2.1
million related to employee relocations that occurred prior to or coincident
with the merger closing. The remaining $16.2 million was expensed through
December 31, 2001 ($13.4 million in 2000 and $2.8 million in 2001) for
accounting fees resulting from merger related filing requirements, consulting
fees related to integration activities such as organization structure, employee
travel between company locations as part of integration activities, internal
labor of employees assigned to integration teams, investor relations
communications activities, and certain benefit costs.

During the merger planning process, approximately 135 positions were identified
for elimination. As of December 31, 2001, all such identified positions were
vacated.

The integration activities experienced by the Company included such things as
information system consolidation, process review and definition, organization
design and consolidation, and knowledge sharing.

As a result of merger integration activities, management retired certain
information systems in 2001. Accordingly, the useful lives of these assets were
shortened in 2000 to reflect this decision. These information system assets are
owned by a wholly owned subsidiary of Vectren, and the fees allocated by the
subsidiary for the use of these systems by the Company's subsidiaries are
reflected in other operating expenses. As a result of the shortened useful
lives, additional fees were incurred by the Company, resulting in additional
other operating expense of $9.6 million ($6.0 million after tax) for the year
ended December 31, 2001 and $11.4 million ($7.1 million after tax) for the year
ended December 31, 2000.

16. Impact of Recently Issued Accounting Guidance

EITF 02-03
In October 2002, the EITF reached a final consensus in EITF Issue 02-03 "Issues
Involved in Accounting for Derivative Contracts Held for Trading Purposes and
Contracts Involved in Energy Trading and Risk Management Activities" (EITF
02-03) that gains and losses (realized and unrealized) on all derivative
instruments within the scope of SFAS 133 should be shown net in the income
statement, whether or not settled physically, if the derivative instruments are
held for "trading purposes." The consensus rescinded EITF Issue 98-10
"Accounting for Contracts Involved in Energy Trading and Risk Management
Activities" (EITF 98-10) as well as other decisions reached on energy trading
contracts at the EITF's June 2002 meeting.

The Company's non-firm wholesale power marketing operations enter into contracts
that are derivatives as defined by SFAS 133, but these operations do not meet
the definition of energy trading activities based upon the provisions in EITF
98-10. Currently, the Company uses a gross presentation to report the results of
these operations as described in Note 12. The Company has re-evaluated its
portfolio of derivative contracts and has determined gross presentation remains
appropriate.

SFAS 143
In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement
Obligations" (SFAS 143). SFAS 143 requires entities to record the fair value of
a liability for an asset retirement obligation 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 to its present value, 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 upon settlement. Any costs of removal recorded in
accumulated depreciation pursuant to regulatory authority will require
disclosure in future periods. The Company adopted this statement on January 1,
2003. The adoption was not material to the Company's results of operations or
financial condition.

FASB Interpretation (FIN) 45
In November 2002, the FASB issued Interpretation 45, "Guarantor's Accounting and
Disclosure Requirements for Guarantees, Including Indirect Guarantees of
Indebtedness of Others" (FIN 45). FIN 45 clarifies the requirements for a
guarantor's accounting for and disclosure of certain guarantees issued and
outstanding and that a guarantor is required to recognize, at the inception of a
guarantee, a liability for the obligations it has undertaken. The objective of
the initial measurement of that liability is the fair value of the guarantee at
its inception. The initial recognition and measurement provisions are applicable
on a prospective basis to guarantees issued or modified after December 31, 2002.
Although management is still evaluating the impact of FIN 45 on its financial
position and results of operations, the adoption is not expected to have a
material effect.

FIN 46
In January 2003, the FASB issued Interpretation 46, "Consolidation of Variable
Interest Entities" (FIN 46). FIN 46 addresses consolidation by business
enterprises of variable interest entities and significantly changes the
consolidation requirements for those entities. FIN 46 is intended to achieve
more consistent application of consolidation policies to variable interest
entities and, thus improves comparability between enterprises engaged in similar
activities when those activities are conducted through variable interest
entities. FIN 46 applies to variable interest entities created after January 31,
2003 and to variable interest entities in which an enterprise obtains an
interest after that date. FIN 46 applies to the Company's third quarter for
variable interest entities in which the Company holds a variable interest
acquired before February 1, 2003. Although management is still evaluating the
impact of FIN 46 on its financial position and results of operations, the
adoption is not expected to have a material effect.

17. Subsequent Event

On January 1, 2003, Vectren transferred certain information technology systems
and related assets and buildings from other entities within its consolidated
group to VUHI. These assets primarily support the operations of VUHI's
subsidiaries. In 2003, transfer will require restatement of VUHI's consolidated
financial statements for all periods presented under accounting rules governing
combinations of entities under common control. Total assets, liabilities, and
equity transferred to VUHI on January 1, 2003 were $134.1 million, $94.6
million, and $39.5 million, respectively.

<PAGE>

18.  Quarterly Financial Data (Unaudited)

As more fully described in Note 3, the Company has restated the results for the
year ended December 31, 2001, including each quarter, as well as the first three
quarters of 2002 to appropriately account for certain transactions. Provided
below is a comparison of restated summarized quarterly financial data to
summarized quarterly financial data previously reported. 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 2002 follows:
<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------
In millions                     Q1                 Q2 (5)                Q3              Q4
---------------------   ------------------   -------------------------------------------------
                           As        As         As        As        As         As        As
2002 Operating data     Reported  Restated   Reported  Restated  Reported   Restated  Reported
                        --------  --------   --------  --------  --------   --------  --------
<S>                     <C>        <C>       <C>        <C>      <C>         <C>      <C>
Operating revenues      $ 483.9    $484.9    $ 298.7    $299.0   $ 278.1     $278.0   $ 455.2
Operating income (6)       78.6      78.5       21.1      22.5      29.9       28.9      69.3
Net income                 40.6      41.0        9.1       7.0       8.9        8.5      37.1
</TABLE>


Summarized quarterly financial data for 2001 follows:
<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------
In millions                     Q1 (1)               Q2 (2)                Q3                  Q4 (4)
------------------------  ------------------   ------------------   ------------------   ------------------
                             As        As         As        As         As        As         As        As
2001 Operating Data (3)   Reported  Restated   Reported  Restated   Reported  Restated   Reported  Restated
                          --------  --------   --------  --------   --------  --------   --------  --------
<S>                       <C>        <C>       <C>        <C>       <C>        <C>       <C>        <C>
Operating revenues        $ 611.9    $614.6    $ 249.6    $248.5    $ 200.3    $196.7    $ 348.6    $ 341.0
Operating income (loss)(6)   70.2      74.8       (3.8)     (3.9)      14.6      13.4       54.4       39.0
Income (loss) before
   extraordinary loss &
   cumulative effect of
   change in accounting
   principle                 31.8      35.0      (12.9)    (13.3)      (0.5)     (1.4)      28.4       18.7
Net income (loss)            35.7      36.1      (12.9)    (13.3)      (0.5)     (1.4)      28.4       18.7
</TABLE>

1. Q1 of 2001 includes charges for cumulative effect of changes in
   accounting principle as described in Note 12.
2. Q2 of 2001 includes restructuring charges as described in Note 15.
3. 2001 includes merger and integration charges as described in Note 15.
4. The benefit clearing adjustment and primarily all of the inventory adjustment
   discussed in Note 3 were recorded in Q4 of 2001.
5. In Q2 of 2002, the Company recorded $3.2 million of after tax carrying costs
   for DSM programs pursuant to existing IURC orders. Management determined that
   the accrual of such carrying costs was more appropriate in periods prior to
   2000 when DSM program expenditures were made. Therefore, such carrying costs
   originally reflected in Q2 of 2002 were reversed and reflected in common
   shareholder's equity as of January 1, 2000.

6. Operating income (loss) in the "As Reported" columns has been adjusted to
   reflect the reclassification of income taxes which prior to Q4 of 2002 was
   included as a component of operating income, consistent with traditional
   reegulated entity income statement presentation.  The income statement
   presentation was changed to the commercial and industrial presentation
   described in Article 5 of Regulation S-X.


<PAGE>

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

Disclosure with respect to this Item, has been previously provided on Form 8-K
originally filed with the SEC on March 26, 2002, as amended on Form 8-K/A filed
with the SEC on May 20, 2002.

                                    PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

Certain information required to be shown for Item 10, Directors and Executive
Officers of the Registrant, is incorporated by reference, with the exception of
the Compensation Committee Report and Performance Graph, from the Proxy
Statement of the registrant's parent company, Vectren Corporation. That report
was prepared and filed electronically with the Securities and Exchange
Commission on March 27, 2003, and is attached to this filing as Exhibit 99.1.

                                    Directors

Niel C. Ellerbrook, age 54, has been a director of Indiana Energy or the Company
since 1991. Mr. Ellerbrook is Chairman of the Board and Chief Executive Officer
of the Company, having served in that capacity since March 2000. Mr. Ellerbrook
served as President and Chief Executive Officer of Indiana Energy from June 1999
to March 2000. Mr. Ellerbrook served as President and Chief Operating Officer of
Indiana Energy from October 1997 to March 2000. From January through October
1997, Mr. Ellerbrook served as Executive Vice President, Treasurer, and Chief
Financial Officer of Indiana Energy; and from 1986 to January 1997 as Vice
President, Treasurer, and Chief Financial Officer of Indiana Energy. Mr.
Ellerbrook is a director of Vectren Utility Holdings, Inc., Indiana Gas Company,
Inc., and Southern Indiana Gas and Electric Co. He is also a director of Old
National Bancorp and Deaconess Hospital of Evansville, Indiana.

Andrew E. Goebel, age 55, has been a director of SIGCORP or the Company since
1997. Mr. Goebel is President and Chief Operating Officer of the Company, having
served in that capacity since March 2000. Mr. Goebel was President and Chief
Operating Officer of SIGCORP from April 1999 to March 2000. From September 1997
through April 1999, Mr. Goebel served as Executive Vice President of SIGCORP;
and from 1996 to September 1997, he served as Secretary and Treasurer of
SIGCORP. Mr. Goebel is a director of Vectren Utility Holdings, Inc., Indiana Gas
Company, Inc., and Southern Indiana Gas and Electric Co. Mr. Goebel is also a
director of Old National Bancorp and Old National Bank. Mr. Goebel is retiring
from the Company effective April 30, 2003.

Jerome A. Benkert, Jr., age 44, has served as Executive Vice President and Chief
Financial Officer of the Company since March 2000 and as Treasurer of the
Company since October 2001 to April 2002. He was Executive Vice President and
Chief Operating Officer of Indiana Energy's administrative services company from
October 1997 to March 2000. Mr. Benkert has served as Controller and Vice
President of Indiana Gas. Mr. Benkert is a director of Vectren Utility Holdings,
Inc., Indiana Gas Company, Inc., Southern Indiana Gas and Electric Co., and
Fifth Third Bank, Indiana.

Ronald E. Christian, age 44, has served as Senior Vice President, General
Counsel, and Secretary of the Company since March 2000. Mr. Christian served as
Vice President and General Counsel of Indiana Energy from July 1999 to March
2000. From June 1998 to July 1999, Mr. Christian was the Vice President, General
Counsel and Secretary of Michigan Consolidated Gas Company in Detroit, Michigan.
He served as the General Counsel and Secretary of Indiana Energy, Indiana Gas
and Indiana Energy Investments, Inc. from 1993 to June 1998. Mr. Christian is a
director of Vectren Utility Holdings, Inc., Indiana Gas Company, Inc., and
Southern Indiana Gas and Electric Co.

William S. Doty, age 52, has served as a director since June 2001. Mr. Doty has
also served as Senior Vice President-Energy Delivery of the Company since April
2001. Mr. Doty served as Senior Vice President of Customer Relationship
Management from January 2001 to April 2001. From January 1999 to January 2001,
Mr. Doty was Vice President of Energy Delivery for Southern Indiana Gas and
Electric Company and previous to January 1999, he was Director of Gas
Operations. Mr. Doty is a director of Southern Indiana Gas and Electric Company.

                            Other Executive Officer

Richard G. Lynch, age 51, has served as Senior Vice President-Human Resources
and Administration of the Company since March 2000. Mr. Lynch was Vice President
of Human Resources for SIGCORP from March 1999 to March 2000. Prior to joining
the Company, Mr. Lynch was the Director of Human Resources for the Mead Johnson
Division of Bristol Myers-Squibb in Evansville, Indiana.

ITEM 11. EXECUTIVE COMPENSATION

Certain information required to be shown for Item 11, Executive Compensation, is
incorporated by reference, with the exception of the Compensation Committee
Report and Performance Graph, from the Proxy Statement of the registrant's
parent company, Vectren Corporation. That report was prepared and filed
electronically with the Securities and Exchange Commission on March 27,2003,
and is attached to this filing as Exhibit 99.1.

The compensation of Niel C. Ellerbrook, Andrew E. Goebel, Jerome A Benkert, Jr.,
and Ronald E. Christian is included in Exhibit 99.1 attached to this filing. In
addition to these named executive officers, the compensation of William S. Doty
is presented below. The compensation presented below and the compensation
included in Exhibit 99.1 represents each executive's Vectren-wide compensation,
not just the portion allocated to VUHI. The tables include a Summary
Compensation Table (Table I), a Summary of Option Grants in Last Fiscal year
(Table II), a table showing Aggregate Option Exercises in Last Fiscal Year and
Fiscal Year End Option Values (Table III) and a table showing the Long-Term
Incentive Plan Awards in Last Fiscal Year (Table IV).
<TABLE>
<CAPTION>
                                      TABLE I
                             SUMMARY COMPENSATION TABLE
        (a)                (b)     (c)       (d)        (e)         (g)      (h)        (i)
    -----------                 ---------------------------------------------------------------
                                    Annual Compensation          Long-term Compensation Payouts

 Name and Principal                                   Other       Options    LTIP      Other
  Position at VUHI                          Bonus  Compensation  (# shares) Payouts Compensation
                          Year  Salary ($)  ($)(1)    ($)(2)         (3)    ($)(4)     ($)(5)
                          ----  ---------   ------    ------       ------   ------     ------
<S>                       <C>    <C>        <C>        <C>         <C>                 <C>
William S. Doty           2002   189,654    61,737     5,931       15,000       -      10,739
Senior Vice President -
Energy Delivery           2001   174,608    10,500     5,709       22,000       -      12,836

                          2000   141,464    96,125     1,413            -       -      18,079
</TABLE>

Earnings are shown on a calendar year basis.

(1)  The amounts shown in this column for 2002 and 2001 are exclusively payments
     under the Company's At-Risk Compensation Plan, which is discussed above in
     Part B, relating to "Annual Incentive Compensation," and Part B of the
     Compensation and Benefits Committee Report in Exhibit 99.1.

     The amounts shown in this column for 2000 include payments under the
     Company's Executive Annual Incentive Plan and the SIGCORP Corporate
     Performance Plan. Payments in 2000 attributable to the Company's Executive
     Annual Incentive Plan for the performance period of April 1 to December 1,
     2000 (Mr. Doty, $64,000). Also, at the close of the merger of Indiana
     Energy and SIGCORP into the Company on March 31, 2000, the existing annual
     incentive programs of the two companies were terminated and a "stub year"
     payout was made based on the portion of the performance cycle that had
     passed. For the SIGCORP Performance Plan, a prorated payout for three
     months, January 1, 2000 to March 31, 2000 was made. For Mr. Doty, this stub
     year bonus was $6,250. Also included in 2000 for Mr. Doty, ($25,875) is the
     payment attributable to SIGCORP's performance for the period January 1 to
     December 31, 1999.

(2)  The amounts shown in this column are dividends paid on restricted shares
     issued under the Vectren Corporation Executive Restricted Stock Plan
     (formerly the Indiana Energy Executive Restricted Stock Plan), which was
     adopted by the Company on March 31, 2000. No restricted shares were issued
     to executives in 2001 and 2002. Mr. Doty did not participate in the Stock
     Plan prior to March 31, 2000.

(3)  The options shown were issued under the Company's At-Risk Compensation
     Plan. For further information, see the discussion in Part B relating to
     "Long-term Incentive Compensation," and Part C of the Compensation and
     Benefits Committee Report in Exhibit 99.1.

(4)  The amounts shown in this column represent the value of shares issued under
     the Vectren Corporation Restricted Stock Plan and for which restrictions
     were lifted in each year. At the time of the merger, Indiana Energy
     executives had restricted stock performance grants relating to open
     performance measurement periods. (Under normal circumstances, at the close
     of each performance cycle, Indiana Energy's Total Shareholder Return would
     have been compared to a peer group and the number of restricted shares
     granted would have been adjusted in accordance with the plan.) The Board
     concluded that it would be difficult, if not inappropriate, to use
     Vectren's performance to make adjustments to the prior grants. Based upon
     the frequency of past performance grants, the Board awarded 75 percent of
     the present value of the potential performance grants. . Mr. Doty did not
     participate in the plan prior to March 31, 2000.

(5)  The amount shown in this column represents several compensation elements.


         For Mr. Doty, this column also contains income related to reimbursement
         for taxable expenses (2002 -- $5,239; 2001 -- $5,680; 2000 -- $2,520),
         imputed earnings from automobile usage (Mr. Doty: 2000 -- $1,167),
         Company contributions to the retirement savings plan (2002 -- $5,500;
         2001 -- $5,100; 2000 -- $5,100), and deferred compensation
         contributions to restore contributions to the company Retirement
         Savings Plan (2001 -- $2,056; 2000 -- $900). At the close of the
         merger, officers coming from SIGCORP were no longer furnished with
         company automobiles (Indiana Energy executives were not furnished with
         company automobiles). As a result of the termination of this
         perquisite, Mr. Doty was given a one-time automobile buyout of $8,392,
         paid in 2000.

                                    TABLE II
                        OPTION GRANTS IN LAST FISCAL YEAR

                Number of     % of Total
                  Shares        Options
                Underlying    Granted to   Exercise
                 Options/     Employees     or Base
                   SARs       in Fiscal   Price (Per  Expiration   Grant Date
      Name       Granted        Year       Share)($)     Date     Present Value
   ----------   ---------     --------    ----------  ----------  -------------
                  (#)(1)                                                ($)
   W.S. Doty     15,000/0       3.29%        23.19     1/1/2013      $70,088

(1)  On December 11, 2002, a total of 384,500 options were awarded effective as
     of January 1, 2003 to all plan participants under the Vectren Corporation
     At-Risk Compensation Plan. Stock options are exercisable upon vesting in
     whole or in part and expire ten years from the date of grant. This grant
     has a vesting schedule pursuant to which 34 percent vests at the end of the
     first year, and 33 percent vests at the end of the second and third years.

(2)  The assumptions used for the Model are as follows: Volatility -- 23.69
     percent based on monthly stock prices for the period of January 1, 2000 to
     December 31, 2002; Risk-free rate of return -- 4.54 percent; Dividend Yield
     -- 4.78 percent over the period of January 1, 2000 to December 31, 2002;
     and, a ten-year exercise term. A discount rate of .9412 was applied to
     reflect a 3-year graduated vesting schedule. (Per a binomial model as
     certified by an independent consultant retained by the Compensation and
     Benefits committee.)
<TABLE>
<CAPTION>
                                    TABLE III
                 AGGREGATED OPTION EXERCISES IN LAST FISCAL YEAR
                        AND FISCAL YEAR-END OPTION VALUES
                           FROM 1/1/2001 TO 12/31/2001

                              Underlying
                              Unexercised     Number of Securities        Value of Unexercised
             Shares Acquired     Value       Underlying Unexercised             In-the-Money
     Name     On Exercise(#)  Realized ($)  Options at Year-End (#)(1)  Options as of 12/31/01 ($)(1)
     ----    ---------------  -----------   --------------------------  -----------------------------
                                            Exercisable  Unexercisable   Exercisable   Unexercisable
                                            -----------  -------------   -----------   -------------
<S>               <C>           <C>           <C>           <C>            <C>             <C>
  W.S. Doty       1,631         14,033        30,657        28,200         99,965          6,072
</TABLE>

(1)  Includes grants authorized by the Compensation and Benefits Committee on
     December 11, 2002 to be effective as of January 1, 2003.




<PAGE>

<TABLE>
<CAPTION>
                                    TABLE IV

               LONG-TERM INCENTIVE PLAN AWARDS IN LAST FISCAL YEAR

                                                        Estimated Future Payouts
                                                    Under Non-Stock Price-Based Plans
      (a)                (b)             (c)           (d)         (e)         (f)
                                      Performance
                      Number of        or Other
                       Shares;       Periods Until  Threshold     Target     Maximum
                      Units or        Maturation    Number of    Number of   Number of
                  Other Rights (1)   or Payout (2)  Shares (3)   Shares (4)  Shares (5)
                  ---------------    -------------  ----------  ----------   ----------
<S>                   <C>                 <C>         <C>          <C>         <C>
  W.S. Doty           4,000               0           1,500        4,000       8,000
</TABLE>

(1)  This column reflects restricted stock grants awarded under the Vectren
     Corporation At-Risk Compensation Plan by the Compensation and Benefits
     Committee on December 11, 2002, to be effective January 1, 2003. The manner
     for determining the awards, and other terms and conditions of the At-Risk
     Plan, are discussed in the Compensation and Benefits Committee Report
     relating to "Long-Term Incentive Compensation." The market value of the
     shares on the date of grant is determined by the market price on the date
     of grant or, if no trading occurs on that date, the market price on the
     next trading day on which shares are traded. Dividends are paid directly to
     the holders of the stock.

(2)  As discussed in the Compensation and Benefits Committee Report relating to
     "Long-Term Incentive Compensation" in Exhibit 99.1, for the grant
     authorized on December 11, 2002 and granted on January 1, 2003, the
     measurement period commenced on January 1, 2003 and will conclude on
     December 31, 2005.

(3)  The ultimate amount of the grant will be determined by the Company's
     performance relative to its peer group. Performance at the 25th percentile
     will result in a threshold payment equal to 0.375 of the initial grant
     which is shown in column (b), and in column (e). Performance versus the
     peer group which is below the 25th percentile will result in a complete
     forfeiture.

(4)  The total number of shares in column (b), and also set forth in column (e),
     are subject to forfeiture as discussed in footnote (3). If the Company's
     performance compared to the peer group during the measurement period places
     it above 25% and below 90%, linear interpolation will be employed to
     perform the award calculation. At target, the payment will be equal to the
     initial grant which is shown in column (b).

(5)  Under the At-Risk Plan, if the Company's performance compared to the peer
     group during the measuring period places it in the 90th percentile, an
     additional performance grant equal to the original grant will be made. In
     that event, the shares shown in column (e) will be doubled.

ITEM 12.  Security  Ownership of Certain  Beneficial  Owners and  Management and
          Related Stockholder Matters

                 Security ownership of certain beneficial owners

As of December 31, 2002, the following stockholder was known to the management
to be the beneficial owner of more than five percent of the outstanding shares
of any class of voting securities as set forth below.

                Name and Address of    Amount and Nature of
Title of Class  Beneficial Owner       Beneficial Ownership   Percent of Class
--------------  -------------------    --------------------   ----------------
Common          Vectren Corporation        10 Shares             100 percent
                20 N.W. Fourth Street      Registered Owner
                Evansville, IN 47708



<PAGE>


                        Security ownership of management


The following table sets forth the beneficial ownership, as of December 31,
2002, of Vectren common stock, by each director and named executive officer in
Item 11 Executive Compensation. Also shown is the total ownership for such
persons as a group. Except as otherwise indicated, each individual has sole
voting and investment power with respect to the shares listed below.


                                  Shares Owned
Name of Beneficial Owner          Beneficially (1)
------------------------          ----------------
Niel C. Ellerbrook                    210,837          (2) (3) (6) (8)
Andrew E. Goebel                      187,976          (2) (3) (4) (5)
Jerome A. Benkert, Jr.                 49,253          (2) (4) (5)
Ronald E. Christian                    48,253          (2) (4) (5)
William S. Doty                        43,047          (2) (4) (5)


All Directors and Named Executive Officers as a Group (5 Persons):  539,366 (1)

(1)  No director, executive officer, or directors and executive officers as a
     group owned beneficially as of December 31, 2002, more than 1 percent of
     common stock of Vectren.

(2)  This amount does not include derivative securities held under the Company's
     Non-Qualified Deferred Compensation Plan. These derivative securities are
     in the form of phantom stock units which are valued as if they were Company
     Common Stock. The amounts shown for the following individuals include the
     following amounts of phantom units:

          Name of Individuals or Identity of Group         Phantom Stock Units
          ----------------------------------------         -------------------
          Niel C. Ellerbrook                                      53,837
          Andrew E. Goebel                                         2,654
          Jerome A. Benkert, Jr.                                  16,436
          Ronald E. Christian                                     27,511
          William S. Doty                                            677

          All Directors and Executive Officers as a
          Group (6 Persons)                                      101,115

(3)  Includes shares held by spouse or jointly with spouse.

(4)  Includes shares granted to executives under the Company's Executive
     Restricted Stock Plan and restricted stock award granted to certain
     executives on January 1, 2003 under the Company's At-Risk Compensation
     Plan. These shares are subject to certain transferability restrictions and
     forfeiture provisions.

(5)  Includes shares which the named individual has the right to acquire as of
     March 3, 2003, or within sixty (60) days thereafter, under the Vectren
     Corporation Stock Option Plan.



<PAGE>


                      Equity Compensation Plan Information

VUHI does not have equity compensation plans separate from Vectren. The
information with respect to common shares issuable under Vectren equity
compensation plans as of December 31, 2002 is included below.
<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------
                                    (a)                (b)                    (c)
--------------------------------------------------------------------------------------------
                                Number of                             Number of securities
                             securities to be       Weighted-         remaining available
                               issued upon           average          for future issuance
                               exercise of        exercise price          under equity
                               outstanding        of outstanding       compensation plans
                             options, warrants   options, warrants   (excluding securities
Plan category                   and rights          and rights       reflected in column (a)
--------------------------------------------------------------------------------------------
<S>                             <C>                  <C>                  <C>
Equity compensation             1,733,762 (2)        $ 21.86              2,909,316 (3)
plans approved by
security holders (1)
--------------------------------------------------------------------------------------------
Equity compensation                     0                  0                      0
plans not approved by
security holders
--------------------------------------------------------------------------------------------
Total                           1,733,762            $ 21.86              2,909,316
============================================================================================
</TABLE>

(1)  Includes the following Vectren Corporation Plans: Vectren Corporation
     At-Risk Compensation Plan, 1994 SIGCORP Stock Option Plan, Vectren
     Corporation Executive Restricted Stock Plan, and Vectren Corporation
     Directors Restricted Stock Plan.
(2)  Includes a stock option grant approved by the Board of Directors'
     Compensation Committee on December 11, 2002, effective January 1, 2003.
(3)  Includes shares available for issuance under the Vectren Corporation
     At-Risk Compensation Plan (2,678,027), of which up to 800,000 shares may be
     issued in restricted stock, Vectren Corporation Executive Restricted Stock
     Plan (186,098), and Vectren Corporation Directors Restricted Stock Plan
     (45,191).

The SIGCORP stock option plan was approved by SIGCORP common shareholders prior
to the merger forming Vectren, and both the directors and executive restricted
stock plans were approved by Indiana Energy common shareholders prior to the
merger forming Vectren. The At-Risk Compensation plan was approved by Vectren
Corporation common shareholders after the merger forming Vectren.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

                Transactions with Vectren and Vectren Affiliates

Refer to Notes 4 and 5 to the Company's financial statements included in Item 8
Financial Statements and Supplementary Data for transactions with other Vectren
companies and Vectren affiliates.

                    Transactions with Directors and Officers

Andrew E. Goebel is a director and President of the Company and a director and
President and Chief Operating Officer of Vectren. During 2002 and 2001, Hasgoe
Cleaning Systems, a cleaning company owned by Mr. Goebel's brother's family,
performed certain cleaning services for the Company and is expected to perform
such services in 2003. During 2002, the cost of such services was $221,745,
which the Company believes to be a fair and reasonable price for the services
rendered.

                                     PART IV

ITEM 14. CONTROLS AND PROCEDURES

                Evaluation of Disclosure Controls and Procedures

Within 90 days prior to the filing of the report, the Company carried out 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 in bringing to their attention on a timely basis material information
relating to the Company required to be disclosed by the Company in its filings
under the Securities Exchange Act of 1934 (Exchange Act).

Disclosure controls and procedures, as defined by the Exchange Act in Rules
13a-14(c) and 15d-14(c), are controls and other procedures of the Company that
are designed to ensure that information required to be disclosed by the Company
in the reports filed or submitted by it under the Exchange Act is recorded,
processed, summarized, and reported within the time periods specified in the
SEC's rules and forms. "Disclosure controls and procedures" include, without
limitation, controls and procedures designed to ensure that information required
to be disclosed by the Company in its Exchange Act reports is accumulated and
communicated to the Company's management, including its principal executive and
financial officers, as appropriate to allow timely decisions regarding required
disclosure.

                           Changes in Internal Control

Since the evaluation of disclosure controls and procedures, there have been no
significant changes to the Company's internal controls and procedures or
significant changes in other factors that could significantly affect the
Company's internal controls and procedures. However, in Note 3 to the
consolidated financial statements (included in Item 8) which discusses the
restatement of 2001 and 2000 previously reported information, the Company
identified certain errors, the net effect of which, related primarily to gas
inventory accounting and the proper clearing of employee benefit related costs
routinely accumulated on the balance sheet. These errors resulted primarily from
insufficient account reconciliation procedures. The Company has taken steps to
improve these internal controls.

Internal control, as defined in American Institute of Certified Public
Accountants Codification of Statements on Auditing Standards (AU ss.319), is a
process, effected by an entity's board of directors, management, and other
personnel, designed to provide reasonable assurance regarding the achievement of
objectives in the following categories: (a) reliability of financial reporting,
(b) effectiveness and efficiency of operations and (c) compliance with
applicable laws and regulations.

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

                 List Of Documents Filed As Part Of This Report

Consolidated Financial Statements

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

Supplemental Schedules

For the years ended December 31, 2002, 2001, and 2000, the Company's Schedule II
-- Valuation and Qualifying Accounts Consolidated Financial Statement Schedules
is presented on page 73. The report of Deloitte & Touche LLP on the schedule
may be found in Item 8.

All other schedules are omitted as the required information is inapplicable or
the information is presented in the Consolidated Financial Statements or related
notes in Item 8.

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  are  listed in the Index to  Exhibits
               beginning on page 78.

               Exhibits   for  the  Company   attached  to  this  filing   filed
               electronically with the SEC are listed on page 83.

              Reports On Form 8-K During The Last Calendar Quarter

On October 25, 2002 Vectren Utility Holdings, Inc. filed a Current Report on
Form 8-K with respect to the release of financial information to the investment
community regarding Vectren Corporations's results of operations, financial
position and cash flows for the three, nine, and twelve month periods ended
September 30, 2002. The financial information was released to the public through
this filing.
         Item 5.  Other Events
         Item 7.  Exhibits
                    99.1  -  Press   Release  -  Third   Quarter   2002  Vectren
                    Corporation Earnings
                    99.2 -  Cautionary  Statement  for  Purposes  of  the  "Safe
                    Harbor"  Provisions  of the  Private  Securities  Litigation
                    Reform Act of 1995

On November 27, 2002, Vectren Utility Holdings, Inc. filed a Current Report on
Form 8-K with respect to a press release issued by Moody's Investors Service
that downgraded the credit ratings on various debt instruments issued by certain
of Vectren Corporation's wholly owned subsidiaries.
         Item 5.  Other Events
         Item 7.  Exhibits
                    99.1 - Press Release - Moody's Investors Service
                    99.2 -  Cautionary  Statement  for  Purposes  of  the  "Safe
                    Harbor"  Provisions  of the  Private  Securities  Litigation
                    Reform Act of 1995


<PAGE>

<TABLE>
<CAPTION>
                                   SCHEDULE II

             Vectren Utility Holdings, Inc. and Subsidiary Companies

                 VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

                Column A                      Column B       Column C         Column D      Column E
------------------------------------------------------------------------------------------------------------------------------------
                                                             Additions
                                                         ------------------
                                             Balance at  Charged   Charged   Deductions    Balance at
                                             Beginning      to     to Other     from         End of
Description                                   Of Year    Expenses  Accounts Reserves, Net     Year
-----------------------------------------------------------------------------------------------------
(In millions)
<S>                                            <C>        <C>        <C>       <C>            <C>
VALUATION AND QUALIFYING ACCOUNTS: AS RESTATED

Year 2002 - Accumulated provision for
            uncollectible accounts             $ 5.1      $ 11.7     $   -     $ 11.3         $ 5.5

Year 2001 - Accumulated provision for
            uncollectible accounts             $ 5.1      $ 15.1     $   -     $ 15.1         $ 5.1

Year 2000 - Accumulated provision for
            uncollectible accounts             $ 3.9      $  6.6     $ 0.1     $  5.5         $ 5.1

OTHER RESERVES:

Year 2002 - Reserve for merger and
            integration charges                $ 0.4      $    -     $   -     $  0.4         $   -

Year 2001 - Reserve for merger and
            integration charges                $ 1.8      $    -     $   -     $  1.4         $ 0.4

Year 2000 - Reserve for merger and
            integration charges                $   -      $ 19.3     $   -     $ 17.5         $ 1.8

Year 2002 - Reserve for restructuring
            costs                              $ 4.3      $    -     $   -     $  0.7         $ 3.6

Year 2001 - Reserve for restructuring
            costs                              $   -      $  9.2     $   -     $  4.9         $ 4.3
</TABLE>




<PAGE>



                                   SIGNATURES

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

                                             VECTREN UTILITY HOLDINGS, INC.


Dated February 26, 2003
                                             /S/ Niel C. Ellerbrook
                                             ----------------------------
                                             Niel C. Ellerbrook,
                                             Chairman and Chief Executive
                                             Officer, Director

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

        Signature                      Title                               Date

  /S/ Niel C. Ellerbrook       Chairman & Chief Executive      February 26, 2003
----------------------------   Officer, Director (Principal    -----------------
      Niel C. Ellerbrook       Executive Officer)



  /S/ Jerome A. Benkert, Jr.   Executive Vice President,       February 26, 2003
----------------------------   Chief Financial Officer &       -----------------
      Jerome A. Benkert, Jr.   Director (Principal Financial
                               Officer)



  /S/ M. Susan Hardwick        Vice President & Controller     February 26, 2003
----------------------------   (Principal Accounting Officer)  -----------------
      M. Susan Hardwick


  /S/ Andrew E. Goebel         Director                        February 26, 2003
-------------------------                                      -----------------
      Andrew E. Goebel


  /S/ Ronald E. Christian      Director                        February 26, 2003
---------------------------                                    -----------------
      Ronald E. Christian






<PAGE>


                            CERTIFICATION PURSUANT TO
                  SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

                      CHIEF EXECUTIVE OFFICER CERTIFICATION

I, Niel C. Ellerbrook, certify that:

1. I have reviewed this annual report on Form 10-K of Vectren Utility Holdings,
Inc.;

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

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

4  The  registrant's  other  certifying  officers  and  I  are  responsible  for
establishing and maintaining  disclosure  controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:

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

          b) evaluated the effectiveness of the registrant's disclosure controls
          and procedures as of a date within 90 days prior to the filing date of
          this annual report (the "Evaluation Date"); and

          c) presented in this annual report our conclusions about the
          effectiveness of the disclosure controls and procedures based on our
          evaluation as of the Evaluation Date;

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

          a) all significant deficiencies in the design or operation of internal
          controls which could adversely affect the registrant's ability to
          record, process, summarize and report financial data and have
          identified for the registrant's auditors any material weaknesses in
          internal controls; and

          b) any fraud, whether or not material, that involves management or
          other employees who have a significant role in the registrant's
          internal controls; and

6. The registrant's other certifying officers and I have indicated in this
annual report whether there were significant changes in internal controls or in
other factors that could significantly affect internal controls subsequent to
the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.

 Date:   February   26,  2003
                                            /s/  Niel  C.   Ellerbrook
                                            ---------------------------------
                                            Niel  C.   Ellerbrook
                                            Chairman and Chief Executive Officer



<PAGE>


                            CERTIFICATION PURSUANT TO
                  SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

                      CHIEF FINANCIAL OFFICER CERTIFICATION

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

1. I have reviewed this annual report on Form 10-K of Vectren Utility Holdings,
Inc.;

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

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

4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:

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

          b) evaluated the effectiveness of the registrant's disclosure controls
          and procedures as of a date within 90 days prior to the filing date of
          this annual report (the "Evaluation Date"); and

          c) presented in this annual report our conclusions about the
          effectiveness of the disclosure controls and procedures based on our
          evaluation as of the Evaluation Date;

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

          a) all significant deficiencies in the design or operation of internal
          controls which could adversely affect the registrant's ability to
          record, process, summarize and report financial data and have
          identified for the registrant's auditors any material weaknesses in
          internal controls; and

          b) any fraud, whether or not material, that involves management or
          other employees who have a significant role in the registrant's
          internal controls; and

6. The registrant's other certifying officers and I have indicated in this
annual report whether there were significant changes in internal controls or in
other factors that could significantly affect internal controls subsequent to
the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.

Date: February 26, 2003

                                   /s/ Jerome A. Benkert, Jr.
                                 ---------------------------------------
                                     Jerome A. Benkert, Jr.
                                     Executive Vice President and
                                     Chief Financial Officer


<PAGE>


                            CERTIFICATION PURSUANT TO
                  SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

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

         Signed this 26th day of February, 2003.






/s/ Jerome A. Benkert, Jr.                  /s/ Niel C. Ellerbrook
--------------------------------------      -----------------------------------
(Signature of Authorized Officer)           (Signature of Authorized Officer)

Jerome A. Benkert, Jr.                      Niel C. Ellerbrook
--------------------------------------      -----------------------------------
(Typed Name)                                (Typed Name)

Executive Vice President and Chief
Financial Officer                          Chairman and Chief Executive Officer
--------------------------------------     ------------------------------------
(Title)                                    (Title)



<PAGE>


                                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.)

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).

10.  Material Contracts

10.1 Agreement, dated, January 30, 1968, for Unit No. 4 at the Warrick Power
     Plant of Alcoa Generating Corporation ("Alcoa"), between Alcoa and Southern
     Indiana Gas and Electric Company. (Filed and designated in Registration No.
     2-29653 as Exhibit 4(d)-A.)

10.2 Letter of Agreement, dated June 1, 1971, and Letter Agreement, dated June
     26, 1969, between Alcoa and Southern Indiana Gas and Electric Company.
     (Filed and designated in Registration No. 2-41209 as Exhibit 4(e)-2.)

10.3 Letter Agreement, dated April 9, 1973, and Agreement dated April 30, 1973,
     between Alcoa and Southern Indiana Gas and Electric Company. (Filed and
     designated in Registration No. 2-53005 as Exhibit 4(e)-4.)

10.4 Electric Power Agreement (the "Power Agreement"), dated May 28, 1971,
     between Alcoa and Southern Indiana Gas and Electric Company. (Filed and
     designated in Registration No. 2-41209 as Exhibit 4(e)-1.)

10.5 Second Supplement, dated as of July 10, 1975, to the Power Agreement and
     Letter Agreement dated April 30, 1973 - First Supplement. (Filed and
     designated in Form 10-K for the fiscal year 1975, File No. 1-3553, as
     Exhibit 1(e).)

10.6 Third Supplement, dated as of May 26, 1978, to the Power Agreement. (Filed
     and designated in Form 10-K for the fiscal year 1978 as Exhibit A-1.)

10.7 Letter Agreement dated August 22, 1978 between Southern Indiana Gas and
     Electric Company and Alcoa, which amends Agreement for Sale in an Emergency
     of Electrical Power and Energy Generation by Alcoa and Southern Indiana Gas
     and Electric Company dated June 26, 1979. (Filed and designated in Form
     10-K for the fiscal year 1978, File No. 1-3553, as Exhibit A-2.)

10.8 Fifth Supplement, dated as of December 13, 1978, to the Power Agreement.
     (Filed and designated in Form 10-K for the fiscal year 1979, File No.
     1-3553, as Exhibit A-3.)

10.9 Sixth Supplement, dated as of July 1, 1979, to the Power Agreement. (Filed
     and designated in Form 10-K for the fiscal year 1979, File No. 1-3553, as
     Exhibit A-5.)

10.10 Seventh Supplement, dated as of October 1, 1979, to the Power Agreement.
     (Filed and designated in Form 10-K for the fiscal year 1979, File No.
     1-3553, as Exhibit A-6.)

10.11 Eighth Supplement, dated as of June 1, 1980 to the Electric Power
     Agreement, dated May 28, 1971, between Alcoa and Southern Indiana Gas and
     Electric Company. (Filed and designated in Form 10-K for the fiscal year
     1980, File No. 1-3553, as Exhibit (20)-1.)

10.12 Amendment Agreement, dated March 3, 2001, between Alcoa Power Generating
     Inc. and Southern Indiana Gas and Electric Company. (Filed and designated
     in Form 10-K, for the year ended December 31, 2001, File No. 1-15467, as
     Exhibit 10.12.)

10.13 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.)

10.14 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.)

10.15 Southern Indiana Gas and Electric Company's nonqualified Supplemental
     Retirement Plan as amended, effective April 16, 1997. (Filed and designated
     in Form 10-K for the fiscal year 1997, File No. 1-3553, as Exhibit 10.29.)

10.16 Vectren Corporation Retirement Savings Plan (amended and restated
     effective January 1, 2002). (Filed and designated in Form 10-Q for the
     quarterly period ended September 30, 2002, File No. 1-15467, as Exhibit
     10.1.)

10.17 Vectren Corporation Combined Non-Bargaining Retirement Plan. (Filed and
     designated in Form 10-Q for the quarterly period ended September 30, 2000,
     File No. 1-15467, as Exhibit 99.2.)

10.18 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.)

10.19 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.)

10.20 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.)

10.21 Gas Sales and Portfolio Administration Agreement between Indiana Gas
     Company, Inc. and ProLiance Energy, LLC, effective March 15, 1996, for
     services to begin April 1, 1996. (Filed and designated in Form 10-Q for the
     quarterly period ended March 31, 1996, File No. 1-6494, as Exhibit 10-C.)

10.22 Amended appendices to the Gas Sales and Portfolio Administration Agreement
     between Indiana Gas Company, Inc. and ProLiance Energy, LLC effective
     November 1, 1998. (Filed and designated in Form 10-Q for the quarterly
     period ended March 31, 1999, File No. 1-6494, as Exhibit 10-A.)

10.23 Amended appendices to the Gas Sales and Portfolio Administration Agreement
     between Indiana Gas Company, Inc. and ProLiance Energy, LLC effective
     November 1, 1999. (Filed and designated in Form 10-K for the fiscal year
     ended September 30, 1999, File No. 1-6494, as Exhibit 10-V.)

10.24 Gas Sales and Portfolio Administration Agreement between Vectren Energy
     Delivery of Ohio and ProLiance Energy, LLC, effective October 31, 2000, for
     services to begin November 1, 2000. (Filed and designated in Form 10-K, for
     the year ended December 31, 2001, File No. 1-15467, as Exhibit 10-24.)

10.25 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.)

10.26 Amendment to Indiana Energy, Inc. Executive Restricted Stock Plan
     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.)

10.27 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.)

10.28 First Amendment to Indiana Energy, Inc. Directors' Restricted Stock Plan,
     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.)

10.29 Second Amendment to Indiana Energy, Inc. Directors Restricted Stock 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.)

10.30 Third Amendment to Indiana Energy, Inc. Directors Restricted Stock Plan,
     renamed the Vectren Corporation Directors Restricted Stock Plan 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.)

10.31 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.)

10.32 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.)

10.33 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.)

10.34 Vectren Corporation Employment Agreement between Vectren Corporation and
     Andrew E. Goebel 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 99.2.)

10.35 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.)

10.36 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.)

10.37 Vectren Corporation Employment Agreement between Vectren Corporation and
     Timothy M. Hewitt 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 99.6.)

10.38 Vectren Corporation Retirement Agreement between Vectren Corporation and
     Timothy M. Hewitt dated as of May 31, 2001. (Filed and designated in Form
     10-K, for the year ended December 31, 2001, File No. 1-15467, as Exhibit
     10.39.)

10.39 Vectren Corporation Employment Agreement between Vectren Corporation and
     J. Gordon Hurst 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 99.7.)

10.40 Vectren Corporation Retirement Agreement between Vectren Corporation and
     J. Gordon Hurst dated as of May 31, 2001. (Filed and designated in Form
     10-K, for the year ended December 31, 2001, File No. 1-15467, as Exhibit
     10.41.)

10.41 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.)

10.42 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.)

10.43 Vectren Corporation Retirement Agreement between Vectren Corporation and
     Thomas J. Zabor dated as of May 31, 2001. (Filed and designated in Form
     10-K, for the year ended December 31, 2001, File No. 1-15467, as Exhibit
     10.44.)

21.  Subsidiaries Of The Company

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

99.  Additional Exhibits

99.1 Vectren Proxy Statement Pursuant to Section 14(a) of the Securities
     Exchange Act of 1934, but not including the Compensation Committee Report
     and Performance Graph. (Filed herewith.)

99.2 Agreement and Plan of Merger dated as of June 11,1999 among Indiana Energy,
     Inc., SIGCORP, Inc. and Vectren Corporation (the "Merger Agreement ").
     (Filed and designated in Form S-4 to (No. 333-90763) filed on November 12,
     1999, File No. 1-15467, as Exhibit 2.)

99.3 Amendment No.1 to the Merger Agreement dated December 14, 1999 (Filed and
     designated in Current Report on Form 8-K filed December 16, 1999, File No.
     1-09091, as Exhibit 2.)

99.4 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.)

99.5 Amended and Restated Code of By-Laws of Vectren Corporation as of February
     26, 2003. (Filed and designated in Form 10-K for the year ended December
     31, 2002, File No. 1-15467, as Exhibit 3.2

99.6 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.)





<PAGE>


                         Vectren Utility Holdings, Inc.
                                 2002 Form 10-K
                                Attached Exhibits

The following Exhibits were filed electronically with the SEC with this filing.
See Page 78 of this Annual Report on Form 10-K for a complete list of exhibits.

Exhibit
Number         Document

21.1           Subsidiaries of the Company

99.1           Vectren Proxy Statement Pursuant to Section 14(a) of the
                Securities Exchange Act of 1934.