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, 2003
                                       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
    incorporation or organization)                    Identification No.)

 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 - 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
30, 2003, 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 1, 2004
--------------------------------             --                -------------
            Class                      Number of Shares             Date

          Omission of Information by Certain Wholly Owned Subsidiaries

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

                                   Definitions

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

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

<PAGE>


                                Table of Contents

Item                                                                     Page
Number                                                                   Number
                                     Part I

   1    Business ...........................................................4
   2    Properties .........................................................8
   3    Legal Proceedings...................................................9
   4    Submission of Matters to Vote of Security Holders..................10

                                     Part II

   5    Market for the Company's Common Equity, Related Stockholder
        Matters, and Issuer Purchases of Equity Securities ................10
   6    Selected Financial Data............................................11
   7    Management's Discussion and Analysis of Results of
        Operations and Financial Condition.................................12
   7A   Qualitative and Quantitative Disclosures About Market Risk.........32
   8    Financial Statements and Supplementary Data........................34
   9    Change in and Disagreements with Accountants on Accounting
        and Financial Disclosure...........................................71
   9A   Controls and Procedures............................................71

                                    Part III

   10   Directors and Executive Officers of the Registrant (A).............72
   11   Executive Compensation (A).........................................72
   12   Security Ownership of Certain Beneficial Owners and
        Management and Related Stockholder Matters (A).....................72
   13   Certain Relationships and Related Transactions (A).................72
   14   Principal Accountant Fees and Services.............................72

                                     Part IV

   15   Exhibits, Financial Statement Schedules, and
        Reports on Form 8-K................................................73
        Signatures.........................................................81

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

                              Access to Information

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

Mailing Address:        Phone Number:        Investor Relations Contact:
P.O. Box 209            (812) 491-4000       Steven M. Schein
Evansville, Indiana                          Vice President, Investor Relations
47702-0209                                   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. VUHI also has assets that provide information technology and
other services to the utilities.

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 and 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 that 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 three operating segments: Gas Utility
Services, Electric Utility Services, and Other Operations. The Gas Utility
Services segment includes the operations of Indiana Gas, the Ohio operations,
and SIGECO's natural gas distribution business and provides natural gas
distribution and transportation services in nearly two-thirds of Indiana and to
west central Ohio. The Electric Utility Services segment includes the operations
of SIGECO's electric transmission and distribution services, which provides
electricity primarily to southwestern Indiana, and includes the Company's power
generating and marketing operations. The Company collectively refers to its gas
and electric operating segments as its regulated operations. Other Operations
primarily provide information technology and other support services to those
utility operations.

At December 31, 2003, the Company had $2.9 billion in total assets, with $1.8
billion (62%) attributed to the Gas Utility Services, $1.0 billion (33%)
attributed to the Electric Utility Services, and $0.1 billion (5%) attributed to
Other Operations. Net income for the year ended December 31, 2003, was $85.6
million with $81.8 million attributed to regulated operations and $3.8 million
attributed to other operations. Net income for the year ended 2002 was $97.1
million.

For further information, refer to Note 14 regarding the activities and assets of
the Company's operating segments, Note 15 regarding special charges in 2001, and
Note 11 regarding the cumulative effect of change in accounting principle in
2001 in the Company's consolidated financial statements included under "Item 8
Financial Statements and Supplementary Data".

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

                              Gas Utility Services

At December 31, 2003, the Company supplied natural gas service to 972,230
Indiana and Ohio customers, including 887,891 residential, 80,292 commercial,
and 4,047 industrial and other customers. This represents customer base growth
of 0.6% compared to 2002.

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, 2003, natural gas revenues were approximately
$1,112.3 million, of which residential customers accounted for 67%, commercial
25%, and industrial and other 8%, 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) were 209,344 MDth for the year ended December 31, 2003. Gas
transported or sold to residential and commercial customers were 118,460 MDth
representing 57% of throughput. Gas transported or sold to industrial and other
contract customers were 90,884 MDth representing 43% of throughput. Rates for
transporting gas provide for the same margins generally earned by selling gas
under applicable sales tariffs.

The sale of gas is seasonal and strongly affected by variations in weather
conditions. To mitigate seasonal demand, the Company has storage capacity at
seven active underground gas storage fields, six liquefied petroleum air-gas
manufacturing plants, and a propane cavern. The Company also contracts with
ProLiance Energy, LLC (ProLiance or ProLiance Energy) to ensure availability of
gas. ProLiance is an unconsolidated, nonregulated, energy marketing affiliate of
Vectren and Citizens Gas and Coke Utility (Citizens Gas). (See the discussion of
Energy Marketing & Services below and Note 4 in the Company's consolidated
financial statements included in "Item 8 Financial Statements and Supplementary
Data" regarding transactions with ProLiance). Purchased natural gas 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
1,775,657 MCF of gas per day can be delivered during peak demand periods from
all sources and for all utilities.


<PAGE>


Gas Purchases

In 2003, the Company purchased 118,684 MDth volumes of gas at an average cost of
$6.36 per Dth, substantially all of which was purchased from ProLiance, which
buys the gas as an agent. The average cost of gas per Dth purchased for the last
five years was: $6.36 in 2003; $4.57 in 2002; $5.83 in 2001; $5.60 in 2000; and
$3.58 in 1999.

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, 2003, the Company supplied electric service to 135,098 Indiana
customers, including 117,868 residential, 17,054 commercial, and 176 industrial
and other customers. This represents customer base growth of 0.8% compared to
2002. In addition, the Company is obligated to provide for firm power
commitments to four 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, 2003, retail and firm wholesale electricity
sales totaled 5,898,852 MWh, resulting in revenues of approximately $309.1
million. Residential customers accounted for 34% of 2003 revenues; commercial
27%; industrial and municipalities 37%; and other 2%. In addition, the Company
sold 4,305,190 MWh through wholesale contracts in 2003, generating revenue, net
of purchased power costs, of $26.5 million.

Generating Capacity

Installed generating capacity as of December 31, 2003, was rated at 1,351 MW.
Coal-fired generating units provide 1,056 MW of capacity, and natural gas or
oil-fired turbines used for peaking or emergency conditions provide 295 MW. 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, in 2003, the Company had 32 MW available
under firm contracts and 95 MW available under interruptible contracts. In
October 2003, the Company executed a firm purchase supply contract for a maximum
of 73MW for the peak cooling season months in each of the next three years.

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 has been, and may continue to 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 1999 through 2003 at the time of the system
summer peak, and the related reserve margin, is presented below in MW.
<TABLE>
<CAPTION>

Date of summer peak load      8/27/2003   8/5/2002   7/31/2001   8/17/2000   7/6/1999
                              ---------   --------   ---------   ---------   --------
<S>                             <C>         <C>        <C>         <C>         <C>
Total load at peak (1)          1,272       1,258      1,234       1,212       1,255

Generating capability           1,351       1,351      1,271       1,256       1,256
Firm purchase supply               32          82         82          75           -
Interruptible contracts            95          95         95          95          95
-------------------------------------------------------------------------------------
Total power supply capacity     1,478       1,528      1,448       1,426       1,351
-------------------------------------------------------------------------------------

Reserve margin at peak            16%         21%        17%         18%          8%
-------------------------------------------------------------------------------------
</TABLE>


(1)  The total load at peak is increased 25 MW in 2003, 2002, 2001, and 1999
     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 2002-2003 season of approximately 948 MW occurred on
January 27, 2003, and was 11% higher than the previous winter peak load of
approximately 854 MW which occurred on March 4, 2002.

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.
Such generating capacity is included in firm purchase supply in the chart above.

Fuel Costs and Purchased Power

Electric generation for 2003 was fueled by coal (99.3%) and natural gas (0.7%).
Oil was used only for testing of gas/oil-fired peaking units.

There are substantial coal reserves in the southern Indiana area, and coal for
coal-fired generating stations has been supplied from operators of nearby
Indiana coal mines including those owned by Vectren Fuels, Inc., a wholly owned
subsidiary of Vectren. Approximately 3.1 million tons of coal were purchased
for generating electricity during 2003, of which substantially all was supplied
by Vectren Fuels, Inc. from its mines and third party purchases. The average
cost of coal consumed in generating electric energy for the years 1999 through
2003 follows:

                                 Year Ended December 31,
                   -------------------------------------------------------
Avg. Cost Per       2003       2002       2001        2000           1999
                   ------     ------     ------      ------         ------
Ton               $ 24.91    $ 23.50    $ 22.48     $ 22.49        $ 21.88
MWh                 11.93      11.00      10.53       10.39          10.13

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 other wholesale customers. Volumes purchased in
2003 totaled 4,082,404 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 settlement of
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 regulated utility industry
for the Company's regulated Indiana and Ohio operations.

                                    Personnel

As of December 31, 2003, the Company and its consolidated subsidiaries had 1,547
employees, of which 884 are subject to collective bargaining arrangements.

In January 2004, the Company signed a five-year labor agreement, ending December
2008, with Local 1393 of the International Brotherhood of Electrical Workers and
United Steelworkers of America locals 12213 and 7441. The agreement provides for
annual wage increases of 3%, a multi-tiered health care plan in which the
employees pay 12% to 16% of the premium, and pension enhancements for early
retirees.

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 four-year labor agreement with Local 702 of the
International Brotherhood of Electrical Workers, ending June 2004. The 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 active gas storage fields located in Indiana
covering 58,290 acres of land with an estimated ready delivery from storage
capability of 5.2 BCF of gas with maximum peak day 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
33,000 MCF of manufactured gas per day. In addition to its company owned storage
and propane capabilities, Indiana Gas has contracted for 17.2 BCF of storage
with a maximum peak day delivery capability of 404,614 MCF per day. Indiana Gas
has the ability to meet a total annual demand, utilizing all of its assets
across various pipelines, of 131.1 BCF with a maximum peak day delivery
capability of 1,068,740 MCF per day. Indiana Gas' gas delivery system includes
11,771 miles of distribution and transmission mains, all of which are in Indiana
except for pipeline facilities extending from points in northern Kentucky to
points in southern Indiana so that gas may be transported to Indiana and sold or
transported by Indiana Gas to ultimate customers in Indiana.

SIGECO owns and operates three underground gas storage fields located in Indiana
covering 6,070 acres of land with an estimated ready delivery from storage
capability of 6.3 BCF of gas with maximum peak day delivery capabilities of
124,748 MCF per day. In addition to its company owned storage delivery
capabilities, SIGECO has contracted for 0.5 BCF of storage with a maximum peak
day delivery capability of 18,699 MCF per day. SIGECO has the ability to meet a
total annual demand, utilizing all of its assets across various pipelines, of
28.4 BCF with a maximum peak day delivery capability of 228,943 MCF per day.
SIGECO's gas delivery system includes 3,026 miles of distribution and
transmission mains, all of which are located in Indiana.

The Ohio operations own and operate three liquefied petroleum (propane) air-gas
manufacturing plants and a cavern for propane storage, all of which are located
in Ohio. The plants and cavern can store 7.5 million gallons of propane, and the
plants can manufacture for delivery 51,047 MCF of manufactured gas per day. In
addition to its propane delivery capabilities, the Ohio operations have
contracted for 13.1 BCF of storage with a maximum peak day delivery capability
of 280,667 MCF per day. The Ohio operations have the ability to meet a total
annual demand, utilizing all of its assets across various pipelines, of 57.9 BCF
with a maximum peak day delivery capability of 477,974 MCF per day. The Ohio
operations' gas delivery system includes 5,216 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, 2003, 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, 50 MW and Broadway Avenue Unit 2, 65
MW); two Northeast Gas Turbines located northeast of Evansville in Vanderburgh
County, Indiana with a combined capacity of 20 MW; and a new 80 MW 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 830 circuit miles of 138,000 and 69,000
volt lines. The transmission system also includes 27 substations with an
installed capacity of 4,235.9 megavolt amperes (Mva). The electric distribution
system includes 3,224 pole miles of lower voltage overhead lines and 289 trench
miles of conduit containing 1,622 miles of underground distribution cable. The
distribution system also includes 92 distribution substations with an installed
capacity of 1,901.7 Mva and 51,417 distribution transformers with an installed
capacity of 2,368.6 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 8 and Note 9 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 regarding the Culley generating station's compliance with the
Clean Air Act were substantially resolved during 2003.

ITEM 4.  Submission of Matters to Vote of Security Holders

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

                                     PART II

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

                                  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 2003, VUHI paid dividends to its parent company of $18.0 million in the
first quarter, $18.2 million in the second quarter, $20.7 million in the third
quarter, and $21.1 million in the fourth quarter.

During 2002, VUHI paid dividends to its parent company of $17.3 million in the
first quarter, $16.7 million in the second quarter, $17.8 million in the third
quarter, and $17.9 million in the fourth quarter.

On January 28, 2004, the board of directors declared a $19.9 million dividend,
payable to Vectren on March 1, 2004.

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

                                  Debt Security

The Company's 7 1/4% Senior Notes, due October 15, 2031, trade on the New York
Stock Exchange under the symbol "AVU." The high and low sales prices for the
Company's publicly traded debt security since issuance in October 2001 as
reported on the New York Stock Exchange are shown in the following table for the
periods indicated.

                                             Price Range
                                    -----------------------------
2003                                    High            Low
----                                -------------   -------------
     First Quarter                      $ 26.60         $ 25.76
     Second Quarter                       27.80           25.69
     Third Quarter                        27.05           25.86
     Fourth Quarter                       27.16           26.00

2002
     First Quarter                      $ 25.60         $ 24.50
     Second Quarter                       25.40           24.50
     Third Quarter                        25.95           24.80
     Fourth Quarter                       26.08           25.15

<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. Operating
revenues for the years ended December 31, 2002, through December 31, 1999, have
been reclassified to reflect the adoption of EITF 03-11. Total assets as of
December 31, 2002, also reflect a reclassification for the adoption of SFAS 143.
See Note 11 and Note 2 to the consolidated financial statements for further
information on the adoption of EITF 03-11 and SFAS 143, respectively, included
under Item 8 "Financial Statements and Supplementary Data." The following
selected financial data also gives effect to the transfer of certain information
technology systems and related assets and buildings from other entities within
Vectren's consolidated group to VUHI that was effective January 1, 2003. The
transfer required retroactive restatement of VUHI's consolidated financial
statements for all periods presented under accounting rules governing
combinations of entities under common control.
<TABLE>
<CAPTION>
                                                         Year Ended December 31,
--------------------------------------------------------------------------------------------
(In millions)                              2003       2002     2001(1)   2000(2,3)    1999
--------------------------------------------------------------------------------------------
<S>                                     <C>        <C>        <C>        <C>        <C>
Operating Data:
Operating revenues                      $ 1,448.8  $ 1,236.9  $ 1,328.3  $ 1,129.9  $  794.9
Operating income                            199.0      207.7      131.4      136.1     109.0
Income before cumulative effect
  of change in accounting principle          85.6       97.1       43.7       55.9      75.4
Net income                                   85.6       97.1       44.8       55.9      75.4

Balance Sheet Data:
Total assets                            $ 2,925.1   $2,780.4  $ 2,489.3  $ 2,509.0  $1,667.7
Redeemable preferred stock                    0.2        0.3        0.5        8.1       8.2
Long-term debt-net of current
  maturities & debt subject to tender       960.5      841.2      900.9      572.6     450.1
Common shareholder's equity                 979.8      768.6      738.9      624.3     627.0
</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 to reflect this decision, resulting in additional
     depreciation expense of approximately $9.6 million for the year ended
     December 31, 2001. In total, merger and integration related costs incurred
     for the year ended December 31, 2001, were $12.4 million ($7.7 million
     after tax).

     The Company incurred restructuring charges of $15.0 million, ($9.3 million
     after tax) relating to employee severance, related benefits and other
     employee related costs, lease termination fees related to duplicate
     facilities, and consulting and other fees.

(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,
     resulting in additional depreciation expense of approximately $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.

             Executive Summary of Consolidated Results of Operations

In 2003, Utility Group earnings were $85.6 million as compared to $97.1 million
in 2002 and $44.8 million in 2001. The $11.5 million decrease occurring in 2003
compared to 2002 was primarily due to increased operating expenses and the
write-off of investments, partially offset by increased wholesale power margins
and retail electric rate recovery related to NOx compliance expenditures and
related operating expenses.

Utility Group earnings increased $52.3 million in 2002 compared to 2001. The
year ended December 31, 2001, included nonrecurring merger, integration, and
restructuring costs and other nonrecurring items totaling $15.9 million after
tax. The increase also reflects improved margins and lower operating costs.
These resulted from favorable weather and lower gas prices and the related
reduction in costs incurred in 2001. Weather increased utility earnings by an
estimated $11 million.

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

The Company has in place a disclosure committee that consists of senior
management as well as financial management. The committee is actively involved
in the preparation and review of the Company's SEC filings.

                           Nonrecurring Items in 2001

Merger & Integration Costs

Merger and integration related costs incurred during 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 and integration
activities, management retired certain information systems in 2001. Accordingly,
the useful lives of these assets were shortened to reflect this decision,
resulting in additional depreciation expense of approximately $9.6 million for
the year ended December 31, 2001. In total, merger and integration related costs
incurred during 2001 were $12.4 million ($7.7 million after tax). Merger and
integration activities resulting from the 2000 merger forming Vectren were
completed in 2001.

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. 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.

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

Throughout this discussion, the terms Gas Utility margin and Electric Utility
margin are used. Gas Utility margin and Electric Utility margin could be
considered non-GAAP measures of income. Gas Utility margin is calculated as Gas
utility revenues less the Cost of gas sold. Electric Utility margin is
calculated as Electric utility revenues less Fuel for electric generation and
Purchased electric energy. These measures exclude Other operating expenses,
Depreciation and amortization, Taxes other than income taxes, Merger and
integration costs, and Restructuring costs, which are included in the
calculation of operating income. The Company believes Gas Utility and Electric
Utility margins are better indicators of relative contribution than revenues
since gas prices and fuel costs can be volatile and are generally collected on a
dollar for dollar basis from customers. Margins should not be considered an
alternative to, or a more meaningful indicator of operating performance than,
operating income or net income as determined in accordance with accounting
principles generally accepted in the United States.

Margin

Margin generated from the sale of natural gas and electricity to residential and
commercial customers is seasonal and impacted by weather patterns in its service
territory. Margin generated from sales to industrial and other contract
customers is impacted by overall economic conditions. In general, margin is not
sensitive to variations in gas or fuel costs. It is, however, impacted by the
collection of state mandated taxes which fluctuate with gas costs and also some
level of fluctuation in volumes sold. Electric generating asset optimization
activities are primarily affected by market conditions, the level of excess
generating capacity, and electric transmission availability. Following is a
discussion and analysis of margin generated from regulated utility operations.

Gas Utility Margin (Gas Utility Revenues less Cost of Gas Sold)

Gas Utility margin and throughput by customer type follows:

                                                Year Ended December 31,
--------------------------------------------------------------------------
(In millions)                                    2003      2002      2001
--------------------------------------------------------------------------
   Residential                                 $ 225.3   $ 217.1   $ 201.9
   Commercial                                     65.0      65.5      57.7
   Contract                                       50.5      50.5      48.4
   Other                                           9.0       4.1       2.7
--------------------------------------------------------------------------
     Total gas utility margin                  $ 349.8   $ 337.2   $ 310.7
==========================================================================
Sold & transported volumes in MMDth:
   To residential & commercial customers         118.5     111.9     102.2
   To contract customers                          90.8      95.8      97.2
--------------------------------------------------------------------------
     Total throughput                            209.3     207.7     199.4
==========================================================================

Gas Utility margin for the year ended December 31, 2003, of $349.8 million
increased $12.6 million, or 4%, compared to 2002. It is estimated that weather
near normal for the year and 6% cooler than the prior year, contributed $8
million in increased residential and commercial margin and was the primary
contributor to increased throughput. The remaining increase is primarily
attributable to $4.5 million in higher utility receipts and excise taxes on
higher gas costs and volumes sold and $1.8 million in recovery of Ohio customer
choice implementation costs. These increases are partially offset by the
negative effect of high gas prices on customer usage.

Gas Utility margin for the year ended December 31, 2002, of $337.2 million
increased $26.5 million, or 9%, compared to 2001. 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, decreased gas
costs, and customer growth of over one percent also contributed. It is estimated
that weather contributed $10 million to the increase in Gas Utility margin,
various rate recovery riders in Ohio contributed $7 million, and other items,
including the impact of lower gas costs and customer growth, contributed $9
million. The effect of cooler weather was the primary factor driving an overall
4% increase in total throughput.

As noted above, gas cost fluctuations have impacted customer usage during the
years ended December 31, 2003, 2002, and 2001. The average cost per dekatherm of
gas purchased in those years was $6.36 in 2003, $4.57 in 2002, and $5.83 in
2001.

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

Electric Utility margin by revenue type follows:

                                                   Year Ended December 31,
------------------------------------------------------------------------------
(In millions)                              2003          2002           2001
------------------------------------------------------------------------------
Residential & commercial                 $ 141.1       $ 145.7        $ 134.4
Industrial                                  53.5          54.9           49.6
Municipalities & other                      20.1          16.9           16.8
------------------------------------------------------------------------------
  Total retail & firm wholesale            214.7         217.5          200.8
Asset optimization                          18.3          12.7           19.1
------------------------------------------------------------------------------
    Total electric utility margin        $ 233.0       $ 230.2        $ 219.9
==============================================================================

Retail & Firm Wholesale Margin
For the year ended December 31, 2003, margin from serving native load and firm
wholesale customers was $214.7 million, a decrease of $2.8 million when compared
to 2002. It is estimated that summer weather 19% cooler than normal and 34%
cooler than last year caused an $8 million decrease in residential and
commercial margin. The estimated effect of weather was partially offset by a
$7.1 million increase in retail electric rates related to recovery of NOx
compliance expenditures and related operating expenses. A slowly recovering
economy continued to negatively impact industrial sales which decreased $1.4
million compared to 2002. As a result primarily of the mild weather and slow
economic conditions, retail and firm wholesale volumes sold decreased 5% to 5.90
GWh in 2003 compared to 6.19 GWh in 2002. Volumes sold in 2001 were 5.82 GWh.
The current year decrease in native load and firm wholesale margin has been
offset by increased optimization margin as more fully described below.

For the year ended December 31, 2002, margin from serving native load and firm
wholesale customers increased $16.7 million or 8%, when compared to 2001. The
increase results primarily from the effect on residential and commercial sales
of cooling weather considerably warmer than the prior year. Weather in 2002 was
27% warmer than 2001 and 23% warmer than normal. In addition to weather, 2002
was positively affected by increased industrial and other wholesale volumes and
rate recovery related to 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 and increased volumes sold, native load and firm
wholesale volumes sold increased 6%. It is estimated that weather contributed $7
million to the increase in electric utility margin, and the increased industrial
and other wholesale volumes and the NOx recovery rider contributed $8 million.

Margin from Asset Optimization Activities
Periodically, generation capacity is in excess of that needed to serve native
load and firm wholesale customers. The Company markets this unutilized capacity
to optimize the return on its owned generation assets. Substantially all of
these contracts are integrated with portfolio requirements around power supply
and delivery and are short-term purchase and sale transactions that expose the
Company to limited market risk.

Following is a reconciliation of asset optimization activity:

                                                    Year Ended December 31,
-------------------------------------------------------------------------------
(In millions)                                      2003        2002      2001
-------------------------------------------------------------------------------
Beginning of Year Net Asset Optimization
    Position                                      $ (0.7)     $ 3.3     $    -

Statement of Income Activity

  Cumulative effect at adoption of SFAS 133            -          -        1.8
  Mark-to-market gains (losses) recognized           0.7       (3.6)       1.5
  Realized gains recognized                         17.6       16.3       17.6
-------------------------------------------------------------------------------
     Net activity in electric utility margin        18.3       12.7       19.1
-------------------------------------------------------------------------------
Net cash received & other adjustments              (18.0)     (16.7)     (17.6)
-------------------------------------------------------------------------------
End of Year Net Asset Optimization Position       $ (0.4)     $(0.7)    $  3.3
===============================================================================
  Included in:
     Prepayments & other current assets           $  2.4      $ 3.5     $  6.1
     Accrued liabilities                            (2.8)      (4.2)      (2.8)

For the years ended December 31, 2003, 2002, and 2001, volumes sold into the
wholesale market were 4.3 GWh, 10.7 GWh, and 3.4 GWh respectively, while volumes
purchased were 4.1 GWh in 2003, 10.3 GWh in 2002, and 2.9 GWh in 2001. A portion
of volumes purchased in the wholesale market is used to serve native load and
firm wholesale customers, and in 2003, greater amounts of purchased power have
been required for native load due to scheduled outages, which has reduced
capacity available for optimization. Additionally, volumes sold and purchased
were lower in 2003 compared to 2002 due to a shorter term focus in hedging and
optimization strategies. While volumes both sold and purchased in the wholesale
market have decreased during 2003, margin from optimization activities has
increased compared to 2002 due primarily to price volatility. Despite the
increased volumes in 2002, margins were lower in 2002 compared to 2001 due to
reduced price volatility.

In July 2003, the EITF released EITF 03-11, "Reporting Realized Gains and Losses
on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not
"Held for Trading Purposes" as Defined in Issue No. 02-3" (EITF 03-11). EITF
03-11 states that determining whether realized gains and losses on physically
settled derivative contracts should be reported in the Statement of Income on a
gross or net basis is a matter of judgment that depends on the relevant facts
and circumstances. The EITF contains a presumption that net settled derivative
contracts should be reported net in the Statement of Income. The Company adopted
EITF 03-11 as required on October 1, 2003.

After considering the facts and circumstances relevant to the asset optimization
portfolio, the Company believes presentation of these optimization activities on
a net basis is appropriate and has reclassified purchase contracts and
mark-to-market activity related to optimization activities from Purchased
electric energy to Electric utility revenues. Prior year financial information
has also been reclassified to conform to this net presentation.

Following is information regarding asset optimization activities included in
Electric utility revenues and Fuel for electric generation in the Statements of
Income:

                                                   Year Ended December 31,
-------------------------------------------------------------------------------
(In millions)                             2003           2002            2001
-------------------------------------------------------------------------------
Activity related to:
  Sales contracts                       $ 152.8        $ 302.8         $ 101.4
  Purchase contracts                     (127.0)        (275.9)          (74.3)
  Mark-to-market gains (losses)             0.7           (3.6)            1.5
-------------------------------------------------------------------------------
  Net asset optimization revenue           26.5           23.3            28.6
-------------------------------------------------------------------------------
  Fuel for electric generation             (8.2)         (10.6)           (9.5)
-------------------------------------------------------------------------------
  Asset optimization margin             $  18.3        $  12.7         $  19.1
===============================================================================

Operating Expenses

Other Operating

For the year ended December 31, 2003, other operating expenses increased $11.5
million compared to 2002. The increase is principally caused by increased
distribution, plant, and transmission operating expenses; power plant and other
maintenance; customer service initiatives; higher insurance premiums; and prior
year insurance recoveries. In addition, operating expenses reflect $1.8 million
in amortization of Ohio choice implementation costs, which are recovered through
increased gas utility margin. The increase in operating expenses was partially
offset by the impact of an Ohio regulatory order. The order allows the deferral
and recovery of uncollectible accounts expense to the extent it differs from the
level included in base rates. The Company estimated the difference to
approximate $4 million in excess of that included in base rates in 2003.

Other operating expenses decreased $13.5 million for the year ended December 31,
2002, when compared to 2001. The decrease results primarily from 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 of
$3.4 million and contributions to low income heating assistance programs of $2.0
million. Insurance recovery in 2002 of $2.8 million of certain maintenance costs
incurred in 2001 also contributed to the decrease.

Depreciation & Amortization

For the year ended December 31, 2003, depreciation and amortization increased
$7.2 million compared to 2002 due to additions to utility plant. Increased
depreciation expense reflects depreciation of utility plant placed into service
including a full year for a gas-fired peaker unit, expenditures for implementing
a choice program for Ohio gas customers, customer system upgrades, and other
upgrades to existing transmission and distribution facilities.

Depreciation and amortization decreased $7.2 million for the year ended December
31, 2002, when compared to 2001. The decrease results from $9.6 million of
expense recognized in 2001 related to assets which had useful lives shortened as
a result of the merger. The discontinuance of goodwill amortization as required
by SFAS 142, which approximated $4.9 million in 2001, also contributed to the
decrease. These decreases were offset somewhat by depreciation of utility plant
and non-utility property additions.

Taxes Other Than Income Taxes

Taxes other than income taxes increased $5.9 million in 2003 compared to 2002.
Higher utility receipts and excise taxes of $4.5 million were recognized in 2003
due to higher gas prices and more volumes sold compared to 2002. The remaining
increase results principally from higher property taxes.

Taxes other than income taxes decreased $0.9 million in 2002 compared to 2001 as
a result of lower revenues subject to the Indiana utility receipts tax.

Other Income (Expense)

Other - net

Other - net decreased $2.3 million in 2003 compared to 2002 and increased $1.5
million in 2002 compared to 2001. The 2003 decrease is primarily due to the $3.9
million write-off of notes receivable and preferred equity investments in BABB
International (BABB), an entity that processed fly ash into building materials.
The 2002 increase results primarily from gains recognized from the sale of
excess emission allowances and other assets.

Equity in Losses of Unconsolidated Affiliates

Equity in losses of unconsolidated affiliates increased $1.3 million in 2002
compared to 2001 principally due to increased losses and increased preferred
ownership in BABB. The smaller loss recognized in 2003 results from the
write-off of the BABB investment.

Interest Expense

Interest expense decreased $3.0 million in 2003 compared to 2002 and decreased
$1.6 million in 2002 compared to 2001. The 2003 decrease reflects the impact of
permanent financing completed in the third quarter of 2003. Lower average
interest rates on adjustable rate debt also contributed to the decreases in 2003
and 2002.

Income Taxes

For the year ended December 31, 2003, federal and state income taxes increased
$4.8 million in 2003 compared to 2002 and increased $25.5 million in 2002
compared to 2001. The 2003 increase results primarily from an increased
effective tax rate that reflects an increase in the Indiana state income tax
rate from 4.5 % to 8.5% and other changes in the effective tax rate recognized
in 2002. The increase in 2002 compared to 2001 is principally due to higher
pre-tax earnings.

                                   Competition

The utility industry has undergone dramatic structural change for several years,
resulting in increasing competitive pressures faced by electric and gas utility
companies. Currently, several states, including Ohio, have passed legislation
allowing electricity customers to choose their electricity supplier in a
competitive electricity market and several other states are considering such
legislation. At the present time, Indiana has not adopted such legislation. Ohio
regulation allows gas customers to choose their commodity supplier. The Company
implemented a choice program for its gas customers in Ohio in January 2003.
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

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 MISO is committed to reliability, the nondiscriminatory operation of the
bulk power transmission system, and to working with all stakeholders to create
cost-effective and innovative solutions. The Carmel, Indiana, based MISO began
operations in December 2001 and serves the electrical transmission needs of much
of the Midwest. 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, and export power to the
wholesale market 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.

                              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 oxide (NOx). Regulations concerning
water quality establish standards relating to intake and discharge of water from
electric generating facilities, including water used for cooling purposes in
electric generating facilities. Because of the scope and complexity of these
regulations, the Company is unable to predict the ultimate effect of such
regulations on its future operations, nor is it possible to predict what other
regulations may be adopted in the future. The Company intends to comply with all
applicable governmental regulations, but will contest any regulation it deems to
be unreasonable or impossible with which to comply.

Clean Air Act

NOx SIP Call Matter

The 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 .141 lbs./MMBTU
by May 31, 2004, (the compliance date). This is a 65% reduction in emission
levels.

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 currently be the most effective method of
reducing NOx emissions where high removal efficiencies are required.


The IURC has issued orders that approve:
o    the Company's project to achieve environmental compliance by investing in
     clean coal technology;
o    a total capital cost investment for this project up to $244 million
     (excluding AFUDC), subject to periodic review of the actual costs incurred;
o    a mechanism whereby, prior to an electric base rate case, the Company may
     recover through a rider that is updated every six months, an 8 percent
     return on its weighted capital costs for the project; and
o    ongoing recovery of operating costs, including depreciation and purchased
     emission allowances through a rider mechanism, related to the clean coal
     technology once the facility is placed into service.

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 is consistent with amounts approved in the IURC's
orders and is expected to be expended during the 2001-2006 period. Through
December 31, 2003, $145.2 million has been expended. After the equipment is
installed and operational, related annual operating expenses, including
depreciation expense, are estimated to be between $24 million and $27 million. A
portion of those expenses began in October 2003 when the Culley SCR became
operational. The 8 percent return on capital investment approximates the return
authorized in the Company's last electric rate case in 1995 and includes a
return on equity.

The Company expects to achieve timely compliance as a result of the project.
Construction of the first SCR at Culley was placed into service in October 2003,
and construction of the Warrick 4 and Brown SCR's is proceeding on schedule.
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. SIGECO's suit was filed in the U.S. District Court for the
Southern District of Indiana. The USEPA alleged 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 alleged that the modifications to the
Culley Generating Station required SIGECO to begin complying with federal new
source performance standards at its Culley Unit 3. The USEPA also issued an
administrative notice of violation to SIGECO making the same allegations, but
alleging that violations began in 1977.

On June 6, 2003, SIGECO, the Department of Justice (DOJ), and the USEPA
announced an agreement that would resolve the lawsuit. The agreement was
embodied in a consent decree filed in U.S. District Court for the Southern
District of Indiana. The mandatory public comment period has expired, and no
comments were received. The Court entered the consent decree on August 13, 2003.

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

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

The Company anticipates that the settlement would result in total capital
expenditures through 2007 in a range between $16 million and $28 million. Other
than the $600,000 civil penalty, which was accrued in the second quarter of
2003, the implementation of the settlement, including these capital expenditures
and related operating expenses, are expected to be recovered through rates.

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
with the most recent correspondence provided on March 26, 2001.

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 (VRP) and is currently conducting some level of
remedial activities, including groundwater monitoring at certain sites, where
deemed appropriate, and will continue remedial activities at the sites as
appropriate and necessary.

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

The estimated accrued costs are limited to Indiana Gas' proportionate share of
the remediation efforts. Indiana Gas has arrangements in place for 19 of the 26
sites with other potentially responsible parties (PRP), which serve to limit
Indiana Gas' share of response costs at these 19 sites to between 20% and 50%.

With respect to insurance coverage, Indiana Gas has received and recorded
settlements from all known insurance carriers in an aggregate amount
approximating $20.4 million.

Environmental matters related to manufactured gas plants have had no material
impact on earnings since costs recorded to date approximate PRP and insurance
settlement recoveries. While Indiana Gas has recorded all costs which it
presently expects to incur in connection with activities at these sites, it is
possible that future events may require some level of additional remedial
activities which are not presently foreseen.

In October 2002, the Company received a formal information request letter from
the IDEM regarding five manufactured gas plants owned and/or operated by SIGECO
and not currently enrolled in the IDEM's VRP. In response, SIGECO submitted to
the IDEM the results of preliminary site investigations conducted in the
mid-1990's. These site investigations confirmed that based upon the conditions
known at the time, the sites posed no risk to human health or the environment.
Follow up reviews have been initiated by the Company to confirm that the sites
continue to pose no such risk.

On October 6, 2003, SIGECO filed applications to enter four of the manufactured
gas plant sites in IDEM's VRP. The remaining site is currently being addressed
in the VRP by another Indiana utility. SIGECO is adding its four sites into the
renewal of the global Voluntary Remediation Agreement that Indiana Gas has in
place with IDEM for its manufactured gas plant sites. The total costs, net of
other PRP involvement and insurance recoveries, that may be incurred in
connection with further investigation, and if necessary, remedial work at the
four SIGECO sites cannot be determined at this time.

                           Rate and Regulatory Matters

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

All metered gas rates in Indiana contain a gas cost adjustment (GCA) clause, and
all metered gas rates in Ohio contain a gas cost recovery (GCR) clause. GCA and
GCR clauses allow the Company to charge for changes in the cost of purchased
gas. Metered electric rates contain a fuel adjustment clause (FAC) that allows
for adjustment in charges for electric energy to reflect changes in the cost of
fuel and the net energy cost of purchased power. Rate structures in the
Company's territories 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.

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

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

Ohio Uncollectible Accounts Expense Tracker

On December 17, 2003, the PUCO approved a request by VEDO and several other
regulated Ohio gas utilities to establish a mechanism to recover uncollectible
account expense outside of base rates. The tariff mechanism establishes an
automatic adjustment procedure to track and recover these costs instead of
providing the recovery of the historic amount in base rates. Through this order,
VEDO received authority to defer its 2003 uncollectible accounts expense to the
extent it differs from the level included in base rates. The Company estimated
the difference to approximate $4 million in excess of that included in base
rates, and accordingly reversed previously established reserves and recorded a
regulatory asset for the difference, totaling $3.0 million.

Gas Cost Recovery (GCR) Audit Proceedings

There is an Ohio requirement that Ohio gas utilities undergo a biannual audit of
their gas acquisition practices in connection with the gas cost recovery (GCR)
mechanism. In the case of VEDO, the two-year period began in November 2000,
coincident with the Company's acquisition of the Ohio operations and
commencement of service in Ohio. The audit provides the initial review of the
portfolio administration arrangement between VEDO and ProLiance. The external
auditor retained by the PUCO staff recently submitted an audit report wherein it
recommended a disallowance of approximately $7 million of previously recovered
gas costs. The Company believes a large portion of the third party auditor
recommendations is without merit. There are two elements of the recommendations
relating to the treatment of a pipeline refund and a penalty which VEDO does not
oppose. A hearing has been held, and based on its audit report, the PUCO staff
has recommended a $6.1 million disallowance. The Ohio Consumer Counselor has
submitted testimony to support an $11.5 million disallowance. For this PUCO
audit period, any disallowance relating to the Company's ProLiance arrangement
will be shared by the Company's joint venture partner. Based on a review of the
matters, the Company has reserved $1.1 million for its estimated share of a
potential disallowance. The Company believes that these proceedings will not
likely have a material effect on the Company's operating results or financial
condition. However, the Company can provide no assurance as to the ultimate
outcome of this proceeding.

Recovery of Purchased Power

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 2004,
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.

Regulatory Initiatives

In addition to the timely recovery of incremental NOx environmental expenditures
discussed above, the Company is pursuing base rate cases in its three gas
territories. The last general rate increase for VEDO and Indiana Gas was in
1992, and was in 1996 for SIGECO gas.

The Company is currently in a collaborative dialogue with the OUCC regarding
SIGECO's existing gas rates. If an agreement is reached between the parties as a
result of that process, it will be subject to review and approval by the IURC.

The Company expects to file a base rate case for Indiana Gas' territory during
the first quarter of 2004 and for VEDO in the second quarter of 2004.
Additionally, as part of the rate case process, the Company is pursuing
authority for recovery of the costs to comply with the Pipeline Safety Act of
2002 and for regulatory authority to amortize periodic expense incurred to
overhaul its electric turbines. The timing and ultimate outcome of any of these
regulatory initiatives is uncertain.

                          Critical Accounting Policies

Management is required to make judgments, assumptions, and estimates that affect
the amounts reported in the consolidated financial statements and the related
disclosures that conform to accounting principles generally accepted in the
United States. Note 2 to the consolidated financial statements describes the
significant accounting policies and methods used in the preparation of the
consolidated financial statements. Certain estimates used in the financial
statements are subjective and use variables that require judgment. These include
the estimates to perform goodwill and other asset impairments tests. The Company
makes other estimates in the course of accounting for unbilled revenue, the
effects of regulation, and intercompany allocations that are critical to the
Company's financial results but that are less likely to be impacted by near term
changes. Other estimates that significantly affect the Company's results, but
are not necessarily critical to operations, include depreciation of utility and
non-utility plant, the valuation of derivative contracts, and the allowance for
doubtful accounts, among others. Actual results could differ from these
estimates.

Goodwill

Pursuant to SFAS No. 142, the Company 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 in both 2003 and 2002
and therefore resulted in no impairment.

Estimating fair value using a discounted cash flow model is subjective and
requires significant judgment in applying a discount rate, growth assumptions,
company expense allocations, and longevity of cash flows. A 100 basis point
increase in the discount rate utilized to calculate the Gas Utility Services
segment's fair value also would have resulted in no impairment charge in 2003 or
2002.

Impairment Review of Investments

The Company has investments in unconsolidated affiliated and notes receivable
convertible into equity interests. When events occur that may cause one of these
investments to be impaired, the Company performs an impairment analysis. An
impairment analysis of notes receivable usually involves the comparison of the
investment's estimated free cash flows to the stated terms of the note. An
impairment analysis of equity method investments involves comparison of the
investment's estimated fair value to its carrying amount. Fair value is
estimated using primarily discounted cash flow analyses. Calculating free cash
flows and fair value is subjective and requires significant judgment in growth
assumptions, longevity of cash flows, and discount rates (for fair value
calculations). As a result of such tests, a $3.9 million dollar write-off of the
BABB investments resulted in 2003.

Unbilled Revenues

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

Regulation

At each reporting date, the Company reviews current regulatory trends in the
markets in which it operates. This review involves judgment and is critical in
assessing the recoverability of regulatory assets as well as the ability to
continue to account for its activities based on the criteria set forth in SFAS
No. 71 "Accounting for the Effects of Certain Types of Regulation" (SFAS 71).
Based on the Company's current review, it believes its regulatory assets are
probable of recovery. If all or part of the Company's operations cease to meet
the criteria of SFAS 71, a write-off of related regulatory assets and
liabilities could be required. In addition, the Company would be required to
determine any impairment to the carrying value of its utility plant and other
regulated assets. In the unlikely event of a change in the current regulatory
environment, such write-offs and impairment charges could be significant.

Intercompany Allocations

Support Services

Vectren and certain subsidiaries of Vectren provide 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, which occurs on September 30. These costs are directly
charged to individual subsidiaries. Other components of costs (such as interest
cost and asset returns) are charged to individual subsidiaries through the
corporate allocation process discussed above. Neither plan assets nor the 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 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 2003 periodic benefit cost: a
discount rate of 6.75%, an expected return on plan assets before expenses of
9.0%, a rate of compensation increase of 4.25%, and a health care cost trend
rate of 10% in 2003 declining to 5% in 2006. During 2003, Vectren reduced the
discount rate and rate of compensation increase by 75 basis points to value 2003
ending pension and postretirement obligations due to a decline in benchmark
interest rates. The Company also lengthened to 2009 the time in which the health
care trend rate declines to 5% primarily due to increases in healthcare costs.
In addition, the Company reduced its 2004 expected return on plan assets 50
basis points from that used to estimate 2003 expense due to recent lower
investment returns and lower interest rates. Future changes in health care
costs, work force demographics, interest rates, or plan changes could
significantly affect the estimated cost of these future benefits that are
allocated to VUHI and its subsidiaries.

                 Impact of Recently Issued Accounting Guidance

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. The Company adopted this statement on
January 1, 2003. The adoption was not material to the Company's results of
operations or financial condition.

The Company collects an estimated cost of removal of its utility plant through
depreciation rates established by regulatory proceedings. As of December 31,
2003, and 2002, such removal costs approximated $229 million and $210 million,
respectively. In 2002, the cost of removal has been included in Other removal
costs, which is in noncurrent liabilities. In 2003, the Company re-characterized
other removal costs to Regulatory liabilities upon adoption of SFAS 143.

SFAS 149

In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on
Derivative Instruments and Hedging Activities" (SFAS 149). SFAS 149 amends and
clarifies the accounting guidance on (1) derivative instruments (including
certain derivative instruments embedded in other contracts) and (2) hedging
activities that fall within the scope of FASB Statement No. 133 (SFAS 133),
"Accounting for Derivative Instruments and Hedging Activities." SFAS 149 amends
SFAS 133 to reflect decisions that were made (1) as part of the process
undertaken by the Derivatives Implementation Group (DIG), which necessitated
amending SFAS 133, (2) in connection with other projects dealing with financial
instruments, and (3) regarding implementation issues related to the application
of the definition of a derivative. SFAS 149 also amends certain other existing
pronouncements which will result in more consistent reporting of contracts that
are derivatives in their entirety or that contain embedded derivatives that
warrant separate accounting. SFAS 149 is effective (1) for contracts entered
into or modified after June 30, 2003, with certain exceptions and (2) for
hedging relationships designated after June 30. The guidance is to be applied
prospectively. The adoption did not have a material effect on the Company's
results of operations or financial condition.

SFAS 150

In May 2003, the FASB issued SFAS No. 150, "Accounting for Certain Financial
Instruments with Characteristics of Both Liabilities and Equity" (SFAS 150).
SFAS 150 requires issuers to classify as liabilities the following three types
of freestanding financial instruments: mandatorily redeemable financial
instruments, obligations to repurchase the issuer's equity shares by
transferring assets, and certain obligations to issue a variable number of
shares. SFAS 150 was effective immediately for financial instruments entered
into or modified after May 31, 2003; otherwise, the standard was effective for
all other financial instruments at the beginning of the Company's third quarter
of 2003. In October 2003, the FASB issued further guidance regarding mandatorily
redeemable stock which is effective January 1, 2004, for the Company. The
Company has approximately $200,000 of outstanding preferred stock of a
subsidiary that is redeemable on terms outside the Company's control. However,
the preferred stock is not redeemable on a specified or determinable date or
upon an event that is certain to occur. The adoption of SFAS 150 on January 1,
2004, did not affect the Company's results of operations or financial condition.

FASB Interpretation (FIN) 45

In November 2002, the FASB issued 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 fair value of the obligations it has undertaken.
The initial recognition and measurement provisions were applicable on a
prospective basis to guarantees issued or modified after December 31, 2002.
Since that date, the adoption has not had a material effect on the Company's
results of operations or financial condition.

FIN 46/46-R (Revised in December 2003)

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 (VIE) and significantly changes the
consolidation requirements for those entities. FIN 46 is intended to achieve
more consistent application of consolidation policies related to VIE's and thus
improves comparability between enterprises engaged in similar activities when
those activities are conducted through VIE's. In December 2003, the FASB
completed its deliberations of proposed modifications to FIN 46 and decided to
codify both the proposed modifications and other decisions previously issued
through certain FASB Staff Positions into one document that was issued as a
revision to the original Interpretation (FIN 46-R). FIN 46-R currently applies
to VIE's created after January 31, 2003, and to VIE's in which an enterprise
obtains an interest after that date. For entities created prior to January 31,
2003, FIN 46 is to be adopted no later than the end of the first interim or
annual reporting period ending after March 15, 2004. Although management is
still evaluating the impact of FIN 46 and related Staff Positions on its
financial position and results of operations, the adoption is not expected to
have a material effect.

Staff Accounting Bulletin No. 104

In December 2003, the SEC published Staff Accounting Bulletin (SAB) No. 104,
"Revenue Recognition". This SAB updates portions of the SEC staff's interpretive
guidance provided in SAB 101 and included in Topic 13 of the Codification of
Staff Accounting Bulletins. SAB 104 deletes interpretative material no longer
necessary and conforms the interpretive material retained because of
pronouncements issued by the FASB's EITF on various revenue recognition topics,
including EITF 00-21, "Revenue Arrangements with Multiple Deliverables." The
Company's adoption of the standard did not have an impact on its revenue
recognition policies.

     United States Securities and Exchange Commission (SEC) Informal Inquiry

As more fully described in the 2002 consolidated financial statements, the
Company restated its annual consolidated financial statements for 2000 and 2001,
and its 2002 quarterly results. The Company received an informal inquiry from
the SEC with respect to this restatement. In response, the Company met with the
SEC staff and provided information in response to their requests, with the most
recent response provided on July 26, 2003.

                               Financial Condition

Within Vectren's consolidated group, VUHI, the parent company, funds short-term
and long-term financing needs of the utility group 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. The guarantees are full and unconditional and joint and
several, and VUHI has no subsidiaries other than the subsidiary guarantors.
VUHI's long-term and short-term obligations outstanding at December 31, 2003,
totaled $550.0 million and $184.4 million, respectively. Additionally, prior to
VUHI's formation, Indiana Gas and SIGECO funded their operations separately, and
therefore, have long-term debt outstanding funded solely by their operations.
VUHI's operations have historically funded almost all of Vectren's common stock
dividends.

VUHI's and Indiana Gas' credit ratings on outstanding senior unsecured debt at
December 31, 2003, are A-/Baa1 as rated by Standard and Poor's Ratings Services
(Standard and Poor's) and Moody's Investors Service (Moody's), respectively.
SIGECO's credit ratings on outstanding senior unsecured debt are BBB+/Baa1.
SIGECO's credit ratings on outstanding secured debt 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 ratings of Moody's and
Standard and Poor's are categorized as investment grade and are unchanged from
December 31, 2002. In July 2003, Standard and Poor's reaffirmed its ratings, and
Moody's reaffirmed its ratings on VUHI's senior unsecured debt. A security
rating is not a recommendation to buy, sell, or hold securities. The rating is
subject to revision or withdrawal at any time, and each rating should be
evaluated independently of any other rating. Standard and Poor's and Moody's
lowest level investment grade rating is BBB- and Baa3, respectively.

The Company's consolidated equity capitalization objective is 45-55% of 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
50% and 46% of total capitalization, including current maturities of long-term
debt and long-term debt subject to tender, at December 31, 2003, and 2002,
respectively.

The Company expects the majority of its capital expenditures, investments, and
debt security redemptions to be provided by internally generated funds. However,
due to significant capital expenditures for NOx compliance equipment at SIGECO
and to further strengthen the Company's capital structure and the capital
structures of its utility subsidiaries, the Company has completed certain
financing transactions as more fully described in the discussion of financing
activity below.

Sources & Uses of Liquidity

Operating Cash Flow

The Company's primary historical source of liquidity to fund working capital
requirements has been cash generated from operations. Cash flow from operating
activities decreased during the year ended December 31, 2003, compared to 2002
by $108.4 million and increased $92.3 million in 2002 compared to 2001. The
primary reason for these changes was favorable changes in working capital
accounts occurring in 2002 due to lower gas prices in that year and higher gas
prices in 2003 and 2001. In 2003, the decrease was partially offset by 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. Additionally, short-term borrowings are required for capital projects and
investments until they are permanently financed.

Cash flow provided by financing activities of $64.5 million for the year ended
December 31, 2003, includes the effects of the permanent financing executed
during the current year in which approximately $407 million in capital
contributions from Vectren, third party debt proceeds, and hedging net proceeds
were received and used to retire higher coupon long-term debt and other short
term borrowings. Common stock dividends have increased in 2003 compared to 2002.

Cash flow required for financing activities of $53.6 million for the year ended
December 31, 2002, includes increased borrowings due to financing a portion of
capital expenditures for NOx compliance temporarily with short-term borrowings.
Cash flow provided by financing activities of $33.9 million for the year ended
December 31, 2001, includes $38.1 million of reductions in borrowings and
preferred stock and $91.6 million in dividends paid to Vectren, offset by
additional capital contributions of $164.4 million. During 2001, $508.4 million
of net proceeds from Vectren capital contributions and debt issuances were
utilized to pay down short-term borrowings and strengthen VUHI's balance sheet.

VUHI Debt Issuance
In March 2003, Vectren filed a registration statement with the Securities and
Exchange Commission with respect to a public offering of authorized but
previously unissued shares of common stock as well as senior unsecured notes of
VUHI. In July 2003, VUHI issued senior unsecured notes with an aggregate
principal amount of $200 million in two $100 million tranches. The first tranche
was 10-year notes due August 2013, with an interest rate of 5.25% priced at
99.746% to yield 5.28% to maturity (2013 Notes). The second tranche was 15-year
notes due August 2018 with an interest rate of 5.75% priced at 99.177% to yield
5.80% to maturity (2018 Notes).

The notes are guaranteed by VUHI's three public utilities: SIGECO, Indiana Gas,
and VEDO. These guarantees are full and unconditional and joint and several. In
addition, they have no sinking fund requirements, and interest payments are due
semi-annually. The notes may be called by VUHI, in whole or in part, at any time
for an amount equal to accrued and unpaid interest, plus the greater of 100% of
the principal amount or the sum of the present values of the remaining scheduled
payments of principal and interest, discounted to the redemption date on a
semi-annual basis at the Treasury Rate, as defined in the indenture, plus 20
basis points for the 2013 Notes and 25 basis points for the 2018 Notes.

Shortly before these issues, VUHI entered into several treasury locks with a
total notional amount of $150.0 million. Upon issuance of the debt, the treasury
locks were settled resulting in the receipt of $5.7 million in cash, which was
recorded as a regulatory liability pursuant to existing regulatory orders. The
value received is being amortized as a reduction of interest expense over the
life of the issues.

The net proceeds from the sale of the senior notes and settlement of related
hedging arrangements approximated $203 million and were used to repay short-term
borrowing and to retire long-term debt with higher interest rates.

Additional Capital Contributions
During 2003, the Company received a $204.1 million equity contribution from
Vectren. Vectren funded $163.2 million of the contribution with proceeds from an
offering of its common stock, $35.0 million was funded by Vectren's nonregulated
operations, and $5.9 million was funded by new share issues from Vectren's
dividend reinvestment plan. These proceeds were used by VUHI and VUHI's
subsidiaries to repay short-term borrowings and to retire long-term debt with
higher interest rates.

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

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

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

Permanent Financing for the Ohio Operations Purchase
In January 2001, Vectren filed a registration statement with the Securities and
Exchange Commission with respect to a public offering of authorized but
previously unissued shares of common stock. In February 2001, the registration
became effective. 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 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.

Both issues are guaranteed by VUHI's three operating utility companies: SIGECO,
Indiana Gas, and VEDO. These guarantees are full and unconditional and joint and
several. In addition, 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.

The net proceeds from the sale of the senior notes and settlement of hedging
arrangements totaled $344.0 million.

The proceeds received from the capital contribution and debt issuance were used
to refinance interim borrowing arrangements used to purchase the Ohio
operations.

Other Financing Transactions
Other Company long-term debt totaling $18.5 million in 2003, $6.5 million in
2001, and $7.6 million in 2001 was retired as scheduled.

At December 31, 2002, the Company had $26.6 million of adjustable rate senior
unsecured bonds which could, at the election of the bondholder, be tendered to
the Company when interest rates are reset. Such bonds were classified as
Long-term debt subject to tender. During 2003, the Company re-marketed $4.6
million of the bonds through 2020 at a 4.5% fixed interest rate and remarketed
$22.0 million of the bonds through 2030 at a 5.0% fixed interest rate. The bonds
are now classified in Long-term debt.

Additionally, during 2003, the Company re-marketed $22.5 million of first
mortgage bonds subject to interest rate exposure on a long term basis. The $22.5
million of mortgage bonds were remarketed through 2024 at a 4.65% fixed interest
rate.

In December 2001, Vectren made an additional equity contribution of $35.0
million with proceeds received from dividends paid by Vectren's nonregulated
operations.

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.

Investing Cash Flow

Cash required for investing activities of $236.1 million for the year ended
December 31, 2003, includes $235.0 million of requirements for capital
expenditures. Investing activities for 2002 were $218.7 million. The increase
occurring in 2003 principally results from higher capital expenditures.

Cash required for investing activities of $218.7 million for the year ended
December 31, 2002, includes $217.3 million of requirements for capital
expenditures. Investing activities for 2001 were $215.3 million. The $3.4
million increase occurring in 2002 is principally the result of additional
capital expenditures for NOx compliance and investments in deferred compensation
funding arrangements, offset by proceeds received from intercompany notes
receivable.

Available Sources of Liquidity

At December 31, 2003, the Company has $351 million of short-term borrowing
capacity, of which approximately $166 million is available.

Beginning in 2003, Vectren began issuing new shares to satisfy dividend
reinvestment plan requirements. During 2003, proceeds of $5.9 million generated
by the dividend reinvestment plan were contributed to VUHI. Management estimates
such new share issues will add similar liquidity to support VUHI's operations in
succeeding years.

Potential & Future Uses of Liquidity

Contractual Obligations

The following is a summary of contractual obligations at December 31, 2003:
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------
(In millions)                  2004      2005     2006     2007     2008  Thereafter
------------------------------------------------------------------------------------
<S>                           <C>       <C>      <C>      <C>       <C>     <C>
Long-term debt (1)            $ 15.0    $   -    $   -    $ 6.5     $ -     $ 972.0
Short-term debt                185.2        -        -        -       -           -
Commodity firm purchase
  commitments                  105.8     29.3        -        -       -           -
Utility & nonutility plant
  purchase commitments (2)      96.8     19.7      1.3        -       -           -
------------------------------------------------------------------------------------
    Total                     $402.8    $49.0    $ 1.3    $ 6.5     $ -     $ 972.0
====================================================================================
</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 2003 (in millions) is $13.5 in 2004, $10.0 in 2005, $53.7
     in 2006, $20.0 in 2007, zero in 2008, and $120.0 thereafter.

(2)  The settlement period of these obligations is estimated.

Planned Capital Expenditures

The timing and amount of capital expenditures, including contractual
purchase commitments discussed above, for the five-year period 2004 - 2008 are
estimated as follows (in millions): $252.9 in 2004, $213.8 in 2005, $222.9 in
2006, 216.4 in 2007, and $233.6 in 2008. Included in planned capital
expenditures for NOx compliance is (in millions) $77.4 in 2004, $19.7 in 2005,
and $3.6 in 2006

Pension and Postretirement Funding Obligations

Vectren has not made significant contributions to its qualified pension plans in
recent years. Due to recent market performance, it is likely to be necessary for
Vectren to make contributions to benefits plans in the coming years. Management
currently estimates that qualified pension plans will require Company
contributions of approximately $5 million in 2004 and approximately $10 million
in 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 include, 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 a change in our credit rating, changes in interest
     rates, and/or changes in market perceptions of the utility industry and
     other energy-related industries.

o    Employee or contractor 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.

<PAGE>

ITEM 7A.  QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK

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

The Company also executes derivative contracts in the normal course of
operations while buying and selling commodities to be used in operations and
optimizing its generation assets.

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 the cost of such purchases through natural
gas and fuel cost adjustment mechanisms.

Electric sales and purchases in the wholesale power market and electric sales to
certain municipalities and large industrial customers are exposed to commodity
price risk associated with fluctuating commodity prices.

The Company's wholesale power marketing activities include asset optimization
activities that manage the utilization of available electric generating capacity
by entering into energy contracts that commit the Company to purchase and sell
electricity in the future. Commodity price risk results from forward positions
that commit the Company to deliver electricity. The Company mitigates price risk
exposure with planned unutilized generation capability and offsetting forward
purchase contracts. The Company accounts for asset optimization contracts that
are derivatives at fair value with the offset marked to market through earnings.

Sales to certain municipalities and large industrial customers are executed to
meet customer demand. Price risk from forward positions obligating the Company
to deliver commodities is mitigated using generating capability, and offsetting
forward purchase contracts. These contracts are expected to be settled by
physical receipt or delivery of the commodity.

Market risk resulting from commodity contracts is measured by management using
the potential impact on pre-tax earnings caused by the effect a 10% adverse
change in forward commodity prices might have on market sensitive derivative
positions outstanding on specific dates. For the years ended December 31, 2003,
and 2002, a 10% adverse change in forward commodity prices would have decreased
earnings by $3.0 million and $1.7 million, respectively, based upon open
positions existing on the last day of those years.

Interest Rate Risk

The Company is exposed to interest rate risk associated with its borrowing
arrangements. Its risk management program seeks to reduce the potentially
adverse effects that market volatility may have on interest expense. The
Company's risk management objective is for between 20% and 30% of its total debt
to be exposed to short-term interest rate volatility. However, there are times
when this targeted range of interest rate exposure may not be attained. To
manage this exposure, the Company may use derivative financial instruments. At
December 31, 2003, such debt obligations, as affected by designated interest
rate swaps, represented 16% of the Company's total debt portfolio.

Market risk is estimated as the potential impact resulting from fluctuations in
interest rates on adjustable rate borrowing arrangements exposed to short-term
interest rate volatility. During 2003 and 2002, the weighted average combined
borrowings under these arrangements were $226.9 million and $234.3 million,
respectively. At December 31, 2003, and 2002, combined borrowings under these
arrangements were $185.2 million and $319.5 million, respectively. Based upon
average borrowing rates under these facilities during the years ended December
31, 2003, and 2002, an increase of 100 basis points (one percentage point) in
the rates would have increased interest expense by $2.3 million in both years.

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. The Company mitigates these risks by
executing derivative contracts that manage the price of forecasted natural gas
purchases. These contracts are subject to regulation, which allows for
reasonable and prudent hedging costs to be recovered through rates. When
regulation is involved, SFAS 71 controls when the offset to mark-to-market
accounting is recognized in earnings.


<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 12, 2004


<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, 2003 and 2002, and the
related consolidated statements of income, shareholder's equity, and cash flows
for each of the three years in the period ended December 31, 2003. Our audits
also included the financial statement schedules listed in the Index at Item 15.
These financial statements and financial statement schedules are the
responsibility of the Company's management. Our responsibility is to express an
opinion on the financial statements and financial statement schedules based on
our audits.

We conducted our audits in accordance with 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, 2003 and 2002, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2003, in conformity with accounting principles generally accepted
in the United States of America. Also, in our opinion, such financial statement
schedules, when considered in relation to the basic consolidated financial
statements taken as a whole, present fairly in all material respects the
information set forth therein.

As discussed in Note 2-H, effective January 1, 2003, the Company adopted
Statement of Financial Accounting Standards ("SFAS") 143, "Accounting for Asset
Retirement Obligations." As discussed in Note 2-G, effective January 1, 2002,
the Company adopted SFAS 142, "Goodwill and Other Intangibles." As discussed in
Note 11, effective January 1, 2001, the Company adopted SFAS 133, "Accounting
for Derivative Instruments and Hedging Activities," as amended.

As discussed in Note 11, in 2003 the Company adopted EITF Issue No. 03-11,
"Reporting Realized Gains and Losses on Derivative Instruments That Are Subject
to FASB Statement No. 133 and "Not Held for Trading Purposes" as Defined in
Issue No. 02-3." Amounts for the years 2002 and 2001 have been reclassified in
the accompanying statements of income to conform to this new method of
presentation.


/s/ DELOITTE & TOUCHE LLP
----------------------------
DELOITTE & TOUCHE LLP
Indianapolis, Indiana
February 12, 2004


<PAGE>


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

                                                           At December 31,
-------------------------------------------------------------------------------
                                                         2003            2002
-------------------------------------------------------------------------------
                ASSETS

Current Assets
   Cash & cash equivalents                           $     8.1        $    10.5
   Accounts receivable - less reserves of $3.1 &
       $5.5, respectively                                114.0            131.9
   Receivables due from other Vectren companies            1.7             56.3
   Accrued unbilled revenues                             128.7            112.7
   Inventories                                            55.1             56.0
   Recoverable fuel & natural gas costs                   20.3             19.3
   Prepayments & other current assets                    131.3             81.3
-------------------------------------------------------------------------------
     Total current assets                                459.2            468.0
-------------------------------------------------------------------------------

Utility Plant
  Original cost                                        3,250.7          3,042.2
  Less:  accumulated depreciation & amortization       1,247.0          1,179.0
-------------------------------------------------------------------------------
     Net utility plant                                 2,003.7          1,863.2
-------------------------------------------------------------------------------

Investments in unconsolidated affiliates                   1.8              2.4
Other investments                                         20.6             21.9
Non-utility property - net                               141.3            139.2
Goodwill - net                                           205.0            205.0
Regulatory assets                                         89.6             75.8
Other assets                                               3.9              4.9
-------------------------------------------------------------------------------
TOTAL ASSETS                                         $ 2,925.1        $ 2,780.4
===============================================================================

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)

                                                             At December 31,
-------------------------------------------------------------------------------
                                                           2003           2002
-------------------------------------------------------------------------------
       LIABILITIES & SHAREHOLDER'S EQUITY

Current Liabilities
   Accounts payable                                    $    63.0      $    74.8
   Accounts payable to affiliated companies                 80.3           85.6
   Payables to other Vectren companies                      13.3           69.8
   Accrued liabilities                                      93.9           83.2
   Short-term borrowings                                   185.2          239.1
   Short-term borrowings from other Vectren companies          -           86.9
   Current maturities of long-term debt                     15.0           39.8
   Long-term debt subject to tender                         13.5           26.6
-------------------------------------------------------------------------------
      Total current liabilities                            464.2          705.8
-------------------------------------------------------------------------------

Long-Term Debt - Net of Current Maturities &
   Debt Subject to Tender                                  960.5          841.2
Deferred Income Taxes & Other Liabilities
   Deferred income taxes                                   201.5          172.3
   Regulatory liabilities & other removal costs            235.0          210.0
   Deferred credits & other liabilities                     83.9           82.2
-------------------------------------------------------------------------------
      Total deferred credits & other liabilities           520.4          464.5
-------------------------------------------------------------------------------
Commitments & Contingencies (Notes 8 - 10)

Cumulative, Redeemable Preferred Stock
    of a Subsidiary                                          0.2            0.3

Common Shareholder's Equity
   Common stock (no par value)                             589.8          385.7
   Retained earnings                                       390.0          382.4
   Accumulated other comprehensive income                      -            0.5
-------------------------------------------------------------------------------
      Total common shareholder's equity                    979.8          768.6
-------------------------------------------------------------------------------

TOTAL LIABILITIES & SHAREHOLDER'S EQUITY               $ 2,925.1      $ 2,780.4
===============================================================================

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 INCOME
                                  (In millions)

                                                        Year Ended December 31,
----------------------------------------------------------------------------------
                                                    2003        2002         2001
----------------------------------------------------------------------------------
<S>                                             <C>          <C>         <C>
OPERATING REVENUES
   Gas utility                                  $ 1,112.3    $  908.0    $ 1,019.6
   Electric utility                                 335.7       328.6        308.5
   Other                                              0.8         0.3          0.2
----------------------------------------------------------------------------------
       Total operating revenues                   1,448.8     1,236.9      1,328.3
----------------------------------------------------------------------------------
OPERATING EXPENSES
   Cost of gas sold                                 762.5       570.8        708.9
   Fuel for electric generation                      86.5        81.6         74.4
   Purchased electric energy                         16.2        16.8         14.2
   Other operating                                  210.1       198.6        212.1
   Merger & integration costs                           -           -          2.8
   Restructuring costs                                  -           -         15.0
   Depreciation & amortization                      117.9       110.7        117.9
   Taxes other than income taxes                     56.6        50.7         51.6
----------------------------------------------------------------------------------
       Total operating expenses                   1,249.8     1,029.2      1,196.9
----------------------------------------------------------------------------------
OPERATING INCOME                                    199.0       207.7        131.4

OTHER INCOME (EXPENSE)
   Other - net                                        4.8         7.1          5.6
   Equity in losses of unconsolidated
      affiliates                                     (0.5)       (1.8)        (0.5)
----------------------------------------------------------------------------------
       Total other income                             4.3         5.3          5.1
----------------------------------------------------------------------------------
Interest expense                                     66.1        69.1         70.7
----------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES                          137.2       143.9         65.8
----------------------------------------------------------------------------------
Income taxes                                         51.6        46.8         21.3
Preferred dividend requirements of subsidiary           -           -          0.8
----------------------------------------------------------------------------------
INCOME BEFORE CUMULATIVE EFFECT OF CHANGE
     IN ACCOUNTING PRINCIPLE                         85.6        97.1         43.7
----------------------------------------------------------------------------------
Cumulative effect of change in accounting
   principle - net of tax                               -           -          1.1
----------------------------------------------------------------------------------
NET INCOME                                       $   85.6    $   97.1    $    44.8
==================================================================================
</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 CASH FLOWS
                                  (In millions)

                                                              Year Ended December 31,
-----------------------------------------------------------------------------------------
                                                           2003        2002        2001
-----------------------------------------------------------------------------------------
<S>                                                      <C>         <C>         <C>
CASH FLOWS FROM OPERATING ACTIVITIES
   Net income                                            $  85.6     $  97.1     $  44.8
   Adjustments to reconcile net income to cash from
         operating activities:
      Depreciation & amortization                          117.9       110.7       117.9
      Deferred income taxes & investment tax credits        24.1       (23.4)      (14.9)
      Pension & postretirement periodic benefit cost         5.9         6.5         5.7
      Equity in earnings of unconsolidated affiliates        0.5         1.8         0.5
      Net unrealized (gain) loss on derivative
           instruments, including cumulative effect
           of change in accounting principle                (0.7)        3.6        (3.3)
      Other non-cash charges - net                          10.7         8.4        14.0
      Changes in working capital accounts:
          Accounts receivable, including to Vectren
               companies & accrued unbilled revenue         44.3       (28.1)       78.9
          Inventories                                        0.9        (1.2)       38.4
          Recoverable fuel & natural gas costs              (1.0)       48.1        25.9
          Prepayments & other current assets               (49.1)       (9.4)      (11.3)
          Accounts payable, including to Vectren
             companies & affiliated companies              (73.6)       73.2       (87.7)
          Accrued liabilities                               12.6         0.1       (10.3)
      Changes in noncurrent assets                          (5.9)       (1.2)       (4.2)
      Changes in noncurrent liabilities                     (3.0)       (8.6)       (9.1)
-----------------------------------------------------------------------------------------
          Net cash flows from operating activities         169.2       277.6       185.3
-----------------------------------------------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES
   Proceeds from:
      Long-term debt - net of issuance costs
         & hedging proceeds                                202.9           -       344.0
      Additional capital contribution                      204.1           -       164.4
   Requirements for:
      Dividends to parent                                  (78.0)      (69.7)      (91.6)
      Retirement of long-term debt,
          including premiums paid                         (121.9)       (6.5)       (7.3)
      Redemption of preferred stock of subsidiary           (0.1)       (0.2)      (17.7)
      Retirement of short-term notes payable                   -           -      (150.0)
      Dividends on preferred stock of subsidiary               -           -        (0.8)
   Net change in short-term borrowings,
        including from other Vectren companies            (140.8)       22.8      (207.1)
   Other activity                                           (1.7)          -           -
-----------------------------------------------------------------------------------------
          Net cash flows from financing activities          64.5       (53.6)       33.9
-----------------------------------------------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES
   Proceeds from other investing activities                    -        10.4         1.5
   Requirements for:
      Capital expenditures, excluding AFUDC equity        (235.0)     (217.3)     (202.8)
      Unconsolidate affiliate and other investments         (1.1)      (11.8)      (14.0)
-----------------------------------------------------------------------------------------
           Net cash flows from investing activities       (236.1)     (218.7)     (215.3)
-----------------------------------------------------------------------------------------
Net (decrease) increase in cash & cash equivalents          (2.4)        5.3         3.9
Cash & cash equivalents at beginning of period              10.5         5.2         1.3
-----------------------------------------------------------------------------------------
Cash & cash equivalents at end of period                 $   8.1     $  10.5    $    5.2
=========================================================================================
Cash paid during the year for:
   Interest                                              $  60.7     $  58.4    $   63.5
   Income taxes                                             52.2        63.3        46.7
</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, 2001                  $ 221.3    $ 403.0        $   -       $ 624.3
------------------------------------------------------------------------------------------
Comprehensive income:
Net income                                                44.8                       44.8
Minimum pension liability adjustment
     & other-net of tax                                                (1.8)         (1.8)
------------------------------------------------------------------------------------------
Total comprehensive income                                                           43.0
------------------------------------------------------------------------------------------
Common stock:
     Additional capital contribution          164.4                                 164.4
     Dividends                                           (91.6)                     (91.6)
Loss on extinguishment of preferred stock                 (1.2)                      (1.2)
------------------------------------------------------------------------------------------
Balance at December 31, 2001                  385.7      355.0         (1.8)        738.9
------------------------------------------------------------------------------------------
Comprehensive income:
Net income                                                97.1                       97.1
Minimum pension liability adjustments &
     other - net of tax                                                 2.3           2.3
------------------------------------------------------------------------------------------
Total comprehensive income                                                           99.4
------------------------------------------------------------------------------------------
Common stock dividends                                   (69.7)                     (69.7)
------------------------------------------------------------------------------------------
Balance at December 31, 2002                  385.7      382.4          0.5         768.6
------------------------------------------------------------------------------------------
Comprehensive income:
Net income                                                85.6                       85.6
Other comprehensive income adjustment
      - net of tax                                                     (0.5)         (0.5)
------------------------------------------------------------------------------------------
Total comprehensive income                                                           85.1
------------------------------------------------------------------------------------------
Common stock:
     Additional capital contribution          204.1                                 204.1
     Dividends                                           (78.0)                     (78.0)
------------------------------------------------------------------------------------------
Balance at December 31, 2003                $ 589.8    $ 390.0        $   -       $ 979.8
==========================================================================================
</TABLE>

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


<PAGE>


                  VECTREN CORPORATION AND SUBSIDIARY COMPANIES
                 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

1.   Organization and Nature of Operations

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. VUHI also has assets that provide information technology and
other services to the utilities.

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, owned as a
tenancy in common by Vectren Energy Delivery of Ohio, Inc. (VEDO), a wholly
owned subsidiary, (53% ownership) and Indiana Gas (47% ownership), 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 and 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 that 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.

2.   Summary of Significant Accounting Policies

A. Principles of Consolidation
The accompanying consolidated financial statements for periods prior to January
1, 2003, reflect the Company on a historical basis as restated for the effects
of the combination of entities under common control whereby certain information
technology systems and related assets and buildings were transferred from other
entities within Vectren's consolidated group to VUHI effective January 1, 2003.
The consolidated financial statements include the accounts of the Company and
its wholly owned and majority owned subsidiaries, after elimination of
significant intercompany transactions.

For the year ended December 31, 2002, operating income and net income
attributable to the contributed assets were $8.5 million and $3.5 million,
respectively. For the year ended December 31, 2002, operating income and net
income attributable to VUHI's operations before the contribution were $199.2
million and $93.6 million, respectively. For the year ended December 31, 2001,
operating income and net income attributable to the contributed assets were $8.1
million and $4.7 million, respectively. For the year ended December 31, 2001,
operating income and net income attributable to VUHI's operations before the
contribution were $123.3 million and $40.1 million, respectively. As of December
31, 2002, total assets attributable to the contributed assets were $131.1
million, and total assets attributable to VUHI's operations before the
contribution were $2,649.3 million.

B. Cash & Cash Equivalents
All highly liquid investments with an original maturity of three months or less
at the date of purchase are considered cash equivalents.

C.   Inventories
Inventories consist of the following:

                                                        At December 31,
-----------------------------------------------------------------------------
(In millions)                                      2003                 2002
-----------------------------------------------------------------------------
Gas in storage - at LIFO cost                    $ 21.9               $ 25.4
Materials & supplies                               19.3                 15.8
Fuel (coal & oil) for electric generation          10.7                 10.0
Gas in storage - at average cost                    2.5                  3.3
Other                                               0.7                  1.5
-----------------------------------------------------------------------------
       Total inventories                         $ 55.1               $ 56.0
=============================================================================

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,
2003, and 2002, by approximately $52.2 million and $32.7 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. 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)                                2003                           2002
---------------------------------------------------------------------------------------------
                                                Depreciation                    Depreciation
                                                 Rates as a                      Rates as a
                                                 Percent of                      Percent of
                                Original Cost   Original Cost   Original Cost   Original Cost
---------------------------------------------------------------------------------------------
<S>                               <C>                 <C>         <C>                <C>
Gas utility plant                 $ 1,721.9           3.6%        $ 1,622.0          3.8%
Electric utility plant              1,322.4           3.4%          1,216.1          3.3%
Common utility plant                   44.3           2.7%             41.6          2.6%
Construction work in progress         162.1             -             162.5            -
---------------------------------------------------------------------------------------------
       Total original cost        $ 3,250.7                       $ 3,042.2
=============================================================================================
</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)                      2003           2002            2001
------------------------------------------------------------------------
AFUDC - borrowed funds             $ 2.1          $ 3.1           $ 2.1
AFUDC - equity funds                 2.9            2.2             2.5
------------------------------------------------------------------------
      Total AFUDC capitalized      $ 5.0          $ 5.3           $ 4.6
========================================================================

Maintenance and repairs, including the cost of removal of minor items of
property and planned major maintenance projects, are charged to expense as
incurred unless deferral is authorized by a rate order. When property that
represents a retirement unit is replaced or removed, the cost of such property
is charged to Utility plant, with an offsetting charge to Accumulated
depreciation and Regulatory liabilities for the cost of removal.

E. Non-utility Property
The depreciation of non-utility property is charged against income over its
estimated useful life (ranging from 5 to 40 years), using the straight-line
method of depreciation. Repairs and maintenance, which are not considered
improvements and do not extend the useful life of the non-utility property, are
charged to expense as incurred. When non-utility property is retired, or
otherwise disposed of, the asset and accumulated depreciation are removed, and
the resulting gain or loss is reflected in income. Non-utility property is
presented net of accumulated depreciation and amortization totaling $57.0
million and $83.8 million as of December 31, 2003, and 2002, respectively. For
the years ended December 31, 2003 and 2001, the Company capitalized interest
totaling $0.9 million and $0.2 million, respectively, on non-utility plant
construction projects. Capitalized interest in 2002 was not significant.

F. Impairment Review of Long-Lived Assets
Long-lived assets are reviewed as facts and circumstances indicate that the
carrying amount may be impaired. This review is performed in accordance with
SFAS No. 144 "Accounting for the Impairment or Disposal of Long-Lived Assets"
(SFAS 144), which the Company adopted on January 1, 2002. SFAS 144 establishes
one accounting model for all impaired long-lived assets and long-lived assets to
be disposed of by sale or otherwise. SFAS 144 requires the evaluation for
impairment involve the comparison of an asset's carrying value to the estimated
future cash flows the asset is expected to generate over its remaining life. If
this evaluation were to conclude that the carrying value of the asset is
impaired, an impairment charge would be recorded based on the difference between
the asset's carrying amount and its fair value (less costs to sell for assets to
be disposed of by sale) as a charge to operations or discontinued operations.

G. Goodwill
Goodwill arising from business combinations is accounted for in accordance with
SFAS No. 142, "Goodwill and Other Intangible Assets" (SFAS 142). The Company
adopted SFAS 142 on January 1, 2002. SFAS 142 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.

As required by SFAS 142, amortization of goodwill relating to the acquisition of
the Ohio operations ceased on January 1, 2002. In 2001, Net income before
extraordinary loss and cumulative effect of change in accounting principle and
Net income would have been $46.7 million and $47.8 million, respectively, had
goodwill not been amortized. 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, and no impairment charges have been recorded since adoption. The
impairment test is performed at the beginning of each year.

Following is a reconciliation of reported net income to the adjusted net income
disclosed above for year ended December 31, 2001:

-----------------------------------------------------------------------
(In millions)                                                     2001
-----------------------------------------------------------------------
Net Income, As Reported                                          $ 44.8
Add: goodwill amortization - net of tax                             3.0
-----------------------------------------------------------------------
Net Income, As Adjusted                                          $ 47.8
=======================================================================

H.  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 expenditures by the Company
for removal costs or future reductions in revenues associated with amounts that
are to be credited to customers through the rate-making process.

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)                                              2003       2002
---------------------------------------------------------------------------
Future amounts recoverable from ratepayers:
    Income taxes                                          $ 18.1     $ 15.8
    Other                                                    1.0          -
---------------------------------------------------------------------------
                                                            19.1       15.8
Amounts deferred for future recovery:
    Demand side management programs                         25.0       23.8
    Other                                                    5.3        3.7
---------------------------------------------------------------------------
                                                            30.3       27.5
Amounts currently recovered through base rates:
    Unamortized debt issue costs                            21.4       19.5
    Premiums paid to reacquire debt                          7.4        4.1
    Demand side management programs                          2.7        3.2
---------------------------------------------------------------------------
                                                            31.5       26.8
Amounts currently recovered through tracking mechanisms:
    Ohio authorized trackers                                 7.5        5.7
    Indiana authorized trackers                              1.2          -
---------------------------------------------------------------------------
                                                             8.7        5.7
---------------------------------------------------------------------------
    Total regulatory assets                               $ 89.6     $ 75.8
===========================================================================

The $31.5 million currently being recovered through base rates is earning a
return with a weighted average recovery period of 18.2 years. The Company has
rate orders for all deferred costs not yet in rates and therefore believes that
future recovery is probable.

<PAGE>

Regulatory liabilities & other removal costs consist of the following:

                                                          At December 31,
-----------------------------------------------------------------------------
 (In millions)                                              2003        2002
-----------------------------------------------------------------------------
Cost of removal                                           $ 228.8     $     -
Interest rate hedging proceeds (See Note 15)                  6.2           -
-----------------------------------------------------------------------------
   Total regulatory liabilities                             235.0           -
-----------------------------------------------------------------------------
Other removal costs                                             -       210.0
-----------------------------------------------------------------------------
   Total regulatory liabilities & other removal costs     $ 235.0     $ 210.0
=============================================================================

SFAS 143 & Other Removal Costs
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. The Company adopted this statement on
January 1, 2003. The adoption was not material to the Company's results of
operations.

The Company collects an estimated cost of removal of its utility plant through
depreciation rates established by regulatory proceedings. As of December 31,
2003, and 2002, such removal costs approximated $229 million and $210 million,
respectively. In 2002, the cost of removal has been included in Other removal
costs, which is in noncurrent liabilities. In 2003, the Company re-characterized
other removal costs to Regulatory liabilities upon adoption of SFAS 143.

Refundable or Recoverable Gas Costs, Fuel for Electric Production & Purchased
Power
All metered gas rates contain a gas cost adjustment clause that allows the
Company to charge for changes in the cost of purchased gas. Metered electric
rates contain a fuel adjustment clause that allows for adjustment in charges for
electric energy to reflect changes in the cost of fuel 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.

I. 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. In 2003, the remaining component of
accumulated other comprehensive income relating to a cash flow hedge was
reclassified to a regulatory liability in accordance with regulatory orders. The
effects of hedging arrangements are further discussed in Note 11.

J. 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.

K. Excise and Utility Receipts Taxes
Excise taxes and a portion of utility receipts taxes are included in rates
charged to customers. Accordingly, the Company records these taxes received as a
component of operating revenues, which totaled $37.0 million in 2003, $32.4
million in 2002, and $26.6 million in 2001. Excise and utility receipts taxes
paid are recorded as a component of Taxes other than income taxes.

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

M. Other Significant Policies
Included elsewhere in these notes are significant accounting policies related to
intercompany allocations and income taxes (Note 3) and derivatives (Note 11).

N. 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.

O. Reclassification
Certain prior year amounts have been reclassified in the consolidated financial
statements and accompanying notes to conform to 2003 classifications.

3.  Transactions with Other Vectren Companies

Support Services and Purchases
Vectren and certain subsidiaries of Vectren provided corporate and general and
administrative services to the Company including legal, finance, tax, risk
management, human resources, which includes charges for restricted stock
compensation and for pension and other postretirement benefits not directly
charged to subsidiaries. These costs have been allocated using various
allocators, primarily number of employees, number of customers and/or revenues.
Allocations are based on cost. VUHI received corporate allocations totaling
$43.4 million, $41.4 million, and $49.4 million for the years ended December 31,
2003, 2002, and 2001, 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, 2003, 2002, and
2001, totaled $77.0 million, $62.1 million, and $58.4 million, respectively.

Retirement Plans and Other Postretirement Benefits
Vectren has multiple defined benefit pension plans and postretirement plans that
require accounting as described in SFAS No. 87 "Employers' Accounting for
Pensions" and SFAS No. 106 "Employers' Accounting for Postretirement Benefits
Other Than Pensions," respectively. An allocation of expense is determined by
Vectren's actuaries, comprised of only service cost and interest on that service
cost, by subsidiary based on headcount at each measurement date. These costs are
directly charged to individual subsidiaries. Other components of costs (such as
interest cost and asset returns) are charged to individual subsidiaries through
the corporate allocation process discussed above. Neither plan assets nor the
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, 2003, 2002, and 2001, periodic pension costs
totaling $5.0 million, $5.5 million and $5.1 million, respectively, was directly
charged by Vectren to the Company. For the years ended December 31, 2003, 2002,
and 2001, other periodic postretirement benefit costs totaling $0.9 million,
$1.0 million, and $1.0 million, respectively, was directly charged by Vectren to
the Company. As of December 31, 2003 and 2002, $52.7 million and $51.8 million,
respectively, is included in deferred credits and other liabilities and
represents expense directly charged to the Company that is yet to be funded to
Vectren, and $2.2 million and $3.5 million, respectively, is included in other
assets for amounts funded in advance to Vectren.

The recently enacted Medicare Prescription Drug, Improvement and Modernization
Act of 2003 (the Medicare Act) provides a prescription drug benefit as well as a
federal subsidy to sponsors of certain retiree health care benefit plans. As
allowed by FASB Staff Position No. 106-1 (FSP 106-1), Vectren has elected to
defer reflecting the effects of the Medicare Act on the accumulated benefit
obligation and net periodic postretirement benefit cost in its year end
consolidated financial statements. Vectren's deferral election expires upon the
occurrence of any event that triggers a required remeasurement of plan assets or
obligations, or upon the issuance of specific authoritative guidance on the
accounting for the federal subsidy. Such guidance is pending and when issued
could require the Company to adjust previously reported information. Upon
expiration of Vectren's deferral or the issuance of guidance, Vectren's
implementation of the Medicare Act may impact VUHI's financial statements.

Cash Management 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.

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

                                                      Year Ended December 31,
--------------------------------------------------------------------------------
(In millions)                                  2003          2002          2001
--------------------------------------------------------------------------------
Current:
    Federal                                  $ 15.0        $ 62.5        $ 32.2
    State                                      12.5           7.7           4.0
--------------------------------------------------------------------------------
Total current taxes                            27.5          70.2          36.2
--------------------------------------------------------------------------------
Deferred:
    Federal                                    27.4         (16.2)        (12.0)
    State                                      (1.1)         (4.9)         (0.6)
--------------------------------------------------------------------------------
Total deferred taxes                           26.3         (21.1)        (12.6)
--------------------------------------------------------------------------------
Amortization of investment tax credits         (2.2)         (2.3)         (2.3)
--------------------------------------------------------------------------------
    Total income tax expense                 $ 51.6        $ 46.8        $ 21.3
================================================================================

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

                                                   Year Ended December 31,
-------------------------------------------------------------------------------
                                                   2003       2002       2001
-------------------------------------------------------------------------------
Statutory rate                                     35.0 %     35.0 %     35.0 %
State and local taxes-net of federal benefit        5.4        1.3        3.3
Amortization of investment tax credit              (1.6)      (1.7)      (4.0)
All other-net                                      (1.2)      (2.3)      (2.2)
-------------------------------------------------------------------------------
       Effective tax rate                          37.6 %     32.3 %     32.1 %
===============================================================================

The liability method of accounting is used for income taxes under which deferred
income taxes are recognized to reflect the tax effect of temporary differences
between the book and tax bases of assets and liabilities at currently enacted
income tax rates. Significant components of the net deferred tax liability
follow:

                                                             At December 31,
-------------------------------------------------------------------------------
(In millions)                                            2003            2002
-------------------------------------------------------------------------------
Noncurrent deferred tax liabilities (assets):
  Depreciation & cost recovery timing
      differences                                      $ 208.7         $ 189.8
  Regulatory assets recoverable through
      future rates                                        26.9            37.5
  Regulatory liabilities to be settled
      through future rates                                (8.8)          (21.7)
  Employee benefit obligations                           (22.7)          (30.2)
  Other - net                                             (2.6)           (3.1)
-------------------------------------------------------------------------------
      Net noncurrent deferred tax liability              201.5           172.3
-------------------------------------------------------------------------------
Current deferred tax liabilities:
  Deferred fuel costs-net                                  6.9             7.7
-------------------------------------------------------------------------------
      Net current deferred tax liability                   6.9             7.7
-------------------------------------------------------------------------------
      Net deferred tax liability                       $ 208.4         $ 180.0
===============================================================================

At December 31, 2003, and 2002, investment tax credits totaling $16.4 million
and $18.6 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,
2003. Alternative Minimum Tax credit carryforwards of approximately $5.2 million
were utilized in 2001.

4.  Transactions with Vectren Affiliates

ProLiance Energy, LLC
ProLiance Energy, LLC (ProLiance), a nonregulated energy marketing affiliate of
Vectren and Citizens Gas and Coke Utility (Citizens Gas), provides natural gas
and related services to Indiana Gas, the Ohio operations, Citizens Gas and
others. ProLiance also began providing service to SIGECO in 2002. ProLiance's
primary business is optimizing the gas portfolios of utilities and providing
services to large end use customers.

Transactions with ProLiance
Purchases from ProLiance for resale and for injections into storage for the
years ended December 31, 2003, 2002, and 2001, totaled $770.7 million, $542.5
million, and $610.6 million, respectively. Amounts owed to ProLiance at December
31, 2003, and 2002, for those purchases were $79.9 million and $83.7 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
Vectren has ownership interests in other affiliated companies accounted for
using the equity method of accounting that perform underground construction and
repair, facilities locating, and meter reading services to the Company. For the
years ended December 31, 2003, 2002, and 2001, fees for these services and
construction-related expenditures paid by the Company to Vectren affiliates
totaled $37.2 million, $38.3 million, and $30.4 million, respectively. Amounts
charged by these affiliates are market based. Amounts owed to unconsolidated
affiliates other than ProLiance totaled $0.4 million and $1.9 million at
December 31, 2003, and 2002, respectively, and are included in Accounts payable
to affiliated companies in the Consolidated Balance Sheets.

5.  Borrowing Arrangements

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

                                                           At December 31,
-----------------------------------------------------------------------------
(In millions)                                             2003          2002
-----------------------------------------------------------------------------
VUHI
  Fixed Rate Senior Unsecured Notes
     2011, 6.625%                                       $ 250.0       $ 250.0
     2013, 5.25%                                          100.0             -
     2018, 5.75%                                          100.0             -
     2031, 7.25%                                          100.0         100.0
-----------------------------------------------------------------------------
     Total VUHI                                           550.0         350.0
-----------------------------------------------------------------------------
SIGECO
  First Mortgage Bonds
     2003, 1978 Series B, 6.25%, tax exempt                   -           1.0
     2016, 1986 Series, 8.875%                             13.0          13.0
     2023, Series, 7.60%                                      -          45.0
     2023, Series B, 6.00%, tax exempt                     22.8          22.8
     2025, 1993 Series, 7.625%                                -          20.0
     2029, 1999 Senior Notes, 6.72%                        80.0          80.0
     2015, 1985 Pollution Control Series A,
        adjustable rate presently 4.30%, tax
        exempt, next rate adjustment: 2004                 10.0          10.0
     2025, 1998 Pollution Control Series A,
        adjustable rate presently 4.75%, tax
        exempt, next rate adjustment: 2006                 31.5          31.5
     2024, 2000 Environmental Improvement
        Series A, fixed in April 2003 at 4.65%,
        tax exempt, weighted average for year: 3.69%       22.5          22.5
-----------------------------------------------------------------------------
     Total first mortgage bonds                           179.8         245.8
-----------------------------------------------------------------------------
  Senior Unsecured Bonds to Third Parties:
     2020, 1998 Pollution Control Series B,
        fixed in April 2003 at 4.50%, tax exempt,
        weighted average for year: 4.16%                    4.6           4.6
     2030, 1998 Pollution Control Series B, fixed
        in April 2003 at 5.00%, tax exempt,
        weighted average for year: 4.48%                   22.0          22.0
     2030, 1998 Pollution Control Series C,
        adjustable rate presently 5.00%, tax
        exempt, next rate adjustment: 2006                 22.2          22.2
-----------------------------------------------------------------------------
     Total senior unsecured bonds                          48.8          48.8
-----------------------------------------------------------------------------
     Total SIGECO                                         228.6         294.6
-----------------------------------------------------------------------------

<PAGE>

                                                            At December 31,
-----------------------------------------------------------------------------
(In millions)                                             2003          2002
-----------------------------------------------------------------------------
Indiana Gas
  Senior Unsecured Notes
     2003, Series F, 5.75%                                    -          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
     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
     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          49.9
-----------------------------------------------------------------------------
     Total Indiana Gas                                    214.9         267.3
-----------------------------------------------------------------------------
Total long-term debt outstanding                          993.5         911.9
  Current maturities of long-term debt                    (15.0)        (39.8)
  Debt subject to tender                                  (13.5)        (26.6)
  Unamortized debt premium & discount - net                (4.5)         (4.3)
-----------------------------------------------------------------------------
     Total long-term debt-net                            $960.5        $841.2
=============================================================================

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

The notes have no sinking fund requirements, and interest payments are due
semi-annually. The notes may be called by VUHI, in whole or in part, at any time
for an amount equal to accrued and unpaid interest, plus the greater of 100% of
the principal amount or the sum of the present values of the remaining scheduled
payments of principal and interest, discounted to the redemption date on a
semi-annual basis at the Treasury Rate, as defined in the indenture, plus 20
basis points for the 2013 Notes and 25 basis points for the 2018 Notes.

Shortly before these issues, VUHI entered into several treasury locks with a
total notional amount of $150.0 million. Upon issuance of the debt, the treasury
locks were settled resulting in the receipt of $5.7 million in cash, which was
recorded as a regulatory liability pursuant to existing regulatory orders. The
value received is being amortized as a reduction of interest expense over the
life of the issues.

The net proceeds from the sale of the senior notes and settlement of related
hedging arrangements approximated $203 million.

VUHI 2001 Issuance
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.

Shortly before these issues, the Company entered into several forward starting
interest rate swaps with total notional amount of $200.0 million. Upon issuance
of the debt, the treasury locks were settled resulting in the receipt of $0.9
million in cash, which was recorded as a regulatory liability pursuant to
existing regulatory orders. The value received is being amortized as a reduction
of interest expense over the life of the issues.

The net proceeds from the sale of the senior notes and settlement of the hedging
arrangements totaled $344.0 million.

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

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

Pursuant to regulatory authority, the premiums paid to retire the net carrying
value of these notes totaling $3.6 million were deferred in Regulatory assets.

Other Financing Transactions
Other Company debt totaling $18.5 million in 2003, $6.5 million in 2002, and
$7.6 million in 2001 was retired as scheduled.

At December 31, 2002, the Company had $26.6 million of adjustable rate senior
unsecured bonds which could, at the election of the bondholder, be tendered to
the Company when interest rates are reset. Such bonds were classified as
Long-term debt subject to tender. During 2003, the Company re-marketed $4.6
million of the bonds through 2020 at a 4.5% fixed interest rate and remarketed
$22.0 million of the bonds through 2030 at a 5.0% fixed interest rate. The bonds
are now classified in Long-term debt.

Additionally, during 2003, the Company re-marketed $22.5 million of first
mortgage bonds subject to interest rate exposure on a long term basis. The $22.5
million of mortgage bonds were remarketed through 2024 at a 4.65% fixed interest
rate.

Long-Term Debt Sinking Fund Requirements & Maturities
The annual sinking fund requirement of SIGECO's first mortgage bonds is one
percent of the greatest amount of bonds outstanding under the Mortgage
Indenture. This requirement may be satisfied by certification to the Trustee of
unfunded property additions in the prescribed amount as provided in the Mortgage
Indenture. SIGECO intends to meet the 2004 sinking fund requirement by this
means and, accordingly, the sinking fund requirement for 2004 is excluded from
Current liabilities in the Consolidated Balance Sheets. At December 31, 2003,
$502.0 million of SIGECO's utility plant remained unfunded under SIGECO's
Mortgage Indenture.

Consolidated maturities and sinking fund requirements on long-term debt during
the five years following 2003 (in millions) are $15.0 in 2004, zero in 2005,
zero in 2006, $6.5 in 2007, and zero in 2008.

Long-Term Debt Put & Call Provisions
Certain long-term debt issues contain put and call provisions that can be
exercised on various dates before maturity. The put or call provisions are not
triggered by specific events, but are based upon dates stated in the note
agreements, such as when notes are re-marketed. Debt which may be put to the
Company during the years following 2003 (in millions) is $13.5 in 2004, $10.0 in
2005, $53.7 in 2006, $20.0 in 2007, zero in 2008, and $120.0 thereafter. Debt
that may be put to the Company within one year is classified as Long-term debt
subject to tender in current liabilities.

Short-Term Borrowings
At December 31, 2003, the Company has $351 million of short-term borrowing
capacity, of which approximately $166 million is available. See the table below
for interest rates and outstanding balances.

                                                     Year Ended December 31,
-------------------------------------------------------------------------------
(In millions)                                   2003         2002         2001
-------------------------------------------------------------------------------
Weighted average commercial paper and
   bank loans outstanding during the year     $ 219.5      $ 155.7      $ 356.1

Weighted average interest rates during
   the year
      Commercial paper                          1.36%        2.61%        4.39%
      Bank loans                                1.86%        2.02%        5.77%

                                                 At December 31,
-------------------------------------------------------------------
(In millions)                                   2003         2002
-------------------------------------------------------------------
Commercial paper                              $ 184.4      $ 239.1
Bank loans                                        0.8            -
-------------------------------------------------------------------
      Total short-term borrowings             $ 185.2      $ 239.1
===================================================================

Prior to the asset transfer discussed in Note 2, the operations contributed to
VUHI relied on the borrowing arrangements of Vectren Capital Corp, a wholly
owned subsidiary of Vectren, for its working capital needs. Borrowings
outstanding from Vectren Capital Corp at December 31, 2002, were $86.9 million.
Interest expense incurred on these borrowing arrangements for the years ended
December 31, 2002, and 2001, totaled $3.0 million and $0.6 million,
respectively.

Covenants
Both long-term and short-term borrowing arrangements contain customary default
provisions; restrictions on liens, sale leaseback transactions, mergers or
consolidations, and sales of assets; and restrictions on leverage and interest
coverage, among other restrictions. As of December 31, 2003, the Company was in
compliance with all financial covenants.

6.  Cumulative Preferred Stock of 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 were 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, 2003,
and 2002, there were 2,277 shares and 3,437 shares outstanding, respectively.

7.  Additional Capital Contributions

2003 Transactions
During 2003, the Company received a $204.1 million equity contribution from
Vectren. Vectren funded $163.2 million of the contribution with proceeds from an
offering of its common stock, $35.0 million was funded by Vectren's nonregulated
operations, and $5.9 million was funded by new share issues from Vectren's
dividend reinvestment plan.

2001 Transactions
During 2001, the Company received a $164.4 million equity contribution from
Vectren. Vectren funded $129.4 million of the contribution with proceeds from an
offering of its common stock and $35.0 million was funded by Vectren's
nonregulated operations.

8.  Commitments & Contingencies

Commitments
Firm purchase commitments for commodities total (in millions) $105.8 in 2004 and
$29.3 in 2005. Firm purchase commitment for utility and non-utility plant total
$117.8 million.

United States Securities and Exchange Commission (SEC) Informal Inquiry
As more fully described in the 2002 consolidated financial statements, the
Company restated its annual consolidated financial statements for 2000 and 2001,
and its 2002 quarterly results. The Company received an informal inquiry from
the SEC with respect to this restatement. In response, the Company met with the
SEC staff and provided information in response to their requests, with the most
recent response provided on July 26, 2003.

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 9 regarding
environmental matters.

9.  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 .141 lbs./MMBTU
by May 31, 2004, (the compliance date). This is a 65% reduction in emission
levels.

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 currently be the most effective method of
reducing NOx emissions where high removal efficiencies are required.

The IURC has issued orders that approve:
o    the Company's project to achieve  environmental  compliance by investing in
     clean coal technology;
o    a total  capital  cost  investment  for  this  project  up to $244  million
     (excluding AFUDC), subject to periodic review of the actual costs incurred;
o    a mechanism whereby, prior to an electric base rate case, the Company may
     recover through a rider that is updated every six months, an eight percent
     return on its weighted capital costs for the project; and
o    ongoing recovery of operating costs, including depreciation and purchased
     emission allowances through a rider mechanism, related to the clean coal
     technology once the facility is placed into service.

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 is consistent with amounts approved in the IURC's
orders and is expected to be expended during the 2001-2006 period. Through
December 31, 2003, $145.2 million has been expended. After the equipment is
installed and operational, related annual operating expenses, including
depreciation expense, are estimated to be between $24 million and $27 million. A
portion of those expenses began in October 2003 when the Culley SCR became
operational. The 8 percent return on capital investment approximates the return
authorized in the Company's last electric rate case in 1995 and includes a
return on equity.

The Company expects to achieve timely compliance as a result of the project.
Construction of the first SCR at Culley was placed into service in October 2003,
and construction of the Warrick 4 and Brown SCR's is proceeding on schedule.
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. SIGECO's suit was filed in the U.S. District Court for the
Southern District of Indiana. The USEPA alleged 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 alleged that the modifications to
the Culley Generating Station required SIGECO to begin complying with federal
new source performance standards at its Culley Unit 3. The USEPA also issued an
administrative notice of violation to SIGECO making the same allegations, but
alleging that violations began in 1977.

On June 6, 2003, SIGECO, the Department of Justice (DOJ), and the USEPA
announced an agreement that would resolve the lawsuit. The agreement was
embodied in a consent decree filed in U.S. District Court for the Southern
District of Indiana. The mandatory public comment period has expired, and no
comments were received. The Court entered the consent decree on August 13, 2003.

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

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

The Company anticipates that the settlement would result in total capital
expenditures through 2007 in a range between $16 million and $28 million. Other
than the $600,000 civil penalty, which was accrued in the second quarter of
2003, the implementation of the settlement, including these capital expenditures
and related operating expenses, are expected to be recovered through rates.

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
with the most recent correspondence provided on March 26, 2001.

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 (VRP) and is currently conducting some level of
remedial activities, including groundwater monitoring at certain sites, where
deemed appropriate, and will continue remedial activities at the sites as
appropriate and necessary.

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

The estimated accrued costs are limited to Indiana Gas' proportionate share of
the remediation efforts. Indiana Gas has arrangements in place for 19 of the 26
sites with other potentially responsible parties (PRP), which serve to limit
Indiana Gas' share of response costs at these 19 sites to between 20% and 50%.

With respect to insurance coverage, Indiana Gas has received and recorded
settlements from all known insurance carriers in an aggregate amount
approximating $20.4 million.

Environmental matters related to manufactured gas plants have had no material
impact on earnings since costs recorded to date approximate PRP and insurance
settlement recoveries. While Indiana Gas has recorded all costs which it
presently expects to incur in connection with activities at these sites, it is
possible that future events may require some level of additional remedial
activities which are not presently foreseen.

In October 2002, the Company received a formal information request letter from
the IDEM regarding five manufactured gas plants owned and/or operated by SIGECO
and not currently enrolled in the IDEM's VRP. In response, SIGECO submitted to
the IDEM the results of preliminary site investigations conducted in the
mid-1990's. These site investigations confirmed that based upon the conditions
known at the time, the sites posed no risk to human health or the environment.
Follow up reviews have been initiated by the Company to confirm that the sites
continue to pose no such risk.

On October 6, 2003, SIGECO filed applications to enter four of the manufactured
gas plant sites in IDEM's VRP. The remaining site is currently being addressed
in the VRP by another Indiana utility. SIGECO is adding its four sites into the
renewal of the global Voluntary Remediation Agreement that Indiana Gas has in
place with IDEM for its manufactured gas plant sites. The total costs, net of
other PRP involvement and insurance recoveries, that may be incurred in
connection with further investigation, and if necessary, remedial work at the
four SIGECO sites cannot be determined at this time.

10.  Rate & Regulatory Matters

Ohio Uncollectible Accounts Expense Tracker
On December 17, 2003, the PUCO approved a request by VEDO and several other
regulated Ohio gas utilities to establish a mechanism to recover uncollectible
accounts expense outside of base rates. The tariff mechanism establishes an
automatic adjustment procedure to track and recover these costs instead of
providing the recovery of the historic amount in base rates. Through this order,
VEDO received authority to defer its 2003 uncollectible accounts expense to the
extent it differs from the level included in base rates. The Company estimated
the difference to approximate $4 million in excess of that included in base
rates, and accordingly reversed previously established reserves and recorded a
regulatory asset for the difference, totaling $3.0 million.

Gas Cost Recovery (GCR) Audit Proceedings
There is an Ohio requirement that Ohio gas utilities undergo a biannual audit of
their gas acquisition practices in connection with the gas cost recovery (GCR)
mechanism. In the case of VEDO, the two-year period began in November 2000,
coincident with the Company's acquisition of the Ohio operations and
commencement of service in Ohio. The audit provides the initial review of the
portfolio administration arrangement between VEDO and ProLiance. The external
auditor retained by the PUCO staff recently submitted an audit report wherein it
recommended a disallowance of approximately $7 million of previously recovered
gas costs. The Company believes a large portion of the third party auditor
recommendations is without merit. There are two elements of the recommendations
relating to the treatment of a pipeline refund and a penalty which VEDO does not
oppose. A hearing has been held, and based on its audit report, the PUCO staff
has recommended a $6.1 million disallowance. The Ohio Consumer Counselor has
submitted testimony to support an $11.5 million disallowance. For this PUCO
audit period, any disallowance relating to the Company's ProLiance arrangement
will be shared by the Company's joint venture partner. Based on a review of the
matters, the Company has reserved $1.1 million for its estimated share of a
potential disallowance. The Company believes that these proceedings will not
likely have a material effect on the Company's operating results or financial
condition. However, the Company can provide no assurance as to the ultimate
outcome of this proceeding.

Recovery of Purchased Power
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 2004,
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.

11.  Derivatives & Other Financial Instruments

Accounting Policy for Derivatives
The Company executes derivative contracts in the normal course of operations
while buying and selling commodities to be used in operations, optimizing its
generation assets, and managing risk.

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

Asset Optimization
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. Substantially all of these
contracts are integrated with portfolio requirements around power supply and
delivery and are primarily short-term purchase and sale contracts that expose
the Company to limited market risk. Contracts with counter-parties subject to
master netting arrangements are presented net in the Consolidated Balance
Sheets. Asset optimization contracts are recorded at market value. 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 Electric utility revenues.

Asset optimization contracts recorded at market value at December 31, 2003,
totaled $2.4 million of Prepayments & other current assets and $2.8 million of
Accrued liabilities, compared to $3.5 million of Prepayments & other current
assets and $4.2 million of Accrued liabilities at December 31, 2002.

In July 2003, the EITF released EITF 03-11, "Reporting Realized Gains and Losses
on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not
"Held for Trading Purposes" as Defined in Issue No. 02-3" (EITF 03-11). EITF
03-11 states that determining whether realized gains and losses on physically
settled derivative contracts should be reported in the Statement of Income on a
gross or net basis is a matter of judgment that depends on the relevant facts
and circumstances. The EITF contains a presumption that net settled derivative
contracts should be reported net in the Statement of Income. The Company adopted
EITF 03-11 as required on October 1, 2003.

After considering the facts and circumstances relevant to the asset optimization
portfolio, the Company believes presentation of these optimization activities on
a net basis is appropriate and has reclassified purchase contracts and
mark-to-market activity related to optimization activities from Purchased
electric energy to Electric utility revenues. Prior year financial information
has also been reclassified to conform to this net presentation.

Following is information regarding asset optimization activities included in
Electric utility revenues and Fuel for electric generation in the Statements of
Income:

                                                    Year Ended December 31,
-------------------------------------------------------------------------------
(In millions)                                2003          2002          2001
-------------------------------------------------------------------------------
Activity related to:
  Sales contracts                          $ 152.8       $ 302.8       $ 101.4
  Purchase contracts                        (127.0)       (275.9)        (74.3)
  Mark-to-market gains (losses)                0.7          (3.6)          1.5
-------------------------------------------------------------------------------
  Net asset optimization revenue              26.5          23.3          28.6
-------------------------------------------------------------------------------
  Fuel for electric generation                (8.2)        (10.6)         (9.5)
-------------------------------------------------------------------------------
  Asset optimization margin                 $ 18.3       $  12.7       $  19.1
===============================================================================

Natural Gas Procurement Activity
The Company's regulated operations have limited exposure to commodity price risk
for purchases and sales of natural gas and electricity for retail customers due
to current Indiana and Ohio regulations which, subject to compliance with those
regulations, allow for recovery of such purchases through natural gas and fuel
cost adjustment mechanisms. Although Vectren's regulated operations are exposed
to limited commodity price risk, volatile natural gas prices can result in
higher working capital requirements, increased expenses including unrecoverable
interest costs, uncollectible accounts expense, and unaccounted for gas, and
some level of price- sensitive reduction in volumes sold. The Company mitigates
these risks by executing derivative contracts that manage the price of
forecasted natural gas purchases. These contracts are subject to regulation
which allows for reasonable and prudent hedging costs to be recovered through
rates. When regulation is involved, SFAS 71 controls when the offset to
mark-to-market accounting is recognized in earnings. The market value of natural
gas procurement derivative contracts at December 31, 2003, was not significant.

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

At December 31, 2003, approximately $6.2 million remains in Regulatory
liabilities related to future interest payments from the 2003 and 2001 interest
rate hedging activities. Of the existing regulatory liability, $0.6 million will
be reclassified to earnings in 2004 and $0.3 million was reclassified to
earnings during 2003.

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 a change in the derivative's market value be
recognized currently in earnings unless specific hedge 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 or other comprehensive income, 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 asset optimization 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:

                                                   At December 31,
-------------------------------------------------------------------------------
                                           2003                    2002
                                    --------------------   --------------------
                                    Carrying   Est. Fair   Carrying   Est. Fair
(In millions)                        Amount      Value      Amount      Value
---------------------------------   --------------------   --------------------
   Long-term debt                   $ 993.5    $ 1,056.8   $ 911.9     $ 968.9
   Short-term borrowings              185.2        185.2     239.1       239.1
   Short-term borrowings from
       other Vectren companies            -            -      86.9        86.9

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.

12.  Additional Operational & Balance Sheet Information

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

                                               Year Ended December 31,
----------------------------------------------------------------------------
(In millions)                          2003            2002            2001
----------------------------------------------------------------------------
AFUDC & capitalized interest          $ 5.9           $ 5.3           $ 4.8
Interest income                         0.6             0.8             0.2
Gains on sale of investments
    & assets                              -             1.8             2.9
Other income                            3.3             1.5             5.1
Other expense                          (5.0)           (2.3)           (7.4)
----------------------------------------------------------------------------
       Total other - net              $ 4.8           $ 7.1           $ 5.6
============================================================================


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

                                                        At December 31,
----------------------------------------------------------------------------
(In millions)                                         2003            2002
----------------------------------------------------------------------------
Prepaid gas delivery service                         $ 97.6          $ 70.3
Prepaid taxes                                          26.8             4.8
Other prepayments & current assets                      6.9             6.2
----------------------------------------------------------------------------
  Total prepayments & other current assets           $131.3          $ 81.3
============================================================================

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

                                                       At December 31,
----------------------------------------------------------------------------
(In millions)                                         2003             2002
----------------------------------------------------------------------------
Accrued taxes                                        $ 29.4          $ 27.3
Refunds to customers & customer deposits               24.5            21.0
Accrued interest                                       15.7            13.4
Deferred income taxes                                   6.9             7.7
Accrued salaries & other                               17.4            13.8
----------------------------------------------------------------------------
       Total accrued liabilities                     $ 93.9          $ 83.2
============================================================================

13.  Subsidiary Guarantor and Consolidating Information

The Company's three operating utility companies, SIGECO, Indiana Gas, and VEDO
are guarantors of VUHI's $346 million in short-term credit facilities, of which
$184.4 million is outstanding at December 31, 2003, and VUHI's $550.0 million
unsecured senior notes outstanding at December 31, 2003. The guarantees are full
and unconditional and joint and several, and VUHI has no subsidiaries other than
the subsidiary guarantors. However, VUHI does have operations other than those
of the subsidiary guarantors. Pursuant to Article 3-10 of Regulation S-X,
disclosure of the results of operations and balance sheets of the subsidiary
guarantors separate from the parent company's operations is required. Following
are consolidating financial statements including information on the combined
operations of the subsidiary guarantors separate from the other operations of
the parent company.

<PAGE>


Consolidating Statement of Income for the year ended December 31, 2003 (in
millions):
<TABLE>
<CAPTION>
                                       Subsidiary   Parent
                                       Guarantors   Company   Eliminations  Consolidated
---------------------------------      ----------   -------   ------------  ------------
<S>                                     <C>          <C>        <C>           <C>
OPERATING REVENUES
   Gas utility                          $ 1,112.3    $    -     $     -       $ 1,112.3
   Electric utility                         335.7         -           -           335.7
   Other                                        -      26.5       (25.7)            0.8
----------------------------------------------------------------------------------------
      Total operating revenues            1,448.0      26.5       (25.7)        1,448.8
----------------------------------------------------------------------------------------
OPERATING EXPENSES
   Cost of gas sold                         762.5         -           -           762.5
   Fuel for electric generation              86.5         -           -            86.5
   Purchased electric energy                 16.2         -           -            16.2
   Other operating                          235.2       0.6       (25.7)          210.1
   Depreciation & amortization              103.7      14.2           -           117.9
   Taxes other than income taxes             55.9       0.7           -            56.6
----------------------------------------------------------------------------------------
       Total operating expenses           1,260.0      15.5       (25.7)        1,249.8
----------------------------------------------------------------------------------------
OPERATING INCOME                            188.0      11.0           -           199.0
OTHER INCOME (EXPENSE)
   Equity in earnings of consolidated
        companies                               -      81.7       (81.7)              -
   Equity in losses of unconsolidated
        affiliates                              -      (0.5)          -            (0.5)
   Other - net                                5.0      28.0       (28.2)            4.8
----------------------------------------------------------------------------------------
        Total other income (expense)          5.0     109.2      (109.9)            4.3
----------------------------------------------------------------------------------------
Interest expense                             62.0      32.3       (28.2)           66.1
----------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES                  131.0      87.9       (81.7)          137.2
----------------------------------------------------------------------------------------
Income taxes                                 49.3       2.3           -            51.6
----------------------------------------------------------------------------------------
NET INCOME                              $    81.7    $ 85.6     $ (81.7)      $    85.6
========================================================================================
</TABLE>

Consolidating Statement of Income for the year ended December 31, 2002 (in
millions):
<TABLE>
<CAPTION>
                                       Subsidiary   Parent
                                       Guarantors   Company   Eliminations   Consolidated
--------------------------------       ----------   -------   ------------   ------------
<S>                                     <C>         <C>          <C>           <C>
OPERATING REVENUES
   Gas utility                          $  908.0    $    -       $    -        $  908.0
   Electric utility                        328.6         -            -           328.6
   Other                                       -      22.3        (22.0)            0.3
-----------------------------------------------------------------------------------------
       Total operating revenues          1,236.6      22.3        (22.0)        1,236.9
-----------------------------------------------------------------------------------------
OPERATING EXPENSES
   Cost of gas sold                        570.8         -             -          570.8
   Fuel for electric generation             81.6         -             -           81.6
   Purchased electric energy                16.8         -             -           16.8
   Other operating                         220.2       0.4         (22.0)         198.6
   Depreciation & amortization              96.8      13.9             -          110.7
   Taxes other than income taxes            50.8      (0.1)            -           50.7
-----------------------------------------------------------------------------------------
       Total operating expenses          1,037.0      14.2         (22.0)       1,029.2
-----------------------------------------------------------------------------------------
OPERATING INCOME                           199.6       8.1             -          207.7
OTHER INCOME (EXPENSE)
   Equity in earnings of consolidated
       companies                               -      95.3         (95.3)             -
   Equity in losses of unconsolidated
       affiliates                              -      (1.8)            -           (1.8)
   Other - net                               5.0      27.6         (25.5)           7.1
-----------------------------------------------------------------------------------------
       Total other income (expense)          5.0     121.1        (120.8)           5.3
-----------------------------------------------------------------------------------------
Interest expense                            63.6      31.0         (25.5)          69.1
-----------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES                 141.0      98.2         (95.3)         143.9
-----------------------------------------------------------------------------------------
Income taxes                                45.7       1.1             -           46.8
-----------------------------------------------------------------------------------------
NET INCOME                              $   95.3      97.1       $ (95.3)      $   97.1
=========================================================================================
</TABLE>


<PAGE>


Consolidating Statement of Income for the year ended December 31, 2001 (in
millions):
<TABLE>
<CAPTION>
                                               Subsidiary  Parent
                                               Guarantors  Company  Eliminations  Consolidated
-----------------------------------------      ----------  -------  ------------  ------------
<S>                                             <C>         <C>        <C>          <C>
OPERATING REVENUES
   Gas utility                                  $ 1,019.6   $   -      $    -       $ 1,019.6
   Electric utility                                 308.5       -           -           308.5
      Other                                             -    29.1       (28.9)            0.2
----------------------------------------------------------------------------------------------
        Total operating revenues                  1,328.1    29.1       (28.9)        1,328.3
----------------------------------------------------------------------------------------------
OPERATING EXPENSES
   Cost of gas sold                                 708.9       -           -           708.9
   Fuel for electric generation                      74.4       -           -            74.4
   Purchased electric energy                         14.2       -           -            14.2
   Other operating                                  241.9    (0.9)      (28.9)          212.1
   Merger & integration costs                         2.8       -           -             2.8
   Restructuring costs                               15.0       -           -            15.0
   Depreciation & amortization                       97.2    20.7           -           117.9
   Taxes other than income taxes                     51.2     0.4           -            51.6
----------------------------------------------------------------------------------------------
           Total operating expenses               1,205.6    20.2       (28.9)        1,196.9
----------------------------------------------------------------------------------------------
OPERATING INCOME                                    122.5     8.9           -           131.4
OTHER INCOME (EXPENSE)
   Equity in earnings of consolidated
      companies                                         -    40.1       (40.1)              -
   Equity in losses of unconsolidated
      affiliates                                        -    (0.5)          -            (0.5)
   Other - net                                        4.9    23.0       (22.3)            5.6
----------------------------------------------------------------------------------------------
        Total other income (expense)                  4.9    62.6       (62.4)            5.1
----------------------------------------------------------------------------------------------
Interest expense                                     67.5    25.5       (22.3)           70.7
----------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES                           59.9    46.0       (40.1)           65.8
----------------------------------------------------------------------------------------------
Income taxes                                         19.0     2.3           -            21.3
Preferred dividend requirements of subsidiary         1.9       -        (1.1)            0.8
----------------------------------------------------------------------------------------------
INCOME BEFORE CUMULATIVE EFFECT OF CHANGE
      IN ACCOUNTING PRINCIPLE                        39.0    43.7       (39.0)           43.7
----------------------------------------------------------------------------------------------
Cumulative effect of change in accounting
   principle - net of tax                             1.1       -           -             1.1
----------------------------------------------------------------------------------------------
NET INCOME                                      $    40.1   $43.7      $(39.0)      $    44.8
==============================================================================================
</TABLE>


<PAGE>

Consolidating Statement of Cash Flows for the year ended December 31, 2003 (in
millions):
<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------
                                                Subsidiary  Parent
                                                Guarantors  Company  Eliminations  Consolidated
-----------------------------------------------------------------------------------------------
<S>                                               <C>       <C>         <C>           <C>
NET CASH FLOWS FROM OPERATING ACTIVITIES          $ 129.4   $  39.8     $     -       $ 169.2
-----------------------------------------------------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES
  Proceeds  from:
     Additional capital contribution                150.0     204.1      (150.0)        204.1
     Long-term debt - net of issuance cost
          & hedging proceeds                       99.0     202.9       (99.0)        202.9
  Requirements for:
     Retirement of long-term debt,
          including premiums paid                  (121.9)        -           -        (121.9)
     Dividends to parent                            (77.9)    (78.0)       77.9         (78.0)
     Redemption of preferred stock of
          subsidiary                                 (0.1)        -           -          (0.1)
  Net change in short-term borrowings,
          including from other Vectren companies     30.9    (150.1)      (21.6)       (140.8)
  Other activity                                     (1.7)        -           -          (1.7)
-----------------------------------------------------------------------------------------------
     Net cash flows from financing activities        78.3     178.9      (192.7)         64.5
-----------------------------------------------------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES
  Proceeds from:
     Consolidated subsidiary distributions              -      77.9       (77.9)            -
  Requirements for:
     Capital expenditures, excluding
         AFUDC equity                              (219.0)    (16.0)          -        (235.0)
     Consolidated subsidiary investments                -    (150.0)      150.0             -
     Unconsolidated affiliate and other
         investments                                    -      (1.1)          -          (1.1)
  Net change in notes receivable from other
         Vectren companies                            8.5    (129.1)      120.6             -
-----------------------------------------------------------------------------------------------
     Net cash flows from investing activities      (210.5)   (218.3)      192.7        (236.1)
-----------------------------------------------------------------------------------------------
Net (decrease) increase in cash & cash
        equivalents                                  (2.8)      0.4           -          (2.4)
Cash & cash equivalents at beginning
        of period                                    10.2       0.3           -          10.5
-----------------------------------------------------------------------------------------------
Cash & cash equivalents at end of period        $     7.4   $   0.7     $     -       $   8.1
===============================================================================================
</TABLE>


Consolidating Statement of Cash Flows for the year ended December 31, 2002 (in
millions):
<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------
                                                Subsidiary  Parent
                                                Guarantors  Company  Eliminations  Consolidated
-----------------------------------------------------------------------------------------------
<S>                                               <C>        <C>        <C>           <C>
NET CASH FLOWS FROM OPERATING ACTIVITIES          $ 269.4    $  8.2     $    -        $ 277.6
-----------------------------------------------------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES
  Proceeds  from:
     Additional capital contribution                 25.0         -      (25.0)             -
     Long-term debt - net of issuance cost
         & hedging proceeds                        37.1         -      (37.1)             -
  Requirements for:
     Retirement of long-term debt,
       including premiums paid                       (6.5)        -          -           (6.5)
     Dividends to parent                            (74.7)    (69.7)      74.7          (69.7)
     Redemption of preferred stock of
       subsidiary                                    (0.2)        -          -           (0.2)
  Net change in short-term borrowings,
       including from other Vectren companies       (88.4)     32.2       79.0           22.8
-----------------------------------------------------------------------------------------------
     Net cash flows from financing activities      (107.7)    (37.5)      91.6          (53.6)
-----------------------------------------------------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES
  Proceeds from:
     Consolidated subsidiary distributions              -      74.7      (74.7)             -
     Other investing activities                       1.5       8.9          -           10.4
  Requirements for:
     Capital expenditures, excluding
        AFUDC equity                               (147.6)    (69.7)         -         (217.3)
     Consolidated subsidiary investments                -     (25.0)      25.0              -
     Unconsolidated affiliate and other
        investments                                  (3.9)     (7.9)         -          (11.8)
  Net change in notes receivable from other
        Vectren companies                            (8.5)     50.4      (41.9)             -
-----------------------------------------------------------------------------------------------
     Net cash flows from investing activities      (158.5)     31.4      (91.6)        (218.7)
-----------------------------------------------------------------------------------------------
Net increase in cash & cash equivalents               3.2       2.1          -            5.3
Cash & cash equivalents at beginning of period        7.0      (1.8)         -            5.2
-----------------------------------------------------------------------------------------------
Cash & cash equivalents at end of period          $  10.2    $  0.3     $    -        $  10.5
===============================================================================================
</TABLE>

Consolidating Statement of Cash Flows for the year ended December 31, 2001 (in
millions):
<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------
                                               Subsidiary  Parent
                                               Guarantors  Company  Eliminations  Consolidated
----------------------------------------------------------------------------------------------
<S>                                              <C>       <C>         <C>           <C>
NET CASH FLOWS FROM OPERATING ACTIVITIES         $ 141.0   $ 44.3      $     -       $ 185.3
----------------------------------------------------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES
  Proceeds  from:
     Additional capital contribution               214.7    164.4       (214.7)        164.4
     Long-term debt - net of issuance cost
        & hedging proceeds                       307.0    344.0       (307.0)        344.0
  Requirements for:
     Retirement of long-term debt,
         including premiums paid                    (7.3)       -            -          (7.3)
     Retirement of short-term notes
          payable                                      -   (150.0)           -        (150.0)
     Dividends to parent                           (62.5)   (91.6)        62.5         (91.6)
     Redemption of preferred stock of
          subsidiary                               (17.7)       -            -         (17.7)
     Dividends on preferred stock of
          subsidiary                                (0.8)       -            -          (0.8)
  Net change in short-term borrowings,
          including from other Vectren companies  (414.3)   (30.9)       238.1        (207.1)
----------------------------------------------------------------------------------------------
     Net cash flows from financing activities       19.1    235.9       (221.1)         33.9
----------------------------------------------------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES
  Proceeds from:
     Consolidated subsidiary distributions             -     62.5        (62.5)            -
     Other investing activities                      1.5        -            -           1.5
  Requirements for:
     Capital expenditures, excluding
         AFUDC equity                             (154.4)   (48.4)           -        (202.8)
     Consolidated subsidiary investments               -   (214.7)       214.7             -
     Unconsolidated affiliate and other
         investments                                (2.2)   (11.8)           -         (14.0)
  Net change in notes receivable from other
         Vectren companies                             -    (68.9)        68.9             -
----------------------------------------------------------------------------------------------
     Net cash flows from investing activities     (155.1)  (281.3)       221.1        (215.3)
----------------------------------------------------------------------------------------------
Net increase (decrease) in cash & cash
     equivalents                                     5.0     (1.1)           -           3.9
Cash & cash equivalents at beginning of
     period                                          2.0     (0.7)           -           1.3
----------------------------------------------------------------------------------------------
Cash & cash equivalents at end of period         $   7.0   $ (1.8)     $     -       $   5.2
==============================================================================================
</TABLE>


Consolidating Balance Sheet as of December 31, 2003 (in millions):
<TABLE>
<CAPTION>

------------------------------------------------------------------------------------------
                                          Subsidiary  Parent
             ASSETS                       Guarantors  Company   Eliminations  Consolidated
             ------                       ----------  -------   ------------  ------------
<S>                                        <C>        <C>        <C>            <C>
Current Assets
   Cash & cash equivalents                 $    7.4   $    0.7   $       -      $    8.1
   Accounts receivable - less reserves        113.6        0.4           -         114.0
   Receivables due from other Vectren
       companies                                0.2       10.5        (9.0)          1.7
   Accrued unbilled revenues                  128.7          -           -         128.7
   Inventories                                 55.1          -           -          55.1
   Recoverable fuel & natural gas costs        20.3          -           -          20.3
   Prepayments & other current assets         138.2        0.9        (7.8)        131.3
------------------------------------------------------------------------------------------
       Total current assets                   463.5       12.5       (16.8)        459.2
------------------------------------------------------------------------------------------
Utility Plant
  Original cost                             3,250.7          -           -       3,250.7
  Less:  accumulated depreciation &
     amortization                           1,247.0          -           -       1,247.0
------------------------------------------------------------------------------------------
       Net utility plant                    2,003.7          -           -       2,003.7
------------------------------------------------------------------------------------------
Investments in consolidated subsidiaries          -      956.2      (956.2)            -
Notes receivable from consolidated
    subsidiaries                                  -      623.4      (623.4)            -
Investments in unconsolidated affiliates        0.2        1.6           -           1.8
Other investments                              14.3        6.3           -          20.6
Non-utility property - net                      5.6      135.7           -         141.3
Goodwill - net                                205.0          -           -         205.0
Regulatory assets                              83.4        6.2           -          89.6
Other assets                                    3.9          -           -           3.9
------------------------------------------------------------------------------------------
TOTAL ASSETS                               $2,779.6   $1,741.9   $(1,596.4)     $2,925.1
==========================================================================================
</TABLE>


<PAGE>


Consolidating Balance Sheet as of December 31, 2003 (in millions), continued:
<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------
                                             Subsidiary  Parent
    LIABILITIES & SHAREHOLDER'S EQUITY       Guarantors  Company  Eliminations  Consolidated
    ----------------------------------       ----------  -------  ------------  ------------
<S>                                          <C>         <C>         <C>           <C>
Current Liabilities
   Accounts payable                          $    57.5   $    5.5    $       -     $   63.0
   Accounts payable to affiliated companies       80.2        0.1            -         80.3
   Payables to other Vectren companies            22.3          -         (9.0)        13.3
   Accrued liabilities                            95.7        8.8        (10.6)        93.9
   Short-term borrowings                           0.8      184.4            -        185.2
   Short-term borrowings from
       other Vectren companies                   177.6          -       (177.6)           -
   Current maturities of long-term debt           15.0          -            -         15.0
   Long-term debt subject to tender               13.5          -            -         13.5
--------------------------------------------------------------------------------------------
       Total current liabilities                 462.6      198.8       (197.2)       464.2
--------------------------------------------------------------------------------------------
Long-Term Debt
   Long-term debt - net of current maturities
       & debt subject to tender                  412.9      547.6            -        960.5
   Long-term debt due to VUHI                    443.0          -       (443.0)           -
--------------------------------------------------------------------------------------------
       Total long-term debt - net                855.9      547.6       (443.0)       960.5
--------------------------------------------------------------------------------------------
Deferred Income Taxes & Other Liabilities
   Deferred income taxes                         194.8        6.7            -        201.5
   Regulatory liabilities & other removal
           costs                                 228.8        6.2            -        235.0
   Deferred credits & other liabilities           81.1        2.8            -         83.9
--------------------------------------------------------------------------------------------
       Total deferred credits & other
            liabilities                          504.7       15.7            -        520.4
--------------------------------------------------------------------------------------------
Cumulative, Redeemable Preferred Stock
      of a Subsidiary                              0.2          -            -          0.2
Common Shareholder's Equity
   Common stock (no par value)                   611.3      589.8       (611.3)       589.8
   Retained earnings                             344.9      390.0       (344.9)       390.0
--------------------------------------------------------------------------------------------
       Total common shareholder's equity         956.2      979.8       (956.2)       979.8
--------------------------------------------------------------------------------------------
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY     $ 2,779.6   $1,741.9    $(1,596.4)    $2,925.1
============================================================================================
</TABLE>

Consolidating Balance Sheet as of December 31, 2002 (in millions):
<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------
                                         Subsidiary  Parent
            ASSETS                       Guarantors  Company  Eliminations  Consolidated
            ------                       ----------  -------  ------------  ------------
<S>                                       <C>        <C>         <C>            <C>
Current Assets
   Cash & cash equivalents                $   10.2   $    0.3    $       -      $  10.5
   Accounts receivable - less reserves       130.8        1.1            -        131.9
   Receivables due from other Vectren
      companies                               39.3       19.7         (2.7)        56.3
   Accrued unbilled revenues                 112.7          -            -        112.7
   Inventories                                56.0          -            -         56.0
   Recoverable fuel & natural gas costs       19.3          -            -         19.3
   Prepayments & other current assets         81.0        0.3            -         81.3
----------------------------------------------------------------------------------------
       Total current assets                  449.3       21.4         (2.7)       468.0
----------------------------------------------------------------------------------------
Utility Plant
  Original cost                            3,042.2          -            -      3,042.2
  Less:  accumulated depreciation &
     amortization                          1,179.0          -            -      1,179.0
----------------------------------------------------------------------------------------
       Net utility plant                   1,863.2          -            -      1,863.2
----------------------------------------------------------------------------------------
Investments in consolidated
     subsidiaries                                -      802.4       (802.4)           -
Notes receivable from consolidated
     subsidiaries                              8.5      493.9       (502.4)           -
Investments in unconsolidated
     affiliates                                0.1        2.3            -          2.4
Other investments                             13.1        8.8            -         21.9
Non-utility property - net                     5.4      133.8            -        139.2
Goodwill - net                               205.0          -            -        205.0
Regulatory assets                             70.9        4.9            -         75.8
Other assets                                   4.5        0.4            -          4.9
----------------------------------------------------------------------------------------
TOTAL ASSETS                              $2,620.0   $1,467.9    $(1,307.5)    $2,780.4
========================================================================================
</TABLE>


Consolidating Balance Sheet as of December 31, 2002 (in millions), continued:
<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------
                                             Subsidiary   Parent
   LIABILITIES & SHAREHOLDER'S EQUITY        Guarantors   Company   Eliminations  Consolidated
   ----------------------------------        ----------   -------   ------------  ------------
<S>                                           <C>         <C>         <C>           <C>
Current Liabilities
   Accounts payable                           $   71.3    $    3.5    $       -     $   74.8
   Accounts payable to affiliated
        companies                                 85.2         0.4            -         85.6
   Payables to other Vectren companies            61.3        11.2         (2.7)        69.8
   Accrued liabilities                            83.8         1.7         (2.3)        83.2
   Short-term borrowings                             -       239.1            -        239.1
   Short-term borrowings from
       other Vectren companies                   147.6        95.4       (156.1)        86.9
   Current maturities of long-term debt           39.8           -            -         39.8
   Long-term debt subject to tender               26.6           -            -         26.6
----------------------------------------------------------------------------------------------
       Total current liabilities                 515.6       351.3       (161.1)       705.8
----------------------------------------------------------------------------------------------
Long-Term Debt
   Long-term debt - net of current maturities
       & debt subject to tender                  492.8       348.4            -        841.2
   Long-term debt due to VUHI                    344.0           -       (344.0)           -
----------------------------------------------------------------------------------------------
       Total long-term debt - net                836.8       348.4       (344.0)       841.2
----------------------------------------------------------------------------------------------
Deferred Income Taxes & Other Liabilities
   Deferred income taxes                         174.6        (2.3)           -        172.3
   Regulatory liabilities & other
       removal costs                             210.0           -            -        210.0
   Deferred credits & other liabilities           80.3         1.9            -         82.2
----------------------------------------------------------------------------------------------
       Total deferred credits & other
           liabilities                           464.9        (0.4)           -        464.5
----------------------------------------------------------------------------------------------
Cumulative, Redeemable Preferred Stock of
    a Subsidiary                                   0.3           -            -          0.3
Common Shareholder's Equity
   Common stock (no par value)                   461.3       385.7       (461.3)       385.7
   Retained earnings                             341.1       382.4       (341.1)       382.4
   Accumulated other comprehensive income            -         0.5            -          0.5
----------------------------------------------------------------------------------------------
       Total common shareholder's equity         802.4       768.6       (802.4)       768.6
----------------------------------------------------------------------------------------------
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY      $2,620.0    $1,467.9    $(1,307.5)    $2,780.4
==============================================================================================
</TABLE>


14.  Segment Reporting

During 2003,  Vectren  transferred  certain  information  technology systems and
related assets and buildings from other entities within its  consolidated  group
to VUHI as further  described  in Note 2. These  assets  primarily  support  the
operations of VUHI's  subsidiaries.  VUHI has further  reorganized  its internal
reporting for the effects of this transfer and has restated certain  information
in its  operating  segments from those  results  reported in its 2002  financial
statements.

VUHI's operations are consist of its regulated operations (the Gas Utility
Services and Electric Utility Services operating segments), and other operations
that provide information technology and other support services to those
regulated operations. In total, there are three operating segments as defined by
SFAS 131 "Disclosure About Segments of an Enterprise and Related Information"
(SFAS 131). Gas Utility Services provides natural gas distribution and
transportation services in nearly two-thirds of Indiana and to west central
Ohio. Electric Utility Services provides electricity primarily to southwestern
Indiana, and includes the Company's power generating and marketing operations.
For its regulated operations the Company uses after tax operating income as a
measure of profitability, consistent with regulatory reporting requirements. The
Company cross manages its regulated margin, other operating expenses, and
capital expenditures as separated between Energy Delivery, which includes the
gas and electric transmission and distribution functions, and Power Supply,
which includes the power generating and marketing operations.

The Other Operations segment also contains other assets and operations that were
previously allocated to the Gas Utility and Electric Utility Segments. The
Company uses net income as the measure of the profitability for this segment.


<PAGE>


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

<TABLE>
<CAPTION>
                                                         Year Ended December 31,
--------------------------------------------------------------------------------------
(In millions)                                        2003          2002         2001
--------------------------------------------------------------------------------------
<S>                                              <C>           <C>          <C>
Revenues
  Gas Utility Services                           $ 1,112.3     $   908.0    $ 1,019.6
  Electric Utility Services                          335.7         328.6        308.5
  Other Operations                                    26.5          22.3         29.1
  Eliminations                                       (25.7)        (22.0)       (28.9)
--------------------------------------------------------------------------------------
         Total revenues                          $ 1,448.8     $ 1,236.9    $ 1,328.3
======================================================================================
Profitability Measure
  Regulated Operating Income
  (Operating Income Less Applicable
           Income Taxes)
       Gas Utility Services                      $    74.9     $    80.7    $    47.1
       Electric Utility Services                      63.8          73.2         56.5
--------------------------------------------------------------------------------------
                                                     138.7         153.9        103.6
--------------------------------------------------------------------------------------
  Regulated other income - net                         5.1           5.1          4.7
  Regulated interest expense & preferred
       dividends                                     (62.0)        (63.7)       (68.2)
  Regulated cumulative effect change in
       accounting principle                              -             -          1.1
--------------------------------------------------------------------------------------
       Regulated Net Income                           81.8          95.3         41.2
--------------------------------------------------------------------------------------
       Other Operations Net Income                     3.8           1.8          3.6
--------------------------------------------------------------------------------------
             Net Income                          $    85.6     $    97.1    $    44.8
======================================================================================
Amounts Included in Profitability Measures
  Depreciation & Amortization
       Gas Utility Services                      $    61.1     $    56.8    $    58.5
       Electric Utility Services                      42.6          40.0         38.7
       Other Operations                               14.2          13.9         20.7
--------------------------------------------------------------------------------------
             Total depreciation & amortization   $   117.9     $   110.7    $   117.9
======================================================================================
  Interest Expense
       Regulated Operations                      $    62.0     $    63.7    $    68.2
       Other Operations                                4.1           5.4          2.5
--------------------------------------------------------------------------------------
             Total interest expense              $    66.1     $    69.1    $    70.7
======================================================================================
  Equity in Losses of Unconsolidated Affiliates
       Other Operations                          $    (0.5)    $    (1.8)   $    (0.5)
======================================================================================
  Income Taxes
       Gas Utility Services                      $    19.5     $    18.2    $    (2.2)
       Electric Utility Services                      29.8          27.5         21.1
       Other Operations                                2.3           1.1          2.4
--------------------------------------------------------------------------------------
               Total income taxes                $    51.6     $    46.8    $    21.3
======================================================================================
</TABLE>

<PAGE>

Information related to the Company's business segments continues:
<TABLE>
<CAPTION>
                                                       Year Ended December 31,
-----------------------------------------------------------------------------------
(In millions)                                      2003         2002          2001
-----------------------------------------------------------------------------------
<S>                                              <C>           <C>          <C>
Capital Expenditures
    Gas Utility Services                         $  95.0      $  63.0      $  77.8
    Electric Utility Services                      124.1         88.8         69.8
    Other Operations                                15.9         65.5         55.2
-----------------------------------------------------------------------------------
              Total capital expenditures         $ 235.0      $ 217.3      $ 202.8
===================================================================================
Investments in Equity Method Investees
    Other Operations                             $     -      $   0.3      $   3.0
===================================================================================
</TABLE>


                                                   At December 31,
-----------------------------------------------------------------------
(In millions)                                  2003              2002
-----------------------------------------------------------------------
Assets
  Utility Group
     Gas Utility Services                  $ 1,805.0         $ 1,728.4
     Electric Utility Services                 974.6             891.6
     Other Operations                          162.4             171.6
     Eliminations                              (16.9)            (11.2)
-----------------------------------------------------------------------
         Total assets                      $ 2,925.1         $ 2,780.4
=======================================================================

15. Special Charges for 2001

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. During 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.

At the beginning of 2002, 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 restructuring accrual was $3.6 million
($1.6 million for severance and $2.0 million for lease costs). During 2003, $0.4
million was paid for severance, and the accrual for lease costs did not
substantially change. At December 31, 2003, the remaining restructuring accrual
was $3.2 million ($1.2 million for severance and $2.0 million for lease costs).
The restructuring accrual is included in Accrued liabilities.

Merger & Integration Costs
Merger and integration costs incurred for the year ended December 31, 2001,
totaled $2.8 million. Those costs related 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, resulting in additional depreciation expense of
approximately $9.6 million ($6.0 million after tax) for the year ended December
31, 2001. Merger and integration activities resulting from the 2000 merger were
completed in 2001.

16.  Impact of Recently Issued Accounting Guidance

SFAS 149
In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on
Derivative Instruments and Hedging Activities" (SFAS 149). SFAS 149 amends and
clarifies the accounting guidance on (1) derivative instruments (including
certain derivative instruments embedded in other contracts) and (2) hedging
activities that fall within the scope of FASB Statement No. 133 (SFAS 133),
"Accounting for Derivative Instruments and Hedging Activities." SFAS 149 amends
SFAS 133 to reflect decisions that were made (1) as part of the process
undertaken by the Derivatives Implementation Group (DIG), which necessitated
amending SFAS 133, (2) in connection with other projects dealing with financial
instruments, and (3) regarding implementation issues related to the application
of the definition of a derivative. SFAS 149 also amends certain other existing
pronouncements which will result in more consistent reporting of contracts that
are derivatives in their entirety or that contain embedded derivatives that
warrant separate accounting. SFAS 149 is effective (1) for contracts entered
into or modified after June 30, 2003, with certain exceptions and (2) for
hedging relationships designated after June 30. The guidance is to be applied
prospectively. The adoption did not have a material effect on the Company's
results of operations or financial condition.

SFAS 150
In May 2003, the FASB issued SFAS No. 150, "Accounting for Certain Financial
Instruments with Characteristics of Both Liabilities and Equity" (SFAS 150).
SFAS 150 requires issuers to classify as liabilities the following three types
of freestanding financial instruments: mandatorily redeemable financial
instruments, obligations to repurchase the issuer's equity shares by
transferring assets, and certain obligations to issue a variable number of
shares. SFAS 150 was effective immediately for financial instruments entered
into or modified after May 31, 2003; otherwise, the standard was effective for
all other financial instruments at the beginning of the Company's third quarter
of 2003. In October 2003, the FASB issued further guidance regarding mandatorily
redeemable stock which is effective January 1, 2004, for the Company. The
Company has approximately $200,000 of outstanding preferred stock of a
subsidiary that is redeemable on terms outside the Company's control. However,
the preferred stock is not redeemable on a specified or determinable date or
upon an event that is certain to occur. The adoption of SFAS 150 on January 1,
2004, did not affect the Company's results of operations or financial condition.

FASB Interpretation (FIN) 45
In November 2002, the FASB issued 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 fair value of the obligations it has undertaken.
The initial recognition and measurement provisions were applicable on a
prospective basis to guarantees issued or modified after December 31, 2002.
Since that date, the adoption has not had a material effect on the Company's
results of operations or financial condition.

FIN 46/46-R (Revised in December 2003)
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 (VIE) and significantly changes the
consolidation requirements for those entities. FIN 46 is intended to achieve
more consistent application of consolidation policies related to VIE's and thus
improves comparability between enterprises engaged in similar activities when
those activities are conducted through VIE's. In December 2003, the FASB
completed its deliberations of proposed modifications to FIN 46 and decided to
codify both the proposed modifications and other decisions previously issued
through certain FASB Staff Positions into one document that was issued as a
revision to the original Interpretation (FIN 46-R). FIN 46-R currently applies
to VIE's created after January 31, 2003, and to VIE's in which an enterprise
obtains an interest after that date. For entities created prior to January 31,
2003, FIN 46 is to be adopted no later than the end of the first interim or
annual reporting period ending after March 15, 2004. Although management is
still evaluating the impact of FIN 46 and related Staff Positions on its
financial position and results of operations, the adoption is not expected to
have a material effect.

Staff Accounting Bulletin No. 104
In December 2003, the SEC published Staff Accounting Bulletin (SAB) No. 104,
"Revenue Recognition". This SAB updates portions of the SEC staff's interpretive
guidance provided in SAB 101 and included in Topic 13 of the Codification of
Staff Accounting Bulletins. SAB 104 deletes interpretative material no longer
necessary and conforms the interpretive material retained because of
pronouncements issued by the FASB's EITF on various revenue recognition topics,
including EITF 00-21, "Revenue Arrangements with Multiple Deliverables." The
Company's adoption of the standard did not have an impact on its revenue
recognition policies.

17.  Quarterly Financial Data  (Unaudited)

Quarterly operating revenues presented below have been adjusted to reflect the
adoption of EITF 03-11. See Note 11 to the consolidated financial statements for
further information on the adoption of EITF 03-11. 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 2003 and 2002 follows:

---------------------------------------------------------------------------
(In millions)                 Q1           Q2           Q3            Q4
---------------------------------------------------------------------------
2003
  Results of Operations:
  Operating revenues       $ 592.9      $ 239.9      $ 210.7       $ 405.3
  Operating income            95.7         17.4         19.4          66.5
  Net income                  47.3          1.4          2.4          34.5

2002
  Results of Operations:
  Operating revenues       $ 428.6      $ 216.8      $ 189.8       $ 401.7
  Operating income            80.8         26.0         30.3          70.6
  Net income                  42.0          8.7          9.0          37.4


<PAGE>


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

None.

ITEM 9a.  CONTROLS AND PROCEDURES

                Evaluation of Disclosure Controls and Procedures

As of December 31, 2003, 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 at providing
reasonable assurance that 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) is brought to their attention on a timely basis.

Disclosure controls and procedures, as defined by the Exchange Act in Rules
13a-15(e) and 15d-15(e), 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 Over Financial Reporting

During the quarter ended December 31, 2003, there have been no significant
changes to the Company's internal control over financial reporting that have
materially affected, or are reasonably likely to materially affect, the
Company's internal control over financial reporting.

Internal control over financial reporting is defined by the SEC in Final Rule:
Management's Reports on Internal Control Over Financial Reporting and
Certification of Disclosure in Exchange Act Periodic Reports. The final rule
defines internal control over financial reporting as a process designed by, or
under the supervision of, the registrant's principal executive and principal
financial officers, or persons performing similar functions, and effected by the
registrant's board of directors, management and other personnel, to provide
reasonable assurance regarding the reliability of financial reporting and the
preparation of financial statements for external purposes in accordance with
generally accepted accounting principles and includes those policies and
procedures that: (1) pertain to the maintenance of records that in reasonable
detail accurately and fairly reflect the transactions and dispositions of the
assets of the registrant, (2) provide reasonable assurance that transactions are
recorded as necessary to permit preparation of financial statements in
accordance with generally accepted accounting principles, and that receipts and
expenditures of the registrant are being made only in accordance with
authorizations of management and directors of the registrant, and (3) provide
reasonable assurance regarding prevention or timely detection of unauthorized
acquisition, use or disposition of the registrant's assets that could have a
material effect on the financial statements.


<PAGE>

                                    PART III

ITEM 10.   DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

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

Vectren's Corporate Governance Guidelines, its charters for each of its Audit,
Compensation and Nominating and Corporate Governance Committees, and its Code of
Ethics covering Vectren's directors, officers and employees are available on
Vectren's website, www.vectren.com, and a copy will be mailed upon request to
Investor Relations, Attention: Steve Schein, 20 N.W. Fourth Street, Evansville,
Indiana 47708. Vectren intends to disclose any amendments to the Code of Ethics
or waivers of the Code of Ethics on behalf of its directors or officers
including, but not limited to, the principal executive officer, principal
financial officer, principal accounting officer or controller and persons
performing similar functions on Vectren's website at the Internet address set
forth above promptly following the date of such amendment or waiver and such
information will also be available by mail upon request to Investor Relations,
Attention: Steve Schein, 20 N.W. Fourth Street, Evansville, Indiana 47708.

ITEM 11.  EXECUTIVE COMPENSATION

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

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

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

ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

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

ITEM 14.  PRINCIPAL ACCOUNTANT FEES AND SERVICES

The following tabulation shows the audit and non-audit fees paid to Deloitte &
Touche, LLP (Deloitte) for the years ending December 31, 2003, and 2002. The
fees presented below represents total Vectren fees, not just the
portion allocated to VUHI.

---------------------------------------------------------------------
                                          2003                2002
---------------------------------------------------------------------
Audit Fees(1)                         $ 1,187,950          $ 350,000
Audit-Related Fees(2)                     234,000            135,555
Tax Fees(3)                                92,000             73,625
All Other Fees(4)                               -                  -
---------------------------------------------------------------------
Total Fees Paid to Deloitte           $ 1,513,950          $ 559,180
=====================================================================

(1)  Aggregate fees incurred payable to Deloitte for professional services
     rendered for the audit of the Company's 2003 fiscal year annual financial
     statements and the review of financial statements included in Company's
     Forms 10-Q filed during the Company's 2003 fiscal year. This includes fees
     incurred for audit services related to certain of the Company's
     subsidiaries in connection with the audit of the Company's financial
     statements. The amount also includes fees paid to Deloitte for the audits
     of the Company's 2000 and 2001 financial statements and the completion of
     the audit of the 2002 financial statements. The 2002 amount relates to the
     audit of the Company's 2002 financial statements and reviews of the
     Company's Forms 10-Q filed during the 2002 fiscal year.

(2)  Audit related fees consisted principally of consultation on various
     accounting issues in 2003 and 2002, and reviews related to various
     financing transactions completed during 2003.

(3)  Tax fees consisted of fees paid to Deloitte for tax planning and review of
     tax returns of the Company.

(4)  All Other Fees - None.

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


                                     PART IV

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

                 List Of Documents Filed As Part Of This Report

Consolidated Financial Statements

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

Supplemental Schedules

For the years ended December 31, 2003, 2002, and 2001, the Company's Schedule II
-- Valuation and Qualifying Accounts Consolidated Financial Statement Schedules
is presented on page 75. 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 attached to this filing filed
                electronically with the SEC are listed on page 76.
              Exhibits for the Company are listed in the Index to Exhibits
                beginning on page 77.

<PAGE>

              Reports On Form 8-K During The Last Calendar Quarter

On October 22, 2003, the Company filed a Current Report on Form 8-K with respect
to the release of financial information to the investment community regarding
Vectren Corporation's results of operations, financial position and cash flows
for the three, nine, and twelve month periods ended September 30, 2003. The
financial information was released to the public through this filing.

         Item  7.  Exhibits
                   99-1 - Press Release - Vectren Corporation Reports Third
                   Quarter 2003 Results
                   99-2 - Cautionary Statement for Purposes of the "Safe Harbor"
                   Provisions of the Private Securities Litigation
                   Reform Act of 1995
         Item 12.  Results of Operations and Financial Condition


On December 11, 2003, the Company filed a Current Report on Form 8-K with
respect to an analyst meeting where a discussion of Vectren Corporation's
current financial and operating results and plans for the future will occur.

         Item 9.  Regulation FD Disclosure
         Index to Exhibits
                   99-1 - Press Release - Vectren Corporation Provides 2004
                   Earnings Guidance
                   99- 2 - Cautionary Statement for Purposes of the "Safe
                   Harbor" Provisions of the Private Securities Litigation
                   Reform Act of 1995

<PAGE>
<TABLE>
                                   SCHEDULE II

             Vectren Utility Holdings, Inc. and Subsidiary Companies
<CAPTION>
                 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 2003 - Accumulated provision for
            uncollectible accounts         $ 5.5       $ 12.2     $ -         $ 14.6       $ 3.1

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

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 2003 - Reserve for restructuring
            costs                          $ 3.6       $    -     $ -         $  0.4       $ 3.2

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>

                         Vectren Utility Holdings, Inc.
                                 2003 Form 10-K
                                Attached Exhibits

The following Exhibits were filed electronically with the SEC with this filing.
See Page 77 of this Annual Report on Form 10-K for a complete list of exhibits.

Exhibit
Number         Document


21.1 List of Company's Significant Subsidiaries

31.1 Chief Executive Officer Certification Pursuant to Section 302 of the
     Sarbanes-Oxley Act of 2002.

31.2 Chief Financial Officer Certification Pursuant to Section 302 of the
     Sarbanes-Oxley Act of 2002.

32.1 Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


<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  Summary description of Southern Indiana Gas and Electric Company's
      nonqualified Supplemental Retirement Plan (Filed and designated in Form
      10-K for the fiscal year 1992, File No. 1-3553, as Exhibit 10-A-17.) First
      Amendment, effective April 16, 1997 (Filed and designated in Form 10-K for
      the fiscal year 1997, File No. 1-3553, as Exhibit 10.29).

10.2  Southern Indiana Gas and Electric Company 1994 Stock Option Plan (Filed
      and designated in Southern Indiana Gas and Electric Company's Proxy
      Statement dated February 22, 1994, File No. 1-3553, as Exhibit A.)

10.3  Indiana Energy, Inc. Unfunded Supplemental Retirement Plan for a Select
      Group of Management Employees as amended and restated effective
      December 1, 1998. (Filed and designated in Form 10-Q for the quarterly
      period ended December 31, 1998, File No. 1-9091, as Exhibit 10-G.)

10.4  Indiana Energy, Inc. Nonqualified Deferred Compensation Plan effective
      January 1, 1999. (Filed and designated in Form 10-Q for the quarterly
      period ended December 31, 1998, File No. 1-9091, as Exhibit 10-H.)

10.5  Indiana Energy, Inc. Executive Restricted Stock Plan as amended and
      restated effective October 1, 1998. (Filed and designated in Form 10-K for
      the fiscal year ended September 30, 1998, File No. 1-9091, as Exhibit
      10-O.) First Amendment, effective December 1, 1998 (Filed and designated
      in Form 10-Q for the quarterly period ended December 31, 1998, File No.
      1-9091, as Exhibit 10-I.).

10.6  Indiana Energy, Inc. Director's Restricted Stock Plan as amended and
      restated effective May 1, 1997. (Filed and designated in Form 10-Q for the
      quarterly period ended June 30, 1997, File No. 1-9091, as Exhibit 10-B.)
      First Amendment, effective December 1, 1998. (Filed and designated in Form
      10-Q for the quarterly period ended December 31, 1998, File No. 1-9091, as
      Exhibit 10-J.) Second Amendment, Plan renamed the Vectren Corporation
      Directors Restricted Stock Plan effective October 1, 2000. (Filed and
      designated in Form 10-K for the year ended December 31, 2000, File No.
      1-15467, as Exhibit 10-34.) Third Amendment, effective March 28, 2001.
      (Filed and designated in Form 10-K for the year ended December 31, 2000,
      File No. 1-15467, as Exhibit 10-35.)

10.7  Vectren Corporation At Risk Compensation Plan effective May 1, 2001.
      (Filed and designated in Vectren Corporation's Proxy Statement dated
      March 16, 2001, File No. 1-15467, as Appendix B.)

10.8  Vectren Corporation Non-Qualified Deferred Compensation Plan, as amended
      and restated effective January 1, 2001. (Filed and designated in Form
      10-K, for the year ended December 31, 2001, File No. 1-15467, as Exhibit
      10.32.)

10.9  Vectren Corporation Employment Agreement between Vectren Corporation and
      Niel C. Ellerbrook dated as of March 31, 2000. (Filed and designated in
      Form 10-Q for the quarterly period ended June 30, 2000, File No. 1-15467,
      as Exhibit 99.1.)

10.10 Vectren Corporation Employment Agreement between Vectren Corporation and
      Jerome A. Benkert, Jr. dated as of March 31, 2000. (Filed and designated
      in Form 10-Q for the quarterly period ended June 30, 2000, File No.
      1-15467, as Exhibit 99.3.)

10.11 Vectren Corporation Employment Agreement between Vectren Corporation and
      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.)

10.12 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.)

10.13 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.)

10.14 Gas Sales and Portfolio Administration Agreement between Indiana Gas
      Company, Inc. and ProLiance Energy, LLC, effective August 30, 2003. (Filed
      and designated in Form 10-K, for the year ended December 31, 2003, File No
      1-1567, as Exhibit 10.15.)

10.15 Gas Sales and Portfolio Administration Agreement between Southern Indiana
      Gas and Electric Company and ProLiance Energy, LLC, effective September 1,
      2002. (Filed and designated in Form 10-K, for the year ended December 31,
      2003, File No 1-1567, as Exhibit 10.16.)

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

10.17 Coal Supply Agreement for F.B. Culley Generating Station between Southern
      Indiana Gas and Electric Company and Vectren Fuels, Inc., dated December
      17, 1997 and effective January 1, 1998. (Filed and designated in Form
      10-K, for the year ended December 31, 2003, File No 1-1567, as Exhibit
      10.18.).  Portions of the document has been omitted pursuant to a request
      to a request for confidential treatment.

10.18 Amendment 1, effective January 1, 2003, to Coal Supply Agreement between
      Southern Indiana Gas and Electric Company and Vectren Fuels, Inc
      originally dated December 17, 1997. . (Filed and designated in Form 10-K,
      for the year ended December 31, 2003, File No 1-1567, as Exhibit 10.19.)

10.19 Coal Supply Agreement for Generating Stations at Yankeetown, Warrick
      County, Indiana, and West Franklin, Posey County, Indiana between Southern
      Indiana Gas and Electric Company and Vectren Fuels, Inc., dated January
      19, 2000. . (Filed and designated in Form 10-K, for the year ended
      December 31, 2003, File No 1-1567, as Exhibit 10.20.)

10.20 Amendment 1, effective January 1, 2004, to Coal Supply Agreement between
      Southern Indiana Gas and Electric Company and Vectren Fuels, Inc
      originally dated January 19, 2000. (Filed and designated in Form 10-K, for
      the year ended December 31, 2003, File No 1-1567, as Exhibit 10.21.)

10.21 Coal Supply Agreement for Warrick Generating Station between Southern
      Indiana Gas and Electric Company and Vectren Fuels, Inc. dated October 1,
      2003.  (Filed and designated in Form 10-K, for the year ended December
      31, 2003, File No 1-1567, as Exhibit 10.22.)

10.22 Coal Supply Agreement for Warrick Generating Station between Southern
      Indiana Gas and Electric Company and Vectren Fuels, Inc. dated January 1,
      2004.  (Filed and designated in Form 10-K, for the year ended December 31,
      2003, File No 1-1567, as Exhibit 10.23.)

10.23 Formation Agreement among Indiana Energy, Inc., Indiana Gas Company, Inc.,
      IGC Energy, Inc., Indiana Energy Services, Inc., Citizens Gas & Coke
      Utility, Citizens Energy Services Corporation and ProLiance Energy, LLC,
      effective March 15, 1996. (Filed and designated in Form 10-Q for the
      quarterly period ended March 31, 1996, File No. 1-9091, as Exhibit 10-C.)

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




<PAGE>


31. Certification Pursuant To Section 302 of the Sarbanes-Oxley Act of 2002
Chief Executive Officer Certification Pursuant to Section 302 Of The
     Sarbanes-Oxley Act Of 2002 is attached hereto as Exhibit 31.1

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

32.   Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
Certification Pursuant To Section 906 of the Sarbanes-Oxley Act Of 2002 is
attached hereto as Exhibit 32.1

99.  Additional Exhibits
99.1 Amended and Restated Articles of Incorporation of Vectren Corporation
     effective March 31, 2000. (Filed and designated in Current Report on
     Form 8-K filed April 14, 2000, File No. 1-15467, as Exhibit 4.1.)

99.2 Amended and Restated Code of By-Laws of Vectren Corporation as of October
     29, 2003. (Filed and designated in Quarterly Report on Form 10-Q filed
     November 13, 2003, File No. 1-15467, as Exhibit 3.1.)

99.3 Shareholders Rights Agreement dated as of October 21, 1999 between Vectren
     Corporation and Equiserve Trust Company, N.A., as Rights Agent. (Filed and
     designated in Form S-4 (No. 333-90763), filed November 12. 1999, File No.
     1-15467, as Exhibit 4.)


<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 25, 2004
                                           /s/ Niel C. Ellerbrook
                                           --------------------------------
                                           Niel C. Ellerbrook,
                                           Chairman, Chief Executive Officer,
                                           and Director

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

        Signature                        Title                        Date


  /s/ Niel C. Ellerbrook       Chairman, Chief Executive       February 25, 2004
---------------------------    Officer, & Director             -----------------
    Niel C. Ellerbrook         (Principal Executive Officer)



/s/ Jerome A. Benkert, Jr.     Executive Vice President,       February 25, 2004
---------------------------    Chief Financial Officer, &      -----------------
  Jerome A. Benkert, Jr.       Director (Principal Financial
                                Officer)



   /s/ M. Susan Hardwick       Vice President & Controller     February 25, 2004
---------------------------    (Principal Accounting Officer)  -----------------
     M. Susan Hardwick


  /s/ Ronald E Christian       Director                        February 25, 2004
---------------------------                                    -----------------
    Ronald E Christian


    /s/ William S. Doty        Director                        February 25, 2004
---------------------------                                    -----------------
      William S. Doty