Edgar Filing: VECTREN UTILITY HOLDINGS INC

SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K

X ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2001

_ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from___________ to____________

Commission Registrant, State of Incorporation; IRS Employer
File Number Address and Telephone Number Identification No.
----------- ---------------------------- ------------------

1-16739 Vectren Utility Holdings, Inc. 35-2104850
(An Indiana Corporation)
20 N. W. Fourth Street
Evansville, Indiana 47708
(812) 491-4000

Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Registrant Title of each class on which registered
-------------------------------- --------------------- ---------------------
Vectren Utility Holdings, Inc. 7 1/4% Senior Notes, New York Stock Exchange
due 10/15/2031

Securities registered pursuant to Section 12(g) of the Act:
Name of each exchange
Registrant Title of each class on which registered
------------------------------ --------------------------- --------------------
Vectren Utility Holdings, Inc. Common Stock - Without Par None

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) have been subject to such filing
requirements for the past 90 days: Yes X No __

Indicate the number 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 22, 2002
------------------------------ ---------------- --------------
Class Number of Shares Date

As of March 22, 2002, all shares outstanding of the Registrant's common stock
were held by Vectren Corporation.

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.

Documents Incorporated by Reference
Certain information in Vectren Corporation's definitive Proxy Statement for the
2002 Annual Meeting of Stockholders, which was filed with the Securities and
Exchange Commission on March 15, 2002, is incorporated by reference in Part III
of this Form 10-K.

Information in the Company's Current Report on Form 8-K, which was filed with
the Securities and Exchange Commission on March 26, 2002, regarding replacement
of the Company's independent auditors, is incorporated by reference in Part I
of this filing.

Table of Contents
Item Page
Number Number
Part I

1 Business ............................................................. 1
2 Properties ........................................................... 6
3 Legal Proceedings..................................................... 7
4 Submission of Matters to Vote of Security Holders..................... 7

Part II

5 Market for Registrant's Common Equity
and Related Stockholder Matters .................................... 7
6 Selected Financial Data............................................... 8
7 Management's Discussion and Analysis
of Results of Operations and Financial Condition.................... 9
7A Qualitative and Quantitative Disclosures About Market Risk............ 25
8 Financial Statements and Supplementary Data........................... 27
9 Change in and Disagreements with Accountants on
Accounting and Financial Disclosure................................. 59

Part III

10 Directors and Executive Officers of
the Registrant...................................................... 59
11 Executive Compensation................................................ 60
12 Security Ownership of Certain Beneficial
Owners and Management............................................... 63
13 Certain Relationships and Related
Transactions........................................................ 64

Part IV

14 Exhibits, Financial Statement Schedules and
Reports on Form 8-K................................................. 64
Signatures............................................................ 67

Definitions
As discussed in this Form 10-K, the abbreviations Dth means dekatherms, MDth
means thousands of dekatherms, MMDth means millions of dekatherms, MW means
megawatts, MMBTU means millions of British thermal units, kWh means kilowatt
hours, Mva means megavolt amperes, and throughput means combined gas sales and
gas transportation volumes.

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 (defined hereafter).

Indiana Gas provides natural gas distribution and transportation services to a
diversified customer base in 311 communities in 49 of Indiana's 92 counties.
SIGECO provides electric generation, transmission, and distribution services to
Evansville, Indiana, and 74 other communities in 8 counties in southwestern
Indiana and participates in the wholesale power market. SIGECO also provides
natural gas distribution and transportation services to Evansville, Indiana, and
64 other communities in 10 counties in southwestern Indiana. The Ohio operations
provide natural gas distribution and transportation services to Dayton, Ohio,
and 87 other communities in 17 counties in west central Ohio.

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

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

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

On October 31, 2000, the Company acquired the natural gas distribution assets of
The Dayton Power and Light Company for approximately $465.0 million. The
acquisition has been accounted for as a purchase transaction in accordance with
APB 16, and accordingly, the results of operations of the acquired businesses
are included 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."

Recent Development

On March 26, 2002, the Company filed a Current Report on Form 8-K announcing its
decision to replace Arthur Andersen LLP as its independent auditors effective
upon the completion of a transition period which is expected to extend through

the conclusion of their review of the financial results of the Company for the
first quarter of 2002. This Form 8-K is included in this filing as Exhibit 99.7.

Narrative Description of the Business

The Company's operations are comprised of its Gas Utility Services and Electric
Utility Services segments. The Gas Utility Services segment includes the
operations of Indiana Gas, the Ohio operations, and SIGECO's natural gas
distribution business and provides natural gas distribution and transportation
services to nearly two-thirds of Indiana and west central Ohio. The Electric
Utility Services segment includes SIGECO's power supply operations, power
marketing operations, and electric transmission and distribution services, which
operate and maintain six coal-fired electric power plants and five gas-fired
peaking units with a total of 1,271 megawatts of generating capacity to provide
electricity to primarily southwestern Indiana.

At December 31, 2001, the Company had $2.4 billion in total assets, with $1.6
billion (66%) attributed to gas utility services and $0.8 billion (34%)
attributed to electric utility services. Net income for the year ended 2001 was
$50.7 million. Excluding nonrecurring charges with an after-tax impact of $15.1
million, net income before nonrecurring items for the year ended 2001 was $65.8
million, with $23.3 million attributed to gas utility services and $42.5 million
attributed to electric utility services. Nonrecurring items, after tax, in 2001
included $7.7 million of merger and integration costs, $9.3 million of
restructuring costs, and $1.9 million gain on the impact of SFAS 133, including
cumulative effect of change in accounting principle. Excluding nonrecurring
items, after tax, the results reflect a decrease of $18.2 million compared to
2000. Nonrecurring items, after tax, in 2000 included $31.6 million of merger
and integration costs.

For further information refer to Note 16 regarding the segments' activities and
assets, Note 3 regarding special charges, and Note 14 regarding the adoption of
and current year impact of SFAS 133 in the Company's consolidated financial
statements included under Part II Item 8 Financial Statements and Supplementary
Data.

Gas Utility Services

Overview

For the year ended December 31, 2001, the Company supplied natural gas service
to 953,214 Indiana and Ohio customers, including 868,685 residential, 80,235
commercial, and 4,294 transportation customers. This represents customer base
growth of nearly 1% compared to 2000.

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, 2001, natural gas revenues were approximately
$1,031.5 million of which residential customers accounted for 66%, commercial
24%, and transportation 10%, respectively.

The Company receives gas revenues by selling gas directly to residential,
commercial, and industrial customers at approved rates or by transporting gas
through its pipelines at approved rates to commercial and industrial customers
that have purchased gas directly from other producers, brokers, or marketers.
Total volume of gas provided to both sales and transportation customers
(throughput) was 199,761 MDth for the year ended December 31, 2001. Transported
gas represented 45% of total throughput. Rates for transporting gas provide for
the same margins generally earned by selling gas under applicable sales tariffs.

The sale of gas is seasonal and strongly affected by variations in weather
conditions. To mitigate seasonal demand, the Company owns and operates eight
underground gas storage fields, six liquefied petroleum air-gas manufacturing
plants and maintains contract storage. Natural gas purchased from suppliers is
injected into storage during periods of light demand which are typically periods
of lower prices. The injected gas is then available to supplement contracted
volumes during periods of peak requirements. Approximately 705,000 Dth of gas
per day can be withdrawn during peak demand periods.

Gas Purchases

In 2001, the Company purchased natural gas from multiple suppliers including
ProLiance Energy, LLC (ProLiance). ProLiance is an unconsolidated, nonregulated,
energy marketing affiliate of Vectren and Citizens Gas and Coke Utility. (See
Note 4 in the Company's consolidated financial statements included in Item 8
Financial Statements and Supplementary Data regarding transactions with
ProLiance). The Company purchased 114,503 MDth volumes of gas in 2001 at an
average cost of $5.63 per MDth, of which 87% was purchased from ProLiance. The
cost of gas purchased for the last five years is as follows:

Average Cost
Year of Gas Purchased
---- ----------------
1997 $3.56
1998 $3.53
1999 $3.58
2000 $5.60
2001 $5.63

Regulatory Matters

See Item 7 Management's Discussion and Analysis of Results of Operations and
Financial Condition regarding the Company's regulated environment.

Environmental Matters

See Item 7 Management's Discussion and Analysis of Results of Operations and
Financial Condition regarding manufactured gas plants.

Electric Utility Services

Overview

The Company supplied electric service to 133,294 Indiana customers (115,770
residential, 17,327 commercial, and 197 industrial) during 2001. In addition,
the Company is obligated to provide for firm power commitments to several

municipalities and to maintain spinning reserve margin requirements under an
agreement with the East Central Area Reliability Group.

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

Revenues

For the year ended December 31, 2001, electricity sales totaled 9,138,770
megawatt hours, resulting in revenues of approximately $378.9 million.
Residential customers accounted for 25% of 2001 revenues; commercial 20%;
industrial 22%; wholesale 32%; and other 1%.

Generating Capacity

Installed generating capacity as of December 31, 2001 was rated at 1,271
megawatts (MW). Coal-fired generating units provide 1,056 MW of capacity and gas
or oil-fired turbines used for peaking or emergency conditions provide 215 MW.

In addition to its generating capacity, the Company has 82 MW available under
firm contracts and 95 MW available under interruptible contracts. New peaking
capacity of 80 MW is under development and is planned to be available for the
summer peaking season in 2002. This new generating capacity will be fueled by
natural gas.

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 ability to
simultaneously interchange approximately 750 MW.

Total load for each of the years 1997 through 2001 at the time of the system
summer peak, and the related reserve margin, is presented below in MW.

Date of Summer Peak Load 7-14-97 7-21-98 7-6-99 8-17-00 7-31-01
------- ------- ------ ------- -------
Total Load at Peak 1,086 1,129 1,230 1,212 1,209

Generating Capability 1,236 1,256 1,256 1,256 1,271
Firm Purchase Supply - - - 75 82
Interruptible Contracts - - 95 95 95
----- ----- ----- ----- -----
Total Power Supply Capacity 1,236 1,256 1,351 1,426 1,448

Reserve Margin at Peak 14% 11% 10% 18% 20%

The winter peak load of the 2000-2001 season of approximately 925 MW occurred on
December 19, 2000 and was 6% higher than the previous winter peak load of
approximately 873 MW which occurred on January 25, 2000.

SIGECO maintains a 1.5% interest in the Ohio Valley Electric Corporation (OVEC).
The OVEC is comprised of several electric utility companies, including SIGECO
that 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,
SIGECO's 1.5% interest in the OVEC makes available approximately 32 MW of
capacity, in addition to its generating capacity, for use in other operations.

Fuel Costs

Electric generation for 2001 was fueled by coal (99.6%) and natural gas (0.4%).
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 strip mines including those owned by Vectren Fuels, Inc., a wholly owned
subsidiary of Vectren. Approximately 3.2 million tons of coal was purchased for
generating electricity during 2001. Of this amount, Vectren Fuels, Inc. supplied
2.6 million tons, of which 1.9 million tons was produced in its coal mines. The
average cost of all coal consumed in generating electrical energy for the years
1997 through 2001 was as follows:

Average Cost
Average Cost Average Cost Per Kwh
Year Per Ton Per MMBTU (In Mills)
----- ------------ ------------ ------------
1997 20.75 0.91 9.80
1998 21.34 0.94 9.97
1999 21.88 0.96 10.13
2000 22.49 0.98 10.39
2001 22.48 1.00 10.53

Other Operating Matters

The Company participates with 7 other utilities and 31 other affiliated groups
located in 8 states comprising the east central area of the United States, in
the East Central Area Reliability group, the purpose of which is to strengthen
the area's electric power supply reliability. In addition, see Item 7
Management's Discussion and Analysis of Results of Operations and Financial
Condition regarding the Company's participation in the Midwest Independent
System Operator group and regarding the change in operations at the Warrick
Generating Station.

Regulatory Matters

See Item 7 Management's Discussion and Analysis of Results of Operations and
Financial Condition regarding the Company's regulated environment.

Environmental Matters

See Item 7 Management's Discussion and Analysis of Results of Operations and
Financial Condition for discussion of the Company's Clean Air Act Compliance
Plan and the USEPA's lawsuit against SIGECO for alleged violations of the Clean
Air Act.

Competition

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

Personnel

As of December 31, 2001, the Company and its subsidiaries had 1,649 employees.

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.

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, continuing through October 2005. The agreement provides a 3.25%
wage increase each year, and the other terms and conditions are substantially
the same as the agreement reached between the Utility Workers Union and Dayton
Power and Light Company in August of 2000.

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

The labor agreement between Indiana Gas, Local Union 1393 of the International
Brotherhood of Electrical Workers and Local Unions 7441 and 12213, United
Steelworkers of America, went into effect in November 1998 for a five year term
expiring on December 2003. The agreement contains a 4% wage increase in 1998 and
3% wage increases each year thereafter during the term of the agreement, in
addition to increased performance incentives, a new sick pay provision and a
simplified pension benefit formula.

ITEM 2. PROPERTIES

Gas Utility Services
Specific to its Indiana operations, Indiana Gas owns and operates five gas
storage fields located in Indiana covering 71,484 acres of land with an
estimated ready delivery from storage capability of 8.0 MMDth of gas with daily
delivery capabilities of 134,160 Dth. For its Indiana operations, Indiana Gas
also maintains 186,578 Dth of gas in contract storage with a daily
deliverability of 3,563 Dth and three liquefied petroleum (propane) air-gas
manufacturing plants in Indiana with a total daily capacity of 31,000 Dth of
gas. Indiana Gas' gas delivery system includes 11,336 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 with an estimated
ready delivery from storage capability of 6.2 MMDth of gas with daily delivery
capabilities of 129,000 Dth. SIGECO's gas delivery system includes 2,921 miles
of distribution and transmission mains all of which are located in Indiana.

The Ohio operations operate three liquefied petroleum (propane) air-gas
manufacturing plants located in Ohio with a total daily capacity of 52,187 Dth,
and approximately 13.9 MMDth of firm storage service from various pipelines with
daily deliverability of 354,788 Dth of gas. The Ohio operations' gas delivery
system includes 5,132 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, 2001 was rated at
1,271 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 Gas Turbine located at the Brown Station; two
Broadway Gas Turbines located in Evansville, Indiana, with a combined capacity
of 115 MW; and two Northeast Gas Turbines located northeast of Evansville in
Vanderburgh County, Indiana with a combined capacity of 20 MW. The Brown and
Broadway Unit 2 turbines are also equipped to burn oil. Total capacity of
SIGECO's five gas turbines is 215 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 828 circuit miles of 138,000 and 69,000
volt lines. The transmission system also includes 27 substations with an
installed capacity of 4,014.2 megavolt amperes (Mva). The electric distribution
system includes 3,205 pole miles of lower voltage overhead lines and 255 trench
miles of conduit containing 1,465 miles of underground distribution cable. The
distribution system also includes 96 distribution substations with an installed
capacity of 1,918.2 Mva and 50,133 distribution transformers with an installed
capacity of 2,284.1 Mva.

The only utility property SIGECO owns outside of Indiana is approximately 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,
as supplemented by various supplemental indentures.

ITEM 3. LEGAL PROCEEDINGS

The Company and its subsidiaries are involved in various legal proceedings
arising in the normal course of business. In the opinion of management, with the
exception of the matters described in Notes 5 and 12 of its consolidated
financial statements included in Item 8 Financial Statements and Supplementary
Data regarding transactions with ProLiance and the Clean Air Act, there are no
legal proceedings pending against the Company that could be material to its
financial position or results of operations.

ITEM 4. Submission of Matters to Vote of Security Holders

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

PART II

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

Common Stock

Market Price

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

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

Dividends Paid to Parent

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

During 2000, VUHI paid dividends to its parent company of $14.2 million, $11.7
million, $15.7 million and $13.4 million in the first, second, third and fourth
quarters, respectively.

On January 23, 2002, the board of directors declared a dividend $17.9 million,
payable to Vectren on March 1, 2002.

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

Debt Security

The Company's 7 1/4% Senior Notes dues October 15, 2031, trade on the New York
Stock Exchange under the symbol "AVU." The high and low sales prices for the
Company's publicly traded debt security since issuance in October 2001 as
reported on the New York Stock Exchange composite transactions reporting systems
were $25.50 and $25.00, respectively.

ITEM 6. SELECTED FINANCIAL DATA

The following table presents selected consolidated financial information. The
information should be read in conjunction with the Company's consolidated
financial statements and notes thereto presented under Item 8 Financial
Statements and Supplementary Data of this Form 10-K. The financial information
as of December 31, 1999-2001 and for each of the four years in the period ended
December 31, 2001 are derived from the Company's audited consolidated financial
statements. The financial information as of December 31, 1997, and 1998 and for
the year ended December 31, 1997 is derived from the Company's internal
unaudited consolidated financial statements. This information has been restated
to reflect the reorganization of entities under common control pursuant to which
Indiana Gas and SIGECO became a subsidiary of VUHI.

As of and for the Year Ended December 31 (in millions)

1997 (4) 1998 1999 2000 (2,3) 2001 (1)
-------- ------- ------- --------- --------

Operating Data:
Operating revenues $ 886.2 $ 785.1 $ 807.1 $ 1,155.2 $ 1,410.4
Operating income 92.5 104.0 109.0 94.5 112.7
Income before cumulative effect
of change in accounting principle 57.9 69.3 75.4 52.4 46.8
Net income 57.9 69.3 75.4 52.4 50.7

Balance Sheet Data:
Total assets 1,563.4 1,568.7 1,623.9 2,454.3 2,391.4
Redeemable preferred stock 8.4 8.3 8.2 8.1 0.5
Long-term debt-net of current
maturities & debt subject to tender 403.7 351.7 450.1 572.6 900.9
Common shareholder's equity 553.2 566.1 583.2 571.8 713.0

(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. These information system assets
are owned by a wholly owned subsidiary of Vectren, and the fees are
allocated by the subsidiary for the use of these systems by the Company. As
a result of the shortened useful lives, additional fees were incurred by
the Company during 2001, resulting in an increase in other operating
expenses of $9.6 million for the year ended December 31, 2001.

In total, merger and integration related costs incurred for the year ended
December 31, 2001 were $12.4 million ($7.7 million after tax).

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

(2) Merger and integration related costs incurred for the year ended December
31, 2000 totaled $32.7 million. These costs relate primarily to transaction
costs, severance and other merger and acquisition integration activities.

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

In total, merger and integration related costs incurred for the year ended
December 31, 2000 were $44.1 million ($31.6 million after tax).

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

(4) During 1997, the board of directors of Indiana Gas authorized management to
undertake the actions necessary and appropriate to restructure Indiana Gas'
operations and recognize a resulting restructuring charge of $39.5 million
($24.5 million after tax) which included estimated costs related to
involuntary workforce reductions.

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
financial statements and notes thereto:

Overview

Description of the Business

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

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

Results of Operations

In millions 2001 2000 1999
------- ------- -------
Net income, as reported $ 50.7 $ 52.4 $ 75.4
Merger and integration costs-net of tax 7.7 31.6 -
Restructuring costs-net of tax 9.3 - -
Impact of SFAS 133, including
cumulative effect of change in
accounting principle-net of tax (1.9) - -
------- ------- -------
Net income before nonrecurring items $ 65.8 $ 84.0 $ 75.4
======= ======= =======

For 2001 compared to the prior year, net income before the impact of
nonrecurring items decreased $18.2 million due to extraordinarily high gas costs
early in the year that unfavorably impacted margins and operating costs,
including uncollectible accounts expense, interest, and excise taxes. Also,
heating weather was 9% warmer than the prior year and lower margins on wholesale
power marketing sales.

For 2000 compared to 1999, net income before the impact of nonrecurring items
increased $8.6 million primarily due to cooler temperatures, and the inclusion
of the Ohio operations for two months, offset by a disallowance of gas costs by
the Indiana Utility Regulatory Commission (IURC).

Special Charges

Merger and Integration Costs
Merger and integration costs incurred for the years ended December 31, 2001 and
2000 were $2.8 million and $32.7 million, respectively. Vectren expects to
realize net merger savings of nearly $200.0 million over ten years from the
elimination of duplicate corporate and administrative programs and greater
efficiencies in operations, business processes and purchasing encompassed in
operations. Merger and integration activities resulting from the 2000 merger
were completed in 2001. Merger costs are reflected in the financial statements
of the operating subsidiaries in which merger savings are expected to be
realized.

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

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

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

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

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

Restructuring Costs
As part of continued cost saving efforts, in June 2001, Vectren's management and
board of directors approved a plan to restructure, primarily, its regulated
operations. The restructuring plan involves 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 related to consulting fees, employee
relocation, and duplicate facilities costs. In total, the Company has incurred
restructuring charges of $15.0 million, ($9.3 million after tax). These charges
were comprised of $7.6 million for severance, related benefits and other
employee related costs, $4.0 million for lease termination fees related to
duplicate facilities, and $3.4 million for consulting and other fees incurred
through December 31, 2001. The restructuring program was completed during 2001,
except for the departure of certain employees impacted by the restructuring.

The $7.6 million expensed for employee severance and related costs are
associated with approximately 100 employees. Employee separation benefits
include severance, healthcare and outplacement services. As of December 31,
2001, approximately 80 employees have exited the business. The restructuring
program was completed during 2001, except for the departure of the remaining
employees impacted by the restructuring and the final settlement of the lease
obligation.

Impact of SFAS 133
Effective January 1, 2001, the Company adopted SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities" (SFAS 133). The cumulative impact
of adoption of SFAS 133 on January 1, 2001 was a gain of approximately $6.3
million ($3.9 million after tax.) Unrealized losses totaling $3.2 million ($2.0
million after tax) arising from the change in market value since the date of
adoption is reflected in purchased electric energy. The net impact of SFAS 133
for the year ended December 31, 2001 is a gain of $3.1 million ($1.9 million
after tax). (See below for a complete discussion of the new accounting
principle.)

New Accounting Principle

In June 1998, the Financial Accounting Standards Board (FASB) issued SFAS 133,
which requires that every derivative instrument be recorded on the balance sheet
as an asset or liability measured at its market value and that changes in the
derivative's market value be recognized currently in earnings unless specific
hedge accounting criteria are met.

in net income or other comprehensive income, as appropriate, as the 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 contracts in the Company's
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 $6.3 million ($3.9 million after tax) recorded as a cumulative
effect of accounting change in the Consolidated Statements of Income. The
majority of this gain results from the Company's power marketing operations.
SFAS 133 did not impact other commodity contracts because they were normal
purchases and sales specifically excluded from the provisions of SFAS 133.

Unrealized losses totaling $3.2 million ($2.0 million after tax) arising from
the difference between the current market value and the market value on the date
of adoption is included in purchased electric energy in the Consolidated
Statements of Income for the year ended December 31, 2001.

Utility Margin (Operating Revenues Less Cost of Gas & Cost of Fuel for Electric
Generation & Purchased Electric Energy)

Gas Utility Margin
Gas Utility margin for the year ended December 31, 2001 of $323.3 million
increased $57.0 million, compared to 2000. For the incremental ten months from
January through October from the Ohio operations, margin before the impact of
higher gas costs and warmer weather was estimated at $82.5 million. Net of this
amount, gas utility margin decreased by $25.5 million. The primary factors
contributing to this decrease were weather that was 9% warmer than the prior
year and the unfavorable impact on margin resulting from extraordinarily high
gas costs early in 2001, coupled with the effects of a weakening economy. The
weather impact reduced margin by approximately $18.0 million compared to the
prior year period. The negative impact of higher gas costs on margin, along with
general economic conditions, approximated $9.4 million. These decreases were
offset somewhat by customer growth of nearly 1% compared to 2000. Including the
Ohio operations, the Company's total throughput was 199.8 MMDth in 2001, 181.2
MMDth in 2000, and 150.7 MMDth in 1999.

Gas Utility margin for the year ended December 31, 2000, of $266.3 million
increased $33.1 million compared to 1999. The Ohio operations represent $28.2
million of the increase. The remaining $4.9 million, or 2%, increase
attributable to Indiana Gas and SIGECO's gas operations reflect 8% (11.9 MMDth)
greater throughput due to much colder temperatures during the fourth quarter of
2000 than in the fourth quarter of 1999 and a 2% growth in customers.
Residential and commercial sales rose 7% and 10%, respectively, during 2000.
Temperatures were 11% colder in 2000 compared to 1999 and approached normal for
the year. These favorable impacts were partially offset by a $3.8 million
disallowance of recoverable gas costs by the IURC, charged against gas revenues
in December 2000.

Cost of gas sold was $708.2 million in 2001, $552.5 million in 2000, and $266.4
million in 1999. Of the increases, the Ohio operations contributed $178.6
million in 2001 and $83.2 million in 2000. Excluding the Ohio operations, cost
of gas sold decreased $22.9 million, or 4% in 2001 and increased $202.9 million,
or 76%, in 2000. The changes are primarily due to fluctuations in average per
unit purchased gas costs and the volume of dekatherms sold. The total average
cost per dekatherm of gas purchased by Indiana Gas and SIGECO was $5.73 in 2001,
$5.72 in 2000, and $3.58 in 1999. The price changes are due primarily to
changing commodity costs in the marketplace.

Electric Utility Margin
Electric Utility margin for the year ended December 31, 2001 of $212.8 million
decreased $11.5 million, or 5%, compared to 2000 primarily from decreased margin
on sales to wholesale energy markets and firm wholesale customers, reflecting
the weakened national economy, and a $3.2 million reduction in margin recorded
to reflect certain wholesale power marketing purchase and sale contracts at
current market values as required by SFAS 133. The decreases were partially
offset by a 3% increase in residential and commercial sales due to cooling
weather 7% warmer than the prior year and a 3% increase in residential and
commercial customer bases.

Electric Utility margin for the year ended December 31, 2000 of $224.3 million
increased $9.8 million, or 5%, compared to 1999 primarily due to a $4.4 million
increase in margins resulting from wholesale energy market activity. The
remaining increase results from increased sales caused by the impact of much
colder fourth quarter temperatures on electric heating sales and a 5% growth in
commercial customers during the year. Retail and firm wholesale electric sales
for 2000 increased 2% and total electric sales increased 8%.

The cost of fuel and purchased power increased $54.0 million, or 48%, in 2001
compared to 2000 and increased $19.1 million, or 20%, in 2000 compared to 1999.
The increases result primarily from more wholesale energy sales. Megawatt hours
sold to the wholesale market increased 106% in 2001 compared to 2000 and
increased 39% in 2000 compared to 1999. The 2001 increase was also affected by
the reductions in margin recorded as a result of SFAS 133.

Operating Expenses (excluding Cost of Gas Sold, Fuel for Electric Generation &
Purchased Electric Energy

Other Operating
Excluding $31.4 million in additional expenses related to the Ohio operations,
utility other operating expenses for the year ended December 31, 2001 decreased
$6.6 million or 3% compared to 2000. The 2001 decrease results, primarily, from
reduced maintenance expenditures and merger synergies in the current year,
offset by increased uncollectible accounts expense resulting from increased gas
costs.

Excluding $7.1 million in expenses related to the Ohio operations, utility other
operating expenses for the year ended December 31, 2000 increased $15.3 million
or 8% compared to 1999. The increase is primarily due to increased charges for
use of corporate assets, including those assets which had useful lives shortened
as a result of the merger.

Depreciation & Amortization
Utility depreciation and amortization increased $14.5 million, or 18%, and $2.9
million, or 4%, in 2001 and in 2000, respectively. The increases are due to the
inclusion of the Ohio operations and depreciation of normal utility plant
additions at Indiana Gas and SIGECO. For the years ended December 31, 2001 and
2000, the increase in utility depreciation and amortization related to the Ohio
operations was $12.9 million, including amortization of goodwill of $4.9
million, and $2.6 million, respectively.

Income Tax
Federal and state income taxes related to utility operations decreased $12.2
million and $8.3 million in 2001 and in 2000, respectively. The 2001 decrease is
due to lower pre-tax earnings. The effective tax rate decreased from 40% in 2000
to 33% in 2001. This decrease in the effective tax rate is due to the
nondeductibility of certain merger and integration costs.

Taxes Other Than Income Taxes
Utility taxes other than income taxes increased $15.1 million and $7.7 million
in 2001 and in 2000, respectively. The years ended December 31, 2001 and 2000
include $15.3 million and $7.1 million, respectively, of additional expense
related to the Ohio operations, primarily state excise tax.

Interest Expense

Utility interest expense increased $24.0 million and $9.3 million, respectively,
during the years ended December 31, 2001 and 2000. The increases are due
primarily to interest related to the financing of the acquisition of the Ohio
operations and increased working capital requirements resulting from higher
natural gas prices.

Competition

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

have passed legislation allowing electricity customers to choose their
electricity supplier in a competitive electricity market and several other
states are considering such legislation. At the present time, Indiana has not
adopted such legislation. Ohio regulation provides for choice of commodity for
all gas customers. The Company plans to implement this choice for its gas
customers in Ohio in 2002. Indiana has not adopted any regulation requiring gas
choice; however, the Company has approved tariffs permitting large volume
customers choice among commodity suppliers.

Other Operating Matters

Midwest Independent System Operator

The Federal Energy Regulatory Commission (FERC) approved the Midwest Independent
System Operator (MISO) as the nation's first regional transmission organization.
The Carmel, Indiana-based MISO began some operations in December 2001 with
control of 73,000 miles of transmission lines carrying up to 81,000 megawatts of
power. More than 20 states are included in the MISO from the Midwest and Plains
states, to Texas, Arkansas, and part of the Southeast. In December 2001, the
IURC approved the Company's request for authority to transfer operational
control over its electric transmission facilities to the MISO.

The FERC has made regional transmission organizations a top priority since the
California power crisis last winter. Regional transmission organizations place
public utility transmission facilities in a region under common control to boost
competition and to provide more reliable power at lower rates. 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 participation in MISO, the Company is unable to determine
the impact MISO participation may have on its operations.

Operation of Warrick Station

In March 2001, Alcoa Power Generating, Inc., a subsidiary of ALCOA, INC. (ALCOA)
began operating the Warrick Generating Station. Prior to March 2001 and since
1956, the Company operated the Warrick Generating Station as an agent for ALCOA.
Three generating units at the station are owned by ALCOA, and the Company owns a
fourth unit equally with ALCOA. The operating change has no impact on the
Company's entitlement to the generating capacity.

Under the new arrangement, the Company reimburses ALCOA for operating costs
pertaining to the Company's share of the fourth unit and pays ALCOA a fee for
agency services. The reimbursed operating costs and the related agency fee are
expected to be comparable to the costs the Company would have incurred to
operate and administer its generating facilities under the previous operating
arrangement. Therefore, this change is not expected to negatively impact the
Company's financial results. Additionally, SIGECO has retained ALCOA as a
wholesale power and transmission services customer.

Environmental Matters

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

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 United States Environmental
Protection Agency (USEPA) finds a state's SIP inadequate to achieve the NAAQS,
the USEPA can call upon the state to revise its SIP (a SIP Call).

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

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

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
(Warrick), and A.B. Brown Generating Station Unit 2 (A.B. Brown). SCR systems
reduce flue gas NOx emissions to atmospheric nitrogen and water using ammonia in
chemical reaction. This technology is known to be the most effective method of
reducing NOx emissions where high removal efficiencies are required.

The IURC issued an order that (1) approves the Company's proposed project to
achieve environmental compliance by investing in clean coal technology, (2)
approves the Company's cost estimate for the construction, subject to periodic
review of the actual costs incurred, and (3) approves a mechanism whereby, prior
to an electric base rate case, the Company may recover a return on its capital
costs for the project, at its overall cost of capital, including a return on
equity.

Based on the level of system-wide emissions reductions required and the control
technology utilized to achieve the reductions, the current estimated
construction cost ranges from $175.0 million to $195.0 million and is expected
to be expended during the 2001-2004 period. Through December 31, 2001,
approximately $22.5 million has been expended. After the equipment is installed
and operational, related additional annual operation and maintenance expenses
are estimated to be between $8.0 million and $10.0 million.

The Company expects the Culley, Warrick and A.B. Brown SCR systems to be
operational by the compliance date. Installation of SCR technology at these
stations 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 best
available control technology was, or should have been, used. Numerous electric
utilities were, and are currently, being investigated by the USEPA under an
industry-wide review for compliance. In July 1999, SIGECO received a letter from
the Office of Enforcement and Compliance Assurance of the USEPA discussing the
industry-wide investigation, vaguely referring to an investigation of SIGECO and
inviting SIGECO to participate in a discussion of the issues. No specifics were
noted; furthermore, the letter stated that the communication was not intended to
serve as a notice of violation. Subsequent meetings were conducted in September
and October 1999 with the USEPA and targeted utilities, including SIGECO,
regarding potential remedies to the USEPA's general allegations.

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

SIGECO believes it performed only maintenance, repair, and replacement
activities at the Culley Generating Station, as allowed under the Act. Because
proper maintenance does not require permits, application of the best available
emission control technology, notice to the USEPA, or compliance with new source
review standards, SIGECO believes that the lawsuit is without merit and intends
to vigorously defend itself.

The lawsuit seeks fines against SIGECO in the amount of $27,500 per day per
violation. The lawsuit does not specify the number of days or violations the
USEPA believes occurred. The lawsuit also seeks a court order requiring SIGECO
to install the best available control technology at the Culley Generating
Station. If the USEPA were successful in obtaining an order, SIGECO estimates
that it would incur capital costs of approximately $40.0 million to $50.0
million to comply with the order. As a result of the NOx SIP call issue, the
majority of the $40.0 million to $50.0 million for best available emissions
technology at Culley Generating Station is included in the $175.0 million to
$195.0 million cost range previously discussed.

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

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

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

Manufactured Gas Plants

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

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

In conjunction with data compiled by expert 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 accrued 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 its $20.4 million accrual.

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.

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
Indiana Utility Regulatory Commission (IURC). The retail gas operations of the
Ohio operations are subject to regulation by the Public Utilities Commission of
Ohio (PUCO). Changes in prices for fuel for electric generation and purchased
power are determined primarily by energy markets. Wholesale energy sales are
subject to regulation by the Federal Energy Regulatory Commission (FERC).

Gas Costs Proceedings

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

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

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

Commodity prices for natural gas purchases were significantly higher during the
2000 - 2001 heating season, primarily due to colder temperatures, increased
demand and tighter supplies. Subject to compliance with applicable state laws,
the Company's utility subsidiaries are allowed full recovery of such changes in
purchased gas costs from their retail customers through these
commission-approved gas cost adjustment mechanisms, and margin on gas sales
should not be impacted. However, in 2001, the Company's utility subsidiaries
experienced higher working capital requirements, increased expenses including
unrecoverable interest costs, uncollectible accounts expense, and unaccounted
for gas and some level of price sensitive reduction in volumes sold.

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

ProLiance Energy, LLC

Vectren has an ownership interest in ProLiance Energy, LLC (ProLiance), a
nonregulated, energy marketing affiliate. ProLiance began providing natural gas
and related services to Indiana Gas, Citizens Gas and Coke Utility (Citizens
Gas) and others in April 1996. ProLiance also provides services to the Ohio
operations.

The sale of gas and provision of other services to Indiana Gas by ProLiance is
subject to regulatory review through the quarterly gas cost adjustment (GCA)
process administered by the IURC. On September 12, 1997, the IURC issued a
decision finding the gas supply and portfolio administration agreements between
ProLiance and Indiana Gas and ProLiance and Citizens Gas to be consistent with
the public interest and that ProLiance is not subject to regulation by the IURC
as a public utility. The IURC's decision reflected the significant gas cost
savings to customers obtained through ProLiance's services and suggested that
all material provisions of the agreements between ProLiance and the utilities
are reasonable. Nevertheless, with respect to the pricing of gas commodity
purchased from ProLiance, the price paid by ProLiance to the utilities for the
prospect of using pipeline entitlements if and when they are not required to
serve the utilities' firm customers, and the pricing of fees paid by the
utilities to ProLiance for portfolio administration services, the IURC concluded
that additional review in the GCA process would be appropriate and directed that
these matters be considered further in the pending, consolidated GCA proceeding
involving Indiana Gas and Citizens Gas.

The IURC has recently commenced processing the GCA proceeding regarding the
three pricing issues. The IURC has indicated that it will also consider the
prospective relationship of ProLiance with the utilities in this proceeding.
Discovery is ongoing, and an evidentiary hearing is scheduled for May 2002.
Indiana Gas continues to record gas costs in accordance with the terms of the
ProLiance contract.

In August 1998, Indiana Gas, Citizens Gas and ProLiance each received a Civil
Investigative Demand (CID) from the United States Department of Justice
requesting information relating to Indiana Gas' and Citizens Gas' relationships
with and the activities of ProLiance. The Department of Justice issued the CID
to gather information regarding ProLiance's formation and operations, and to
determine if trade or commerce had been restrained. In October 2001, the
Antitrust Division of the Department of Justice informed the Company that it
closed the investigation without further action.

Fuel & Purchased Power Costs

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

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

As a result of an appeal of a generic order issued by the IURC in August 1999
regarding guidelines for the recovery of purchased power costs, SIGECO entered
into a settlement agreement with the OUCC that provides certain terms with
respect to the recoverability of such costs. The settlement, originally approved
by the IURC in August 2000, has been extended by agreement through March 2002
and additional settlement discussions are expected in 2002. 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.

Significant Accounting Policies

As described in Note 2 to the consolidated financial statements, significant
accounting policies include the following:

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.

Utility Plant & Depreciation

Utility plant is stated at historical cost, including an allowance for the cost
of funds used during construction (AFUDC). Depreciation of utility property is
provided using the straight-line method over the estimated service lives of the
depreciable assets. 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. Maintenance and repairs, including the cost of removal of
minor items of property and planned major maintenance projects, are charged to
expense as incurred. When property that represents a retirement unit is replaced
or removed, the cost of such property is credited to utility plant, and such
cost, together with the cost of removal less salvage, is charged to accumulated
depreciation.

Impairment Review of Long-Lived Assets

Long-lived assets are reviewed for impairment in accordance with SFAS No. 121,
"Accounting for Impairment of Long-Lived Assets and for Long-Lived Assets to be
Disposed Of" as facts and circumstances indicate that the carrying amount may be
impaired. Specifically, the evaluation for impairment involves 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 as a charge to operations based on the difference between the
asset's carrying amount and its fair value. The same policy is currently
utilized for goodwill.

Regulation
Retail public utility operations affecting Indiana customers are subject to
regulation by the Indiana Utility Regulatory Commission (IURC), and retail
public utility operations affecting Ohio customers are subject to regulation by
the Public Utilities Commission of Ohio (PUCO). The Company's wholesale energy
transactions are subject to regulation by the Federal Energy Regulatory
Commission (FERC).

SFAS 71
The Company's accounting policies give recognition to the rate-making and
accounting practices of these agencies and to accounting principles generally
accepted in the United States, including the provisions of SFAS No. 71
"Accounting for the Effects of Certain Types of Regulation" (SFAS 71).
Regulatory assets represent probable future revenues associated with certain
incurred costs, which will be recovered from customers through the rate-making
process. Regulatory liabilities represent probable future reductions in revenues
associated with amounts that are to be credited to customers through the
rate-making process.

The Company continually assesses the recoverability of costs recognized as
regulatory assets and the ability to continue to account for its activities in
accordance with SFAS 71, 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 costs of deregulated plant and inventory assets.

Refundable or Recoverable Gas Costs, Fuel for Electric Production & Purchased
Power
All metered gas rates contain a gas cost adjustment clause that allows the
Company to charge for changes in the cost of purchased gas. Metered electric
rates typically contain a fuel adjustment clause that allows for adjustment in
charges for electric energy to reflect changes in the cost of fuel and the net
energy cost of purchased power. Metered electric rates also allow recovery,
through a quarterly rate adjustment mechanism, for the margin on electric sales
lost due to the implementation of demand side management programs.

The Company records any under-or-over-recovery resulting from gas and fuel
adjustment clauses each month in revenues. A corresponding asset or liability is
recorded until the under-or-over-recovery is billed or refunded to utility
customers. The cost of gas sold is charged to operating expense as delivered to
customers, and the cost of fuel for electric generation is charged to operating
expense when consumed.

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.

Impact of Recently Issued Accounting Guidance on Future Operations

SFAS 141 & 142

The FASB issued two new statements of financial accounting standards in July
2001: SFAS No. 141, "Business Combinations" (SFAS 141), and SFAS No. 142,
"Goodwill and Other Intangible Assets" (SFAS 142). These interrelated standards
change the accounting for business combinations and goodwill in two significant
ways:

SFAS 141 requires that the purchase method of accounting be used for all
business combinations initiated after June 30, 2001. Use of the
pooling-of-interests method is prohibited. This change does not affect the
pooling-of-interest transaction forming Vectren.

SFAS 142 changes the accounting for goodwill from an amortization approach to an
impairment-only approach. Thus, amortization of goodwill that is not included as
an allowable cost for rate-making purposes will cease upon adoption of the
statement. This includes goodwill recorded in past business combinations, such
as the Company's acquisition of the Ohio operations. Goodwill is to be tested
for impairment at a reporting unit level at least annually.

SFAS 142 also requires the initial impairment review of all goodwill and other
intangible assets within six months of the adoption date, which is January 1,
2002 for the Company. 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 would be
recognized. Results of the initial impairment review are to be treated as a
change in accounting principle in accordance with APB Opinion No. 20 "Accounting
Changes." An impairment loss recognized as a result of an impairment test
occurring after the initial impairment review is to be reported as a part of
operations.

SFAS 142 also changes certain aspects of accounting for intangible assets;
however, the Company does not have any significant intangible assets.

The adoption of SFAS 141 will not materially impact operations. As required by
SFAS 142, amortization of goodwill relating to the acquisition of the Ohio
operations, which approximates $5.0 million per year, will cease on January 1,
2002. Initial impairment reviews to be performed within six months of adoption
of SFAS 142 are not expected to have a significant impact on operations.

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. SFAS 143 is effective for fiscal years
beginning after June 15, 2002, with earlier application encouraged. The Company
is currently evaluating the impact that SFAS 143 will have on its operations.

SFAS 144

In October 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets" (SFAS 144). SFAS 144 develops one accounting
model for all impaired long-lived assets and long-lived assets to be disposed
of. SFAS 144 replaces the existing authoritative guidance in FASB Statement No.
121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to Be Disposed Of" and certain aspects of APB Opinion No. 30, "Reporting
Results of Operations-Reporting the Effects of Disposal of a Segment of a
Business."

This new accounting model retains the framework of SFAS 121 and requires that
those impaired long-lived assets and long-lived assets to be disposed of be
measured at the lower of carrying amount or fair value (less cost to sell for
assets to be disposed of), whether reported in continuing operations or in
discontinued operations. Therefore, discontinued operations will no longer be
measured at net realizable value or include amounts for operating losses that
have not yet occurred.

SFAS 144 also broadens the reporting of discontinued operations to include all
components of an entity with operations that can be distinguished from the rest
of the entity and that will be eliminated from the ongoing operations of the
entity in a disposal transaction.

SFAS 144 is effective for fiscal years beginning after December 15, 2001, with
earlier application encouraged. The Company is evaluating the impact SFAS 144
will have on its operations.

Financial Condition

The Company's equity capitalization objective is 40-55% of total capitalization.
This objective may have varied, and will vary, depending on particular business
opportunities and seasonal factors that affect the Company's operation. The
Company's equity component was 44% and 49% of total capitalization, including
current maturities of long-term debt and long-term debt subject to tender, at
December 31, 2001 and 2000, respectively.

Short-term cash working capital is required primarily to finance customer
accounts receivable, unbilled utility revenues resulting from cycle billing, gas
in underground storage, prepaid gas delivery services, capital expenditures, and
investments until permanently financed. Short-term borrowings tend to be
greatest during the summer when accounts receivable and unbilled utility
revenues related to electricity are highest and gas storage facilities are being
refilled. However, working capital requirements have been significantly higher
throughout 2001 due to the extraordinarily high natural gas costs early in 2001
and the acquisition of the Ohio operations, initially funded with short-term
borrowings.

The Company expects the majority of its capital expenditures and debt security
redemptions to be provided by internally generated funds; however, additional
financing may be required due to the possible early redemption of debt at
Indiana Gas and significant capital expenditures for NOx compliance equipment at
SIGECO.

VUHI's and Indiana Gas' credit ratings on outstanding senior unsecured debt at
December 31, 2001 are A-/A2. SIGECO's credit ratings on outstanding secured debt
at December 31, 2001 are A-/A1. VUHI's commercial paper has a credit rating of
A-2/P-1.

Cash Flow From Operations

The Company's primary source of liquidity to fund working capital requirements
has been cash generated from operations, which totaled approximately $119.5
million, $16.5 million, and $152.7 million, for the years ended December 31,
2001, 2000, and 1999, respectively.

Cash flow from operations increased during the year ended December 31, 2001
compared to 2000 by $103.0 million due primarily to favorable changes in working
capital accounts due to a return to lower gas prices.

Cash flow from operations decreased during 2000 as compared to 1999 by
approximately $136.2 million. The decrease is primarily attributable to merger
and integration costs, increased recoverable fuel and natural gas costs and
increased working capital requirements resulting from higher natural gas costs.

Financing Activities

Sources & Uses of Liquidity
At December 31, 2001, the Company has approximately $360.0 million of short-term
borrowing capacity, of which approximately $85.8 million is available. Included
in regulated capacity is VUHI's credit facility, which was renewed in June 2001
and extended through June 2002. As part of the renewal, the facility's capacity
decreased from $435.0 million to $350.0 million. Indiana Gas' $155.0 million
commercial paper program expired in 2001 and was not required and, therefore,
not renewed.

During the five-year period 2002-2006, maturities and sinking fund requirements
on long-term debt subject to mandatory redemption (in millions) are $1.3 in
2002, $17.3 in 2003, $16.3 in 2004, $1.3 in 2005, and $1.3 in 2006. Also during
the five-year period 2002-2006, exercisable put provisions on long-term debt (in
millions) are $11.5 in 2002, $0 in 2003, $3.5 in 2004, $10.0 in 2005 and $53.7
in 2006.

At December 31, 2001, $273.3 million of commercial paper was supported by the
VUHI facility whereby VUHI must maintain a rating of better than BB+/Ba1.

Financing Cash Flow. Cash flow required for financing activities of $31.6
million for the year ended December 31, 2001 includes $42.1 million of
reductions in net borrowings and $64.9 million in common stock dividends, offset
by additional capital contributions of $164.4 million. During 2001, $344.0
million of net proceeds from long-term debt issuances was utilized to pay down
short-term borrowings and to fund the construction of NOx compliance equipment.

Cash flow from financing activities of $566.0 million for the year ended
December 31, 2000 includes $623.1 million of additional net borrowings offset by
$55.0 million in common stock dividends. This is an increase of $596.2 million
over prior year due primarily to funding the acquisition of the Ohio operations
and increased working capital requirements.

Financing the Ohio Operations Purchase. On October 31, 2000, the acquisition of
the Ohio operations was completed for a purchase price of approximately $465.0
million. Commercial paper and $150.0 million in floating rate notes were issued

to fund the purchase. The floating rate notes' interest rate was equal to the
three-month US dollar LIBOR rate plus 0.75%. Concurrent with the completion of
this financing, an interest rate swap was executed which in effect resulted in a
fixed rate of 6.64%. During 2001, the Company has refinanced these interim
borrowing arrangements with permanent financing in the form of new equity and
long-term debt.

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

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

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

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

The Company has $31.5 million of adjustable rate pollution control series first
mortgage bonds and $22.2 million of adjustable rate pollution control series
unsecured senior notes which could, at the election of the bondholder, be
tendered to the Company when interest rates are reset. Prior to the latest reset
on March 1, 2001, the interest rates were reset annually, and the bonds were
presented as current liabilities. Effective March 1, 2001, the bonds were reset
for a five-year period and have been classified as long-term debt.

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

Capital Expenditures & Other Investment Activities

Cash required for investing activities of $146.1 million for the year ended
December 31, 2001 includes $145.8 million of requirements for capital
expenditures. Investing activities for the years ended December 31, 2000 and
1999 were $581.1 million and $122.2 million, respectively. The $458.9 million
increase occurring in 2000 is principally the result of the $463.3 million
acquisition of the Ohio operations.

Planned Capital Expenditures & Investments
New construction, normal system maintenance and improvements, and information
technology investments needed to provide service to a growing customer base will
continue to require substantial expenditures. Additionally, during the

three-year period 2002-2004, construction costs for NOx emissions control
equipment are estimated to total between $150.0 million and $170.0 million and
additional generation is planned. Planned capital expenditures for the five year
period 2002 - 2006 (in millions) are estimated as follows: $165.7 in 2002,
$234.3 in 2003, $134.4 in 2004, $119.4 in 2005, and $150.8 in 2006. These
amounts include expenditures for NOx compliance of approximately (in millions)
$35.9 in 2002, $101.3 in 2003 and $15.1 in 2004.

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, including, but
not limited to Vectren's realization of net merger savings, are forward-looking
statements. Such statements are based on management's beliefs, as well as
assumptions made by and information currently available to management. When used
in this filing, the words "believe," "anticipate," "endeavor," "estimate,"
"expect," "objective," "projection," "forecast," "goal," and similar expressions
are intended to identify forward-looking statements. In addition to any
assumptions and other factors referred to specifically in connection with such
forward-looking statements, factors that could cause the Company's actual
results to differ materially from those contemplated in any forward-looking
statements included, among others, the following:

|X| 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.

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

|X| 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.

|X| 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 natural gas
transmission, gathering and processing, and similar entities with
regulatory oversight.

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

|X| 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.

|X| Availability or cost of capital, resulting from changes in the
Company, including its security ratings, changes in interest rates,
and/or changes in market perceptions of the utility industry and other
energy-related industries.

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

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

|X| 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.

|X| Changes in federal, state or local legislature requirements, such as
changes in tax laws or rates, environmental laws and regulations.

The Company undertakes no obligation to publicly update or revise any
forward-looking statements, whether as a result of changes in actual results,
changes in assumptions, or other factors affecting such statements.

ITEM 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK

The Company is exposed to market 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.

Commodity Price Risk. The Company's regulated operations have limited exposure
to commodity price risk for purchases and sales of natural gas and electric
energy for its retail customers due to current Indiana and Ohio regulations,
which subject to compliance with applicable state regulations, allow for
recovery of such purchases through natural gas and fuel cost adjustment
mechanisms.

The Company does engage in limited, wholesale power marketing activities that
may expose the Company to commodity price risk associated with fluctuating
electric power prices. These power marketing activities manage the utilization
of its available electric generating capacity. Power marketing operations enter
into forward contracts that commit the Company to purchase and sell electric
power in the future.

Commodity price risk results from forward sales contracts that commit the
Company to deliver commodities on specified future dates. Power marketing uses
planned unutilized generation capability and forward purchase contracts to
protect certain sales transactions from unanticipated fluctuations in the price
of electric power, and periodically, will use derivative financial instruments
to protect its interests from unplanned outages and shifts in demand.

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

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

Interest Rate Risk. The Company is exposed to interest rate risk associated with
its adjustable rate borrowing arrangements. Its risk management program seeks to
reduce the potentially adverse effects that market volatility may have on
operations.

Under normal circumstances, the Company tries to limit the amount of adjustable
rate borrowing arrangements exposed to short-term interest rate volatility to a
maximum of 25% of total debt. However, there are times when this targeted level
of interest rate exposure may be exceeded. To manage this exposure, the Company

may periodically use derivative financial instruments to reduce earnings
fluctuations caused by interest rate volatility. At December 31, 2001, such
obligations represented 25% 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 including bank notes, lines of credit, commercial
paper, and certain adjustable rate long-term debt instruments. At December 31,
2001 and 2000, the combined borrowings under these facilities totaled $296.7
million and $682.8 million, respectively. Based upon average borrowing rates
under these facilities during the years ended December 31, 2001 and 2000, an
increase of 100 basis points (1%) in the rates would have increased interest
expense by $5.3 million and $2.2 million, respectively.

Other Risks. By using forward purchase contracts and derivative financial
instruments to manage risk, the Company exposes itself to counter-party credit
risk and market risk. The Company manages this exposure to counter-party credit
risk by entering into contracts with financially sound companies that can be
expected to fully perform under the terms of the contract. The Company attempts
to manage exposure to market risk associated with commodity contracts and
interest rates by establishing and monitoring parameters that limit the types
and degree of market risk that may be undertaken. As of December 31, 2001, the
Company has a net receivable from Enron Corp. of approximately $1.0 million,
which has been fully reserved.

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.

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, are 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'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 and Chief Executive Officer
January 24, 2002.

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

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. (an Indiana corporation) and subsidiary companies as of December
31, 2001 and 2000, and the related consolidated statements of income, common
shareholder's equity and cash flows for each of the three years in the period
ended December 31, 2001. These financial statements and the schedule referred to
below are the responsibility of the Company's management. Our responsibility is
to express an opinion on these financial statements and the schedule based on
our audits.

We conducted our audits in accordance with auditing standards generally accepted
in the United States. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. 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, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of Vectren Utility
Holdings, Inc. and subsidiary companies as of December 31, 2001 and 2000, and
the results of their operations and their cash flows for each of the three years
in the period ended December 31, 2001, in conformity with accounting principles
generally accepted in the United States.

As discussed in Note 14 to the consolidated financial statements, effective
January 1, 2001, the Company changed its method of accounting for derivative
instruments and hedging activities.

Our audits were made for the purpose of forming an opinion on the basic
financial statements taken as a whole. The schedule listed under Part IV Item
14(a)(2) is presented for the purpose of complying with the Securities and
Exchange Commission's rules and is not part of the basic financial statements.
The schedule has been subjected to the auditing procedures applied in the audits
of the basic financial statements and, in our opinion, fairly states in all
material respects the financial data required to be set forth therein in
relation to the basic financial statements taken as a whole.

/s/ Arthur Andersen LLP
Arthur Andersen LLP
Indianapolis, Indiana,
January 24, 2002.

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

At December 31,
--------------------
2001 2000
--------- ---------
ASSETS
Utility Plant
Original cost $ 2,903.2 $ 2,788.8
Less: Accumulated depreciation &
amortization 1,308.2 1,233.0
-------- ---------
Net utility plant 1,595.0 1,555.8
-------- ---------
Current Assets
Cash & cash equivalents 7.2 2.2
Accounts receivable-less reserves of
$5.6 & $5.6, respectively 125.3 173.3
Receivables from other Vectren companies 26.6 34.3
Accrued unbilled revenues 78.3 143.4
Inventories 55.3 93.3
Recoverable fuel & natural gas costs 76.5 96.1
Prepayments & other current assets 127.4 73.1
-------- ---------
Total current assets 496.6 615.7
-------- ---------

Investments in unconsolidated affiliates 4.0 1.0
Other investments 12.2 8.7
Non-utility property-net 6.3 5.6
Goodwill-net 193.1 198.0
Regulatory assets 61.4 56.3
Other assets 22.8 13.2
-------- ---------
TOTAL ASSETS $ 2,391.4 $ 2,454.3
======== ========

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

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

At December 31,
----------------------
2001 2000
---------- ---------
LIABILITIES & SHAREHOLDER'S EQUITY

Capitalization
Common shareholder's equity
Common stock (no par value) $ 385.7 $ 221.3
Retained earnings 329.0 350.5
Accumulated other comprehensive income (1.7) -
-------- --------
Total common shareholder's equity 713.0 571.8
-------- --------
Cumulative Preferred Stock of Subsidiary
Redeemable 0.5 8.1
Nonredeemable - 8.9
-------- --------
Total preferred stock 0.5 17.0
-------- --------
Short-term borrowings- refinanced - 129.4
Long-term debt- net of current maturities and debt
subject to tender 900.9 572.6
-------- --------
Total capitalization 1,614.4 1,290.8
-------- --------
Commitments & Contingencies (Notes 4-5, 11-13)

Current Liabilities
Accounts payable 79.0 91.9
Accounts payable to affiliated companies 36.5 147.4
Payables to other Vectren companies 11.5 25.4
Accrued liabilities 97.5 95.6
Short-term borrowings- net of amounts refinanced 274.2 374.0
Short-term borrowings to other Vectren companies - 6.9
Notes payable, 6.64% - 150.0
Long-term debt subject to tender 11.5 -
Current maturities of long-term debt 1.3 -
-------- --------
Total current liabilities 511.5 891.2
-------- --------

Deferred Credits & Other Liabilities
Deferred income taxes 171.8 184.6
Deferred credits & other liabilities 93.7 87.7
-------- --------
Total deferred credits & other liabilities 265.5 272.3
-------- --------
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY $ 2,391.4 $ 2,454.3
======== ========

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

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

Year Ended December 31,
----------------------------
2001 2000 1999
-------- -------- ------
OPERATING REVENUES
Gas revenues $ 1,031.5 $ 818.8 $ 499.6
Electric revenues 378.9 336.4 307.5
-------- -------- ------
Total operating revenues 1,410.4 1,155.2 807.1
-------- -------- ------
COST OF OPERATING REVENUES
Cost of gas sold 708.2 552.5 266.4
Fuel for electric generation 74.4 75.7 72.2
Purchased electric energy 91.7 36.4 20.8
-------- -------- ------
Total cost of operating revenues 874.3 664.6 359.4
-------- -------- ------
TOTAL OPERATING MARGIN 536.1 490.6 447.7

OPERATING EXPENSES
Other operating 234.7 209.9 187.5
Merger & integration costs 2.8 32.7 -
Restructuring costs 15.0 - -
Depreciation & amortization 96.9 82.4 79.5
Income taxes 22.7 34.9 43.2
Taxes other than income taxes 51.3 36.2 28.5
-------- -------- ------
Total operating expenses 423.4 396.1 338.7
-------- -------- ------
OPERATING INCOME 112.7 94.5 109.0

Other - net 5.0 5.0 4.3
Interest expense 70.1 46.1 36.8
Preferred dividend requirement
of subsidiary 0.8 1.0 1.1
-------- -------- ------
INCOME BEFORE CUMULATIVE EFFECT OF
CHANGE IN ACCOUNTING PRINCIPLE 46.8 52.4 75.4
-------- -------- ------
Cumulative effect of change in
accounting principle
principle - net of tax 3.9 - -
-------- -------- ------
NET INCOME $ 50.7 $ 52.4 $ 75.4
======== ======== ======

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

VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
Year Ended December 31,
--------------------------
2001 2000 1999
------ ------ ------
CASH FLOWS FROM OPERATING ACTIVITIES

Net income $ 50.7 $ 52.4 $ 75.4
Adjustments to reconcile net income to cash from
operating activities:
Depreciation & amortization 96.9 82.4 79.5
Deferred income taxes & investment tax credits (6.3) 5.2 2.0
Net unrealized gain on derivative instruments,
including cumulative effect of change in
accounting principle (3.1) - -
Other non-cash charges- net 18.4 7.6 16.7

Changes in assets and liabilities:
Accounts receivable, including to Vectren
companies & accrued unbilled revenue 105.7 (221.1) (13.6)
Inventories 38.0 15.9 10.9
Recoverable fuel & natural gas costs 19.6 (82.3) 0.3
Prepayments & other current assets (49.0) (36.8) (13.1)
Regulatory assets (1.5) (1.2) 3.0
Accounts payable, including to Vectren
companies & affiliated companies (130.7) 193.7 12.9
Accrued liabilities (8.4) 2.1 (8.1)
Other noncurrent assets & liabilities (10.8) (1.4) (13.2)
------ ------ ------
Total adjustments 68.8 (35.9) 77.3
------ ------ ------
Net cash flows from operating activities 119.5 16.5 152.7
------ ------ ------
CASH FLOWS FROM (REQUIRED FOR) FINANCING ACTIVITIES
Proceeds from:
Long-term debt- net of issuance costs 344.0 67.9 108.5
Additional capital contribution 164.4 - -
Short-term notes payable - 150.0 -
Other proceeds - 1.6 4.7
Requirements for:
Retirement of short-term notes payable (150.0) - -
Dividends on common stock (64.9) (55.0) (58.3)
Retirement of preferred stock of subsidiary (17.7) (2.0) -
Retirement of long-term debt (7.3) (0.7) (56.6)
Dividends on preferred stock of subsidiary (0.8) (1.0) (1.1)
Net change in short-term borrowings (236.1) 405.2 (27.4)
------ ------ ------
Net cash flows from (required for)
financing activities 31.6 566.0 (30.2)
------ ------ ------

CASH FLOWS (REQUIRED FOR) INVESTING ACTIVITIES
Capital expenditures (145.8) (110.7) (123.6)
Unconsolidated affiliate investments (3.0) - -
Acquisition of the Ohio operations - (463.3) -
Other investing proceeds (payments) 2.7 (7.1) 1.4
------ ------ ------
Net cash flows (required for) investing
activities (146.1) (581.1) (122.2)
------ ------ ------
Net increase in cash & cash equivalents 5.0 1.4 0.3

Cash & cash equivalents at beginning of period 2.2 0.8 0.5
------ ------ ------
Cash & cash equivalents at end of period $ 7.2 $ 2.2 $ 0.8
====== ====== ======

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

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

Accumulated
Other
Common Retained Comprehensive
Stock Earnings Loss Total
-------- -------- ------------- -------

Balance at December 31, 1998 $ 221.3 $ 344.8 $ - $ 566.1

Net income & comprehensive income 75.4 75.4

Common stock dividends (58.3) (58.3)
------- ------- ----- -------
Balance at December 31, 1999 221.3 361.9 - 583.2

Net income & comprehensive income 52.4 52.4

Common stock dividends (55.0) (55.0)
Contributions to parent (9.1) (9.1)
Other 0.3 0.3
------- ------- ----- -------
Balance at December 31, 2000 221.3 350.5 - 571.8

Comprehensive income:
Net income 50.7 50.7
Minimum pension liability adjustment
& other-net of tax (1.7) (1.7)
------- ------- ----- -------
Total comprehensive income 49.0
------- ------- ----- -------
Common stock:
Additional capital contribution 164.4 164.4
Dividends (64.9) (64.9)
Contributions to parent (6.1) (6.1)
Loss on extinquishment of preferred stock (1.2) (1.2)
------- ------- ----- -------
Balance at December 31, 2001 $ 385.7 $ 329.0 $ (1.7) $ 713.0
======= ======= ===== =======

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

VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

1. Organization and Nature of Operations

Overview
Vectren Utility Holdings, Inc. (VUHI or the Company), an Indiana corporation,
was formed on March 31, 2000 to serve as the intermediate holding company for
Vectren Corporation's (Vectren) three operating public utilities, Indiana Gas
Company, Inc. (Indiana Gas), formerly a wholly owned subsidiary of Indiana
Energy, Inc. (Indiana Energy), Southern Indiana Gas and Electric Company
(SIGECO), formerly a wholly owned subsidiary of SIGCORP, Inc. (SIGCORP), and the
Ohio operations (defined hereafter).

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

Acquisition of the Natural Gas Distribution Assets of The Dayton Power and Light
Company
On October 31, 2000, the Company acquired the natural gas distribution assets of
The Dayton Power and Light Company for approximately $465.0 million. The
acquisition has been accounted for as a purchase transaction in accordance with
APB 16, and accordingly, the results of operations of the acquired businesses
are included in the accompanying financial statements since the date of
acquisition.

The purchase price was allocated to the assets and liabilities acquired based on
the fair value of those assets and liabilities as of the acquisition date.
Because of the regulatory environment in which the Ohio operations operate, the
book value of rate-regulated assets and liabilities is generally considered to
be fair value. Goodwill, in the amount of $198.0 million, has been recognized
for the excess amount of the purchase price paid over the fair value of the net
assets acquired. Prior to the Company's adoption of Statement of Financial
Accounting Standards (SFAS) No.142 "Goodwill and Intangible Assets" on January
1, 2002, this goodwill was amortized on a straight-line basis over 40 years.
(See Note 17 for further information on the adoption of this standard.)

Had the acquisition of the Ohio operations occurred on January 1, 1999, pro
forma operating revenues and net income for the year ended December 31, 2000
would have been $1,339.5 million and $51.0 million, respectively. For the year
ended December 31, 1999, pro forma operating revenues and net income would have

been $1,026.0 million and $72.1 million, respectively. This pro forma
information is not necessarily indicative of the results that actually would
have occurred if the transaction had been consummated at the beginning of the
periods presented and is not intended to be a projection of future results.
These pro forma results are unaudited.

2. Summary of Significant Accounting Policies

A. Principles of Consolidation
The accompanying consolidated financial statements for periods prior to March
31, 2000 reflect the Company on a historical basis as restated for the effects
of the combination of entities under common control whereby Indiana Gas and
SIGECO became subsidiaries of VUHI. The consolidated financial statements
include the accounts of VUHI and its wholly owned subsidiaries, after
elimination of intercompany transactions. However, the Company's results of
operations are presented prior to certain reclassifications necessary to conform
to the financial statement presentation of Vectren.

For the three months ended March 31, 2000, operating revenues and net income
contributed by the predecessor companies were $171.6 million and $8.8 million,
respectively, by Indiana Gas and $102.2 million and $4.0 million, respectively,
by SIGECO. For the year ended December 31, 1999, operating revenues and net
income contributed were $431.4 million and $29.7 million, respectively, by
Indiana Gas and $375.7 million and $45.7 million, respectively by SIGECO.

B. 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.

C. Cash and Cash Equivalents
All highly liquid investments with an original maturity of three months or less
at the date of purchase are considered cash equivalents. Cash paid during the
periods reported for interest, income taxes and acquired assets and liabilities
are as follows:
Year Ended December 31,
----------------------------
In millions 2001 2000 1999
------- -------- -------
Cash paid during the year for
Interest (net of amount capitalized) $ 62.9 $ 45.2 $ 32.1
Income taxes 46.7 44.8 42.4
------ -------- -------
Details of acquisition (Note 1)
Book value of assets acquired $ - $ 278.1 $ -
Liabilities assumed - 7.9 -
------ -------- -------
Net assets acquired $ - $ 270.2 $ -
====== ======== =======

D. Inventories
Inventories consist of the following:
At December 31,
-------------------
In millions 2001 2000
------- -------
Gas in storage - at LIFO cost $ 24.3 $ 19.0
Materials & supplies 17.0 15.3
Fuel (coal and oil) for electric generation 9.5 4.1
Emission allowances 1.4 3.9
Gas in storage - at average cost 0.8 49.4
Other 2.3 1.6
------- -------
Total inventories $ 55.3 $ 93.3
======= =======

Based on the average cost of gas purchased during December, the cost of
replacing the current portion of gas in storage carried at LIFO cost exceeded
LIFO cost at December 31, 2001 and 2000 by approximately $17.9 million and $64.3
million, respectively. All other inventories are carried at average cost.

E. Utility Plant and Depreciation
Utility plant is stated at historical cost, including an allowance for the cost
of funds used during construction (AFUDC). Depreciation of utility plant 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, is as follows:

At and For the Year Ended December 31,
-------------------------------------------------
In millions 2001 2000
------------------------ -----------------------
Depreciation Depreciation
Rates as a Rates as a
Original Percent of Original Percent of
Cost Original Cost Cost Original Cost
-------- ------------- -------- -------------

Gas utility plant $1,523.0 3.6% $1,543.9 3.6%
Electric utility plant 1,148.9 3.3% 1,136.8 3.3%
Common utility plant 41.3 2.6% 47.3 3.3%
Construction work in progress 190.0 - 60.8 -
-------- ------------- -------- -------------
Total original cost $2,903.2 $2,788.8
======== ============= ======== =============

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 is as follows:

Year Ended December 31,
------------------------------
In millions 2001 2000 1999
--------- --------- -------
AFUDC - borrowed funds $ 2.1 $ 2.3 $ 3.1
AFUDC - equity funds 2.5 2.6 0.7
------- ------- -------
Total AFUDC capitalized $ 4.6 $ 4.9 $ 3.8
======= ======= =======

Maintenance and repairs, including the cost of removal of minor items of
property and planned major maintenance projects, are charged to expense as
incurred. When property that represents a retirement unit is replaced or
removed, the cost of such property is credited to utility plant, and such cost,
together with the cost of removal less salvage, is charged to accumulated
depreciation.

F. Impairment Review of Long-Lived Assets
Long-lived assets are reviewed for impairment in accordance with SFAS No. 121,
"Accounting for Impairment of Long-Lived Assets and for Long-Lived Assets to be
Disposed Of" as facts and circumstances indicate that the carrying amount may be
impaired. Specifically, the evaluation for impairment involves 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 as a charge to operations based on the difference between the
asset's carrying amount and its fair value. (See Note 17 for further information
on the adoption of SFAS 144, "Accounting for the Impairment or Disposal of
Long-Lived Assets.") The same policy is currently utilized for goodwill.

G. Regulation
Retail public utility operations affecting Indiana customers are subject to
regulation by the Indiana Utility Regulatory Commission (IURC), and retail
public utility operations affecting Ohio customers are subject to regulation by
the Public Utilities Commission of Ohio (PUCO). The Company's wholesale energy
transactions are subject to regulation by the Federal Energy Regulatory
Commission (FERC).

At December 31,
----------------
In millions 2001 2000
------- -------
Demand side management programs $ 26.2 $ 26.2
Unamortized debt discount & expenses 21.5 16.7
Other 13.7 13.4
------ ------
Total regulatory assets $ 61.4 $ 56.3
====== ======

As of December 31, 2001, $38.8 million of regulatory assets is reflected in
rates charged to customers. The remaining $22.6 million, which is not yet
included in rates, represents electric demand side management (DSM) costs
incurred after 1993. The Company is currently recovering $3.6 million of DSM
costs in rates. Based upon this prior regulatory authority, management believes
that future recovery of DSM costs not currently included in rates is probable.
At December 31, 2001 and 2000, the weighted average recovery period of
regulatory assets included in rates is 23.1 years and 23.3 years, respectively.

H. Comprehensive Income
Comprehensive income is a measure of all changes in equity that result from the
transactions or other economic events during the period from non-shareholder
transactions. This information is reported in the Consolidated Statements of
Common Shareholders' 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).

I. Revenues
Revenues are recorded as products and services are delivered to customers. To
more closely match revenues and expenses, the Company records revenues for all
gas and electricity delivered to customers but not billed at the end of the
accounting period.

J. Excise Taxes
Excise taxes are included in rates charged to customers. Accordingly, the
Company records excise tax received as a component of operating revenues. Excise
taxes paid are recorded as a component of taxes other than income taxes.

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

L. Reclassifications
Certain reclassifications have been made to the prior years' financial
statements to conform to the current year presentation. These reclassifications
have no impact on net income previously reported.

3. Special Charges

Merger and Integration Costs
Merger and integration costs incurred for the years ended December 31, 2001 and
2000 were $2.8 million and $32.7 million, respectively. Merger and integration
activities, resulting from the 2000 merger were completed in 2001. Merger costs
are reflected in the financial statements of the operating subsidiaries in which
merger savings are expected to be realized.

Since March 31, 2000, $35.5 million has been expensed associated with merger and
integration activities. Accruals were established at March 31, 2000 totaling
$19.3 million. Of this amount, $5.5 million related to employee and executive
severance costs, $11.7 million related to transaction costs and regulatory
filing fees incurred prior to the closing of the merger, and the remaining $2.1
million related to employee relocations that occurred prior to or coincident
with the merger closing. At December 31, 2001, the remaining accrual related to
employee severance was not significant. The remaining $16.2 million was expensed
($13.4 million in 2000 and $2.8 million in 2001) for accounting fees resulting
from merger related filing requirements, consulting fees related to integration
activities such as organization structure, employee travel between company
locations, internal labor of employees assigned to integration teams, investor
relations communication activities, and certain benefit costs.

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

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

Restructuring and Related Charges
As part of continued cost saving efforts, in June 2001, Vectren's management and
the board of directors approved a plan to restructure, primarily, its regulated
operations. The restructuring plan involves 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 has 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 incurred through
December 31, 2001. Components of restructuring expense incurred through December
31, 2001 are as follows:

Accrual for Incurred Expenses
Expected ------------------------ Total
In millions Cash Payments Paid in Cash Non-Cash Expense
------------- ------------ -------- -------
Severance & related costs $ 1.3 $ 5.5 $ 0.8 $ 7.6
Lease termination fees 3.0 - 1.0 4.0
Consulting fees & other - 3.4 - 3.4
------ ------ ------ -------
Total $ 4.3 $ 8.9 $ 1.8 $ 15.0
====== ====== ====== =======

The $7.6 million expensed for employee severance and related costs are
associated with approximately 100 employees. Employee separation benefits
include severance, healthcare and outplacement services. As of December 30,
2001, approximately 80 employees have exited the business. The restructuring
program was completed during 2001, except for the departure of the remaining
employees impacted by the restructuring and the final settlement of the lease
obligation.

Components of the accrual for expected cash payments, which is included in
accrued liabilities, as of December 31, 2001 is as follows:

Accrual at Accrual at
June 30, Cash December 31,
In millions 2001 Payments Additions 2001
------- -------- --------- -------
Severance & related costs $ 6.2 $ (4.9) $ - $ 1.3
Lease termination fees 2.0 - 1.0 3.0
----- ------ ----- -----
Total $ 8.2 $ (4.9) $ 1.0 $ 4.3
===== ====== ===== =====

4. Transactions with Other Vectren Companies

Support Services and Purchases
Vectren and certain subsidiaries of Vectren have provided corporate, general and
administrative services to the Company including legal, finance, tax, risk
management, and human resources. The costs have been allocated to the Company
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.
VUHI received corporate allocations totaling $116.9 million, $65.2 million, and
$31.4 million for the years ended December 31, 2001, 2000, and 1999,
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, 2001, 2000, and
1999, totaled $35.6 million, $25.7 million, and $20.5 million, respectively.

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

Vectren's three operating utility companies, SIGECO, Indiana Gas, and VEDO are
guarantors of VUHI's $350.0 million commercial paper program, of which $273.3
million is outstanding at December 31, 2001 and VUHI's $350.0 million unsecured
senior notes outstanding at December 31, 2001. VUHI has no significant
independent assets or operations other than the assets and operations of these
operating utility companies. These guarantees are full and unconditional and
joint and several.

Stock-Based Incentive Plans
The Company does not have stock-based compensation plans separate from Vectren.
Employees participate in Vectren's stock-based compensation plans that provide
for awards of restricted stock and stock options to purchase Vectren common
stock at prices equal to the fair value of the underlying shares at the date of
grant. Consistent with Vectren, the Company accounts for participation in these
plans in accordance with APB Opinion No. 25, "Accounting for Stock Issued to
Employees" and related interpretations in measuring compensation costs for its
stock options. Had compensation cost for stock options been determined
consistent with SFAS No. 123, "Accounting for Stock-based Compensation," a fair
value based model, net income would not have been materially different than
reported net income.

Resulting from the merger of Indiana Energy and SIGCORP into Vectren, other
operating expense includes approximately $1.0 million of compensation expense
related to the issuance of approximately 48,000 shares of restricted stock to
individuals employed by Indiana Energy at the merger date.

5. Transactions with Vectren Affiliates

ProLiance Energy, LLC
Vectren has an ownership interest in ProLiance Energy, LLC (ProLiance), a
nonregulated, energy marketing affiliate. ProLiance began providing natural gas
and related services to Indiana Gas, Citizens Gas and Coke Utility (Citizens
Gas) and others in April 1996. ProLiance also provides services to the Ohio
operations.

Purchases from ProLiance for resale and for injections into storage for the
years ended December 31, 2001, 2000, and 1999 totaled $610.6 million, $478.9
million, and $240.7 million, respectively. Amounts charged by ProLiance are
market based as evidenced by a competitive bidding process for capacity and
storage services and commodity indexes.

Other Affiliate Transactions
Vectren has ownership interests in other companies that provide materials
management, underground construction and repair, facilities locating, and meter
reading to the Company. Fees for these services and construction-related
expenditures totaled $30.4 million, $6.9 million, and $5.9 million,
respectively, for the years ended December 31, 2001, 2000, and 1999. Amounts
charged by these affiliates are market based.

Payables to Affiliates
Amounts owed to unconsolidated affiliates of Vectren approximated $36.5 million
and $147.4 million at December 31, 2001 and 2000, respectively, and are included
in accounts payable to affiliated companies.

6. Common Shareholder's Equity

As of December 31, 2000 the Company had classified $129.4 million of commercial
paper as short-term borrowings- refinanced in capitalization in the Consolidated
Balance Sheets. In February 2001, the Company repaid $129.4 million of
commercial paper with proceeds received from an equity contribution by Vectren.
Vectren funded the contribution with the proceeds from an offering of its common
stock. In December 2001, Vectren made an additional equity contribution of $35.0
million with proceeds received from dividends paid by Vectren's nonregulated
operations. This contribution was also used to repay short-term borrowings.

7. Cumulative Preferred Stock of Subsidiary

Nonredeemable
Nonredeemable preferred stock contains call options that were exercised 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 and as of December 31, 2000, there were 85,519 shares of the 4.80%
Series outstanding and 3,000 shares of the 4.75% Series outstanding.

Redeemable
In September 2001, the 6.50%, $100 par value preferred stock 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 and as of
December 31, 2000, there were 75,000 shares outstanding.

As the preferred stock redeemed was that of a subsidiary, the loss on redemption
of $1.2 million in 2001 is reflected in retained earnings. The total redemption
price was $17.7 million.

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, 2001 and
2000, there were 4,597 shares and 5,757 shares outstanding, respectively.

8. Borrowing Arrangements

Long-Term Debt
Senior unsecured obligations and first mortgage bonds outstanding and classified
as long-term are as follows:

At December 31,
----------------
In millions 2001 2000
------ ------
VUHI
Fixed Rate Senior Unsecured Notes
2011, 6.625% $ 250.0 $ -
2031, 7.25% 100.0 -
------ ------
Total VUHI 350.0 -
------ ------
SIGECO
First Mortgage Bonds
Fixed Rate:
2003, 1978 Series B, 6.25%, tax exempt 1.0 1.0
2016, 1986 Series, 8.875% 13.0 13.0
2023, 1993 Series, 7.60% 45.0 45.0
2023, 1993 Series B, 6.00% 22.8 22.8
2025, 1993 Series, 7.625% 20.0 20.0
2029, 1999 Senior Notes, 6.72% 80.0 80.0
Adjustable Rate:
2015, 1985 Pollution Control Series A, presently
4.30%, tax exempt, next rate adjustment: 2004 10.0 10.0
2025, 1998 Pollution Control Series A, presently
4.75%, tax exempt, next rate adjustment: 2006 31.5 31.5
2024, 2000 Environmental Improvement Series A,
tax exempt, adjusts every 35 days, weighted
average for year: 3.13% 22.5 22.5
------ ------
Total First Mortgage Bonds 245.8 245.8
------ ------
Adjustable Rate Senior Unsecured Bonds
2020, 1998 Pollution Control Series B, presently
4.40%, tax exempt, next rate adjustment: 2003 4.6 4.6
2030, 1998 Pollution Control Series B, presently
4.40%, tax exempt, next rate adjustment: 2003 22.0 22.0
2030, 1998 Pollution Control Series C, presently
5.00%, tax exempt, next rate adjustment: 2006 22.2 22.2
------ ------
Total Adjustable Rate Senior Unsecured Bonds 48.8 48.8
====== ======
Total SIGECO 294.6 294.6
------ ------

At December 31,
--------------
In millions 2001 2000
---- -----
Indiana Gas
Fixed Rate Senior Unsecured Notes
2003, Series F, 5.75% 15.0 15.0
2004, Series F, 6.36% 15.0 15.0
2007, Series E, 6.54% 6.5 6.5
2013, Series E, 6.69% 5.0 5.0
2015, Series E, 7.15% 5.0 5.0
2015, Insured Quarterly, 7.15% 20.0 20.0
2015, Series E, 6.69% 5.0 5.0
2015, Series E, 6.69% 10.0 10.0
2021, Private Placement, 9.375%, $1.3
due annually in 2002 25.0 25.0
2021, Series A, 9.125% - 7.0
2025, Series E, 6.31% 5.0 5.0
2025, Series E, 6.53% 10.0 10.0
2027, Series E, 6.42% 5.0 5.0
2027, Series E, 6.68% 3.5 3.5
2027, Series F, 6.34% 20.0 20.0
2028, Series F, 6.75% 13.8 14.1
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% 50.0 50.0
------ ------
Total Indiana Gas 273.8 281.1
------ ------

Total long-term debt outstanding 918.4 575.7
Less: Debt subject to tender 11.5 -
Maturities & sinking fund requirements 1.3 -
Unamortized debt premium & discount - net 4.7 3.1
------ ------
Total long-term debt-net $ 900.9 $ 572.6
====== ======

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

These issues have no sinking fund requirements, and interest payments are due
quarterly for the October Notes and semi-annually for the December Notes. The
October Notes are due October 2031, but may be called by the Company, in whole
or in part, at any time after October 2006 at 100% of the principal amount plus
any accrued interest thereon. The December Notes are due December 2011, but may
be called by the Company, in whole or in part, at any time for an amount equal
to accrued and unpaid interest, plus the greater of 100% of the principal amount
of the notes to be redeemed 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 the hedging
arrangements (see Note 14) totaled $344.0 million and were used to reduce
existing debt outstanding under VUHI's short-term borrowing arrangements.

As more fully described in Note 4, both issues are guaranteed by VUHI's three
operating utility companies: SIGECO, Indiana Gas, and VEDO.

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

Long-Term Debt Sinking Fund Requirements & Maturities
The annual sinking fund requirement of SIGECO's first mortgage bonds is 1% of
the greatest amount of bonds outstanding under the Mortgage Indenture. This
requirement may be satisfied by certification to the Trustee of unfunded
property additions in the prescribed amount as provided in the Mortgage
Indenture. SIGECO intends to meet the 2002 sinking fund requirement by this
means and, accordingly, the sinking fund requirement for 2002 is excluded from
current liabilities in the Consolidated Balance Sheets. At December 31, 2001,
$279.3 million of SIGECO's utility plant remained unfunded under SIGECO's
Mortgage Indenture.

Consolidated maturities and sinking fund requirements on long-term debt subject
to mandatory redemption during the five years following 2001 (in millions) are
$1.3 in 2002, $17.3 in 2003, $16.3 in 2004, $1.3 in 2005, and $1.3 in 2006.

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. 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 2001 (in millions) is $11.5 in 2002, $3.5 in 2004, $10.0 in 2005,
$53.7 in 2006 and $140.0 thereafter.

Of these debt instruments containing put options, the Company has $31.5 million
of adjustable rate pollution control series first mortgage bonds and $22.2
million of adjustable rate pollution control series unsecured senior notes which
could, at the election of the bondholder, be tendered to the Company when
interest rates are reset. Prior to the latest reset on March 1, 2001, the
interest rates were reset annually, and the bonds were presented as current
liabilities. Based on the new terms, these bonds are classified as long-term
debt.

Short-Term Borrowings
At December 31, 2001, the Company has approximately $360.0 million of short-term
borrowing capacity, of which approximately $85.8 million is available. Included
in regulated capacity is VUHI's credit facility, which was renewed in June 2001
and extended through June 2002. As part of the renewal, the facility's capacity
decreased from $435.0 million to $350.0 million. Indiana Gas' $155.0 million
commercial paper program expired in 2001 and was not required and, therefore,
not renewed. See the table below for interest rates and outstanding balances.

Year ended December 31,
----------------------------
2001 2000 1999
------- ------- ------

Weighted average total outstanding during the year $ 356.1 $ 190.0 $ 92.5

Weighted average interest rates during the year:
Commercial paper 4.39% 6.62% 6.30%
Bank loans 5.77% 6.60% 6.26%

At December 31,
---------------
In millions 2001 2000
------ ------
Commercial paper $ 273.3 $ 463.3
Bank loans 0.9 40.1
------ ------
Total short-term borrowings 274.2 503.4
------ ------
Less short-term borrowings- refinanced - 129.4
------ ------
Total short-term borrowings- net of
amounts refinanced $ 274.2 $ 374.0
====== ======

As more fully described in Note 4, VUHI's commercial paper program is guaranteed
by its three operating utility companies: SIGECO, Indiana Gas, and VEDO.

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, 2001, the Company was in
compliance with all financial covenants.

9. Income Taxes

Vectren and subsidiary companies file a consolidated federal income tax return.
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
are as follows:

Year Ended December 31,
------------------------
In millions 2001 2000 1999
------ ------ ------
Current:
Federal $ 16.6 $ 26.8 $ 35.5
State 3.4 2.9 5.7
----- ----- -----
Total current taxes 20.0 29.7 41.2
----- ----- -----

Deferred:
Federal 4.9 6.0 3.6
State 0.1 1.6 0.8
----- ----- -----
Total deferred taxes 5.0 7.6 4.4
----- ----- -----

Amortization of investment
tax credits (2.3) (2.4) (2.4)
----- ----- -----

Total income tax expense $ 22.7 $ 34.9 $ 43.2
===== ===== =====

A reconciliation of the Federal statutory rate to the effective income tax rate
is as follows:

Year Ended December 31,
--------------------------
2001 2000 1999
------ ------ ------
Statutory rate 35.0% 35.0% 35.0%
State and local taxes- net of Federal
benefit 3.3 3.4 3.6
Nondeductible merger costs - 4.8 -
Amortization of investment tax credit (3.3) (2.7) (2.0)
All other- net (2.3) (0.5) (0.2)
------ ------ ------
Effective tax rate 32.7% 40.0% 36.4%
====== ====== ======

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 as of
December 31, 2001 and 2000 are as follows:

At December 31,
------------------
In millions 2001 2000
------- -------
Deferred tax liabilities:
Depreciation and cost recovery timing differences $ 186.0 $ 178.7
Deferred fuel costs- net 22.7 20.3
Regulatory assets recoverable through future rates 33.4 34.0
Deferred tax assets:
Regulatory liabilities to be settled through future rates (25.2) (22.0)
LIFO inventory (2.0) (7.9)
Tax credit carryforward - (9.0)
Other - net (22.4) (6.1)
------- -------
Net deferred tax liability $ 192.5 $ 188.0
======= =======

The Company has no tax credit carryforwards at December 31, 2001. At December
31, 2000, the Company has Alternative Minimum Tax Credit carryforwards of
approximately $9.0 million which were utilized in 2001.

10. Retirement Plans and Other Postretirement Benefits

Effective July 1, 2000, the SIGCORP and Indiana Energy defined benefit pension
plans, defined contribution retirement savings plans, and postretirement health
care plans and life insurance plans for employees not covered by a collective
bargaining agreement were merged. The merged plans became Vectren plans, and as
a result, the respective plan assets and plan obligations were transferred to
Vectren through cash payment for assets and cash receipt for obligations. These
transfers resulted in no gain or loss.

Both Indiana Gas and SIGECO continue to maintain defined benefit pension and
other postretirement benefit plans which cover eligible full-time hourly and
salaried employees covered by collective bargaining arrangements. Because
employees of other Vectren companies also participate in the plans, a portion of
the benefit cost and net amount recognized is allocated to those companies. The
plans are primarily non-contributory. The non-pension plans include plans for
health care and life insurance through a combination of self-insured and fully
insured plans.

The detailed disclosures of benefit components that follow are based on an
actuarial valuation performed as of and for the years ended December 31, 2001
and 2000 and use a measurement date as of September 30. The disclosures required
for the year ended December 31, 1999 have been restated based on actuarial
valuations previously performed for SIGCORP as of December 31 and Indiana Energy
as of September 30. In management's opinion, disclosures from revised actuarial
valuations would not differ materially from those presented below.

A summary of the components of net periodic benefit cost for the three years
ended December 31, 2001 is as follows:

Year Ended December 31,
-----------------------
Pension Benefits Other Benefits
--------------------------- ---------------------------
In thousands 2001 2000 1999 2001 2000 1999
------------- ------- ------- ------- ------- ------- -------

Service cost $ 2.8 $ 2.6 $ 4.6 $ 1.0 $ 1.3 $ 1.5
Interest cost 6.1 6.7 10.5 5.8 5.9 4.9
Expected return on plan assets (7.5) (8.6) (13.8) (0.8) (0.8) (0.8)
Amortization of prior service cost 0.4 0.2 0.3 - - -
Amortization of transitional
obligation (asset) (0.6) (0.7) (0.7) 3.0 3.7 3.3
Amortization of actuarial gain (0.3) (0.6) (0.2) (1.0) (1.5) (0.9)
Settlement, curtailment, & other
charges (credits) (1.4) 0.8 - (0.6) - -
------- ------- ------- ------- ------- -------
Net plan periodic benefit cost (0.5) 0.4 0.7 7.4 8.6 8.0
Less: Allocations to other Vectren
companies - - - 0.6 0.2 0.2
------- ------- ------- ------- ------- -------
Net VUHI periodic benefit cost $ (0.5) $ 0.4 $ 0.7 $ 6.8 $ 8.4 $ 7.8
======= ======= ======= ======= ======= =======

A reconciliation of the plans' benefit obligations, fair value of plan assets,
funded status and amounts recognized in the Consolidated Balance Sheets at
December 31, 2001 and 2000 follows:

Pension Benefits Other Benefits
---------------- ---------------
In millions 2001 2000 2001 2000
------ ------- ------ ------
Benefit Obligation:
Benefit obligation at beginning
of year $ 75.1 $ 151.0 $ 77.4 $ 68.3
Service cost - benefits earned
during the year 2.8 2.6 1.0 1.3
Interest cost on projected
benefit obligation 6.1 6.7 5.8 5.9
Plan amendments 4.0 - - (0.7)
Transfers - (84.1) - -
Settlements & (curtailments) (1.5) 0.7 (0.6) -
Benefits paid (4.5) (5.0) (1.7) (5.4)
Actuarial loss 4.0 3.2 1.7 8.0
----- ------ ----- -----
Benefit obligation at end of year $ 86.0 $ 75.1 $ 83.6 $ 77.4
===== ====== ===== =====

Fair Value of Plan Assets:
Plan assets at fair value at
beginning of year $ 90.0 $ 187.3 $ 11.2 $ 11.7
Actual return on plan assets (11.6) 10.6 (1.6) 0.6
Employer contributions - - 0.9 4.3
Transfers - (102.9) - -
Benefits paid (4.5) (5.0) (1.7) (5.4)
----- ------ ----- -----
Fair value of plan assets at
end of year $ 73.9 $ 90.0 $ 8.8 $ 11.2
===== ====== ===== =====

Pension Benefits Other Benefits
--------------- ---------------
In millions 2001 2000 2001 2000
------ ------ ------ ------
Funded Status: $ (12.1) $ 14.9 $ (74.8) $ (66.2)
Unrecognized transitional
obligation (asset) (0.8) (1.5) 34.9 40.0
Unrecognized service cost 3.3 1.4 - -
Unrecognized net (gain) loss
and other 8.6 (16.4) (12.9) (20.1)
------ ------ ------ ------
Net amount recognized for plans (1.0) (1.6) (52.8) (46.3)
Less: Allocations to other
Vectren companies - - (5.4) (2.4)
------ ------ ------ ------
Net amount recognized for VUHI $ (1.0) $ (1.6) $ (47.4) $ (43.9)
====== ====== ====== ======

As of December 31, 2001 the Company incurred an additional minimum pension
liability of approximately $6.2 million which is included in deferred credits
and other liabilities. This liability is offset by an intangible asset of
approximately $2.4 million which is included in other noncurrent assets and a
pre-tax charge to accumulated comprehensive income approximating $3.8 million.
At both December 31, 2001 and 2000 the net amount recognized for postretirement
obligations is included in deferred credits and other liabilities.

At December 31, 2001, all pension plans had accumulated benefit obligations in
excess of plan assets. The accumulated benefit obligation for the Company's
plans was $76.3 million. At December 31, 2000, all pension plans had plan assets
in excess of their accumulated benefit obligation.

Weighted-average assumptions used in the accounting for these plans were as
follows:

Pension Benefits Other Benefits
---------------- --------------
2001 2000 2001 2000
---- ---- ----- ----
Discount rate 7.25% 7.75% 7.25% 7.75%
Expected return on plan assets 9.00% 8.50% 9.00% 9.00%
Rate of compensation increase 4.75% 5.25% 4.75% 5.25%
CPI rate N/A N/A 12.00% 7.00%
---- ---- ----- ----

As of December 31, 2001, the health care cost trend is 12.0% declining to 5.0%
in 2006 and remaining level thereafter. Future changes in health care costs,
work force demographics, interest rates, or plan changes could be significantly
affect the estimated cost of these future benefits.

A 1.0% change in the assumed health care cost trend for the postretirement
health care plan would have the following effects as of and for the year ended
December 31, 2001:

In millions 1% Increase 1% Decrease
------------------------------------------------------------------------------
Effect on the aggregate of the service & interest
cost components $ 0.6 $ (0.5)
Effect on the postretirement benefit obligation 5.5 (4.5)
------------------------------------------------------------------------------

The Company has adopted Voluntary Employee Beneficiary Association Trust
Agreements for the funding of postretirement health benefits for retirees and
their eligible dependents and beneficiaries. Annual funding is discretionary and
is based on the projected cost over time of benefits to be provided to cover
persons consistent with acceptable actuarial methods. To the extent these
postretirement benefits are funded, the benefits are not liabilities in these
consolidated financial statements.

11. Commitments and Contingencies

Construction Commitments
The Company has entered into a contract to purchase and construct an 80-megawatt
combustion gas turbine generator. The total cost of the project is estimated to
be $33.0 million and is expected to be completed by the summer of 2002. Through
December 31, 2001 $23.2 million has been expended.

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 12 regarding the
Culley Generating Station Litigation and Note 5 regarding ProLiance Energy, LLC.

12. 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
United States Environmental Protection Agency (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.

Based on the level of system-wide emissions reductions required and the control
technology utilized to achieve the reductions, the current estimated
construction cost ranges from $175.0 million to $195.0 million and is expected
to be expended during the 2001-2004 period. Through December 31, 2001, $22.5
million has been expended. After the equipment is installed and operational,
related additional annual operation and maintenance expenses are estimated to be
between $8.0 million and $10.0 million.

compliant with Indiana's NOx emissions budget allotted by the USEPA; therefore,
the Company has recorded no accrual for potential penalties that may result from
noncompliance.

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

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

SIGECO believes it performed only maintenance, repair and replacement activities
at the Culley Generating Station, as allowed under the Act. Because proper
maintenance does not require permits, application of the best available control
technology, notice to the USEPA, or compliance with new source performance
standards, SIGECO believes that the lawsuit is without merit, and intends to
vigorously defend itself.

The lawsuit seeks fines against SIGECO in the amount of $27,500 per day per
violation. The lawsuit does not specify the number of days or violations the
USEPA believes occurred. The lawsuit also seeks a court order requiring SIGECO
to install the best available emissions technology at the Culley Generating
Station. If the USEPA were successful in obtaining an order, SIGECO estimates
that it would incur capital costs of approximately $40.0 million to $50.0
million to comply with the order. As a result of the NOx SIP call issue, the
majority of the $40.0 million to $50.0 million for best available emissions
technology at Culley Generating Station is included in the $175.0 million to
$195.0 million cost range previously discussed.

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

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

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

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

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

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

13. Rate and Regulatory Matters

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

Purchased Power Costs
As a result of an appeal of a generic order issued by the IURC in August 1999
regarding guidelines for the recovery of purchased power costs, SIGECO entered
into a settlement agreement with the OUCC that provides certain terms with

respect to the recoverability of such costs. The settlement, originally approved
by the IURC in August 2000, has been extended by agreement through March 2002
and additional settlement discussions are expected in 2002. 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.

14. Risk Management, Derivatives and Other Financial Instruments

Risk Management
The Company is exposed to market 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.

Commodity Price Risk The Company's regulated operations have limited exposure to
commodity price risk for purchases and sales of natural gas and electric energy
for its retail customers due to current Indiana and Ohio regulations, which
subject to compliance with applicable state regulations, allow for recovery of
such purchases through natural gas and fuel cost adjustment mechanisms.

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

Interest Rate Risk The Company is exposed to interest rate risk associated with
its adjustable rate borrowing arrangements. Its risk management program seeks to
reduce the potentially adverse effects that market volatility may have on
operations.

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 this exposure to counter-party credit
risk by entering into contracts with financially sound companies that can be
expected to fully perform under the terms of the contract. The Company attempts
to manage exposure to market risk associated with commodity contracts and
interest rates by establishing and monitoring parameters that limit the types
and degree of market risk that may be undertaken. As of December 31, 2001, the
Company has a net receivable from Enron Corp. of approximately $1.0 million,
which has been fully reserved.

Accounting for Forward Contracts and Other Financial Instruments

Commodity Contracts At origination, all contracts to buy and sell electric power
are designated as "physical" or "other-than-trading." The Company does not have
any contracts designated as "trading" as defined by EITF 98-10.

Power marketing contracts are designated as "physical" when there is intent and
ability to physically deliver power from SIGECO's unutilized generating
capacity. Power marketing contracts are designated as "other-than-trading" when
there is intent to receive power to manage base and peak load capacity. Both
contract designations generally require settlement by physical delivery of
electricity. However, certain of these contracts may be net settled in
accordance with industry standards when unplanned outages, favorable pricing
movements, and shifts in demand occur.

Prior to the adoption of SFAS No. 133 "Accounting for Derivative Instruments and
Hedging Activities" (SFAS 133) contracts in the "physical" and
"other-than-trading" portfolios received accounting recognition on settlement
with revenues recorded in electric utility revenues and costs recorded in fuel
for electric generation for those contracts fulfilled through generation and in
purchased electric energy for contracts purchased in the wholesale energy
market. Subsequent to the adoption of SFAS 133, certain contracts that are
periodically settled net are recorded at market value.

Contracts recorded at market value are recorded as current or noncurrent assets
or liabilities in the Consolidated Balance Sheets depending on their value and
on when the contracts are expected to be settled. Changes in market value are
recorded in the Consolidated Statements of Income as purchased electric energy.
Market value is determined using quoted market prices from independent sources.

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

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

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

Impact of New Accounting Principle
In June 1998, the Financial Accounting Standards Board (FASB) issued SFAS 133,
which requires that every derivative instrument be recorded on the balance sheet
as an asset or liability measured at its market value and that changes in the
derivative's market value be recognized currently in earnings unless specific
hedge accounting criteria are met.

SFAS 133, as amended, requires 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, as the cumulative
effect of a change in accounting principle in accordance with APB Opinion No.
20, "Accounting Changes."

As of December 31, 2001, the Company has derivative assets resulting from its
power marketing operations of $5.2 million classified in other current assets as
well as derivative liabilities of $2.0 million classified in accrued
liabilities. Unrealized losses totaling $3.2 million arising from the difference
between the current market value and the market value on the date of adoption is
included in purchased electric energy in the Consolidated Statements of Income
for the year ended December 31, 2001.

The Company assesses and documents the hedging relationship between its
financial instruments, including interest rate swaps, and underlying risks as
well as the investment's risk management objectives and anticipated
effectiveness. When the hedging relationship is highly effective, these
instruments are designated as cash flow hedges. The adoption of SFAS 133 had no
impact as the market value of the Company's cash flow hedges was zero on January
1, 2001.

As of December 31, 2001, no interest rate swaps are outstanding. Approximately
$0.9 million remains in accumulated other comprehensive income that is related
to interest rate swaps hedging future interest payments. Of that amount, $0.1
million will be reclassified to earnings within the next twelve months.

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

At December 31,
-----------------------------------------
2001 2000
-------------------- -------------------
Carrying Est. Fair Carrying Est. Fair
In millions Amount Value Amount Value
------------------- -------------------

Long term debt $ 918.4 $ 912.0 $ 575.7 $ 561.0
Short-term borrowings & notes payable 274.2 274.2 653.4 653.4
Redeemable preferred stock of subsidiary - - 7.7 7.5
------ ------ ------ ------

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.

15. Additional Operational and Balance Sheet Information

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

At December 31,
-------------------
In millions 2001 2000
------- -------
Accrued taxes $ 28.6 $ 41.4
Deferred income taxes 20.7 3.4
Refunds to customers & customer deposits 18.7 15.3
Accrued interest 12.8 9.8
Other 16.7 25.7
------- -------
Total accrued liabilities $ 97.5 $ 95.6
======= =======

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

At December 31,
----------------------
In millions 2001 2000
------- -------
Prepaid gas delivery service $ 67.7 $ 34.8
Other prepayments & current assets 59.7 38.3
------- -------
Total prepayments & other current assets $ 127.4 $ 73.1
======= =======

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

Year ended December 31,
-----------------------------
In millions 2001 2000 1999
------- ------- -------
AFUDC $ 4.6 $ 4.9 $ 3.8
Other income 2.3 3.3 0.6
Other expense (1.9) (3.2) (0.1)
------- ------- -------
Total other - net $ 5.0 $ 5.0 $ 4.3
======= ======= =======

16. Segment Reporting

There were two operating segments during 2001: (1) Gas Utility Services and (2)
Electric Utility Services. The Gas Utility Services segment includes the
operations of Indiana Gas, the Ohio operations, and SIGECO's natural gas
distribution business and provides natural gas distribution and transportation
services in nearly two-thirds of Indiana and west central Ohio. The Electric
Utility Services segment includes the operations of SIGECO's power generating
and marketing operations, and electric transmission and distribution services,
which provides electricity to primarily southwestern Indiana.

The following tables provide information about business segments. The Company
makes decisions on finance and dividends at the corporate level; these topics
are addressed on a consolidated basis.

Year ended December 31,
------------------------------
In millions 2001 2000 1999
-------- --------- -------
Operating Revenues
Gas Utility Services $ 1,031.5 $ 818.8 $ 499.6
Electric Utility Services 378.9 336.4 307.5
-------- -------- ------
Total operating revenues $ 1,410.4 $ 1,155.2 $ 807.1
======== ======== ======

Year ended December 31,
---------------------------
In millions 2001 2000 1999
------- ------ -------
Interest Expense
Gas Utility Services $ 51.0 $ 28.0 $ 19.3
Electric Utility Services 19.1 18.1 17.5
------ ------ ------
Total interest expense $ 70.1 $ 46.1 $ 36.8
====== ====== ======
Income Taxes
Gas Utility Services $ 2.4 $ 11.5 $ 18.9
Electric Utility Services 20.3 23.4 24.3
------ ------ ------
Total income taxes $ 22.7 $ 34.9 $ 43.2
====== ====== ======
Net Income
Gas Utility Services $ 9.9 $ 15.6 $ 33.6
Electric Utility Services 40.8 36.8 41.8
------ ------ ------
Net income $ 50.7 $ 52.4 $ 75.4
====== ====== ======
Depreciation & Amortization
Gas Utility Services $ 58.2 $ 43.8 $ 38.7
Electric Utility Services 38.7 38.6 40.8
------ ------ ------
Total depreciation & amortization $ 96.9 $ 82.4 $ 79.5
====== ====== ======
Capital Expenditures
Gas Utility Services $ 76.1 $ 67.2 $ 72.5
Electric Utility Services 69.7 43.5 51.1
------ ------ ------
Total capital expenditures $ 145.8 $ 110.7 $ 123.6
====== ====== ======

At December 31,
-------------------------
In millions 2001 2000
------- --------
Identifiable Assets
Gas Utility Services $ 1,580.2 $ 1,648.0
Electric Utility Services 811.2 806.3
-------- --------
Total identifiable assets $ 2,391.4 $ 2,454.3
======== ========

17. Impact of Recently Issued Accounting Guidance

SFAS 141 & 142

statement. This includes goodwill recorded in past business combinations, such
as the Company's acquisition of the Ohio operations. Goodwill is to be tested
for impairment at a reporting unit level at least annually.

SFAS 142 also changes certain aspects of accounting for intangible assets;
however, the Company does not have any significant intangible assets.

SFAS 143

SFAS 144

SFAS 144 is effective for fiscal years beginning after December 15, 2001, with
earlier application encouraged. The Company is evaluating the impact SFAS 144
will have on its operations.

18. Quarterly Financial Data (Unaudited)

Summarized quarterly financial data for 2001 and 2000 is as follows:

In millions Q1 Q2 Q3 Q4
------- ------ ------- -------
2001
Operating revenues $ 611.1 $ 248.8 $ 201.9 $ 348.6
Operating income 51.6 2.6 15.5 43.0
Income (loss) before cumulative effect
of change in accounting principle 31.8 (12.9) (0.5) 28.4
Net income (loss) 35.7 (12.9) (0.5) 28.4
------- ------- ------- -------

2000
Operating revenues $ 273.8 $ 178.8 $ 188.1 $ 514.5
Operating income 21.9 11.9 19.3 41.4
Net income 12.8 3.0 10.1 26.5
------- ------- ------- -------

1. Information in any one quarterly period is not indicative of annual results
due to the seasonal variations common to the Company's utility operations.
2. Q1 of 2001 includes charges for cumulative effect of changes in accounting
principle as described in Note 14.
3. Q2 of 2001 includes restructuring charges as described in Note 3.
4. 2001 & 2000 includes merger and integration charges as described in Note 3.

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

None

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

Certain information required to be shown for Item 10, Directors and Executive
Officers of the Registrant, is incorporated by reference, with the exception of
the Compensation Committee Report and Performance Graph, from the Proxy
Statement of the registrant's parent company, Vectren Corporation. That report
was prepared and filed electronically with the Securities and Exchange
Commission on March 15, 2002, and is attached to this filing as Exhibit 99.1.

Directors

Niel C. Ellerbrook, age 53, has been a director of VUHI since its inception,
March 31, 2000. Mr. Ellerbrook is Chairman of the Board and Chief Executive
Officer of VUHI, having served in that capacity since June 2001. Mr. Ellerbrook
has been a director of Indiana Energy or Vectren since 1991. Mr. Ellerbrook is
Chairman of the Board and Chief Executive Officer of Vectren, having served in
that capacity since March 2000. Mr. Ellerbrook served as President and Chief
Executive Officer of Indiana Energy from June 1999 to March 2000. Mr. Ellerbrook
served as President and Chief Operating Officer of Indiana Energy from October
1997 to March 2000. From January through October 1997, Mr. Ellerbrook served as
Executive Vice President, Treasurer, and Chief Financial Officer of Indiana
Energy; and from 1986 to January 1997 as Vice President, Treasurer, and Chief
Financial Officer of Indiana Energy. Mr. Ellerbrook is a director of Indiana Gas
Company, Inc. and Southern Indiana Gas and Electric Co. He is also a director of
Fifth Third Bank, Indiana, and Deaconess Hospital of Evansville, Indiana.

Andrew E. Goebel, age 54, has been a director of VUHI since its inception, March
31, 2000. Mr. Goebel is President of VUHI, having served in that capacity since
June 2001. Mr. Goebel has also been a director of SIGCORP or Vectren since 1997.
Mr. Goebel is President and Chief Operating Officer of Vectren, having served in
that capacity since March 2000. Mr. Goebel was President and Chief Operating
Officer of SIGCORP from April 1999 to March 2000. From September 1997 through
April 1999, Mr. Goebel served as Executive Vice President of SIGCORP; and from
1996 to September 1997, he served as Secretary and Treasurer of SIGCORP. Mr.
Goebel is a director of Indiana Gas Company, Inc. and Southern Indiana Gas and
Electric Co. Mr. Goebel is also a director of Old National Bancorp and Old
National Bank.

Jerome A. Benkert, Jr., age 43, has been a director and an executive officer,
serving as Executive Vice President and Chief Financial Officer, of VUHI since
its inception, March 31, 2000 and as Treasurer since October 2001. Mr. Benkert
was elected as Executive Vice President and Chief Financial Officer of Vectren
on March 31, 2000 and as Treasurer of Vectren since October 2001. He was
Executive Vice President and Chief Operating Officer of Indiana Energy's
administrative services company from October 1997 to March 2000. Mr. Benkert has
served as Controller and Vice President of Indiana Gas. Mr. Benkert is a
director of Indiana Gas Company, Inc. and Southern Indiana Gas and Electric Co.

Ronald E. Christian, age 43, has been a director and an executive officer,
serving as Senior Vice President, General Counsel and Secretary, of VUHI since
its inception, March 31, 2000. Mr. Christian was elected Senior Vice President,
General Counsel, and Corporate Secretary of Vectren on March 31, 2000. Mr.
Christian served as Vice President and General Counsel of Indiana Energy from
July 1999 to March 2000. From June 1998 to July 1999, Mr. Christian was the Vice
President, General Counsel and Secretary of Michigan Consolidated Gas Company in
Detroit, Michigan. He served as the General Counsel and Secretary of Indiana
Energy, Indiana Gas and Indiana Energy Investments, Inc. from 1993 to June 1998.
Mr. Christian is a director of Indiana Gas Company, Inc. and Southern Indiana
Gas and Electric Co.

William S. Doty, age 51, has served as a director since June 2001. Mr. Doty has
also served as Senior Vice President-Energy Delivery of the Company since April
2001. Mr. Doty served as Senior Vice President of Customer Relationship
Management from January 2001 to April 2001. From January 1999 to January 2001,
Mr. Doty was Vice President of Energy Delivery for Southern Indiana Gas and
Electric Company and previous to January 1999, he was Director of Gas
Operations. Mr. Doty is a director of Southern Indiana Gas and Electric Company.

Other Executive Officers

Richard G. Lynch, age 50, has been an executive officer, serving as Senior Vice
President of Human Resources and Administration, of VUHI since its inception,
March 31, 2000. Mr. Lynch also serves as Senior Vice President of Human
Resources of Vectren Corporation since March 31, 2000. Mr. Lynch was Vice
President of Human Resources for SIGCORP from March 1999 to March 2000. Prior to
joining the Company, Mr. Lynch was the Director of Human Resources for the Mead
Johnson Division of Bristol Myers-Squibb in Evansville, Indiana.

ITEM 11. EXECUTIVE COMPENSATION

Certain information required to be shown for Item 11, Executive Compensation, is
incorporated by reference, with the exception of the Compensation Committee
Report and Performance Graph, from the Proxy Statement of the registrant's
parent company, Vectren Corporation. That report was prepared and filed
electronically with the Securities and Exchange Commission on March 15, 2002,
and is attached to this filing as Exhibit 99.1.

The compensation of Niel C. Ellerbrook, Andrew E. Goebel, Jerome A Benkert, Jr.,
and Ronald E. Christian is included in Exhibit 99.1 attached to this filing. In
addition to these named executive officers, the compensation of William S. Doty
and J. Gordon Hurst is presented below. Mr. Hurst served a President of VUHI
until his retirement in June 2001. The compensation presented below and the
compensation included in Exhibit 99.1 represents each executive's Vectren-wide
compensation, not just the portion allocated to VUHI. The tables include a
Summary Compensation Table (Table I), a Summary of Option Grants in Last Fiscal
year (Table II), a table showing Aggregate Option Exercises in Last Fiscal Year
and Fiscal Year End Option Values (Table III) and a table showing the Long-Term
Incentive Plan Awards in Last Fiscal Year (Table IV).

TABLE I
SUMMARY COMPENSATION TABLE
(a) (b) (c) (d) (e) (g) (h) (i)
----------------------------------------------------------
Annual Compensation Long-term Compensation Payouts
Other Options Other
Compen- (# LTIP Compen-
Name and Principal Bonus sation shares) Payouts sation
Position at VUHI Year Salary ($) ($) (1) ($) (2) (3) ($) (4) ($) (5)
---------------- ---- --------- ------- ------- ------- ------- -------

William S. Doty 2001 174,608 10,500 5,709 22,000 - 12,836
Senior Vice President - 2000 141,464 96,125 1,413 - - 18,079
Energy Delivery 1999 117,528 15,900 - 5,224 - 10,700

J. Gordon Hurst 2001 239,227 - 8,042 - - 139,037
President (Retired 2000 259,118 250,089 3,148 - - 12,333
June 2001) 1999 217,048 62,500 - 33,390 - 8,762

Earnings are shown on a calendar year basis.

(1) The amounts shown in this column for 2001 are payments under Vectren's
At-Risk Compensation Plan, which is discussed in Part B relating to
"Annual Incentive Compensation," and Part C of the Compensation Committee
Report, in Exhibit 99.1 The amounts shown for 2000 are payments under the
SIGCORP Corporate Performance Plan. The amounts paid in 1999 are
attributable to SIGCORP's performance in the previous year.

The amounts shown for 2001 are attributable to Vectren's At-Risk
Compensation Plan for the performance period of January 1 to December 31,
2001.

Included in year 2000 of the table are payments attributable to Vectren's
Executive Annual Incentive Plan for the performance period of April 1 to
December 1, 2000 (Mr. Doty, $64,000; Mr. Hurst, $151,000). As of the time
of the preparation of Vectren's proxy statement for last year's meeting,
these payments were not yet calculable and were not determined by the
Compensation Committee until after the finalization and mailing of the
proxy statement.

At the close of the merger of Indiana Energy and SIGCORP into the Company
on March 31, 2000, the existing annual incentive programs of the two
companies were terminated and a "stub year" payout was made based on the
portion of the performance cycle that had passed. For the SIGCORP
Performance Plan, a prorated payout for three months, January 1, 2000 to
March 31, 2000 was made. For Mr. Doty, this stub year bonus was $6,250,
and for Mr. Hurst, was $19,688. Also included in 2000 (for Mr. Doty,
$25,875 and for Mr. Hurst $79,401) is the payment attributable to
SIGCORP's performance for the period January 1 to December 31, 1999.

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

(3) For 1999, the options shown in this column were restated to reflect the
conversion ratio of 1.333 described in the Section titled "Voting
Securities" in Exhibit 99.1. The options shown for year 2001 were issued
under Vectren's At-Risk Compensation Plan. For further information, see
the discussion above in Part B relating to "Long-term Incentive
Compensation," and Part C of the Compensation Committee Report in Exhibit
99.1.

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

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

This column contains payment made to Mr. Hurst under the terms of a
retirement agreement in which Vectren agreed to make the following
severance payments to him: 2001 -- $116,746; 2002 -- $1,067,316; 2003 --
$584,752; 2004 -- $526,817.

For Mr. Doty and Mr. Hurst, this column also contains income related to
reimbursement for club dues and other executive benefits (Mr. Doty: 2001 --
$5,680, 2000 -- $2,520, 1999 -- $1,050; Mr. Hurst: 2001 -- $2,230, 2000 --
$1,074, 1999 -- $1,190), imputed earnings from automobile usage (Mr. Doty:
2000 -- $1,167, 1999 -- $4,850; Mr. Hurst: 2000 -- $621, 1999 -- $2,772),
company contributions to the retirement savings plan (Mr. Doty: 2001 --
$5,100 2000 -- $5,100, 1999 -- $4,800; Mr. Hurst: 2001 -- $3,043, 2000 --
$5,100, 1999 -- $4,800), deferred compensation contributions to restore
contributions to the company Retirement Savings Plan (Mr. Doty: 2001 --
$2,056, 2000 -- $900), and contributions to the non qualified retirement
plan (Mr. Hurst: 2001 -- $17,018). At the close of the merger, officers
coming from SIGCORP were no longer furnished with company automobiles
(Indiana Energy executives were not furnished with company automobiles). As
a result of the termination of this perquisite, officers with company cars
were given a one-time automobile buyout of (Mr. Doty -- $8,392; Mr. Hurst
-- $5,538) in 2000.

TABLE II
OPTION GRANTS IN LAST FISCAL YEAR

Number of % of Total
Shares Options
Underlying Granted to Exercise or
Options/ SARs Employees in Base Price Expiration Grant Date
Name Granted Fiscal Year (Per Share)($) Date Present Value
----------- ------- ------------ -------------- ---------- -------------
(#) (1) ($) (2)

W.S. Doty 22,000/0 2.8 22.54 5/1/2011 121,440
J.G. Hurst 0/0 0 0 N/A 0

(1) In 2001, a total of 783,999 options were awarded to all plan
participants under the Vectren Corporation At-Risk Compensation Plan.
Stock options are exercisable in whole or in part from the date of the
grant for a period of ten years. This grant has a vesting schedule
pursuant to which 20 percent vests each year for the first five years.

(2) The assumptions used for the Model are as follows: Volatility -- 25.79
percent based on monthly stock prices for the period of March 1, 1998
to February 28, 2001; Risk-free rate of return -- 5.75 percent;
Dividend Yield -- 4.30 percent over the period of March 1, 1998 to
February 28, 2001; and, a ten-year exercise term. Discount of .9159
applied to reflect 5-year graduated vesting schedule. (Per binomial
model as certified by an independent consultant.)

TABLE III
AGGREGATED OPTION EXERCISES IN LAST FISCAL YEAR
AND FISCAL YEAR-END OPTION VALUES
FROM 1/1/2001 TO 12/31/2001

Underlying Number of Securities Value of Unexercised
Shares Acquired Unexercised Value Underlying Unexercised In-the-Money
Name On Exercise(#) Realized ($) Options at Year-End(#) Options as of 12/31/01($)
---- -------------- ----------------- ---------------------- ------------------------
Exercisable Unexercisable Exercisable Unexercisable

W.S. Doty 1,000 8,044 23,488 22,000 130,797 31,680
J.G. Hurst 31,792 192,797 56,626 - 374,482 -

TABLE IV

LONG-TERM INCENTIVE PLAN AWARDS IN LAST FISCAL YEAR

Estimated Future Payouts
Under Non-Stock Price-Based Plans
(a) (b) (c) (d) (e) (f)
Performance
Number of or Other
Shares; Periods Until Threshold Target Maximum
Units or Maturation Number of Number Number of
Other Rights(1) or Payout Shares of Shares Shares

W.S. Doty 0 0 0 0 0
J.G. Hurst 0 0 0 0 0

(1) No restricted shares were awarded to Executives during fiscal year 2001
under the Vectren Corporation Restricted Stock Plan or the Vectren's
At-Risk Compensation Plan.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

Security ownership of certain beneficial owners

As of December 31, 2001, the following stockholder was known to the management
to be the beneficial owner of more than five percent of the outstanding shares
of any class of voting securities as set forth below.

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

Security ownership of management

The following table sets forth the beneficial ownership, as of December 31,
2001, of Vectren common stock, by each director and executive officer named in
Item 11 Executive Compensation. Also shown is the total ownership for such
persons as a group. Except as otherwise indicated, each individual has sole
voting and investment power with respect to the shares listed below.

Shares Owned
Name of Beneficial Owner Beneficially (1)
------------------------ ----------------
Niel C. Ellerbrook 118,038 (2) (3) (4) (5)
Andrew E. Goebel 188,518 (2) (3) (4) (5)
Jerome A. Benkert, Jr. 25,787 (2) (4) (5)
Ronald E. Christian 26,687 (2) (4) (5)
J. Gordon Hurst 62,858 (2) (3) (4) (5)
William S. Doty 34,431 (2) (4) (5)

All Directors and Executive Officers as a Group (6 Persons): 456,319 (1)

(1) No director, executive officer, or directors and executive officers as a
group owned beneficially as of December 31, 2001, more than 1 percent of
common stock of Vectren

(2) Does not include derivative securities held under Vectren's Non-Qualified
Deferred Compensation Plan. These derivative securities are in the form of
phantom stock units which are valued as if they were Vectren common stock,
but will be distributed in cash (not Vectren common stock) when paid. The
amounts shown for the following individuals include the following amounts
of phantom units:

Name of Individuals or Identity of Group Phantom Stock Units
---------------------------------------- -------------------
Niel C. Ellerbrook 50,854
Andrew E. Goebel 10,019
Jerome A. Benkert, Jr. 15,525
Ronald E. Christian 25,987
J. Gordon Hurst 1,055
William S. Doty 457

All Directors and Executive Officers as a
Group (6 Persons) 103,897

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

(4) Includes shares granted to executives under the Company's Executive
Restricted Stock Plan, which are subject to certain transferability
restrictions and forfeiture provisions.

(5) Includes shares which the named individual has the right to acquire as of
December 31, 2001, or within sixty (60) days thereafter, under the Vectren
Stock Option Plan (formerly the SIGCORP, Inc. Stock Option Plan) or
Vectren's At-Risk Compensation Plan.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

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

Transactions with directors and officers
Andrew E. Goebel is a director and President of the Company and a director and
President and Chief Operating Officer of Vectren. During 2000 and 2001, Hasgoe
Cleaning Systems, a cleaning company owned by Mr. Goebel's brother, performed
certain cleaning services for the Company and is expected to perform such
services in 2002. During 2001, the cost of such serves was $140,023, which the
Company believes to be a fair and reasonable price for the services rendered.

PART IV

ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

(A) List Of Documents Filed As Part Of This Report

(1) Consolidated Financial Statements

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

(2) Consolidated Financial Statement Schedules

PAGE IN FORM 10-K
-----------------
For the years ended December 31, 2001,
2000, and 1999: Schedule II -- Valuation
and Qualifying Accounts 66

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

(3) Exhibits

Exhibits for the Company are listed in the Index to Exhibits
beginning on page 68. Exhibits for the Company attached to
this filing are listed on page 74.

(B) Reports on Form 8-K

On October 18, 2001, VUHI filed a Current Report on Form 8-K with respect to
filing an Underwriting Agreement, dated October 12, 2001, in connection with
VUHI's issuance of $100,000,000 aggregate principal amount of its senior debt
securities.
Item 5. Other Events
Item 7. Financial Statements and Exhibits

Exhibit 1 - Underwriting Agreement, dated October 12, 2001, between
Vectren Utility Holdings, Inc., Indiana Gas Company, Inc.,
Southern Indiana Gas and Electric Company, Vectren Energy
Delivery of Ohio, Inc. and Merrill Lynch, Pierce, Fenner
& Smith Incorporated.

On October 19, 2001, VUHI filed a Current Report on Form 8-K with respect to
filing an Indenture dated October 19, 2001 and the First Supplemental Indenture
(including the Form of Note) dated October 19, 2001, in connection with the
issuance by VUHI of $100,000,000 aggregate principal amount of its 7 1/4% Senior
Notes due October 15, 2031.
Item 5. Other Events
Item 7. Financial Statements and Exhibits
Exhibit 4.1 - 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. Underwriting Agreement, dated
October 12, 2001, between Vectren Utility Holdings,
Inc., Indiana Gas Company, Inc., Southern Indiana
Gas and Electric Company, Vectren Energy Delivery of
Ohio, Inc. and Merrill Lynch, Pierce, Fenner & Smith
Incorporated.
Exhibit 4.2 - 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.

On October 24, 2001, VUHI filed a Current Report on Form 8-K with respect to the
release of Vectren's financial information to the investment community regarding
Vectren's results of operations, financial position and cash flows for the
three, six, and nine month periods ended September 30, 2001. The financial
information was released to the public through this filing.
Item 5. Other Events

Item 7. Exhibits
99.1 - Press Release - Third Quarter 2001 Vectren Corporation
Earnings
99.2 - Cautionary Statement for Purposes of the "Safe Harbor"
Provisions of the Private Securities Litigation Reform Act
of 1995

On November 26, 2001, VUHI filed a Current Report on Form 8-K with respect to an
analyst meeting where a discussion of Vectren's current financial and operating
results and plans for the future will occur.
Item 5. Other Events
Item 7. Exhibits
99.1 - Press Release - Vectren to Update Business Strategies
99.2 - Cautionary Statement for Purposes of the "Safe Harbor"
Provisions of the Private Securities Litigation Reform Act
of 1995

On November 29, 2001, VUHI filed a Current Report on Form 8-K with respect to
filing an Underwriting Agreement, dated November 27, 2001 in connection with
VUHI's issuance of $250,000,000 aggregate principal amount of its senior debt
securities and to filing the form of Second Supplemental Indenture (including
the Form of Note) in connection with the issuance by VUHI of $250,000,000
aggregate principal amount of its 6 5/8% Senior Notes due December 1, 2011.
Item 5. Other Events
Item 7. Financial Statements and Exhibits
Exhibit 1 - Underwriting Agreement, dated November 27, 2001,
among Vectren Utility Holdings, Inc., Indiana Gas Company,
Inc., Southern Indiana Gas and Electric Company and Vectren
Energy Delivery of Ohio, Inc.
Exhibit 4.1 - Form of Second Supplemental Indenture, among
Vectren Utility Holdings, Inc., Indiana Gas Company, Inc.,
Southern Indiana Gas and Electric Company, Vectren Energy
Delivery of Ohio, Inc. and U.S. Bank Trust National
Association.

SCHEDULE II

VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
(In millions)

-------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
-------------------------------------------------------------------------------------------
Additions
-----------------
Balance Charged Charged Balance
Beginning to to Other Deductions End of
Description Of Year Expenses Accounts Net Year
-------------------------------------------------------------------------------------------

VALUATION AND QUALIFYING ACCOUNTS:

Year 2001 - Accumulated provision for
uncollectible accounts $ 5.6 $ 15.1 $ - $ 15.1 $ 5.6

Year 2000 - Accumulated provision for
uncollectible accounts $ 3.9 $ 6.6 $ 0.5 $ 5.4 $ 5.6

Year 1999 - Accumulated provision for
uncollectible accounts $ 3.9 $ 3.4 $ - $ 3.4 $ 3.9

OTHER RESERVES:

Year 2001 - Reserve for restructuring
charges $ - $ 9.2 $ - $ 4.9 $ 4.3

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

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

Year 2001 - Reserve for injuries
and damages $ 1.8 $ 2.9 $ - $ 3.0 $ 1.7

Year 2000 - Reserve for injuries
and damages $ 1.5 $ 0.9 $ - $ 0.6 $ 1.8

Year 1999 - Reserve for injuries
and damages $ 1.3 $ 0.7 $ - $ 0.5 $ 1.5

SIGNATURES

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

VECTREN UTILITY HOLDINGS, INC.

Dated March 28, 2002
/s/ Niel C. Ellerbrook
----------------------------
Niel C. Ellerbrook, Chairman
and Chief Executive Officer

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 March 28, 2002
---------------------------- Officer, Director (Principal ----------------
Niel C. Ellerbrook Executive Officer)

/S/ Jerome A. Benkert, Jr. Executive Vice President, March 28, 2002
---------------------------- Chief Financial Officer, & ---------------
Jerome A. Benkert, Jr. Treasurer, Director (Principal
Financial Officer)

/S/ M. Susan Hardwick Vice President & Controller, March 28, 2002
---------------------------- Principal Accounting Officer) ---------------
M. Susan Hardwick

/S/ Andrew E. Goebel Director March 28, 2002
---------------------------- ---------------
Andrew E. Goebel

/S/ Ronald E. Christian Director March 28, 2002
---------------------------- ---------------
Ronald E. Christian

Vectren Utility Holdings, inc.
2001 Form 10-K Annual Report
Index To Exhibits

2. Plan Of Acquisition, Reorganization, Arrangement, Liquidation Or
Succession
EX - 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 (credit facility) and 99.1 (commitment letter).)

3. Articles Of Incorporation And By-Laws
EX - 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)

EX - 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
EX - 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.)

EX - 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.)

EX - 4.3 $350.0 million Credit Agreement arranged by Banc One Capital
Markets, Inc. dated as of June 28, 2001 among Vectren Utility
Holdings, Inc., as borrower; Indiana Gas Company, Inc. as
guarantor; Southern Indiana Gas and Electric Company, as
guarantor; Vectren Energy Delivery of Ohio, Inc., as guarantor;
and Lenders: Banc One, NA, as Agent; Firstar Bank, N.A., as
Co-Syndication Agent; ABN AMRO Bank, N.V., as Co-Syndication
Agent; The Bank of New York, as Co-Documentation Agent; The
Industrial Bank of Japan, Limited, as Co-Documentation Agent; the
Fuji Bank, Limited, as Co-Documentation Agent; and National City
Bank of Indiana, as Co-Agent. (Filed herewith.)

EX - 4.4 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).

9. Voting Trust Agreement
Not applicable

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

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

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

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

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

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

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

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

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

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

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

EX - 10.12 Amendment Agreement, dated March 3, 2001, between Alcoa Power
Generating Inc. and Southern Indiana Gas and Electric Company.
(Filed and designated in Form 10-K for the fiscal year 2001, File
No. 1-15467, as Exhibit 10-12.)

EX - 10.13 Summary description of Southern Indiana Gas and Electric
Company's nonqualified Supplemental Retirement Plan (Filed and
designated in Form 10-K for the fiscal year 1992, File No.
1-3553, as Exhibit 10-A-17.)

EX - 10.14 Southern Indiana Gas and Electric Company 1994 Stock Option Plan
(Filed and designated in Southern Indiana Gas and Electric
Company's Proxy Statement dated February 22, 1994, File No.
1-3553, as Exhibit A.)

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

EX - 10.16 Vectren Corporation Retirement Savings Plan. (Filed and
designated in Form 10-Q for the quarterly period ended September
30, 2000, File No. 1-15467, as Exhibit 99.1.)

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

EX - 10.18 Indiana Energy, Inc. Unfunded Supplemental Retirement Plan for a
Select Group of Management Employees as amended and restated
effective December 1, 1998. (Filed and designated in Form 10-Q
for the quarterly period ended December 31, 1998, File No.
1-9091, as Exhibit 10-G.)

EX - 10.19 Indiana Energy, Inc. Nonqualified Deferred Compensation Plan
effective January 1, 1999. (Filed and designated in Form 10-Q for
the quarterly period ended December 31, 1998, File No. 1-9091, as
Exhibit 10-H.)

EX - 10.20 Formation Agreement among Indiana Energy, Inc., Indiana Gas
Company, Inc., IGC Energy, Inc., Indiana Energy Services, Inc.,
Citizens Gas & Coke Utility, Citizens Energy Services Corporation
and ProLiance Energy, LLC, effective March 15, 1996. (Filed and
designated in Form 10-Q for the quarterly period ended March 31,
1996, File No. 1-9091, as Exhibit 10-C.)

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

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

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

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

EX - 10.25 Indiana Energy, Inc. Executive Restricted Stock Plan as amended
and restated effective October 1, 1998. (Filed and designated in
Form 10-K for the fiscal year ended September 30, 1998, File No.
1-9091, as Exhibit 10-O.)

EX - 10.26 Amendment to Indiana Energy, Inc. Executive Restricted Stock Plan
effective December 1, 1998. (Filed and designated in Form 10-Q
for the quarterly period ended December 31, 1998, File No.
1-9091, as Exhibit 10-I.)

EX - 10.27 Indiana Energy, Inc. Director's Restricted Stock Plan as amended
and restated effective May 1, 1997. (Filed and designated in Form
10-Q for the quarterly period ended June 30, 1997, File No.
1-9091, as Exhibit 10-B.)

EX - 10.28 First Amendment to Indiana Energy, Inc. Directors' Restricted
Stock Plan, effective December 1, 1998. (Filed and designated in
Form 10-Q for the quarterly period ended December 31, 1998, File
No. 1-9091, as Exhibit 10-J.)

EX - 10.29 Second Amendment to Indiana Energy, Inc. Director's Restricted
Stock Plan, renamed the Vectren Corporation Directors Restricted
Stock Plan effective October 1, 2000. (Physically filed and
designated in Form 10-K for the year ended December 31, 2000,
File No. 1-15467, as Exhibit 10.34.)

EX - 10.30 Third Amendment to Indiana Energy, Inc. Director's Restricted
Stock Plan, renamed the Vectren Corporation Directors Restricted
Stock Plan effective March 28, 2000. (Physically filed and
designated in Form 10-K for the year ended December 31, 2000,
File No. 1-15467, as Exhibit 10.35.)

EX - 10.31 Vectren Corporation At Risk Compensation Plan effective May 1,
2001. (Filed and designated in Vectren Corporation's Proxy
Statement dated March 16, 2001, File No. 1-15467, as Appendix B.)

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

EX - 10.33 Vectren Corporation Employment Agreement between Vectren
Corporation and Niel C. Ellerbrook dated as of March 31, 2000.
(Filed and designated in Form 10-Q for the quarterly period ended
June 30, 2000, File No. 1-15467, as Exhibit 99.1.)

EX - 10.34 Vectren Corporation Employment Agreement between Vectren
Corporation and Andrew E. Goebel dated as of March 31, 2000(Filed
and designated in Form 10-Q for the quarterly period ended June
30, 2000, File No. 1-15467, as Exhibit 99.2.)

EX - 10.35 Vectren Corporation Employment Agreement between Vectren
Corporation and Jerome A. Benkert, Jr. dated as of March 31,
2000. (Filed and designated in Form 10-Q for the quarterly period
ended June 30, 2000, File No. 1-15467, as Exhibit 99.3.)

EX - 10.36 Vectren Corporation Employment Agreement between Vectren
Corporation and Ronald E. Christian dated as of March 31, 2000.
(Filed and designated in Form 10-Q for the quarterly period ended
June 30, 2000, File No. 1-15467, as Exhibit 99.5.)

EX - 10.37 Vectren Corporation Employment Agreement between Vectren
Corporation and Timothy M. Hewitt dated as of March 31, 2000.
(Filed and designated in Form 10-Q for the quarterly period ended
June 30, 2000, File No. 1-15467, as Exhibit 99.6.)

EX - 10.38 Vectren Corporation Retirement Agreement between Vectren
Corporation and Timothy M. Hewitt dated as of May 31, 2001.
(Filed and designated in Form 10-K for the year ended December
31, 2001, File No. 1-15467, as Exhibit 10-39.)

EX - 10.39 Vectren Corporation Employment Agreement between Vectren
Corporation and J. Gordon Hurst dated as of March 31, 2000.
(Filed and designated in Form 10-Q for the quarterly period ended
June 30, 2000, File No. 1-15467, as Exhibit 99.7.)

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

EX - 10.41 Vectren Corporation Employment Agreement between Vectren
Corporation and Richard G. Lynch dated as of March 31, 2000.
(Filed and designated in Form 10-Q for the quarterly period ended
June 30, 2000, File No. 1-15467, as Exhibit 99.8.)

EX - 10.42 Vectren Corporation Employment Agreement between Vectren
Corporation and William S. Doty dated as of April 30, 2001 (Filed
and designated in Form 10-K for the year ended December 31, 2001,
File No. 1-15467, as Exhibit 10.43.)

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

11. Statement Re Computation Of Per Share Earnings
Not applicable.

12. Statements Re Computation Of Ratios
Not applicable.

13. Annual Report To Security Holders, Form 10-Q Or Quarterly Report To
Security Holders
Not applicable.

16. Letter Re Change In Certifying Accountant
Not applicable.

18. Letter Re Change In Accounting Principles
Not applicable.

21. Subsidiaries Of The Company
EX - 21.1 Listing of Subsidiaries (Filed herewith.)

22. Published Report Regarding Matters Submitted To Vote Of Security Holders
Not applicable.

23. Consents Of Experts And Counsel
Not applicable.

24. Power Of Attorney
Not applicable.

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

EX - 99.2 Agreement and Plan of Merger dated as of June 11,1999 among
Indiana Energy, Inc., SIGCORP, Inc. and Vectren Corporation (the
"Merger Agreement "). (Filed and designated in Current Report on
Form 8-K filed June 14, 19999, File No. 1-9091, as Exhibit 2.)

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

EX - 99.4 Amended and Restated Articles of Incorporation of Vectren
Corporation effective March 31, 2000. (Filed and designated in
Current Report on Form 8-K filed April 14, 2000, File No.
1-15467, as Exhibit 4.1.)

EX - 99.5 Code of Bylaws of Vectren Corporation. (Filed and designated in
Form S-3 (No. 333-5390), filed January 19, 2001, File No.
1-15467, as Exhibit 4.2.)

EX - 99.6 Shareholders Rights Agreement dated as of October 21, 1999
between Vectren Corporation and Equiserve Trust Company, N.A., as
Rights Agent. (Filed and designated in Form S-4 (No. 333-90763),
filed November 12, 1999, File No 1-15467, as Exhibit 4.)

EX - 99.7 Current Report on Form 8-K, regarding the replacement of the
Company's independent auditors, dated March 22, 2002. (Filed
herewith.)

EX - 99.8 Letter regarding audit quality representation of Arthur Andersen
LLP (Filed herewith.)

Vectren Utility Holdings, Inc.
2001 Form 10-K
Attached Exhibits

The following Exhibits are attached hereto. See Part IV of this Annual Report on
Form 10-K for a complete list of exhibits.

Exhibit
Number Document
4.3 $350.0 million Credit Agreement arranged by Banc One Capital
Markets, Inc. dated as of June 28, 2001 among Vectren Utility
Holdings, Inc., as borrower; Indiana Gas Company, Inc. as
guarantor; Southern Indiana Gas and Electric Company, as
guarantor; Vectren Energy Delivery of Ohio, Inc., as guarantor;
and Lenders: Banc One, NA, as Agent; Firstar Bank, N.A., as
Co-Syndication Agent; ABN AMRO Bank, N.V., as Co-Syndication
Agent; The Bank of New York, as Co-Documentation Agent; The
Industrial Bank of Japan, Limited, as Co-Documentation Agent; the
Fuji Bank, Limited, as Co-Documentation Agent; and National City
Bank of Indiana, as Co-Agent.

21.1 Subsidiaries of the Company

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

99.7 Current Report on Form 8-K, regarding the replacement of the
Company's independent auditors, dated March 22, 2002.

99.8 Letter regarding audit quality representation of Arthur Andersen
LLP