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

                                    FORM 10-Q

[X]  QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
     ACT OF 1934

                  For quarterly period ended September 30, 2001

                                       OR

[ ]  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
     EXCHANGE ACT OF 1934

For the transition period from                       to
                                    -----------------  -----------------

                          Commission file number 1-3553


                    SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
                    ------------------------------------------
             (Exact name of registrant as specified in its charter)

         INDIANA                                          35-0672570
(State or other jurisdiction of                        (I.R.S Employer
incorporation or organization)                       Identification No.)


                20 N.W. Fourth Street, Evansville, Indiana 47741
                ------------------------------------------------
              (Address of principal executive offices and Zip Code)

                                 (812) 491-4000
                       ---------------------------------
              (Registrant's telephone number, including area code)

         Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.

Yes [X]  No [ ]

         Indicate the number of shares outstanding of each of the issuer's
classes of common stock, as of the latest practicable date.

  Common Stock - Without par value      15,754,826        November 10, 2001
---------------------------------   -----------------   ----------------------
              Class                  Number of shares            Date


<PAGE>  2


                                TABLE OF CONTENTS


Item                                                                  Page
Number                                                               Number
                    PART I. FINANCIAL INFORMATION
   1   Financial Statements (Unaudited)
       Southern Indiana Gas and Electric Company
         Condensed Balance Sheets                                      3-4
         Condensed Statements of Operations                             5
         Condensed Statements of Cash Flows                             6
       Notes to Condensed Unaudited Financial Statements               7-15
   2   Management's Discussion and Analysis of Results of
       Operations and Financial Condition                             16-21
   3   Quantitative and Qualitative Disclosure About Market
       Risk                                                           22-23

                    PART II. OTHER INFORMATION
   1   Legal Proceedings                                               24
   6   Exhibits and Reports on Form 8-K                                24
       Signatures                                                      25


<PAGE>  3


                          PART I. FINANCIAL INFORMATION

ITEM 1.  FINANCIAL STATEMENTS (UNAUDITED)

                    SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
                            CONDENSED BALANCE SHEETS
                             (Unaudited - Thousands)

                                                     September 30,  December 31,
                   ASSETS                                 2001        2000
                   ------                              ----------   ----------

Utility Plant at original cost:
    Electric                                           $1,174,363   $1,175,552
    Gas                                                   161,088      160,872
                                                       ----------   ----------
                                                        1,335,451    1,336,424
    Less: accumulated depreciation and amortization       679,660      650,499
                                                       ----------   ----------
                                                          655,791      685,925
    Construction work in progress                          86,158       52,582
                                                       ----------   ----------
       Net utility plant                                  741,949      738,507
                                                       ----------   ----------

Current Assets:
    Cash and cash equivalents                               2,995        1,613
    Accounts receivable, less reserves of $2,216 and
       $2,639, respectively                                47,691       49,554
    Accounts receivable from affiliated company                 -       27,829
    Accrued unbilled revenues                               9,759       24,414
    Inventories                                            42,008       31,055
    Recoverable fuel and natural gas costs                 18,175       28,703
    Other current assets                                   10,569          312
                                                       ----------   ----------
       Total current assets                               131,197      163,480
                                                       ----------   ----------

Other Investments and Property:
    Environmental improvement funds held by trustee         1,071        1,056
    Nonutility property and other, net                      1,001        1,960
                                                       ----------   ----------
       Total other investments and property                 2,072        3,016
                                                       ----------   ----------

Other Assets:
    Regulatory assets                                      33,464       33,443
    Deferred charges, net                                  14,954       12,868
                                                       ----------   ----------
       Total other assets                                  48,418       46,311
                                                       ----------   ----------

TOTAL ASSETS                                           $  923,636   $  951,314
                                                       ==========   ==========


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


<PAGE> 4


                SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
                         CONDENSED BALANCE SHEETS
                         (Unaudited - Thousands)

                                                   September 30,December 31,
       SHAREHOLDER'S EQUITY AND LIABILITIES          2001          2000
       ------------------------------------        ----------   -----------

Capitalization:
    Common stock                                    $ 78,258      $ 78,258
    Retained earnings                                262,489       258,877
    Accumulated comprehensive income                      22             -
                                                    --------      --------
      Total common shareholder's equity              340,769       337,135
    Cumulative nonredeemable preferred stock               -         8,890
    Cumulative redeemable preferred stock                  -         7,500
    Cumulative special preferred stock                   460           576
    Long-term debt, net of current maturities        291,652       237,799
                                                    --------      --------
         Total capitalization, net of current
          maturities                                 632,881       591,900
                                                    --------      --------

Commitments and Contingencies (Notes 7 through 9)

Current Liabilities:
    Current maturities of adjustable rate bonds
    subject to tender                                      -        53,700
    Short-term borrowings                              4,689        40,154
    Notes payable to affiliated company               61,377             -
    Accounts payable to affiliated companies          27,595        11,486
    Accounts payable                                  21,290        60,085
    Dividends payable                                      -           144
    Accrued taxes                                     13,606         9,956
    Accrued interest                                   5,459         6,047
    Refunds to customers                               3,130         3,543
    Deferred income taxes                              8,220        11,295
    Other accrued liabilities                          2,364        14,278
                                                    --------      --------
      Total current liabilities                      147,730       210,688
                                                    --------      --------

Deferred Credits and Other Liabilities:
    Deferred income taxes                            106,144       112,122
    Unamortized investment tax credits                14,929        15,944
    Accrued postretirement benefits other
     than pensions                                    15,509        14,054
    Accrued pensions                                   4,818         6,310
    Other                                              1,625           296
                                                    --------      --------
      Total deferred credits and other
       liabilities                                   143,025       148,726
                                                    --------      --------

TOTAL SHAREHOLDER'S EQUITY AND LIABILITIES          $923,636      $951,314
                                                    ========      ========


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


<PAGE>  5

<TABLE>
<CAPTION>

                        SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
                            CONDENSED STATEMENTS OF OPERATIONS
                                 (Unaudited - Thousands)

                                             Three Months          Nine Months
                                          Ended September 30,   Ended September 30,
                                          -------------------   -------------------
                                            2001       2000       2001       2000
                                          --------   --------   --------   --------
<S>                                       <C>        <C>        <C>        <C>
OPERATING REVENUES:
    Electric revenues                     $104,335   $ 97,936   $287,564    $249,215
    Gas revenues                            11,032     14,739     74,333     58,148
                                          --------   --------   --------   --------
       Total operating revenues            115,367    112,675    361,897    307,363
                                          --------   --------   --------   --------

COST OF OPERATING REVENUES:
    Cost of fuel and purchased power        43,576     32,603    126,232     80,704
    Cost of gas                              5,926      9,877     51,913     36,523
                                          --------   --------   --------   --------
       Total cost of operating revenues     49,502     42,480    178,145    117,227
                                          --------   --------   --------   --------
         Total margin                       65,865     70,195    183,752    190,136

OPERATING EXPENSES:
    Operations and maintenance              23,659     25,191     72,550     74,934
    Merger and integration costs               286        433        588     14,192
    Restructuring costs                        433          -      4,777          -
    Depreciation and amortization           11,053     10,634     33,190     32,836
    Income taxes                             8,336      9,738     18,043     18,585
    Taxes other than income taxes            3,125      3,332      9,978      9,672
                                          --------   --------   --------   --------
       Total operating expenses             46,892     49,328    139,126    150,219
                                          --------   --------   --------   --------

OPERATING INCOME                            18,973     20,867     44,626     39,917

OTHER INCOME-NET                               766      1,107      2,553      2,698

INTEREST EXPENSE                             5,047      4,951     15,420     14,600
                                          --------   --------   --------   --------

INCOME BEFORE CUMULATIVE EFFECT OF
    CHANGE IN ACCOUNTING PRINCIPLE          14,692     17,023     31,759     28,015

CUMULATIVE EFFECT OF CHANGE IN
     ACCOUNTING PRINCIPLE-NET OF TAX             -          -      3,938          -
                                          --------   --------   --------   --------

NET INCOME                                  14,692     17,023     35,697     28,015

PREFERRED STOCK DIVIDEND                       268        241        748        776

LOSS ON EXTINGUISHMENT OF
    PREFERRED STOCK                          1,176          -      1,170          -
                                          --------   --------   --------   --------

NET INCOME APPLICABLE TO COMMON
    SHAREHOLDER                           $ 13,248   $ 16,782   $ 33,779   $ 27,239
                                          ========   ========   ========   ========
</TABLE>


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


<PAGE>  6

<TABLE>
<CAPTION>

                              SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
                                  CONDENSED STATEMENTS OF CASH FLOWS
                                       (Unaudited - Thousands)


                                                                   Nine Months
                                                               Ended September 30,
                                                               --------------------
                                                                 2001        2000
                                                               --------    --------

<S>                                                            <C>         <C>
NET CASH FLOWS FROM OPERATING ACTIVITIES                       $ 61,528    $ 64,026
                                                               --------    --------

CASH FLOWS (REQUIRED FOR) FINANCING ACTIVITIES
    Dividends on and retirement of preferred stock              (18,424)     (2,776)
    Net change in short-term borrowings and notes payable
      to affiliated company                                      25,912         161
    Dividends on common stock                                   (24,006)    (21,445)
                                                               --------    --------
        Net cash flows (required for) financing activities      (16,518)    (24,060)
                                                               --------    --------

CASH FLOWS (REQUIRED FOR) INVESTING ACTIVITIES
    Capital expenditures                                        (44,747)    (39,113)
    Proceeds from sale of assets                                  1,119           -
                                                               --------    --------
        Net cash flows (required for) investing activities      (43,628)    (39,113)
                                                               --------    --------

Net increase in cash                                              1,382         853

Cash and cash equivalents at beginning of period                  1,613         449
                                                               --------    --------

Cash and cash equivalents at end of period                     $  2,995    $  1,302
                                                               ========    ========
</TABLE>


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

<PAGE>  7


                    SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
                     NOTES TO CONDENSED FINANCIAL STATEMENTS
                                   (UNAUDITED)

1.       Organization and Nature of Operations

Southern Indiana Gas and Electric Company (SIGECO or the Company) operates as a
separate wholly owned subsidiary of Vectren Corporation (Vectren) and provides
generation, transmission, distribution and the sale of electric power to
Evansville, Indiana, and 74 other communities in 8 counties in southwestern
Indiana, and the distribution and sale of natural gas to Evansville, Indiana,
and 64 communities in 10 counties in southwestern Indiana.

Vectren is an Indiana corporation that was organized on June 10, 1999 solely for
the purpose of effecting the merger of Indiana Energy, Inc. (Indiana Energy) and
SIGCORP, Inc. (SIGCORP), SIGECO's former parent company. On March 31, 2000, the
merger of Indiana Energy with SIGCORP and into Vectren was consummated with a
tax- free exchange of shares that has been accounted for as a
pooling-of-interests. The merger did not affect SIGECO's preferred stock or debt
securities.

2.       Basis of Presentation

The interim condensed financial statements included in this report have been
prepared by the Company, without audit, as provided in the rules and regulations
of the Securities and Exchange Commission. Certain information and footnote
disclosures normally included in financial statements prepared in accordance
with accounting principles generally accepted in the United States have been
omitted as provided in such rules and regulations. The Company believes that the
information in this report reflects all adjustments necessary to fairly state
the results of the interim periods reported. These condensed financial
statements and related notes should be read in conjunction with the Company's
audited annual financial statements for the year ended December 31, 2000 filed
on Form 10-K/A. Because of the seasonal nature of the Company's operations, the
results shown on a quarterly basis are not necessarily indicative of annual
results.

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 statements
and the reported amounts of revenues and expenses during the reporting period.
Actual results could differ from those estimates.

Certain reclassifications have been made to prior period condensed financial
statements to conform with the current year classification. These
reclassifications have no impact on previously reported net income.

3.       Merger and Integration Costs

Merger and integration costs incurred for the three and nine months ended
September 30, 2001 were $0.3 million and $0.6 million, respectively, and for the
three and nine months ended September 30, 2000 totaled $0.4 million and $14.2
million, respectively. The continued merger integration activities will be
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, $14.7 million has been expensed associated with merger and
integration activities. Accruals were established at March 31, 2000 totaling
$7.4 million. Of this amount, $0.7 million related to employee and executive
severance costs and $6.7 million related to transaction costs and regulatory
filing fees incurred prior to the closing of the merger. At September 30, 2001,
the accrual remaining for such costs totaled $0.3 million, all related to
severance costs. Of the $14.7 million expensed, the remaining $7.3 million was
expensed through September 30, 2001 ($6.7 million in 2000 and $0.6 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


<PAGE>  8

activities, internal labor of employees assigned to integration teams, investor
relations communications activities, and certain benefit costs.

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

4.       Restructuring Costs

In June 2001, the management and board of directors of Vectren approved a plan
to restructure, primarily, its regulated operations. The restructuring plan
involves the elimination of administrative and supervisory positions in its
utility operations and corporate office. Charges of $4.3 million were expensed
in June 2001 as a direct result of the restructuring plan. Additional charges
incurred during the third quarter relating primarily to consulting fees and
employee relocation totaled $0.4 million. It total, the Company has incurred
restructuring charges of $4.8 million. These charges were comprised of $3.5
million for severance, related benefits and other employee related costs and
$1.3 million for consulting fees incurred as of September 30, 2001.

Components of restructuring expenses incurred through September 30, 2001 are as
follows:

<TABLE>
<CAPTION>


                                  Accrual for      Incurred Expenses
                                 Expected Cash  ------------------------
In millions                         Payments    Paid in Cash    Non-Cash    Total Expense
                                    --------    ------------    --------    -------------
<S>                                  <C>            <C>           <C>          <C>
Severance and related costs          $ 0.4          $2.3          $0.8         $3.5
Consulting fees                          -           1.3             -          1.3
                                   ---------    -------------   --------    -------------
              Total                  $ 0.4          $3.6          $0.8         $4.8
                                   =========    =============   ========    =============
</TABLE>


The $3.5 million expensed for employee severance and related costs is associated
with approximately 35 employees. Employee separation benefits include severance,
healthcare and outplacement services. As of September 30, 2001, approximately 20
employees have exited the business. These charges also include a non-cash charge
of $0.8 million related to the curtailment of a post retirement medical plan,
which included the impacted employees. The accrual for severance and related
costs and consulting fees, when first established, totaled $3.5 million and $0.8
million, respectively. With the exception of cash payments, there have been no
modifications to the accrual since it was established. The restructuring program
will be completed during 2001.

5.       Preferred Stock

In September 2001, the Company notified holders of its 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 $1.3464 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 $0.9694 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 $0.7339 in
accrued and unpaid dividends. Prior to the redemption, there were 75,000 shares
outstanding.

6.       Long - Term Debt

The Company has $53.7 million of adjustable rate pollution control series first
mortgage bonds which could, at the election of the bondholder, be tendered to
the Company when the interest rates are reset. Prior to the latest reset on
March 1, 2001, the interest rates were reset annually, and the bonds subject to
tender were presented in the Condensed Balance Sheets as current liabilities.
Effective March 1, 2001, the bonds were reset for a five-year period and have
been classified as long-term debt. Resulting from the reset, the interest rate
on the $31.5 million Series A bonds increased from 4.30% to 4.75%, and the
interest rate on the $22.2 million Series C bonds increased from 4.45% to 5.00%.


<PAGE>  9

7.      Commitments and Contingencies

Vectren Utility Holdings, Inc. (VUHI) serves as the intermediate holding company
for Vectren Corporation's (Vectren) three operating utility companies, the
Company, VEDO and Indiana Gas Company, Inc., who are guarantors of VUHI's $350.0
million commercial paper program, of which $343.8 million is outstanding at
September 30, 2001 and VUHI's $350.0 million unsecured senior notes, of which
zero is outstanding at September 30, 2001. In October 2001, $100.0 million of
the unsecured senior notes were issued. The proceeds of which were used to pay
down outstanding commercial paper. 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.

The Company is party to various legal proceedings arising in the normal course
of business. In the opinion of management there are no legal proceedings pending
against the Company that are likely to have a material adverse effect on its
financial position or results of operations. See Note 8 regarding the Culley
Generating Station Investigation Matter.

8.       Environmental Matters

NOx SIP Call Matter
On October 27, 1998, the United States Environmental Protection Agency (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) that required
uniform nitrogen oxide (NOx) emissions reductions of 85% by utilities and other
large sources in certain Midwestern states and the District of Columbia. These
emission levels are below those already imposed by Phase I and Phase II of the
Clean Air Act Amendments of 1990 (the Act).

In their state implementation plans (SIPs), the USEPA encouraged states to
target utility coal-fired boilers for the majority of the reductions required,
especially NOx emissions. Northeastern states have claimed that ozone transport
from Midwestern states (including Indiana) is the primary reason for their ozone
concentration problems. Although this premise is challenged by others based on
various air quality modeling studies, including studies commissioned by the
USEPA, the USEPA intends to incorporate a regional control strategy to reduce
ozone transport.

The NOx emissions budget for Indiana stipulated in the USEPA's final ruling
requires a 31% reduction in total NOx emissions from Indiana. Indiana's
implementation plan requires the Company to lower its system-wide NOx emissions
to .14/mmbtu. Based on the level of system-wide emissions reductions required
and the control technology utilized to achieve the reductions, the current
estimated construction cost of the control equipment ranges from $175.0 million
to $200.0 million and is expected to be expended during the 2001-2004 period.
Related additional annual operation and maintenance expenses are estimated to be
$8.0 million to $10.0 million. Through September 30, 2001, approximately $10.8
million has been expended. The Company's system-wide compliance is required by
May 31, 2004 (the compliance date).

In April 2001, the Company initiated steps toward compliance with the revised
regulations. These steps include upgrading Culley Generating Station Unit 3
(Culley), Warrick Generating Station Unit 4 (Warrick), and A.B. Brown Generating
Station Unit 2 (A.B. Brown) with selective catalytic reduction (SCR) systems.
SCR systems reduce flue gas NOx emissions to atmospheric nitrogen and water
using ammonia in a chemical reaction. This technology is known to be the most
effective method of reducing NOx emissions where high removal efficiencies are
required. The Company expects the Culley, Warrick and A.B. Brown SCR systems to
be operational by the compliance date. Modifications to these stations are
expected to reduce the Company's overall NOx emissions to levels compliant with
Indiana's NOx emissions budget allotted by the USEPA. No accrual has been
recorded by the Company related to the NOx SIP Call matter. The rules governing
NOx emissions are to be applied prospectively.


<PAGE>  10

In August 2001, the Indiana Utility Regulatory Commission (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
project cost estimate for the construction, subject to periodic review of actual
costs incurred and (3) approves a mechanism for recovery of construction work in
progress on an ongoing basis so that prior to an electric rate base case, the
Company will recover its capital costs for the project, at its overall cost of
capital, including a return on equity.

Culley Generating Station Investigation Matter
The USEPA initiated an investigation under Section 114 of the Act of the
Company'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 performance standards should
be applied to the modifications and whether the best available control
technology was, or should have been, used. Numerous other electric utilities
were, and are currently, being investigated by the USEPA under an industry-wide
review for similar compliance. The Company responded to all of the USEPA's data
requests during the investigation. In July 1999, the Company received a letter
from the Office of Enforcement and Compliance Assurance of the USEPA discussing
the industry-wide investigation, vaguely referring to the investigation of the
Company and inviting the Company 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 the Company, regarding potential remedies to the USEPA's general
allegations.

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

The Company 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
performance standards, the Company believes that the lawsuit is without merit,
and intends to vigorously defend the lawsuit.

The lawsuit seeks fines against the Company 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 the
Company to install the best available emissions technology at the Culley
Generating Station. If the USEPA is successful in obtaining an order, the
Company 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 $200.0 million cost range previously discussed.

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

While it is possible that the Company could be subjected to criminal penalties
if the Culley Generating Station continues to operate without complying with the
new source performance standards and the allegations are determined by a court
to be valid, the Company 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.


<PAGE> 11

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

9.       Rate and Regulatory Matters

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 is allowed full recovery of such changes in purchased gas and fuel
costs for its retail customers through commission-approved gas and fuel cost
adjustment mechanisms.

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, the Company
entered into a settlement agreement with the Indiana Office of Utility Consumer
Counselor (OUCC) that provides certain terms with respect to the recoverability
of such costs. The settlement, originally approved by the IURC on August 9,
2000, has been extended by agreement through March 2002. Under the settlement,
the Company can recover the entire cost of purchased power up to an established
benchmark, and during forced outages, the Company will bear a limited share of
its purchased power costs regardless of the market costs at that time. Based on
this agreement, the Company believes it has limited its exposure to
unrecoverable purchased power costs.

10.      Affiliate Transactions

Certain wholly owned subsidiaries of Vectren began providing support services to
the Company beginning April 1, 2000. Approximately $6.2 million of certain
assets owned by the Company were contributed to a wholly owned subsidiary of
Vectren (Vectren Resources, LLC). The contribution of assets was reflected as a
reduction of common shareholder's equity and is omitted from the Condensed
Statements of Cash Flows.

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. For
the three months ended September 30, 2001 and 2000, amounts billed by other
wholly owned subsidiaries of Vectren to the Company were $9.1 million and $10.5
million, respectively. For the nine months ended September 30, 2001 and 2000,
amounts billed by other wholly owned subsidiaries of Vectren to the Company were
approximately $30.6 million and $20.8 million, respectively. Prior to April 1,
2000, these costs were incurred by the Company directly.

Vectren Fuels, Inc., a wholly owned subsidiary of Vectren, owns and operates
coal mines from which the Company purchases fuel used for electric generation.
Amounts paid for such purchases for the three months ended September 30, 2001
and 2000 were $7.3 million and $4.2 million respectively. Amounts paid for such
purchases for the nine months ended September 30, 2001 and 2000 were $28.2
million and $14.3 million, respectively. Amounts charged by Vectren Fuels, Inc.
are market based.

The Company also participates in a centralized cash management program with its
parent, affiliated companies and banks, which permits funding of checks as they
are presented.

Amounts owed to wholly owned subsidiaries of Vectren including notes payable to
an affiliated company, as of September 30, 2001 and December 31, 2000 totaled
$89.0 million and $11.5 million, respectively. Amounts due from wholly owned
subsidiaries of Vectren as of December 31, 2000 totaled $27.8 million.


<PAGE>  12

11.      Risk Management and New Accounting Principle

Risk Management
The Company is exposed to market risks associated with commodity prices,
interest rates, and counterparty 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 regulations, which
subject to compliance with applicable state regulations, allow for recovery of
such purchases through natural gas and fuel cost adjustment mechanisms. (See
Note 9 Rate and Regulatory Matters.)

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 wholesale power marketing activities manage the
utilization of the Company's 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 electric power 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.

Interest Rate Risk. The Company is exposed to interest rate risk associated with
its short-term borrowings and adjustable rate long term debt. 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 short-term
debt and adjustable rate long-term debt outstanding to a maximum of 25% of total
debt. However, there are times when this targeted level of interest rate
exposure may be exceeded.

Other Risks. By using forward purchase contracts and derivative financial
instruments to manage risk, the Company exposes itself to counterparty credit
risk and market risk. The Company manages this exposure to counterparty 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 manages
exposure to market risk associated with commodity contracts by establishing and
monitoring parameters that limit the types and degree of market risk that may be
undertaken.

Accounting for Forward Contracts and Other Financial Instruments
Commodity Contracts. At origination all contracts to buy and sell electric power
are designated as "physical", "other-than-trading" or "trading."

Power marketing contracts are designated as "physical" when there is intent and
ability to physically deliver power from the Company'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.


<PAGE>  13

Prior to the adoption of Statement of Financial Accounting Standard 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 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.

The Company may occasionally enter into forward purchase and sale contracts
designated as "trading" that attempt to take advantage of short-term movement in
commodity prices. Commodity contracts designated as "trading" are generally
settled net in accordance with industry trading standards. These contracts are
accounted for at market value. As of September 30, 2001, the Company has no
contracts designated as "trading."

Contracts recorded at market value are recorded as assets or liabilities in the
Condensed Balance Sheets as deferred charges, net, other current assets, other
accrued liabilities and other liabilities, as appropriate, and changes in market
value are recorded in the Condensed Statements of Operations as purchased
electric energy. Market value is determined using quoted market prices from
independent sources.

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, is effective for fiscal years beginning after June 15,
2000 and must be applied to derivative instruments and certain derivative
instruments embedded in hybrid contracts that were issued, acquired or
substantively modified after December 31, 1998. The Company adopted SFAS 133 as
of January 1, 2001.

SFAS 133 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."

Resulting from the adoption of SFAS 133, certain contracts in the power
marketing operations that are periodically settled net were required to be
recorded at market value. Previously, the Company accounted for these contracts
on settlement. The cumulative impact of the adoption of SFAS 133 resulting from
marking these contracts to market on January 1, 2001 was an earnings gain of
approximately $6.3 million ($3.9 million net of tax) recorded as a cumulative
effect of accounting change in the Condensed Statements of Operations. SFAS 133
did not impact other commodity contracts because they were normal purchases and
sales that are specifically excluded.

As of September 30, 2001, the Company has derivative assets resulting from its
power marketing operations of $6.9 million classified in other current assets as
well as derivative liabilities of $3.8 million classified in other accrued
liabilities. Unrealized losses totaling $3.3 million arising from the difference
between the current market value and the market value on the date of adoption is
included in fuel and purchased power in the Condensed Statements of Operations
for the nine months ended September 30, 2001. Unrealized losses for the three
months ended September 30, 2001 were $0.9 million.



<PAGE>  14


12.     Segment Reporting

Operating segments are defined as components of an enterprise for which separate
financial information is available and evaluated regularly by the chief
operating decision makers in deciding how to allocate resources and in the
assessment of performance.

There were two operating segments of the Company during the reported periods:
(1) Electric Utility Services and (2) Gas Utility Services. The Electric Utility
Services segment generates, transmits, distributes and sells electricity
primarily within southwestern Indiana and in periods of under utilized capacity,
sells unutilized electricity to other wholesale customers. The Gas Utility
Services segment distributes, transports and sells natural gas to Evansville,
Indiana and 64 communities in ten counties in southwestern Indiana. Revenues for
each segment are attributable to customers in the United States.

Certain information relating to the Company's business segments is presented
below.

<TABLE>
<CAPTION>
                                        Three Months               Nine Months
                                     Ended September 30,      Ended September 30,
                                    ---------------------    ---------------------
In thousands                           2001        2000        2001         2000
                                    ---------   ---------    ---------   ---------
<S>                                 <C>         <C>          <C>         <C>
Operating Revenues:
     Electric Utility Services      $ 104,335   $  97,936    $ 287,564   $ 249,215
     Gas Utility Services              11,032      14,739       74,333      58,148
                                    ---------   ---------    ---------   ---------
         Total operating revenues   $ 115,367   $ 112,675    $ 361,897   $ 307,363
                                    =========   =========    =========   =========

Net Income Applicable to
  Common Shareholder:
     Electric Utility Services      $  11,380   $  17,570    $  31,526   $  26,053
     Gas Utility Services               1,868        (788)       2,253       1,186
                                    ---------   ---------    ---------   ---------
         Net income applicable to
          common shareholder        $  13,248   $  16,782    $  33,779   $  27,239
                                    =========   =========    =========   =========
</TABLE>


                                 September 30,  December 31,
                                       2001         2000
                                 ------------   -----------
Identifiable Assets:
Electric Utility Services           $770,562     $799,104
Gas Utility Services                 153,074      152,210
                                    --------     --------
    Total identifiable assets       $923,636     $951,314
                                    ========     ========

13.      Impact of Recently Issued Accounting Guidance

SFAS 141 and 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
         not included as an allowable cost for ratemaking purposes will cease
         upon adoption of the statement. This includes goodwill recorded in past


<PAGE>  15

         business combinations. 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. The Company has no significant components of goodwill.

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 and SFAS 142 are not expected to materially impact
operations.

SFAS 143

Also 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 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,
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 currently evaluating the impact
that SFAS 144 will have on its operations.




<PAGE>  16


ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND
        FINANCIAL CONDITION

                    SOUTHERN INDIANA GAS AND ELECTRIC COMPANY

                           Description of the Business

Southern Indiana Gas and Electric Company (SIGECO or the Company) operates as a
separate wholly owned subsidiary of Vectren Corporation (Vectren) and provides
generation, transmission, distribution and sale of electric power to Evansville,
Indiana, and 74 other communities in 8 counties in southwestern Indiana, and the
distribution and sale of natural gas to Evansville, Indiana, and 64 communities
in 10 counties in southwestern Indiana.

Vectren is an Indiana Corporation that was organized on June 10, 1999 solely for
the purpose of effecting the merger of Indiana Energy, Inc. (Indiana Energy) and
SIGCORP, Inc. (SIGCORP), SIGECO's former parent company. On March 31, 2000, the
merger of Indiana Energy with SIGCORP and into Vectren was consummated with a
tax- free exchange of shares that has been accounted for as a
pooling-of-interests. The merger did not affect SIGECO's preferred stock or debt
securities.

                              Results of Operations

Net Income Applicable to Common Shareholder

For the three months ended September 30, 2001, net income applicable to common
shareholder was $13.2 million. Net income applicable to common shareholder
before merger and integration costs and restructuring costs was $13.7 million,
compared to net income applicable to common shareholder before merger and
integration costs for the third quarter of 2000 of $17.1 million.

For the nine months ended September 30, 2001, net income applicable to common
shareholder was $33.8 million. Net income applicable to common shareholder
before merger and integration costs and restructuring costs was $37.1 million,
compared to net income applicable to common shareholder before merger and
integration costs for the nine months ended September 30, 2000 of $38.3 million.

See discussion of merger and integration costs and restructuring costs that
follow.

Merger and Integration Costs

Merger and integration costs incurred for the three and nine months ended
September 30, 2001 were $0.3 million ($0.2 million after tax) and $0.6 million
($0.4 million after tax), respectively, and for the three and nine months ended
September 30, 2000 totaled $0.4 million ($0.3 million after tax) and $14.2
million ($11.1 million after tax), respectively. Vectren expects to realize net
merger savings of nearly $200.0 million over the next ten years from the
elimination of duplicate corporate and administrative programs and greater
efficiencies in operations, business processes and purchasing encompassed in
operations. The continued merger integration activities, which will contribute
to the merger savings, will be 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, $14.7 million has been expensed associated with merger and
integration activities. Accruals were established at March 31, 2000 totaling
$7.4 million. Of this amount, $0.7 million related to employee and executive
severance costs and $6.7 million related to transaction costs and regulatory
filing fees incurred prior to the closing of the merger. At September 30, 2001,
the accrual remaining for such costs totaled $0.3 million, all related to
severance costs. Of the $14.7 million expensed, the remaining $7.3 million was
expensed through September 30, 2001 ($6.7 million in 2000 and $0.6 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


<PAGE>  17

activities, internal labor of employees assigned to integration teams, investor
relations communications activities, and certain benefit costs.

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

Restructuring Costs

In June 2001, the management and board of directors of Vectren approved a plan
to restructure, primarily, its regulated operations. The restructuring plan
involves the elimination of administrative and supervisory positions in its
utility operations and corporate office. Charges of $4.3 million ($2.7 million
after tax) were expensed in June 2001 as a direct result of the restructuring
plan. Additional charges incurred during the third quarter relating primarily to
consulting fees and employee relocation totaled $0.4 million ($0.3 million after
tax). In total, the Company has incurred restructuring charges of $4.8 million
($3.0 million after tax). These charges were comprised of $3.5 million for
severance, related benefits and other employee related costs and $1.3 million
for consulting fees incurred as of September 30, 2001.

The $3.5 million expensed for employee severance and related costs is associated
with approximately 35 employees. Employee separation benefits include severance,
healthcare and outplacement services. As of September 30, 2001, approximately 20
employees have exited the business. These charges also include a non-cash charge
of $0.8 million related to the curtailment of a post retirement medical plan,
which included the impacted employees. The restructuring program will be
completed during 2001.

Utility Margin (Operating Revenues Less Cost of Fuel and Purchased Power and
Cost of Gas)

Electric Utility Margin
Electric Utility margin for the three months ended September 30, 2001 of $60.8
million, decreased $4.5 million, or 7%, compared to 2000 due to decreased margin
on wholesale energy sales and a reduction in margin recorded to reflect certain
wholesale power marketing purchase and sale contracts at current market values
as required by Statement of Financial Accounting Standard No. 133 "Accounting
for Derivative Instruments and Hedging Activities" (SFAS 133). The decrease in
wholesale margin is attributable to changes in wholesale electric prices. This
overall decrease was partially offset by an increase in residential and
commercial activity. Retail megawatt hours sold to residential and commercial
customers increased 7% for the quarter. This retail increase results from
weather 11% warmer than the previous year and combined residential and
commercial customer growth of 2%.

Electric Utility margin for the nine months ended September 30, 2001 of $161.3
million, decreased $7.2 million, or 4% over 2000 primarily due to decreased
margin on wholesale energy sales and a reduction in margin recorded to reflect
certain wholesale power marketing purchase and sale contracts at current market
values as required by SFAS 133. The decrease in wholesale margin is attributable
to changes in wholesale electric prices. This overall decrease was partially
offset by a $6.2 million increase in residential and commercial margin. Retail
megawatt hours sold to residential and commercial customers increased 7% for the
nine month period. This retail increase results from weather 12% warmer than the
previous year and combined residential and commercial customer growth of 3%.

Total cost of fuel for and purchased power increased $11.0 million, or 34%, and
$45.5 million, or 56%, for the three and nine month periods ended September 30,
2001, compared to the same periods in the prior year due primarily to increased
purchased power related to greater sales to other utilities and power marketers
as well as reductions in margin recorded as a result of SFAS 133.

Gas Utility Margin
Gas Utility margin for the three months ended September 30, 2001 of $5.1 million
was comparable to the prior year.

Total cost of gas sold was $5.9 million for the three months ended September 30,
2001 compared to $9.9 million in 2000. This decrease of $4.0 million, or 40% is
primarily due to a 32% decrease in volumes sold in 2001 in addition to decreased
gas costs. The total average cost per dekatherm of gas purchased by the Company
for the three months ended September 30, 2001 was $4.54 compared to $5.23 for
the same period in 2000.

Gas Utility margin for the nine months ended September 30, 2001 of $22.4 million
increased $0.8 million, or 4%, compared to 2000. The increase is due to a 3%
increase in volumes sold to residential and commercial customers resulting
primarily from weather 8% colder than the previous year. These favorable impacts
on gas margin were partially offset by reduced consumption, the cost of
unaccounted for gas, and a 6% decrease in volumes transported for and sold to
contract customers, all primarily due to the effects of increased gas costs.

Total cost of gas sold was $51.9 million for the nine months ended September 30,
2001 and $36.5 million in 2000. This increase of $15.4 million, or 42%, compared
to 2000 is primarily due to higher per unit purchased gas costs in addition to a
3% increase in volumes sold to residential and commercial customers. The total
average cost per dekatherm of gas purchased by the Company for the nine months
ended September 30, 2001 was $5.70 compared to $4.77 for the same period in
2000.

Commodity prices for natural gas purchased 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 is allowed full recovery of such changes in purchased gas costs from its
retail customers through commission-approved gas cost adjustment mechanisms, and
margin on gas sales should not be impacted. However, in 2001, the Company has
experienced and may continue to experience higher working capital requirements,
increased expenses including unrecoverable interest costs, uncollectibles and
unaccounted for gas, and some level of price sensitive reduction in volumes
sold.

Operating Expenses

Operations and Maintenance
Operations and maintenance expenses decreased $1.5 million, or 6%, for the three
months ended September 30, 2001 compared to the prior year, and operations and
maintenance expenses decreased $2.4 million, or 3% for the nine months ended
September 30, 2001. The decreases reflect merger synergies causing less general
and administrative expenses.

Income Taxes
Federal and state income taxes decreased $1.4 million for the three month period
and decreased $0.5 million for the nine month period due primarily due to
fluctuations in pre-tax earnings. The effective tax rate for the nine month
period in 2000 was higher as a result of the non-deductibility of certain merger
and integration costs.

Interest Expense

Interest expense for the three months ended September 30, 2001 was comparable to
the prior year and increased by $0.8 million for the nine months ended September
30, 2001 when compared to the prior year. The increase was due primarily to
increased working capital requirements resulting from higher natural gas prices.

                             Other Operating Matters

New Accounting Principle and Cumulative Effect of Change in Accounting Principle

See Note 11 in the condensed financial statements included in Part 1, Item 1
regarding the adoption of SFAS 133, as amended.


<PAGE>  19

                               Financial Condition

Liquidity and Capital Resources

The Company's equity capitalization objective is 40-55% of total capitalization.
This objective may have varied, and will vary, from time to time, depending on
particular business opportunities and seasonal factors that affect the Company's
operation. The Company's common equity component was 54% and 52% of total
capitalization, including current maturities of long-term debt, at September 30,
2001 and December 31, 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, 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 higher
natural gas costs.

Vectren Utility Holdings, Inc. (VUHI) serves as the intermediate holding company
for Vectren Corporation's (Vectren) three operating utility companies, the
Company, VEDO and Indiana Gas Company, Inc., who are guarantors of VUHI's $350.0
million commercial paper program, of which $343.8 million is outstanding at
September 30, 2001 and VUHI's $350.0 million unsecured senior notes, of which
zero is outstanding at September 30, 2001. In October 2001, $100.0 million of
the unsecured senior notes were issued. The proceeds of which were used to pay
down outstanding commercial paper. 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.

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 $61.5
million and $64.0 million for the nine months ended September 30, 2001 and 2000,
respectively.

Cash flow from operations decreased during the nine months ended September 30,
2001 compared to 2000 by $2.5 million due to decreased working capital
requirements, offset by increased net income.

The Company expects the majority of its capital expenditures and debt security
redemptions to be provided by internally generated funds.

Financing Activities
Cash flow required for financing activities of $16.5 million for the nine months
ended September 30, 2001 includes common stock dividends of $24.0 million and
the retirement of a majority of outstanding preferred stock, offset by $25.9
million of additional net borrowings. This is a decrease of $7.5 million in cash
required for financing activities when compared to the nine months ended
September 30, 2000. The decrease is primarily due to increased reliance on
short-term borrowings.

In September 2001, the Company notified holders of its 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 $1.3464 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 $0.9694 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 $0.7339 in
accrued and unpaid dividends. Prior to the redemption, there were 75,000 shares
outstanding.

The Company has $53.7 million of adjustable rate pollution control series first
mortgage bonds which could, at the election of the bondholder, be tendered to
the Company when the interest rates are reset. Prior to the latest reset on


<PAGE>  20

March 1, 2001, the interest rates were reset annually, and the bonds subject to
tender were presented in the Condensed Balance Sheets as current liabilities.
Effective March 1, 2001, the bonds were reset for a five-year period and have
been classified as long-term debt. Resulting from the reset, the interest rate
on the $31.5 million Series A bonds increased from 4.30% to 4.75%, and the
interest rate on the $22.2 million Series C bonds increased from 4.45% to 5.00%.

At September 30, 2001, the Company has approximately $24.0 million of short-term
borrowing capacity with third parties for use in its operations, of which
approximately $19.3 million is available.

The Company's credit rating on outstanding debt at September 30, 2001 was A/A1.
Subsequent to September 30, 2001, Standard & Poor's lowered its above ratings by
one level.

Capital Expenditures and Other Investment Activities
Cash required for investing activities of $43.6 million for the nine months
ended September 30, 2001 is comprised mainly of capital expenditures. Cash
requirements for investing activities have increased $4.5 million from prior
year requirements due to an increase in capital expenditures for utility plant,
principally for NOx compliance.

New construction, normal system maintenance and improvements, and technology
investments needed to provide service to a growing customer base will continue
to require substantial expenditures. Capital expenditures for the remainder of
2001 are estimated at $31.1 million and are expected to be $105.8 million for
2002.

Environmental and Regulatory Matters

See Notes 8 and 9 in the Condensed Financial Statements included in Part I, Item
1 regarding matters affecting operations including Culley Generating Station
Investigation Matter compliance (Note 8) and purchased power cost recovery (Note
9).

Impact of Recently Issued Accounting Guidance

See Note 13 in the Condensed Financial Statements included in Part I, Item 1
regarding recently issued accounting standards.

                           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 Vectren and its
subsidiaries' 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


<PAGE>  21

               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.



<PAGE>  22


ITEM 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Risk Management
The Company is exposed to market risks associated with commodity prices,
interest rates, and counterparty 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 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 regulations which, subject to
compliance with applicable state regulations, allow for recovery of such
purchases through natural gas and fuel cost adjustment mechanisms. (See Note 9
Rate and Regulatory Matters in the condensed financial statements included in
Part 1, Item 1.)

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 wholesale 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 electric power 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 of pre-tax
earnings resulting from a 10% adverse change in the forward price of electricity
on market sensitive financial instruments (all contracts not expected to be
settled by physical receipt or delivery). For the three and nine months ended
September 30, 2001, a 10% adverse change in the forward prices of electricity on
market sensitive financial instruments would have decreased pre-tax earnings by
approximately $0.6 million and $2.0 million, respectively.

Interest Rate Risk. The Company is exposed to interest rate risk associated with
its short-term borrowings and adjustable rate long term debt. The Company's 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 short-term
debt and adjustable rate long-term debt outstanding to a maximum of 25% of total
debt. However, there are times when this targeted level of interest rate
exposure may be exceeded.

At September 30, 2001, the Company's short-term debt, represented 18% of the
Company's total debt portfolio due primarily to resetting of adjustable rate
bonds for a five year period, offset by increased working capital requirements
resulting from higher purchased gas costs.

Market risk is estimated as the potential impact resulting from fluctuations in
interest rates on short-term borrowings, including bank notes, lines of credit
and notes payable to affiliated companies. At September 30, 2001 and December
31, 2000, the combined borrowings under these facilities totaled $66.1 million
and $40.2 million, respectively. Based upon average borrowing rates under these
facilities during the three months ended September 30, 2001 and 2000, an
increase of 100 basis points (1%) in the rates would have increased interest
expense by $0.1 million for both periods. For the nine months ended September
30, 2001 and 2000, an increase of 100 basis points in the rates would have
increased interest expense by $0.3 million and $0.2 million, respectively.


<PAGE>  23

Other Risks. By using forward purchase contracts and derivative financial
instruments to manage risk, the Company exposes itself to counterparty credit
risk and market risk. The Company manages this exposure to counterparty 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 manages
exposure to market risk associated with commodity contracts by establishing and
monitoring parameters that limit the types and degree of market risk that may be
undertaken.





<PAGE>  24



                    SOUTHERN INDIANA GAS AND ELECTRIC COMPANY

                              PART II - OTHER ITEMS


ITEM 1.  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 the
financial position or results of operations. See Note 8 regarding the Culley
Generating Station Investigation Matter in Part 1, Item 1.

ITEM 6.  EXHIBITS AND REPORTS ON FORM 8-K

Exhibits

     None


Reports on Form 8-K

On July 27, 2001, the Company filed a Current Report on Form 8-K with respect to
the release of financial information to the investment community regarding
Vectren's results of operations, financial position and cash flows for the
three, nine and twelve month periods ended June 30, 2001. The financial
information was released to the public through this filing.
         Item 5.  Other Events
         Item 7.  Exhibits
                    99.1 - Press Release - Second Quarter 2001 Vectren Earnings
                    99.2 - Cautionary Statement for Purposes of the "Safe
                         Harbor" Provisions of the Private Securities Litigation
                         Reform Act of 1995




<PAGE>  25



                                   SIGNATURES

      Pursuant to the requirements 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.


                                   SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
                                   -----------------------------------------
                                                   Registrant




        November 14, 2001                 /s/Jerome A. Benkert, Jr.
                                          -------------------------
                                          Jerome A. Benkert, Jr.
                                          Executive Vice President,
                                          Chief Financial Officer and Treasurer


                                          /s/M. Susan Hardwick
                                          ------------------------
                                          M. Susan Hardwick
                                          Vice President and Controller