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 the quarterly period ended June 30, 2000

                             OR

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

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)  (Zip Code)

                       (812) 465-5300
    (Registrant's telephone number, including area code)


Indicate by check mark whether the Registrants (1) have
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
Registrants were 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 of shares outstanding of each of the
Registrants' classes of common stock, as of the latest
practicable date:

<TABLE>
<S>                                <C>                <C>
Common Stock - Without par value   15,754,826         August 11, 2000
---------------------------------  ----------         ---------------
              Class                Number of shares         Date
</TABLE>



<PAGE> 2
<TABLE>
                             TABLE OF CONTENTS

Item                                                     Page
Number                                                   Number
<S>       <C>                                            <C>
            Part I.  Financial Information
  1       Financial Statements (Unaudited)
          Southern Indiana Gas and Electric Company
                  Balance Sheets                         3-4
                  Statements of Income                   5-6
                  Statements of Cash Flows               7
          Notes to Financial Statements                  8-13
  2       Management's Discussion and Analysis of
                  Financial Condition and Results of
                  Operations                             14-19
          Quantitative & Qualitative Disclosure About
  3               Market Risk                            19-20

              Part II.  Other Information
  1       Legal Proceedings                              21
  4       Submission of Matters to a Vote of Security    21
          Holders
  6       Exhibits and Reports on Form 8-K               21
          Signatures                                     22



<PAGE> 3

</TABLE>
<TABLE>
                SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
                              BALANCE SHEETS
                         (Unaudited - Thousands)

                                             June 30          December 31
                                     ----------------------   -----------
                                     2000         1999        1999
<S>                                  <C>          <C>         <C>
ASSETS

Utility Plant, at original cost:
  Electric                           $1,147,068   $1,149,334  $1,160,216
  Gas                                   155,034      150,551     156,918
                                     ----------   ----------  ----------
                                      1,302,102    1,299,885   1,317,134
  Less: accumulated depreciation
   and amortization                     634,869      614,404     623,611
                                     ----------   ----------  ----------
                                        667,233      685,481     693,523
  Construction work in progress          63,595       46,130      45,393
                                     ----------   ----------  ----------
    Net utility plant                   730,828      731,611     738,916

Current Assets:
  Cash and cash equivalents                 840          343         449
  Accounts receivables, less reserves
   of $2,171, $2,460 and $2,138,
   respectively                          41,389       27,587      34,738
  Accrued unbilled revenues              12,871       13,587      18,736
  Inventories                            28,814       38,736      39,190
  Current regulatory assets              10,185        7,555       7,921
  Other current assets                        -        3,056       2,970
                                     ----------   ----------  ----------
    Total current assets                 94,099       90,864     104,004

Other Investments and Property:
  Environmental improvement fund
   held by trustee                        1,020        4,384         996
  Notes receivable                        7,326            -       1,159
  Nonutility property and other, net      2,925        1,577       1,627
                                     ----------   ----------  ----------
    Total other investments and
     property                            11,271        5,961       3,782

Other Assets:
  Unamortized premium on reacquired
   debt                                   3,825        4,050       3,937
  Demand side management programs        25,845       24,995      25,298
  Allowance inventory                     2,269        2,269       2,269
  Deferred charges                       10,236       14,466      16,553
                                     ----------   ----------  ----------
     Total other assets                  42,175       45,780      48,057

TOTAL ASSETS                         $  878,373   $  874,216  $  894,759
                                     ==========   ==========  ==========
<FN>
The accompanying notes are an integral part
 of these financial statements.
</FN>
</TABLE>




<PAGE> 4
<TABLE>
                SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
                              BALANCE SHEETS
                         (Unaudited - Thousands)
                                               June 30        December 31
                                        -------------------   -----------
                                        2000        1999      1999
<S>                                     <C>         <C>       <C>
SHAREHOLDER'S EQUITY AND LIABILITIES

Capitalization:
Common Stock                            $ 78,258    $ 78,258  $ 78,258
Retained Earnings                        254,819     246,127   256,312
Contributions                            (12,132)          -         -
                                        --------    --------  --------
   Total common shareholder's equity     320,945     324,385   334,570
Cumulative nonredeemable preferred
 stock                                    11,090      11,090    11,090
Cumulative redeemable preferred stock      7,500       7,500     7,500
Cumulative special preferred stock           575         692       692
Long-term debt, net of current
 maturities                              237,697     169,799   238,282
                                        --------    --------  --------
   Total capitalization, excluding
    bonds subject to tender              577,807     513,466   592,134
                                        --------    --------  --------
Commitments and Contingencies

Current Liabilities:
Current maturities of adjustable rate
 bonds subject to tender                  53,700      53,700    53,700

   Notes payable                          16,352      83,584    22,880
   Notes payable to affiliated company    14,011      20,500         -
   Accounts payable                       30,264      17,779    28,560
   Dividends payable                         104         117       117
   Accrued taxes                           9,813       2,124     8,408
   Accrued interest                        5,636       4,082     6,012
   Refunds to customers                    2,306       2,916     5,375
   Other accrued liabilities              22,018      24,688    22,706
                                        --------    --------  --------
     Total current liabilities           154,204     209,490   147,758
                                        --------    --------  --------
Deferred Credits and Other Liabilities:
  Accumulated deferred income taxes      115,706     118,555   122,977
  Unamortized investment tax credits      16,658      18,087    17,372
  Accrued postretirement benefits other
   than pensions                          13,703      13,006    12,041
  Other                                      295       1,612     2,477
                                        --------    --------  --------
   Total deferred credits and
    other liabilities                    146,362     151,260   154,867
                                        --------    --------  --------
TOTAL SHAREHOLDER'S EQUITY AND
LIABILITIES                             $878,373    $874,216  $894,759
                                        =========   ========  =========
<FN>
The accompanying notes are an integral part
 of these financial statements.
</FN>
</TABLE>




<PAGE> 5
<TABLE>
                SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
                           STATEMENTS OF INCOME
                         (Unaudited - Thousands)

                                  Three Months Ended    Six Months Ended
                                        June 30             June 30
                                  ------------------  ------------------
                                  2000      1999      2000       1999
<S>                               <C>       <C>       <C>        <C>
OPERATING REVENUES:
  Electric revenues               $78,289   $73,802   $151,279   $144,789
  Gas revenues                     14,182    10,516     43,409     40,214
                                  -------   -------   --------   --------
    Total operating revenues      92,471     84,318    194,688    185,003
                                  ------    -------   --------   --------
COST OF OPERATING REVENUES:
  Cost of fuel and purchased
   power                           26,423    23,943     48,101     44,073
  Cost of gas                       7,012     4,867     26,646     24,372
                                  -------   -------   --------   --------
    Total cost of operating
     revenues                      33,435    28,810     74,747     68,445
                                  -------   -------   --------   --------
      Total margin                 59,036    55,508    119,941    116,558
                                  -------   -------   --------   --------
OPERATING EXPENSES:
  Operations and maintenance       28,505    24,357     49,743     46,586
  Merger costs                      1,402         -     13,759          -
  Depreciation and amortization    10,712    11,216     22,202     22,433
  Income taxes                      4,610     4,535      8,847     11,865
  Taxes other than income taxes     3,107     3,062      6,340      6,189
                                  -------   -------   --------   --------
    Total operating expenses       48,336    43,170    100,891     87,073

OPERATING INCOME                   10,700    12,338     19,050     29,485

OTHER INCOME -NET                     892       203      1,591        286
                                  -------   -------   --------   --------
INCOME BEFORE INTEREST AND
PREFERRED STOCK DIVIDEND           11,592    12,541     20,641     29,771

INTEREST EXPENSE                    4,866     4,655      9,649      9,378
                                  -------   -------   --------   --------
NET INCOME                          6,726     7,886     10,992     20,393

PREFERRED STOCK DIVIDEND              267       269        535        539
                                  -------   -------   --------   --------
NET INCOME APPLICABLE TO COMMON
SHAREHOLDERS                      $ 6,459   $ 7,617   $ 10,457   $ 19,854
                                  =======   =======   ========   ========
<FN>
The accompanying notes are an integral part
 of these financial statements.
</FN>
</TABLE>








<PAGE> 6
<TABLE>
               SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
                         STATEMENTS OF INCOME
                        (Unaudited - Thousands)

                                                  Twelve Months Ended
                                                        June 30
                                                 --------------------
                                                 2000        1999
<S>                                              <C>         <C>
OPERATING REVENUES:
  Electric revenues                              $314,059    $299,901
  Gas revenues                                     71,407      66,802
                                                 --------    --------
    Total operating revenues                      385,466     366,703
                                                 --------    --------
COST OF OPERATING REVENUES:
  Cost of fuel and purchased power                 96,974      92,380
  Cost of gas                                      41,886      38,358
                                                 --------    --------
    Total cost of operating revenues              138,860     130,738
                                                 --------    --------
      Total margin                                246,606     235,965

OPERATING EXPENSES:
  Operations and maintenance                       98,815      93,108
  Merger costs                                     13,759           -
  Depreciation and amortization                    44,636      43,570
  Income taxes                                     23,409      24,731
  Taxes other than income taxes                    12,996      12,004
                                                 --------    --------
    Total operating expenses                      193,615     173,413

OPERATING INCOME                                   52,991      62,552

OTHER INCOME -NET                                   3,859         689
                                                 --------    --------
INCOME BEFORE INTEREST AND PREFERRED
STOCK DIVIDEND                                     56,850      63,241

INTEREST EXPENSE                                   19,483      20,201
                                                 --------    --------
NET INCOME                                         37,367      43,040

PREFERRED STOCK DIVIDEND                            1,074       1,086
                                                 --------    --------
NET INCOME APPLICABLE TO COMMON SHAREHOLDERS     $ 36,293    $ 41,954
                                                 ========    ========
<FN>
The accompanying notes are an integral part
 of these financial statements.
</FN>
</TABLE>








<PAGE> 7
<TABLE>
                SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
                         STATEMENTS OF CASH FLOWS
                         (Unaudited - Thousands)

                                                          Twelve Months
                                   Six Months Ended           Ended
                                       June 30               June 30
                                 -----------------     -----------------
                                 2000        1999      2000      1999
<S>                              <C>         <C>       <C>       <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
  Net income                      $10,992    $20,393   $37,367   $43,040
  Adjustments to reconcile net
   income to net cash provided
   from operating activities:
    Depreciation and amortization  22,202     22,433    44,636    43,570
    Deferred income taxes and
     investment tax credits, net   (7,984)      (307)   (4,277)    2,880
    Allowance for other funds
     used during construction           -         51       245        43
    Changes in assets and liabilities:
      Receivables, net (including
       accrued unbilled revenues)   (6,953)    8,274   (20,410)    6,390
      Inventories                   10,376     5,654     9,923    (3,099)
      Accounts payable               1,705   (10,348)   12,485    (2,200)
      Accrued taxes                  1,405    (2,647)    7,689    (1,766)
      Refunds to customers and
       from gas suppliers           (3,069)      761      (611)    2,221
      Other assets and
       liabilities                   5,421    10,092     3,315     5,544
                                   -------   -------   -------   -------
    Net cash flows from operating
     activities                     34,095    54,356    90,362    96,623
                                   -------   -------   -------   -------

CASH FLOWS (REQUIRED FOR) FINANCING ACTIVITIES:
  Retirement of long-term debt           -   (45,000)  (10,000)  (59,000)
  Proceeds from long-term debt           -         -    80,000         -
  Dividends paid                   (15,545)  (16,191)  (31,734)  (31,533)
  Reduction in preferred stock        (117)     (116)     (116)     (232)
  Change in environmental
   improvement funds held by
   trustee                             (23)      (84)    3,364      (187)
  Net change in short-term
   borrowings and notes payable
   to affiliated company             6,898    38,395   (75,876)   60,260
  Other                              3,174       213     2,815        (2)
                                   -------   -------   -------   -------
    Net cash flows(required for)
     financing activities           (5,613)  (22,783)  (31,547)  (30,694)
                                   -------   -------   -------   -------
CASH FLOWS (REQUIRED FOR)
INVESTING ACTIVITIES:
  Construction expenditures (net
   of allowance for funds
   used during construction)       (25,243)  (31,422)  (54,498)  (62,565)
  Change in nonutility property     (1,298)        -    (1,348)      (15)
  Other                             (1,550)     (320)   (2,472)   (3,112)
                                   -------   -------   -------   -------
    Net cash flows (required for)
     investing activities          (28,091)  (31,742)  (58,318)  (65,692)
                                   -------   -------   -------   -------
Net increase (decrease) in cash
and
 cash equivalents                      391      (169)      497       237

Cash and cash equivalents at
 beginning of period                   449       512       343       106
                                   -------   -------   -------   -------
Cash and cash equivalents at end
 of period                         $   840   $   343   $   840   $   343
                                   =======   =======   =======   =======
<FN>
The accompanying notes are an integral part
 of these financial statements.
</FN>
</TABLE>


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

1.  Organization and Nature of Operations

Southern Indiana Gas and Electric Company (SIGECO) is an
operating public utility. SIGECO provides generation,
transmission, distribution and sales of electric power to
Evansville, Indiana and 74 other communities and the
distribution of natural gas to Evansville, Indiana and 64
other communities in ten counties in southwestern Indiana.

2.  Financial Statements

The interim consolidated financial statements included in
this report have been prepared, without audit, as provided
in the rules and regulations of the Securities and Exchange
Commission (SEC).  Certain information and footnote
disclosures normally included in financial statements
prepared in accordance with generally accepted accounting
principles have been omitted as provided in such rules and
regulations.  SIGECO believes that the information in this
report reflects all adjustments necessary to fairly state
the results of the interim periods reported, that all such
adjustments are of a normal recurring nature, and the
disclosures are adequate to make the information presented
not misleading. The preparation of financial statements in
conformity with generally accepted accounting principles
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.   These interim financial
statements should be read in conjunction with the financial
statements and notes thereto included in SIGECO's latest
annual report on Form 10-K.

Because all of the common stock of SIGECO is owned by
Vectren (see below), SIGECO does not report earnings per
share.

Because of the seasonal nature of SIGECO's utility
operations, the results shown on a quarterly basis are not
necessarily indicative of annual results.

3.  Indiana Energy, Inc. and SIGCORP, Inc. Merger

On June 14, 1999, Indiana Energy, Inc. (Indiana Energy) and
SIGCORP, Inc. (SIGCORP) jointly announced the signing of a
definitive agreement to combine into a new holding company
named Vectren Corporation (Vectren). The merger was
conditioned, among other things, upon the approvals of the
shareholders of each company and customary regulatory
approvals.  Such approvals were obtained and the merger was
consummated on March 31, 2000.  As provided for in the
merger agreement, Indiana Energy shareholders received one
share of Vectren common stock for each share of Indiana
Energy held at the March 31, 2000 closing date. SIGCORP
shareholders received one and one-third shares of Vectren
common stock for each share of SIGCORP held at the March 31,
2000 closing date.  The transaction was accounted for as a
pooling of interests.  The transaction was a tax-free
exchange of shares.

Southern Indiana Gas and Electric Company, formerly a wholly
owned subsidiary of SIGCORP,  operates as a separate wholly
owned subsidiary of Vectren.

4.  Merger Costs

Merger costs incurred by Vectren for the three and six
months ended June 30, 2000 totaled $3.3 million and $30.4
million, respectively.  These costs relate primarily to
transaction costs, severance and other merger integration
activities.  Vectren expects to realize net merger savings
of nearly $200 million over the next ten years from the
elimination of duplicate corporate and administrative
programs and greater efficiencies in operations, business
processes and purchasing.  The continued merger integration
activities will be substantially complete by 2001. Merger
costs are reflected in the financial statements of the
operating subsidiaries in which the merger savings are
expected to be realized. Merger costs expensed by SIGECO for
the three and six months ended June 30, 2000 totaled $1.4
million and $13.8 million, respectively.





<PAGE> 9

5.  Cash Flow Information

For purposes of the Statements of Cash Flows, SIGECO
considers cash investments with an original maturity of
three months or less to be cash equivalents.  Cash paid
during the periods reported for interest and income taxes
were as follows:

<TABLE>
                                Six Months Ended     Twelve Months Ended
                                    June 30                June 30
                               -----------------     -------------------
                                 2000      1999        2000       1999
<S>                            <C>       <C>         <C>       <C>
Thousands
Interest (net of amount
capitalized)                   $ 8,798   $ 9,698     $14,537   $19,128
Income taxes                   $13,618   $14,766     $24,327   $23,209
</TABLE>

6.  Capitalization

On July 3, 2000, all of SIGECO's $9,975,000 Adjustable Rate
Pollution Control Revenue Bonds were remarketed and the
interest rate was reset to 4.75% from 4.55%. The new
interest rate will be effective from July 1, 2000 through
June 30, 2001.

On July 7, 2000, SIGECO repurchased 22,000 shares of its
4.75% nonredeemable $100 par value preferred stock at a
purchase price of $84.25 per share. The stock was
repurchased as treasury stock and is to be retired.

7.  Gas in Underground Storage

Based on the average cost of gas purchased during June 2000,
the cost of replacing the current portion of gas in
underground storage exceeded LIFO cost at June 30, 2000 by
approximately $18.9 million.

8.  Refundable or Recoverable Gas and Fuel Costs

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

SIGECO records any adjustment clause under-or-overrecovery
each month in revenues. A corresponding asset or liability
is recorded until such time as the under-or-overrecovery 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.

On August 18, 1999, the Indiana Utility Regulatory
Commission (IURC) issued a generic order which established
new guidelines for the recovery of purchased power costs.
Those guidelines provided that SIGECO is able to recover
through rates the total cost incurred for purchased power if
over a period of seven days the average cost of purchased
power is below the highest cost of internal generation at
SIGECO or the higher costs can be justified in a fuel
adjustment clause filing. The generic order issued by the
IURC was appealed by the Indiana Office of Utility Consumer
Counselor (OUCC). On August 9, 2000, the IURC approved a
settlement between SIGECO and the OUCC which resolved all
issues between SIGECO and the OUCC regarding the IURC's
generic order and dismissed the OUCC's appeal. The
settlement pertains to the summer months of 2000 and the
parties have agreed to collaborate on a permanent agreement
covering future periods.  The settlement provides a price
cap on the recovery from retail electric customers of
purchased power costs incurred by SIGECO during normal
economic dispatch conditions and provides for 85 percent
recoverability of purchased power costs incurred during
unplanned forced outages. SIGECO does not anticipate the
potential limitation of recoverability of its purchased
power costs to be material under this settlement.

<PAGE> 10

9.  Environmental Costs

In October 1997, the United States Environmental Protection
Agency (USEPA) proposed a rulemaking that could require
uniform NOx emissions reductions of 85 percent by utilities
and other large sources in a 22-state region spanning areas
in the Northeast, Midwest, Great Lakes, Mid-Atlantic and
South. This rule is referred to as the "NOx SIP call".  The
USEPA provided each state a proposed budget of allowed NOx
emissions, a key ingredient of ozone, which requires a
significant reduction of such emissions.  Under that budget,
utilities may be required to reduce NOx emissions to a rate
of 0.15 lb/mmBtu below levels already imposed by Phase I and
Phase II of the Clean Air Act Amendments of 1990.
Midwestern states (the alliance) have been working together
to determine the most appropriate compliance strategy as an
alternative to the USEPA proposal.  The alliance submitted
its proposal, which calls for a smaller, phased in reduction
of NOx levels, to the USEPA and the Indiana Department of
Environmental Management in June 1998.

In July 1998, Indiana submitted its proposed plan to the
USEPA in response to the USEPA's proposed new NOx rule and
the emissions budget proposed for Indiana.  The Indiana
plan, which calls for a reduction of NOx emissions to a rate
of 0.25 lb/mmBtu by 2003, is less stringent than the USEPA
proposal but more stringent than the alliance proposal.

On October 27, 1998, 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). The final rule requires that 23 states and
jurisdictions must file revised state implementation plans
(SIPs) with the USEPA by no later than September 30, 1999,
which was essentially unchanged from its October 1997,
proposed rule.  The USEPA has 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 USEPA's final ruling is being
litigated in the federal courts by approximately ten
midwestern states, including Indiana.

During the second quarter of 1999, the USEPA lost two
federal court challenges to key air-pollution control
requirements.  In the first ruling by the U.S. Circuit Court
of Appeals for the District of Columbia on May 14, 1999, the
Court struck down the USEPA's attempt to tighten the one-
hour ozone standard to an eight-hour standard and the
attempt to tighten the standard for particulate emissions,
finding the actions unconstitutional.  In the second ruling
by the same Court on May 25, 1999, the Court placed an
indefinite stay on the USEPA's attempts to reduce the
allowed NOx emissions rate from levels required by the Clean
Air Act Amendments of 1990.  The USEPA appealed both court
rulings.  On October 29, 1999, the Court refused to
reconsider its May 14, 1999 ruling.

On March 3, 2000, the D.C. Circuit of Appeals upheld the
USEPA's October 27, 1998 final rule requiring 23 states and
the District of Columbia to file revised SIPs with the USEPA
by no later than September 30, 1999.  Numerous petitioners,
including several states, have filed petitions for rehearing
with the U.S. Court of Appeals for the District of Columbia
in Michigan v. the USEPA. On June 22, 2000, the D.C. Circuit
Court of Appeals denied petition for rehearing en banc and
lifted its May 25, 1999 stay.

The proposed NOx emissions budget for Indiana stipulated in
the USEPA's final ruling requires a 36 percent reduction in
total NOx emissions from Indiana.  The ruling could require
SIGECO to lower its system-wide emissions by approximately
70 percent.  Depending on the level of system-wide emissions
reductions ultimately required, and the control technology
utilized to achieve the reductions, the estimated
construction costs of the control equipment could reach $100
million, and related additional operation and maintenance
expenses could be an estimated $8 million to $10 million,
annually.  Under the USEPA implementation schedule, the
emissions reductions and required control equipment must be
implemented and in place by May 15, 2003.

The USEPA initiated an investigation under Section 114 of
the Clean Air Act (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 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.  SIGECO responded to all of
the USEPA's data requests during the investigation.  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 the
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 with the
USEPA and targeted utilities, including SIGECO, regarding
potential remedies to the USEPA's general allegations.

<PAGE> 11

On November 3, 1999, the USEPA filed a lawsuit against seven
utilities, including SIGECO.  The USEPA alleges that,
beginning in 1992, SIGECO violated the Clean Air 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
SIGECO to begin complying with federal new source
performance standards.

SIGECO believes it performed only maintenance, repair and
replacement activities at the Culley Generating Station, as
allowed under the Clean Air 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, SIGECO
believes that the lawsuit is without merit, and intends to
vigorously defend the lawsuit.

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 is successful
in obtaining an order, SIGECO estimates that it would incur
capital costs of approximately $40 million to $50 million
complying with the order.  In the event that SIGECO is
required to install system-wide NOx emission control
equipment, as a result of the NOx SIP call issue, the
majority of the $40 million to $50 million for best
available emissions technology at Culley Generating Station
would be included in the $100 million expenditure 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 new source
performance standards 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
Clean Air Act.  Consequently, SIGECO anticipates at this
time that the plant will continue to operate while the
matter is being decided.

10.  Commitments and Contingencies

SIGECO is party to various legal proceeding arising in the
normal course of business.  In the opinion of management,
there are no legal proceedings pending against SIGECO that
are likely to have a material adverse effect on the
financial position or results of operations.  Refer to Note
9 for litigation matters concerning the Clean Air Act.

11.  Affiliated Transactions

Certain wholly owned subsidiaries of Vectren began providing
support services to SIGECO beginning April 1, 2000.  As of
March 31, 2000, certain assets owned by Sigeco were
contributed to a wholly owned subsidiary of Vectren (Vectren
Resources, LLC).  The contribution of assets is reflected as
a reduction of common shareholder's equity.  Vectren
Resources, LLC provides asset services to Sigeco, the fee
for which is reflected in operation and maintenance expenses
in the accompanying financial statements.  Services provided
include corporate-level management services, information
technology, financial, human resources, purchasing, building
and fleet services.  Amounts billed by the affiliates to
SIGECO for the three months ended June 30, 2000, totaled
$10.3 million.  Prior to April 1, 2000, these costs were
incurred by SIGECO directly.

SIGECO purchases coal from a wholly owned subsidiary of
Vectren.  SIGECO's coal purchases during the three, six and
twelve months ended June 30, 2000 totaled $6.0 million, $9.3
million and $19.9 million, respectively.  SIGECO's coal
purchases during the three, six and twelve months ended June
30, 1999 totaled $5.0 million, $9.9 million and $19.5
million, respectively.

SIGECO 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 due from unconsolidated affiliates totaled $4.3
million, $0 million and $2.0 million at June 30, 2000 and
1999 and December 31, 1999, respectively, and are included
in Accounts Receivable on the Consolidated Balance Sheets.

<PAGE> 12

12.  Segments of Business

SIGECO adopted Statement of Financial Accounting Standards
(SFAS) No. 131 "Disclosure about Segments of an Enterprise
and Related Information."  SFAS No. 131 establishes
standards for the reporting of information about operating
segments in financial statements and disclosures about
products, services and geographical areas.  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.

The operating segments of SIGECO are defined as (1) Gas
Utility Services and (2) Electric Utility Services.


<TABLE>

                                      Three Months         Six Months
                                     Ended June 30       Ended June 30
                                    ----------------   ------------------
                                   2000 <1>    1999   2000 <1>     1999
<S>                                <C>       <C>      <C>        <C>
Operating Revenues:
  Gas Utility Services             $14,182   $10,516  $ 43,409   $ 40,214
  Electric Utility Services         78,289    73,802   151,279    144,789
                                   -------   -------  --------   --------
  Total operating revenues         $92,471   $84,318  $194,688   $185,003
                                   -------   -------  --------   --------
Interest Expense:
  Gas Utility Services             $   438   $   419  $    868   $    844
  Electric Utility Services          4,428     4,236     8,781      8,534
                                   -------   -------  --------   --------
  Total interest expense           $ 4,866   $ 4,655  $  9,649   $  9,378
                                   -------   -------  --------   --------
Income Taxes:
  Gas Utility Services             $   345   $    36  $  1,321   $  1,649
  Electric Utility Services          4,265     4,499     7,526     10,216
                                   -------   -------  --------   --------
  Total income taxes               $ 4,610   $ 4,535  $  8,847   $ 11,865
                                   -------   -------  --------   --------
Depreciation and amortization:
  Gas Utility Services             $ 1,129   $ 1,158  $  2,374   $  2,315
  Electric Utility Services          9,583    10,058    19,828     20,118
                                     -------   -------  --------   --------
  Total depreciation and
   amortization                      $10,712   $11,216  $ 22,202   $ 22,433
                                   -------   -------  --------   --------
Net income:
  Gas Utility Services             $   584   $   187  $  1,974   $  3,014
  Electric Utility Services          5,875     7,430     8,483     16,840
                                   -------   -------  --------   --------
  Net income                       $ 6,459   $ 7,617  $ 10,457   $ 19,854
                                   -------   -------  --------   --------
Capital Expenditures:
  Gas Utility Services             $ 2,051   $ 3,025  $  4,209   $  5,225
  Electric Utility Services          9,545    14,407    21,034     26,197
                                   -------   -------  --------   --------
  Total capital expenditures       $11,596   $17,432  $ 25,243   $ 31,422
                                   -------   -------  --------   --------
</TABLE>


<TABLE>
                                                     Twelve Months
                                                     Ended June 30
                                                  -------------------
                                                  2000 <1>     1999
<S>                                               <C>        <C>
Operating Revenues:
   Gas Utility Services                           $ 71,407   $ 66,802
   Electric Utility Services                       314,059    299,901
                                                  --------   --------
   Total operating revenues                       $385,466   $366,703
                                                  --------   --------
Interest Expense:
   Gas Utility Services                           $  1,753   $  1,818
   Electric Utility Services                        17,730     18,383
                                                  --------   --------
   Total interest expense                         $ 19,483   $ 20,201
                                                  --------   --------
Income Taxes:
   Gas Utility Services                           $  1,656   $  2,554
   Electric Utility Services                        21,753     22,177
                                                  --------   --------
   Total income taxes                             $ 23,409   $ 24,731
                                                  --------   --------
Depreciation and amortization:
   Gas Utility Services                           $  4,688   $  4,477
   Electric Utility Services                        39,948     39,093
                                                    --------   --------
   Total depreciation and amortization              $ 44,636   $ 43,570
                                                  --------   --------
Net income:
   Gas Utility Services                           $  2,830   $  4,547
   Electric Utility Services                        33,463     37,407
                                                  --------   --------
   Net income                                     $ 36,293   $ 41,954
                                                  --------   --------
Capital Expenditures:
   Gas Utility Services                           $  8,975   $ 11,203
   Electric Utility Services                        45,523     51,362
                                                  --------   --------
   Total capital expenditures                     $ 54,498   $ 62,565
                                                  --------   --------
</TABLE>


<TABLE>
                                 As of June 30      As of December 31
                              -------------------  -----------------
                                2000      1999           1999
<S>                           <C>       <C>        <C>
Identifiable Assets:
  Gas Utility Services        $140,540  $139,875   $143,161
  Electric Utility Services    737,833   734,341    751,598
  Total identifiable assets   $878,373  $874,216   $894,759
<FN>

<F1>  The 2000 amounts include merger costs
(see Note 4).
</FN>
</TABLE>

<PAGE> 13

13.  New Accounting Pronouncement

In June 1998, the Financial Accounting Standards Board
(FASB) issued SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities". The statement, as
amended by SFAS No. 138, establishes accounting and
reporting standards requiring that every derivative
instrument, including certain derivative instruments
embedded in other contracts, be recorded in the balance
sheet as either an asset or liability measured at its fair
value. The statement requires that changes in the
derivative's fair value be recognized currently in earnings
unless specific hedge accounting criteria are met. Special
accounting for qualifying hedges allows a derivative's gains
and losses to offset related results on the hedged item in
the income statement, and requires that a company must
formally document, designate, and assess the effectiveness
of transactions that receive hedge accounting. SIGECO is
required to adopt SFAS No. 133 no later than January 1,
2001.  In certain of its operations, SIGECO utilizes
derivative instruments to manage pricing decisions, minimize
the risk of price volatility, and minimize price risk
exposure in the energy markets. SIGECO has not quantified
the impact of adopting this statement on its financial
position or results of operations.

14.  Reclassifications

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


<PAGE> 14

          SOUTHERN INDIANA GAS AND ELECTRIC COMPANY

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

        Indiana Energy, Inc. and SIGCORP, Inc. Merger

On June 14, 1999, Indiana Energy, Inc. (Indiana Energy) and
SIGCORP, Inc. (SIGCORP) jointly announced the signing of a
definitive agreement to combine into a new holding company
named Vectren Corporation (Vectren). The merger was
conditioned, among other things, upon the approvals of the
shareholders of each company and customary regulatory
approvals.  Such approvals were obtained and the merger was
consummated on March 31, 2000.  As provided for in the
merger agreement, Indiana Energy shareholders received one
share of Vectren common stock for each share of Indiana
Energy held at the March 31, 2000 closing date. SIGCORP
shareholders received one and one-third shares of Vectren
common stock for each share of SIGCORP held at the March 31,
2000 closing date.  The transaction was accounted for as a
pooling of interests.  The transaction was a tax-free
exchange of shares.

Southern Indiana Gas and Electric Company (SIGECO), formerly
a wholly owned subsidiary of SIGCORP, operates as a separate
wholly owned subsidiary of Vectren.

                    Results of Operations

                         Net Income

Net income applicable to common shareholders was $6.5
million for the three months ended June 30, 2000.  Net
income applicable to common shareholders before merger
related charges (see merger costs below) was $8.3 million
for the three months ended June 30, 2000 as compared to net
income applicable to common shareholders of $7.6 million for
the same period in 1999.

Net income applicable to common shareholders was $10.5
million for the six months ended June 30, 2000. Net income
applicable to common shareholders before merger related
charges was $21.3 million for the six months ended June 30,
2000 as compared to net income applicable to common
shareholders of $19.9 million for the same period in 1999.

Net income applicable to common shareholders was $36.3
million for the twelve months ended June 30, 2000. Net
income applicable to common shareholders before merger
related charges was $47.1 million for the twelve months
ended June 30, 2000 as compared to net income applicable to
common shareholders of $42.0 million for the same period in
1999.

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

Electric utility margin for the three months ended June 30,
2000 was $51.9 million compared to $49.9 million for the
same period last year.  During the current quarter, a $2.6
million increase in margin from nonfirm wholesale sales to
other utilities and power marketers was the primary reason
for the increase in total electric margin.  Sales to these
customers were up 20 percent and average unit sales margins
were greater compared to the year ago period.

Electric utility margin for the six months ended June 30,
2000 was $103.2 million compared to $100.7 million for the
same period last year.  For the six month period ending June
30, 2000, a 38 percent increase in sales to other utilities
and power marketers and higher average unit margins from
these sales contributed an additional $4.0 million to
electric margin, more than offsetting the impact of 6
percent fewer residential electric sales.

Electric utility margin for the twelve-month period ended
June 30, 2000, was $217.1 million compared to $207.5 million
for the same period last year. The $9.6 million increase in
margin reflected a $7.5 million increase in margin from
sales to other utilities and power marketers and a 4 percent
increase in retail and firm wholesale electric sales
primarily due to stronger industrial and commercial sales.

<PAGE> 15

    Gas Margin (Gas Operating Revenues Less Cost of Gas)

Gas utility margin for the quarter ended June 30, 2000 was
$7.2 million compared to $5.6 million for the same period
last year reflecting a 13 percent increase in total system
throughput (combined sales and transportation volumes) due
to slightly more favorable weather conditions and continued
growth in the commercial and industrial sectors.

Gas utility margin for the six months ended June 30, 2000
was $16.8 million compared to $15.8 million for the same
period in 1999.  The increase is primarily attributable to
the addition of new residential and commercial customers.
These increases were partially offset by 3 percent warmer
temperatures during the first half of 2000 compared to the
year ago period.  Total throughput increased 4 percent
compared to the same period a year ago.

Gas utility margin for the twelve months ended June 30, 2000
was $29.5 million compared to $28.4 million for the same
period last year for the same reasons as described above.

SIGECO's rates for gas transportation generally provide for
the same margins as are earned on the sale of gas under its
applicable sales tariffs.

 Operating Expenses (excluding Cost of Fuel, Purchased Power
                      and Cost of Gas)

Operation and maintenance expenses increased $4.1 million,
or 17 percent, for the three months ended June 30, 2000
compared to the same period in 1999.  The increase is
primarily attributable to a rise in the utility operating
expenses due to $1.2 million additional scheduled
maintenance projects at SIGECO's generation facilities.

Operation and maintenance expenses increased $3.2 million,
or 7 percent, for the six months ended June 30, 2000 when
compared to the same period a year ago.  The six month
increase is also primarily attributable to the rise in
utility operating expenses due to an additional $1.6 million
of scheduled maintenance projects at SIGECO's generation
facilities and increased general and administrative costs.

During the twelve-month period ended June 30, 2000 SIGECO's
operation and maintenance expenses increased $5.7 million,
or 6 percent, compared to the same period in 1999 for the
reasons discussed above.

Depreciation and amortization expense increased $1.1 million
during the twelve months ended June 30, 2000 compared to the
same period in the prior year due to additions to plant to
serve new customers.

Income taxes decreased $3.0 million and $1.3 million,
respectively, for the six and twelve months ended June 30,
2000 when compared to the same periods one year ago due to
changes in taxable income. Taxable income decreased
primarily due to the recognition of tax-deductible merger
costs.

Taxes other than income taxes increased slightly primarily
due to higher property tax expense, which is the result of
additions to utility plant.

                        Merger Costs

Merger costs incurred by Vectren for the three and six
months ended June 30, 2000 totaled $3.3 million and $30.4
million, respectively.  These costs relate primarily to
transaction costs, severance and other merger integration
activities.  Vectren expects to realize net merger savings
of nearly $200 million over the next ten years from the
elimination of duplicate corporate and administrative
programs and greater efficiencies in operations, business
processes and purchasing.  The continued merger integration
activities, which will contribute to the merger savings,
will be substantially complete by 2001.  Merger costs are
reflected in the financial statements of the operating
subsidiaries in which the merger savings are expected to be
realized.  Merger costs expensed by SIGECO for the three and
six months ended June 30, 2000 totaled $1.4 million and
$13.8 million, respectively.


                        Other Income

Other Income - Net increased $0.7 million, $1.3 million and
$3.2 million, respectively, for the three, six and twelve
months ended June 30, 2000, compared to the prior year
periods due chiefly to additional capitalized interest costs
related to utility projects under construction.

<PAGE> 16


Environmental Matters

In October 1997, the United States Environmental Protection
Agency (USEPA) proposed a rulemaking that could require
uniform NOx emissions reductions of 85 percent by utilities
and other large sources in a 22-state region spanning areas
in the Northeast, Midwest, Great Lakes, Mid-Atlantic and
South. This rule is referred to as the "NOx SIP call".  The
USEPA provided each state a proposed budget of allowed NOx
emissions, a key ingredient of ozone, which requires a
significant reduction of such emissions.  Under that budget,
utilities may be required to reduce NOx emissions to a rate
of 0.15 lb/mmBtu below levels already imposed by Phase I and
Phase II of the Clean Air Act Amendments of 1990.
Midwestern states (the alliance) have been working together
to determine the most appropriate compliance strategy as an
alternative to the USEPA proposal.  The alliance submitted
its proposal, which calls for a smaller, phased in reduction
of NOx levels, to the USEPA and the Indiana Department of
Environmental Management in June 1998.

In July 1998, Indiana submitted its proposed plan to the
USEPA in response to the USEPA's proposed new NOx rule and
the emissions budget proposed for Indiana.  The Indiana
plan, which calls for a reduction of NOx emissions to a rate
of 0.25 lb/mmBtu by 2003, is less stringent than the USEPA
proposal but more stringent than the alliance proposal.

On October 27, 1998, 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). The final rule requires that 23 states and
jurisdictions must file revised state implementation plans
(SIPs) with the USEPA by no later than September 30, 1999,
which was essentially unchanged from its October 1997,
proposed rule.  The USEPA has 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 USEPA's final ruling is being
litigated in the federal courts by approximately ten
midwestern states, including Indiana.

During the second quarter of 1999, the USEPA lost two
federal court challenges to key air-pollution control
requirements.  In the first ruling by the U.S. Circuit Court
of Appeals for the District of Columbia on May 14, 1999, the
Court struck down the USEPA's attempt to tighten the one-
hour ozone standard to an eight-hour standard and the
attempt to tighten the standard for particulate emissions,
finding the actions unconstitutional.  In the second ruling
by the same Court on May 25, 1999, the Court placed an
indefinite stay on the USEPA's attempts to reduce the
allowed NOx emissions rate from levels required by the Clean
Air Act Amendments of 1990.  The USEPA appealed both court
rulings.  On October 29, 1999, the Court refused to
reconsider its May 14, 1999 ruling.

On March 3, 2000, the D.C. Circuit of Appeals upheld the
USEPA's October 27, 1998 final rule requiring 23 states and
the District of Columbia to file revised SIPs with the USEPA
by no later than September 30, 1999.  Numerous petitioners,
including several states, have filed petitions for rehearing
with the U.S. Court of Appeals for the District of Columbia
in Michigan v. the USEPA. On June 22, 2000, the D.C. Circuit
Court of Appeals denied petition for rehearing en banc and
lifted its May 25, 1999 stay.

The proposed NOx emissions budget for Indiana stipulated in
the USEPA's final ruling requires a 36 percent reduction in
total NOx emissions from Indiana.  The ruling could require
SIGECO to lower its system-wide emissions by approximately
70 percent.  Depending on the level of system-wide emissions
reductions ultimately required, and the control technology
utilized to achieve the reductions, the estimated
construction costs of the control equipment could reach $100
million, and related additional operation and maintenance
expenses could be an estimated $8 million to $10 million,
annually.  Under the USEPA implementation schedule, the
emissions reductions and required control equipment must be
implemented and in place by May 15, 2003.

The USEPA initiated an investigation under Section 114 of
the Clean Air Act (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 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.  SIGECO responded to all of
the USEPA's data requests during the investigation.  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 the
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 with the
USEPA and targeted utilities, including SIGECO, regarding
potential remedies to the USEPA's general allegations.

<PAGE> 17

On November 3, 1999, the USEPA filed a lawsuit against seven
utilities, including SIGECO.  The USEPA alleges that,
beginning in 1992, SIGECO violated the Clean Air 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
SIGECO to begin complying with federal new source
performance standards.

SIGECO believes it performed only maintenance, repair and
replacement activities at the Culley Generating Station, as
allowed under the Clean Air 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, SIGECO
believes that the lawsuit is without merit, and intends to
vigorously defend the lawsuit.

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 is successful
in obtaining an order, SIGECO estimates that it would incur
capital costs of approximately $40 million to $50 million
complying with the order.  In the event that SIGECO is
required to install system-wide NOx emission control
equipment, as a result of the NOx SIP call issue, the
majority of the $40 million to $50 million for best
available emissions technology at Culley Generating Station
would be included in the $100 million expenditure 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 new source
performance standards 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
Clean Air Act.  Consequently, SIGECO anticipates at this
time that the plant will continue to operate while the
matter is being decided.

                New Accounting Pronouncement

In June 1998, the FASB issued SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities". The
statement, as amended by SFAS No. 138, establishes
accounting and reporting standards requiring that every
derivative instrument, including certain derivative
instruments embedded in other contracts, be recorded in the
balance sheet as either an asset or liability measured at
its fair value. The statement requires that changes in the
derivative's fair value be recognized currently in earnings
unless specific hedge accounting criteria are met. Special
accounting for qualifying hedges allows a derivative's gains
and losses to offset related results on the hedged item in
the income statement, and requires that a company must
formally document, designate, and assess the effectiveness
of transactions that receive hedge accounting. SIGECO is
required to adopt SFAS No. 133 no later than January 1,
2001.  In certain of its operations, SIGECO utilizes
derivative instruments to manage pricing decisions, minimize
the risk of price volatility, and minimize price risk
exposure in the energy markets. SIGECO has not quantified
the impact of adopting this statement on its financial
position or results or operations.

               Liquidity and Capital Resources

SIGECO's capitalization objectives are 45-60 percent common
and preferred equity and 40-55 percent long-term debt. These
objectives may have varied, and will vary, from time to
time, depending on particular business opportunities and
seasonal factors that affect the company's operations.

<PAGE> 18
New construction and normal system maintenance and
improvements needed to provide service to a growing customer
base will continue to require substantial expenditures.
Capital expenditures for fiscal 2000 are estimated at
approximately $50 million, of which $25.2 million have been
expended through June 30, 2000.  For the twelve months ended
June 30, 2000, capital expenditures totaled $54.5 million.

SIGECO has $66 million of short-term borrowing capacity, of
which $49.6 million was available at June 30, 2000.

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 at their highest and gas storage facilities
are being refilled.


Financing Activities

On July 3, 2000, all of SIGECO's $9,975,000 Adjustable Rate
Pollution Control Revenue Bonds were remarketed and the
interest rate was reset to 4.75% from 4.55%. The new
interest rate will be effective from July 1, 2000 through
June 30, 2001.

On July 7, 2000, SIGECO repurchased 22,000 shares of its
4.75% nonredeemable $100 par value preferred stock at a
purchase price of $84.25 per share. The stock was
repurchased as treasury stock and is to be retired.

SIGECO expects the majority of its capital expenditure
requirements and debt security redemptions to be provided by
internally generated funds.

SIGECO's credit rating on outstanding debt at June 30, 2000
was AA/Aa2.

Cash required for financing activities of $5.6 million for
the six months ended June 30, 2000 includes, among other
things, $15.5 million of dividends and $6.9 million of
additional net borrowings. Cash required for financing
activities of $31.5 million for the twelve months ended June
30, 2000 includes, among other things, $31.7 million of
dividends and $5.9 million of additional net debt pay-downs.

Cash required for investing activities of $28.1 million for
the six months ended June 30, 2000 includes, among other
things, $25.2 million of capital expenditures.  Cash
required for investing activities of $58.3 million for the
twelve months ended June 30, 2000 includes, among other
things, $54.5 million of capital expenditures.

                 Forward-Looking Information

A "safe harbor" for forwarding-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 statements. Certain
matters described in Management's Discussion and Analysis of
Financial Condition and Results of Operations, 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 SIGECO's actual results to differ materially from
those contemplated in any forward-looking statements
included, among others, the following:

*  Factors affecting utility operations such as unusual
weather conditions; catastrophic weather-related damage;
unusual maintenance or repairs; unanticipated changes to
fossil fuel costs; unanticipated changes to gas supply
costs, or availability due to higher demand, shortages,
transportation problems or other developments; environmental
or pipeline incidents; transmission or distribution
incidents; unanticipated changes to electric energy supply
costs, or availability due to demand, shortages,
transmission problems or other developments; or electric
transmission or gas pipeline system constraints.

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

<PAGE> 19

*  Regulatory factors such as unanticipated changes in rate-
setting policies or procedures, recovery of investments and
costs made under traditional regulation, and the frequency
and timing of rate increases.

*  Financial or regulatory accounting principles or policies
imposed by the Financial Accounting Standards Board, the
Securities and Exchange Commission, the Federal Energy
Regulatory Commission, state public utility commissions,
state entities which regulate natural gas transmission,
gathering and processing, and similar entities with
regulatory oversight.

*  Economic conditions including inflation rates and
monetary fluctuations.

*  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.

*  Availability or cost of capital, resulting from changes
in SIGECO,  interest rates, and securities ratings or market
perceptions of the utility industry and energy-related
industries.

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

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

*  Costs and other effects of legal and administrative
proceedings, settlements, investigations, claims, and other
matters, including, but not limited to, those described in
the Other Operating Matters section of Management's
Discussion and Analysis of Financial Condition and Results
of Operations.

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

SIGECO 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.

                         Seasonality

Because of the seasonal nature of SIGECO's utility
operations, the results shown on a quarterly basis are not
necessarily indicative of annual results.

Item 3. Quantitative and Qualitative Disclosures about
Market Risk

SIGECO's debt portfolio contains a substantial amount of
fixed-rate long-term debt and, therefore, does not expose
the company to the risk of material earnings or cash flow
loss due to changes in market interest rates.  SIGECO
attempts to mitigate its exposure to interest rate
fluctuations through management of its short-term borrowings
and the use of interest rate hedging instruments.  An
internal guideline to manage short-term interest rate
exposure has been established.  This guideline targets a
level of 25 percent of the company's total debt portfolio to
consist of adjustable rate bonds with a maturity of less
than one year, short-term notes and commercial paper.
However, it is acknowledged that there may be times that the
guideline may be exceeded.

SIGECO utilizes contracts for the forward sale of
electricity to effectively manage the utilization of its
available generating capability.  Such contracts include
forward physical contracts for wholesale sales of its
generating capability, during periods when SIGECO's
available generating capability is expected to exceed the
demands of its retail, or native load, customers.  To
minimize the risk related to these forward contracts, SIGECO
may utilize call option contracts to hedge against the
unexpected loss of its generating capability during periods
of heavy demand.  SIGECO also utilizes forward physical
contracts for the wholesale purchase of generating
capability to resell to other utilities and power marketers
through non-firm "buy-resell" transactions where the sale
and purchase prices of power are concurrently set.  As of
June 30, 2000, management believes exposure from these
positions was not material.


<PAGE> 20

Exposure to electricity market price risk results from the
use of forward contracts to effectively manage the supply
of, and demand for, the generation capability of SIGECO's
generating plants related to its wholesale power marketing
activities.  SIGECO is not currently exposed to market risks
for purchases of electric energy power and natural gas for
its retail customers due to current Indiana regulations
which allow for recovery of such purchases through SIGECO's
fuel and natural gas cost adjustment mechanisms.  A 1999
generic order issued by the IURC established new guidelines
for the recovery of purchased electric power costs through
the fuel adjustment clauses.  This order was appealed by the
Indiana Office of the Utility Consumer Counselor (OUCC). On
August 9, 2000, the IURC approved a settlement between
SIGECO and the OUCC which resolved all issues between SIGECO
and the OUCC regarding the IURC's generic order and
dismissed the OUCC's appeal. The settlement pertains to the
summer months of 2000 and the parties have agreed to
collaborate on a permanent agreement covering future
periods.  The settlement provides a price cap on the
recovery from retail electric customers of purchased power
costs incurred by SIGECO during normal economic dispatch
conditions and provides for 85 percent recoverability of
purchased power costs incurred during unplanned forced
outages. SIGECO does not anticipate the potential limitation
of recoverability of its purchased power costs to be
material under this settlement.

SIGECO is also exposed to counterparty credit risk when a
supplier defaults upon a contract to pay or deliver the
commodity.  To mitigate risk, procedures to determine and
monitor the creditworthiness of counterparties have been
established.

At June 30, 2000, SIGECO was not engaged in other contracts
which would cause exposure to the risk of material earnings
or cash flow loss due to changes in market commodity prices,
foreign currency exchange rates, or interest rates.






<PAGE> 21

          SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
                 PART II - OTHER INFORMATION

Item 1. Legal Proceedings

See Note 9 of the Notes to Financial Statements for
discussion of the litigation matters relating to USEPA
allegations that SIGECO violated the Clean Air Act.

Item 4. Submission of Matters to a Vote of Security Holders

       None

Item 6. Exhibits and Reports on Form 8-K

Exhibits

27  27   Financial Data Schedule, filed herewith.

Form 8-K's

On April 14, 2000 SIGECO filed a Current Report on Form 8-K
with respect to the change in control of SIGECO as a result
of the merger of Indiana Energy, Inc. and SIGCORP, Inc into
Vectren Corporation.

  Item 1.  Changes in Control of Registrant

On April 17, 2000 SIGECO filed an Amended Current Report on
Form 8-K changing the signature of the report to M. Susan
Hardwick, Vice President and Controller.

  Item 1.  Changes in Control of Registrant

On April 27, 2000 SIGECO filed a Current Report on Form 8-K
with respect to the release by Vectren Corporation of
summary financial information to the investment community
regarding Vectren Corporation's consolidated results of
operation, financial position and cash flows for the three-
and twelve-month ended periods of March 31, 2000.  Items
reported include:

  Item 5.  Other Events

  Item 7.  Exhibits

   Exhibit 99-1  Press Release
   Exhibit 99-2  Analyst Report - First Quarter 2000
   Exhibit 99-3  Cautionary Statement for Purposes of the
"Safe Harbor" Provisions of the Private Securities
Litigation Reform Act of 1995

On April 27, 2000 SIGECO filed a Current Report on Form 8-K
with respect to an analyst teleconference call held on April
27, 2000.

  Item 5.  Other Events

  Item 7.  Exhibits

     Exhibit 99  Analyst script teleconference call dated
April 27, 2000



                         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
                       ELECRIC COMPANY
                       Registrant


August 14, 2000        /s/ M. Susan Hardwick
                       M. Susan Hardwick
                       Vice President and Controller

August 14, 2000        /s/ Jerome A. Benkert
                       Jerome A. Benkert
                       Executive Vice President and
                       Chief Financial Officer