UNITED STATES SECURITIES AND EXCHANGE COMMISSION

                     Washington, D.C. 20549

                           FORM 10-Q


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

For the quarterly period ended        September 30, 1996

                                   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                     0-4117-1


                            IES UTILITIES INC.
         (Exact name of registrant as specified in its charter)

           Iowa                                        42-0331370
(State or other jurisdiction of                     (I.R.S. Employer
 incorporation or organization)                    Identification No.)

 IES Tower, Cedar Rapids, Iowa                            52401
(Address of principal executive offices)                (Zip Code)

Registrant's telephone number, including area code    (319) 398-4411


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.


            Class                            Outstanding at October 31, 1996
Common Stock, $2.50 par value                         13,370,788 shares



                           IES UTILITIES INC.


                                  INDEX


  
  
                                                                     Page No.


Part I.  Financial Information.



Item 1.  Consolidated Financial Statements.

         Consolidated Balance Sheets -
           September 30, 1996 and December 31, 1995                   3 - 4

         Consolidated Statements of Income -
           Three, Nine and Twelve Months Ended
           September 30, 1996 and 1995                                  5

         Consolidated Statements of Cash Flows -
           Three, Nine and Twelve Months Ended
           September 30, 1996 and 1995                                  6

         Notes to Consolidated Financial Statements                   7 - 18

Item 2.  Management's Discussion and Analysis of the
         Results of Operations and Financial Condition.              19 - 41



Part II.  Other Information.                                         42 - 46



Signatures.                                                            47

                          PART 1. - FINANCIAL INFORMATION
ITEM 1. - CONSOLIDATED FINANCIAL STATEMENTS
                            CONSOLIDATED BALANCE SHEETS

                                                   September 30,
                                                       1996        December 31,
ASSETS                                              (Unaudited)        1995
                                                           (in thousands)
Property, plant and equipment:
  Utility -
    Plant in service -
        Electric                                   $ 1,949,085     $ 1,900,157
        Gas                                            171,050         165,825
        Other                                          109,924         106,396
                                                     2,230,059       2,172,378
    Less - Accumulated depreciation                  1,020,070         950,324
                                                     1,209,989       1,222,054
    Leased nuclear fuel, net of amortization            36,525          36,935
    Construction work in progress                       90,191          52,772
                                                     1,336,705       1,311,761
  Other, net of accumulated depreciation
    and amortization of $1,334,000 and
    $1,166,000, respectively                             5,145           5,477
                                                     1,341,850       1,317,238


Current assets:
  Cash and temporary cash investments                    1,102           2,734
  Accounts receivable -
    Customer, less reserve                               5,275          18,619
    Other                                                8,816           8,912
  Income tax refunds receivable                          1,633             846
  Production fuel, at average cost                      14,224          12,155
  Materials and supplies, at average cost               21,536          27,229
  Adjustment clause balances                               750               0
  Regulatory assets                                     24,351          22,791
  Prepayments and other                                 16,830          18,556
                                                        94,517         111,842


Investments:
  Nuclear decommissioning trust funds                   54,870          47,028
  Cash surrender value of life insurance 
    policies                                             4,089           3,582
  Other                                                    421             475
                                                        59,380          51,085


Other assets:
  Regulatory assets                                    212,753         207,202
  Deferred charges and other                            22,213          21,268
                                                       234,966         228,470
                                                   $ 1,730,713     $ 1,708,635



                          CONSOLIDATED BALANCE SHEETS (CONTINUED)

                                                   September 30,
                                                       1996        December 31,
CAPITALIZATION AND LIABILITIES                      (Unaudited)        1995
                                                           (in thousands)
Capitalization:
  Common stock - par value $2.50 per share - 
    authorized 24,000,000 shares; 
    13,370,788 shares outstanding                  $    33,427     $    33,427
  Paid-in surplus                                      279,042         279,042
  Retained earnings                                    219,206         212,522
      Total common equity                              531,675         524,991
  Cumulative preferred stock - par value
    $50 per share - authorized 466,406 
    shares; 366,354 shares outstanding                  18,320          18,320
  Long-term debt (excluding current portion)           517,279         465,463
                                                     1,067,274       1,008,774


Current liabilities:
  Notes payable to associated companies                  4,230           8,888
  Other short-term borrowings                           78,000         101,000
  Capital lease obligations                             13,523          15,717
  Maturities and sinking funds                           8,140          15,140
  Accounts payable                                      50,945          64,564
  Accrued interest                                       8,715           8,038
  Accrued taxes                                         59,457          50,369
  Accumulated refueling outage provision                14,441           7,690
  Adjustment clause balances                                 0           3,148
  Environmental liabilities                              5,418           5,521
  Other                                                 18,991          17,300
                                                       261,860         297,375


Long-term liabilities:
  Pension and other benefit obligations                 42,463          41,866
  Capital lease obligations                             23,002          21,218
  Environmental liabilities                             39,392          40,905
  Other                                                  7,310           8,719
                                                       112,167         112,708


Deferred credits:
  Accumulated deferred income taxes                    254,281         252,663
  Accumulated deferred investment tax credits           35,131          37,115
                                                       289,412         289,778


Commitments and contingencies (Note 6)


                                                   $ 1,730,713     $ 1,708,635

The accompanying Notes to Consolidated Financial Statements
are an integral part of these statements.

<TABLE>
                             CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
<CAPTION>

                                                  For the                         For the                         For the
                                             Three Months Ended              Nine Months Ended              Twelve Months Ended
                                                September 30                    September 30                    September 30
                                            1996            1995            1996            1995            1996            1995
                                                                               (in thousands)
<S>                                  <C>             <C>             <C>             <C>             <C>             <C>
Operating revenues:
    Electric                           $  173,626      $  183,876      $  436,027      $  433,502      $  562,996      $  558,219
    Gas                                    12,169          14,214         103,854          89,241         151,906         127,767
    Other                                   4,375           2,358          13,296           8,216          17,143          10,829
                                          190,170         200,448         553,177         530,959         732,045         696,815


Operating expenses:
    Fuel for production                    29,148          31,945          72,168          71,691          96,733          89,576
    Purchased power                        18,655          19,954          55,125          53,399          68,600          74,061
    Gas purchased for resale                5,034           7,940          64,445          59,527          96,116          85,481
    Other operating expenses               37,594          35,798         112,506         102,854         154,902         138,620
    Maintenance                            13,192          11,912          37,516          34,202          46,901          47,972
    Depreciation and amortization          21,908          19,315          65,957          60,632          84,709          78,667
    Taxes other than income taxes          11,386          12,224          34,996          36,955          43,054          45,952
                                          136,917         139,088         442,713         419,260         591,015         560,329


Operating income                           53,253          61,360         110,464         111,699         141,030         136,486


Interest expense and other:
   Interest expense                        11,466          11,242          33,346          33,432          44,375          43,988
   Allowance for funds used during
     construction                            -761            -762          -2,141          -2,662          -2,904          -3,608
   Miscellaneous, net                       6,230            -244           5,090             348           5,597            -528
                                           16,935          10,236          36,295          31,118          47,068          39,852


Income before income taxes                 36,318          51,124          74,169          80,581          93,962          96,634


Income taxes:
    Current                                15,132          21,463          33,487          24,441          42,513          31,096
    Deferred                                1,834             486           1,296          11,083             527           9,863
    Amortization of investment
       tax credits                           -661            -667          -1,984          -2,012          -2,658          -2,673
                                           16,305          21,282          32,799          33,512          40,382          38,286


Net income                                 20,013          29,842          41,370          47,069          53,580          58,348
Preferred dividend requirements               229             229             686             686             914             914
Net income available for
  common stock                         $   19,784      $   29,613      $   40,684      $   46,383      $   52,666      $   57,434


The accompanying Notes to Consolidated Financial Statements
are an integral part of these statements.

</TABLE>






<TABLE>
                          CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
<CAPTION>
                                                          For the Three               For the Nine               For the Twelve
                                                          Months Ended                Months Ended                Months Ended
                                                          September 30                September 30                September 30
                                                       1996          1995          1996          1995          1996          1995
                                                                                     (in thousands)

<S>                                              <C>           <C>           <C>           <C>           <C>           <C>
  Cash flows from operating activities:
    Net income                                     $  20,013     $  29,842     $  41,370     $  47,069     $  53,580     $  58,348
    Adjustments to reconcile net income to net 
      cash flows from operating activities -
       Depreciation and amortization                  21,908        19,315        65,957        60,632        84,709        78,667
       Amortization of principal under capital
         lease obligations                             4,945         4,934        14,195        10,801        19,108        14,463
       Deferred taxes and investment
         tax credits                                   1,173          -181          -688         9,071        -2,131         7,190
       Refueling outage provision                      1,831         3,006         6,751        -9,954         9,199        -6,807
       Amortization of other assets                    2,041         2,107         7,191         4,789         9,845         5,429
       Other                                              13          -196           -24          -558           657        -1,057
    Other changes in assets and liabilities -
       Accounts receivable                             5,466        -6,675         6,440        -2,130        -1,146        -6,879
       Production fuel, materials and supplies        -1,118           839          -190        -2,092         3,560        -3,247
       Accounts payable                                2,353          -343       -11,075       -19,302         3,832         6,082
       Accrued taxes                                  21,259        32,419         8,301        26,399       -12,313        11,419
       Provision for rate refunds                        -43         2,759          -106        12,966       -12,966        12,966
       Adjustment clause balances                     -3,559            -7        -3,898         1,903        -1,220           969
       Gas in storage                                 -8,280        -4,737           965         4,587        -1,193         3,543
       Other                                          -2,816        -2,438         1,607         2,481        -2,058         1,213
         Net cash flows from operating activities     65,186        80,644       136,796       146,662       151,463       182,299


  Cash flows from financing activities:
    Dividends declared on common stock               -12,000       -10,000       -34,000       -33,000       -44,000       -48,000
    Dividends declared on preferred stock               -229          -229          -686          -686          -914          -914
    Proceeds from issuance of long-term debt          60,000             0        60,000        50,000       110,000        50,000
    Reductions in long-term debt                     -15,000             0       -15,140       -50,140       -65,140       -50,140
    Net change in short-term borrowings              -47,345       -33,977       -27,658         3,309        23,426        56,196
    Principal payments under capital
      lease obligations                               -4,626        -3,314       -14,162        -9,529       -19,096       -13,608
    Sale of utility accounts receivable                    0         9,000         7,000        11,000             0        12,000
    Other                                               -182             0          -354             0        -2,056             0
      Net cash flows from financing activities       -19,382       -38,520       -25,000       -29,046         2,220         5,534


  Cash flows from investing activities:
    Construction and acquisition expenditures -
       Utility                                       -39,701       -31,669       -97,084       -89,664      -133,524      -154,200
       Other                                              -2          -805          -344        -2,782          -902        -4,645
    Deferred energy efficiency expenditures           -3,887        -4,987       -12,643       -12,965       -17,708       -17,611
    Nuclear decommissioning trust funds               -1,502        -1,832        -4,506        -4,598        -6,008        -5,981
    Other                                                272        -1,888         1,149        -7,318         3,137        -3,172
      Net cash flows from investing activities       -44,820       -41,181      -113,428      -117,327      -155,005      -185,609


  Net increase (decrease) in cash and temporary
    cash investments                                     984           943        -1,632           289        -1,322         2,224


  Cash and temporary cash investments at
    beginning of period                                  118         1,481         2,734         2,135         2,424           200


  Cash and temporary cash investments at
    end of period                                  $   1,102     $   2,424     $   1,102     $   2,424     $   1,102     $   2,424


  Supplemental cash flow information:
    Cash paid during the period for -
      Interest                                     $  10,866     $   8,428     $  30,443     $  30,500     $  44,511     $  41,842
      Income taxes                                 $   3,921     $   1,498     $  35,489     $  12,881     $  51,691     $  25,312

    Noncash investing and financing activities -
      Capital lease obligations incurred           $     939     $     149     $  13,785     $   2,807     $  13,896     $   5,851


The accompanying Notes to Consolidated Financial Statements 
are an integral part of these statements.

</TABLE>



         NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

                           September 30, 1996


(1)  GENERAL:

     The interim Consolidated Financial Statements have been prepared by
IES   Utilities  Inc.  (Utilities)  and  its  consolidated  subsidiaries
(collectively  the Company), without audit, pursuant to  the  rules  and
regulations  of  the  United States Securities and  Exchange  Commission
(SEC).   Utilities is a wholly-owned subsidiary of IES  Industries  Inc.
(Industries).   Utilities' wholly-owned subsidiary is IES Ventures  Inc.
(Ventures),  which  is  a  holding company for unregulated  investments.
Utilities  is  engaged  principally  in  the  generation,  transmission,
distribution and sale of electric energy and the purchase, distribution,
transportation and sale of natural gas.  The Company's principal markets
are located in the state of Iowa.

      Certain information and footnote disclosures normally included  in
financial  statements  prepared in accordance  with  generally  accepted
accounting  principles have been condensed or omitted pursuant  to  such
rules   and  regulations,  although  the  Company  believes   that   the
disclosures   are  adequate  to  make  the  information  presented   not
misleading.   In the opinion of the Company, the Consolidated  Financial
Statements  include all adjustments, which are normal and  recurring  in
nature, necessary for the fair presentation of the results of operations
and   financial  position.   Certain  prior  period  amounts  have  been
reclassified on a basis consistent with the 1996 presentation.

       The  preparation  of  financial  statements  in  conformity  with
generally  accepted  accounting principles requires management  to  make
estimates and assumptions that affect: 1) the reported amounts of assets
and  liabilities and the disclosure of contingent assets and liabilities
at  the date of the financial statements, and 2) the reported amounts of
revenues and expenses during the reporting period.  Actual results could
differ from those estimates.

      It  is  suggested that these Consolidated Financial Statements  be
read  in conjunction with the Consolidated Financial Statements and  the
notes  thereto  included in the Company's Form 10-K for the  year  ended
December  31, 1995.  The accounting and financial policies  relative  to
the  following  items have been described in those notes and  have  been
omitted herein because they have not changed materially through the date
of this report:

     Summary of significant accounting policies
     Leases
     Utility accounts receivable (other than discussed in Note 4)
     Income taxes
     Benefit plans
     Preferred and preference stock
     Debt (other than discussed in Note 5)
     Estimated fair value of financial instruments
     Commitments and contingencies (other than discussed in Note 6)
     Jointly-owned electric utility plant
     Segments of business

(2)  POTENTIAL BUSINESS COMBINATIONS:
     (a)  Proposed Merger of Industries -

      Industries, WPL Holdings, Inc. (WPLH) and Interstate Power Company
(IPC)  have  entered  into  an  Agreement and  Plan  of  Merger  (Merger
Agreement), dated November 10, 1995, as amended, providing for:  a)  IPC
becoming  a  wholly-owned  subsidiary of WPLH,  and  b)  the  merger  of
Industries  with  and  into  WPLH,  which  merger  will  result  in  the
combination  of  Industries  and  WPLH  as  a  single  holding   company
(collectively,  the Proposed Merger).  The new holding company  will  be
named  Interstate Energy Corporation (Interstate Energy), and Industries
will  cease  to  exist.   Each holder of Industries  common  stock  will
receive 1.14 shares of Interstate Energy common stock for each share  of
Industries  common stock.  The Proposed Merger, which will be  accounted
for  as  a  pooling  of interests, has been approved by  the  respective
Boards  of  Directors and by the shareholders of each  company.   It  is
still  subject  to  approval  by several federal  and  state  regulatory
agencies.  The companies expect to receive such regulatory approvals  by
the  summer  of  1997.  The corporate headquarters of Interstate  Energy
will be in Madison, Wisconsin.

       The  business  of  Interstate  Energy  will  consist  of  utility
operations   and   various   non-utility   enterprises.    The   utility
subsidiaries  currently serve approximately 870,000  electric  customers
and  360,000  natural  gas  customers in Iowa, Wisconsin,  Illinois  and
Minnesota.

     (b)  Unsolicited Acquisition Proposal -

      On  August 5, 1996, MidAmerican Energy Company (MAEC), an electric
and  natural  gas  utility company based in Des Moines, Iowa,  announced
that  it had made an unsolicited offer to acquire Industries in  a  cash
and  stock transaction.  Industries' Board of Directors rejected  MAEC's
offer  and  the  shareholders of Industries  subsequently  approved  the
Proposed Merger, thereby also rejecting MAEC's offer.

(3)  RATE MATTERS:
     (a)  1995 Gas Rate Case -

      On  August 4, 1995, Utilities applied to the Iowa Utilities  Board
(IUB) for an annual increase in gas rates of $8.8 million, or 6.2%.   An
interim   increase  of  $8.6  million  was  requested   and   the   IUB,
subsequently,  approved  an interim increase of $7.1  million  annually,
effective  October 11, 1995, subject to refund.  On April 4,  1996,  the
IUB  issued  an order approving a settlement agreement entered  into  by
Utilities,  the  Office of Consumer Advocate and  all  three  industrial
intervenor  groups,  which  allowed  Utilities  a  $6.3  million  annual
increase.  Utilities subsequently filed final compliance  tariffs  which
became effective on May 30, 1996.  Primarily because of changes in  rate
design, there was a refund obligation of approximately $43,000 which was
made in the third quarter of 1996.

      (b)  Electric Price Announcements -

       Utilities  and  its  Iowa-based  proposed  merger  partner,  IPC,
announced  in April their intentions to hold retail electric  prices  to
their current levels until at least January 1, 2000.  The companies made
the   proposal   as  part  of  their  testimony  in  the  merger-related
application filed with the IUB; the application was later withdrawn  and
will  be  resubmitted in either the fourth quarter of 1996 or the  first
quarter of 1997 and the companies intend to include the same proposal in
the  resubmittal of the filing.  The proposal excludes price changes due
to   government-mandated  programs,  such  as  energy  efficiency   cost
recovery, or unforeseen dramatic changes in operations.

       Utilities,  Wisconsin  Power  and  Light  Company  (the   utility
subsidiary  of  WPLH)  and  IPC also agreed to  freeze  their  wholesale
electric prices for four years from the effective date of the merger  as
part   of  their  merger  filing  with  the  Federal  Energy  Regulatory
Commission  (FERC).   The  Company does not  expect  the  merger-related
electric  price  proposals  to have a material  adverse  effect  on  its
financial position or results of operations.

     (c)  Energy Efficiency Cost Recovery -

      Current  IUB  rules mandate Utilities to spend 2% of electric  and
1.5%  of  gas  gross  retail operating revenues  for  energy  efficiency
programs.   Under  provisions of the IUB rules, Utilities  is  currently
recovering  the energy efficiency costs incurred through 1993  for  such
programs, including its direct expenditures, carrying costs, a return on
its  expenditures and a reward.  These costs are being recovered over  a
four-year  period and the recovery began on June 1, 1995.   In  December
1996,  under  provisions of the IUB rules, the  Company  will  file  for
recovery of the costs relating to its 1994 and 1995 programs.

      Iowa  statutory changes enacted in 1996, and applicable to  future
programs  once  the legislation is adopted by the IUB,  have  eliminated
both:  1) the 2% and 1.5% spending requirements described above in favor
of IUB-determined energy savings targets and 2) the delay in recovery of
energy  efficiency costs by allowing recovery which is  concurrent  with
spending.   This  will eventually eliminate the regulatory  asset  which
exists under the current rate making mechanism.

(4)  UTILITY ACCOUNTS RECEIVABLE:

      Utilities  has entered into an agreement, which expires  in  1999,
with  a  financial  institution  to  sell,  with  limited  recourse,  an
undivided  fractional  interest of up to $65  million  in  its  pool  of
utility  accounts receivable.  At September 30, 1996,  $65  million  was
sold under the agreement.

(5)  DEBT:
     (a)  Long-Term Debt -

      In  September  1996, Utilities repaid at maturity $15  million  of
Series  J,  6.25%  First Mortgage Bonds and, in a separate  transaction,
issued $60 million of Collateral Trust Bonds, 7.25%, due 2006.

     (b)  Short-Term Debt -

      At  September  30,  1996, the Company had  bank  lines  of  credit
aggregating  $121.1  million, of which $78 million  was  being  used  to
support  commercial paper (weighted average interest rate of 5.47%)  and
$11.1   million  to  support  certain  pollution  control   obligations.
Commitment  fees  are  paid to maintain these lines  and  there  are  no
conditions  which restrict the unused lines of credit.  In  addition  to
the above, Utilities has an uncommitted credit facility with a financial
institution whereby it can borrow up to $40 million.  Rates are  set  at
the  time  of borrowing and no fees are paid to maintain this  facility.
At  September 30, 1996, there were no borrowings outstanding under  this
facility.

(6) CONTINGENCIES:
    (a)  Environmental Liabilities -

     The Company has recorded environmental liabilities of approximately
$45  million in its Consolidated Balance Sheets at September  30,  1996.
The significant items are discussed below.

          Former Manufactured Gas Plant (FMGP) Sites

      Utilities has been named as a Potentially Responsible Party  (PRP)
by  various federal and state environmental agencies for 28 FMGP  sites,
but  believes  it  is not responsible for two of these  sites  based  on
extensive  reviews  of the ownership records and historical  information
available  for  the two sites.  Utilities has notified  the  appropriate
regulatory  agency that it believes it does not have any  responsibility
as  relates  to these two sites, but no response has been received  from
the  agency  on this issue.  Utilities is also aware of six other  sites
that  it  may  have owned or operated in the past and for  which,  as  a
result,  it  may be designated as a PRP in the future in the event  that
environmental  concerns  arise at these  sites.   Utilities  is  working
pursuant  to  the  requirements of the various agencies to  investigate,
mitigate,  prevent and remediate, where necessary, damage  to  property,
including damage to natural resources, at and around the sites in  order
to protect public health and the environment.  Utilities believes it has
completed  the remediation of seven sites although it is in the  process
of  obtaining final approval from the applicable environmental  agencies
on  this  issue  for each site.  Utilities is in various stages  of  the
investigation  and/or remediation processes for the remaining  19  sites
and  estimates  the  range  of  additional  costs  to  be  incurred  for
investigation  and/or remediation of the sites to be  approximately  $22
million to $54 million.

      Utilities  has recorded environmental liabilities related  to  the
FMGP  sites  of  approximately $34 million (including  $4.6  million  as
current  liabilities) at September 30, 1996.  These  amounts  are  based
upon  Utilities' best current estimate of the amount to be incurred  for
investigation   and  remediation  costs  for  those  sites   where   the
investigation  process has been or is substantially completed,  and  the
minimum  of  the  estimated  cost  range  for  those  sites  where   the
investigation is in its earlier stages.  It is possible that future cost
estimates   will   be  greater  than  the  current  estimates   as   the
investigation process proceeds and as additional facts become known;  in
addition, Utilities may be required to monitor these sites for a  number
of  years upon completion of remediation, as is the case with several of
the sites for which remediation has been completed.

      In  April 1996, Utilities filed a lawsuit against certain  of  its
insurance  carriers seeking reimbursement for investigation, mitigation,
prevention,  remediation and monitoring costs associated with  the  FMGP
sites.  Settlement discussions are proceeding between Utilities and  its
insurance  carriers regarding the recovery of these FMGP-related  costs.
The  amount of aggregate potential recovery, or the regulatory treatment
of  any  such recoveries, cannot be reasonably determined at  this  time
and,  accordingly, no estimated amounts have been recorded at  September
30, 1996.  Regulatory assets of approximately $34 million, which reflect
the  future  recovery that is being provided through  Utilities'  rates,
have been recorded in the Consolidated Balance Sheets.  Considering  the
current rate treatment allowed by the IUB, management believes that  the
clean-up costs incurred by Utilities for these FMGP sites will not  have
a  material  adverse  effect on its financial  position  or  results  of
operations.

          National Energy Policy Act of 1992

      The  National Energy Policy Act of 1992 requires owners of nuclear
power  plants  to  pay  a special assessment into a "Uranium  Enrichment
Decontamination and Decommissioning Fund."  The assessment is based upon
prior  nuclear  fuel purchases and, for the Duane Arnold  Energy  Center
(DAEC), averages $1.4 million annually through 2007, of which Utilities'
70% share is $1.0 million.  Utilities is recovering the costs associated
with  this assessment through its electric fuel adjustment clauses  over
the  period the costs are assessed.  Utilities' 70% share of the  future
assessment, $10.7 million payable through 2007, has been recorded  as  a
liability  in  the Consolidated Balance Sheets, including  $0.8  million
included  in "Current liabilities - Environmental liabilities,"  with  a
related regulatory asset for the unrecovered amount.

     (b)  Air Quality Issues -

      The  Clean  Air  Act  Amendments of 1990 (Act)  requires  emission
reductions of sulfur dioxide (SO2) and nitrogen oxides (NOx) to  achieve
reductions  of atmospheric chemicals believed to cause acid  rain.   The
provisions of the Act are being implemented in two phases; the  Phase  I
requirements  have been met and the Phase II requirements affect  eleven
other  fossil  units beginning in the year 2000.  Utilities  expects  to
meet  the  requirements of Phase II by switching to lower sulfur  fuels,
capital  expenditures  primarily related to fuel burning  equipment  and
boiler  modifications,  and  the possible purchase  of  SO2  allowances.
Utilities estimates capital expenditures at approximately $23.5 million,
including $7.4 million in 1996 (of which $4.1 million was expended as of
September 30, 1996), in order to meet the acid rain requirements of  the
Act.

      The  acid  rain program under the Act also governs SO2 allowances.
An allowance is defined as an authorization for an owner to emit one ton
of  SO2 into the atmosphere.  Currently, Utilities receives a sufficient
number  of allowances annually to offset its emissions of SO2  from  its
Phase  I units.  It is anticipated that in the year 2000, Utilities  may
have  an  insufficient  number  of allowances  annually  to  offset  its
estimated  emissions and may have to purchase additional allowances,  or
make   modifications  to  the  plants  or  limit  operations  to  reduce
emissions.   Utilities is reviewing its options to ensure that  it  will
have  sufficient  allowances  to offset its  emissions  in  the  future.
Utilities  believes  that  the  potential cost  of  ensuring  sufficient
allowances  will  not have a material adverse effect  on  its  financial
position or results of operations.

      The  Act  and  other federal laws also require the  United  States
Environmental  Protection  Agency  (EPA)  to  study  and  regulate,   if
necessary,  additional  issues  that  potentially  affect  the  electric
utility  industry, including emissions relating to NOx, ozone transport,
mercury   and   particulate  control;  toxic  release  inventories   and
modifications  to  the  PCB  rules.  Currently,  the  impacts  of  these
potential regulations are too speculative to quantify.

     In 1995, the EPA published the Sulfur Dioxide Network Design Review
for Cedar Rapids, Iowa, which, based on the EPA's assumptions and worst-
case  modeling  method  suggests that the Cedar  Rapids  area  could  be
classified  as  "nonattainment" for the  National  Ambient  Air  Quality
Standard  (NAAQS)  established for SO2.  The worst-case  modeling  study
suggested that two of Utilities' generating facilities contribute to the
modeled  exceedences and recommended that additional monitors be located
near  Utilities' sources to assess actual ambient air quality.   In  the
event   that   Utilities'  facilities  contribute  excessive  emissions,
Utilities  would be required to reduce emissions, which would  primarily
entail   capital  expenditures  for  modifications  to  the  facilities.
Utilities is currently exploring its options to modify one of its fossil
generating  facilities to reduce SO2 emissions.  Utilities is  proposing
to resolve the remainder of EPA's nonattainment concerns by installing a
new  stack at the other generating facility contributing to the  modeled
exceedences at a potential aggregate capital cost of up to $4.5  million
over the next four years.

     (c)  FERC Order No. 636 -

      Pursuant to FERC Order No. 636 (Order 636), which transitions  the
natural  gas supply business to a less regulated environment,  Utilities
has enhanced access to competitively priced gas supply and more flexible
transportation  services.   However,  under  Order  636,  Utilities   is
required  to  pay certain transition costs incurred and  billed  by  its
pipeline suppliers.

      Utilities  began  paying  the transition  costs  in  1993  and  at
September  30, 1996, has recorded a liability of $4.2 million for  those
transition  costs that have been incurred, but not yet  billed,  by  the
pipelines to date, including $2.0 million expected to be billed  through
September 1997.  Utilities is currently recovering the transition  costs
from  its customers through its Purchased Gas Adjustment Clauses as such
costs are billed by the pipelines.  Transition costs, in addition to the
recorded  liability, that may ultimately be charged to  Utilities  could
approximate $4.1 million.  The ultimate level of costs to be  billed  to
Utilities  depends on the pipelines' future filings with  the  FERC  and
other  future  events,  including  the  market  price  of  natural  gas.
However,  Utilities believes any transition costs that  the  FERC  would
allow  the  pipelines to collect from Utilities would be recovered  from
its  customers, based upon regulatory treatment of these costs currently
and  similar past costs by the IUB.  Accordingly, regulatory assets,  in
amounts corresponding to the recorded liabilities, have been recorded to
reflect the anticipated recovery.

     (d)  Nuclear Insurance Programs -

      Public  liability for nuclear accidents is governed by  the  Price
Anderson  Act of 1988 which sets a statutory limit of $8.9  billion  for
liability  to  the public for a single nuclear power plant incident  and
requires  nuclear power plant operators to provide financial  protection
for  this  amount.   As  required,  Utilities  provides  this  financial
protection  for a nuclear incident at the DAEC through a combination  of
liability  insurance  ($200  million)  and  industry-wide  retrospective
payment  plans  ($8.7  billion).  Under  the  industry-wide  plan,  each
operating licensed nuclear reactor in the United States is subject to an
assessment  in the event of a nuclear incident at any nuclear  plant  in
the  United States.  Based on its ownership of the DAEC, Utilities could
be  assessed  a  maximum of $79.3 million per nuclear incident,  with  a
maximum  of  $10 million per incident per year (of which Utilities'  70%
ownership  portion would be approximately $55 million  and  $7  million,
respectively) if losses relating to the incident exceeded $200  million.
These  limits  are subject to adjustments for changes in the  number  of
participants and inflation in future years.

      Utilities is a member of Nuclear Mutual Limited (NML) and  Nuclear
Electric Insurance Limited (NEIL).  These companies provide $1.9 billion
of  insurance  coverage on certain property losses at DAEC for  property
damage,  decontamination  and premature decommissioning.   The  proceeds
from   such   insurance,  however,  must  first  be  used  for   reactor
stabilization and site decontamination before they can be used for plant
repair  and  premature  decommissioning.  NEIL  also  provides  separate
coverage  for  the  cost  of replacement power during  certain  outages.
Owners  of nuclear generating stations insured through NML and NEIL  are
subject  to retroactive premium adjustments if losses exceed accumulated
reserve  funds.  NML and NEIL's accumulated reserve funds are  currently
sufficient  to  more than cover its exposure in the event  of  a  single
incident  under  the primary and excess property damage  or  replacement
power coverages. However, Utilities could be assessed annually a maximum
of  $3.0  million  under NML, $9.8 million for NEIL  property  and  $0.7
million  for  NEIL  replacement power if losses exceed  the  accumulated
reserve  funds.  Utilities is not aware of any losses that  it  believes
are likely to result in an assessment.

     In the unlikely event of a catastrophic loss at DAEC, the amount of
insurance  available  may  not be adequate  to  cover  property  damage,
decontamination and premature decommissioning.  Uninsured losses, to the
extent  not  recovered through rates, would be borne  by  Utilities  and
could  have  a material adverse effect on Utilities' financial  position
and results of operations.

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

      The Consolidated Financial Statements include the accounts of  IES
Utilities   Inc.   (Utilities)   and   its   consolidated   subsidiaries
(collectively  the Company).  Utilities is a wholly-owned subsidiary  of
IES Industries Inc. (Industries).  Utilities' wholly-owned subsidiary is
IES Ventures Inc. (Ventures), which is a holding company for unregulated
investments.

                       POTENTIAL BUSINESS COMBINATIONS
                                    
     (a)  Proposed Merger of Industries -

      Industries, WPL Holdings, Inc. (WPLH) and Interstate Power Company
(IPC)  have  entered  into  an  Agreement and  Plan  of  Merger  (Merger
Agreement), dated November 10, 1995, as amended, providing for:  a)  IPC
becoming  a  wholly-owned  subsidiary of WPLH,  and  b)  the  merger  of
Industries  with  and  into  WPLH,  which  merger  will  result  in  the
combination  of  Industries  and  WPLH  as  a  single  holding   company
(collectively,  the Proposed Merger).  The new holding company  will  be
named  Interstate Energy Corporation (Interstate Energy), and Industries
will  cease  to  exist.   Each holder of Industries  common  stock  will
receive 1.14 shares of Interstate Energy common stock for each share  of
Industries  common stock.  The Proposed Merger, which will be  accounted
for  as  a  pooling  of interests, has been approved by  the  respective
Boards  of  Directors and by the shareholders of each  company.   It  is
still  subject  to  approval  by several federal  and  state  regulatory
agencies.  The companies expect to receive such regulatory approvals  by
the  summer  of  1997.  The corporate headquarters of Interstate  Energy
will be in Madison, Wisconsin.

       The  business  of  Interstate  Energy  will  consist  of  utility
operations   and   various   non-utility   enterprises.    The   utility
subsidiaries  currently serve approximately 870,000  electric  customers
and  360,000  natural  gas  customers in Iowa, Wisconsin,  Illinois  and
Minnesota.

     (b)  Unsolicited Acquisition Proposal -

      On  August 5, 1996, MidAmerican Energy Company (MAEC), an electric
and  natural  gas  utility company based in Des Moines, Iowa,  announced
that  it had made an unsolicited offer to acquire Industries in  a  cash
and  stock transaction.  Industries' Board of Directors rejected  MAEC's
offer  and  the  shareholders of Industries  subsequently  approved  the
Proposed Merger, thereby also rejecting MAEC's offer.

                          RESULTS OF OPERATIONS
                                    
      The  following  discussion  analyzes significant  changes  in  the
components  of  net  income  available for common  stock  and  financial
condition from the prior periods for the Company:

      The  Company's  net  income available for common  stock  decreased
($9.8) million, ($5.7) million and ($4.8) million during the three, nine
and  twelve  month periods, respectively.  The decrease in earnings  for
all  three periods was primarily due to cooler weather conditions during
the  third quarter of 1996 as compared to the third quarter of 1995  and
Utilities'  share  of  the  costs incurred relating  to  the  successful
defense  of  the hostile takeover attempt mounted by MAEC.  The  weather
conditions in the third quarter of 1996 and 1995 were cooler than normal
and  significantly warmer than normal, respectively.   Accordingly,  the
Company estimates the weather conditions impacted the quarterly earnings
by  approximately  $8  million  on  a comparative  basis.   The  company
estimates  that its share of the hostile takeover defense costs  reduced
earnings  for the three periods by approximately $4 million.   Increased
operating expenses and a higher effective income tax rate also adversely
impacted  earnings  for the three periods.  These items  were  partially
offset by sales growth in Utilities' service territory, the impact of  a
natural  gas pricing increase implemented in the fourth quarter of  1995
and increased steam volumes sold.

      The  Company's  operating income increased or  (decreased)  ($8.1)
million,  ($1.2)  million and $4.5 million during the  three,  nine  and
twelve   month  periods,  respectively.   The  contrasting  relationship
between the change in operating income and net income was primarily  due
to Utilities' share ($6.5 million) of the hostile takeover defense costs
which   are   included  in  "Miscellaneous,  net"  in  the  Consolidated
Statements  of  Income.   Reasons for the  changes  in  the  results  of
operations are explained in the following discussion.

Electric  Revenues   Electric revenues and Kwh sales (before  off-system
sales) for Utilities increased or (decreased) as compared with the prior
period as follows:

                                                  Changes vs. Prior Period
                                                 Three      Nine     Twelve
                                                 Months     Months   Months
                                                       ($ in millions)
                                                                        
Total electric revenues                          $ (10.3)  $   2.5   $   4.8
Off-system sales revenues                           (2.0)      2.1       3.6
Electric revenues (excluding off-system sales)   $  (8.3)  $   0.4   $   1.2
                
Electric sales (excluding off-system sales): 
  Residential and Rural                            (17.9)%    (4.7)%    (2.8)%
  General Service                                   (7.9)     (2.9)      0.1
  Large General Service                              5.2       3.5       4.4
Total                                               (3.9)      0.2       1.5


     Weather had a significant impact on sales during the three and nine
month  periods.   The largest effect of weather for the periods  was  on
sales  to  residential and rural customers.  Under  historically  normal
weather conditions, total sales (excluding off-system sales) during  the
three, nine and twelve month periods would have increased 4.9%, 2.7% and
2.9%, respectively.  The sales comparisons for the nine and twelve month
periods  were  impacted by a true-up adjustment to  Utilities'  unbilled
sales  recorded in the second quarter of 1995.  The sales  increases  to
the  large  general  service  customers  (which  are  not  significantly
impacted  by  weather) during all three periods reflect  the  underlying
strength  of the economy as industrial expansions in Utilities'  service
territory continued during these periods.

     Utilities' electric tariffs include energy adjustment clauses (EAC)
that  are designed to currently recover the costs of fuel and the energy
portion of purchased power billings.

     The decrease in the electric revenues during the three month period
was  primarily due to the weather-related decrease in sales to consumers
as  discussed previously, lower fuel costs collected through the EAC and
lower  off-system  sales.   The  nine and twelve  month  increases  were
primarily  due to increased sales to consumers, higher off-system  sales
and the recovery of expenditures for energy efficiency programs pursuant
to  an  Iowa  Utilities Board (IUB) order.  The impact of the  nine  and
twelve month increases was partially offset by the 1995 unbilled revenue
adjustment.

      Refer  to  Note  3(b)  of  the  Notes  to  Consolidated  Financial
Statements  for  a  discussion of merger-related  retail  and  wholesale
electric price proposals that Utilities has announced.

Gas Revenues   Gas revenues increased or decreased ($2.0) million, $14.6
million  and $24.1 million for the three, nine and twelve month periods,
respectively.  Utilities' gas sales and transported volumes increased or
(decreased)  for the periods ended September 30, 1996, as compared  with
the prior periods, as follows:

                                  Changes vs. Prior Period
                      Three Months      Nine Months       Twelve Months
                                                         
Residential              (8.2)%            11.7%              14.9%
Commercial              (11.2)              8.6               11.7
Industrial               (5.3)              2.2               (5.5)
                                                   
Sales to consumers       (8.6)              9.7               11.4
                                                   
Transported volumes     (15.3)             (6.3)              (3.4)
                                                   
Total                   (12.2)              4.9                7.2
                                                   


      Under historically normal weather conditions, Utilities' gas sales
and  transported  volumes would have increased or  (decreased)  (12.1)%,
0.1%  and  0.7%  during  the  three,  nine  and  twelve  month  periods,
respectively.

      Utilities'  gas  tariffs include purchased gas adjustment  clauses
(PGA) that are designed to currently recover the cost of gas sold.

      On  August  4,  1995, Utilities applied to the IUB for  an  annual
increase  in  gas rates of $8.8 million, or 6.2%.  The IUB  approved  an
interim  increase of $7.1 million annually, effective October 11,  1995,
subject  to  refund.  On April 4, 1996, the IUB issued  an  order  which
allowed Utilities a $6.3 million annual increase.  Refer to Note 3(a) of
the  Notes to Consolidated Financial Statements for a further discussion
of the gas rate case.

      Utilities' gas revenues increased during both the nine and  twelve
month  periods  primarily because of higher gas costs recovered  through
the  PGA,  the  gas pricing increase, recovery of expenditures  for  the
energy  efficiency  programs and increased sales to  ultimate  consumers
(largely  on  account  of  the weather).  The three  month  decrease  in
Utilities' gas revenues was due to lower gas costs recovered through the
PGA partially offset by the gas pricing increase.

Other Revenues   Other revenues increased $2.0 million, $5.1 million and
$6.3   million  during  the  three,  nine  and  twelve  month   periods,
respectively, primarily because of an increase in steam revenues, due to
increased volumes sold.

Operating Expenses   Fuel for production increased or (decreased) ($2.8)
million, $0.5 million and $7.2 million during the three, nine and twelve
month periods, respectively.  The three month decrease was primarily due
to  lower Kwh generation, due to the decreased sales, and lower  average
fuel  costs.   The  twelve month increase was substantially  related  to
increased  Kwh  generation, primarily the result of a  refueling  outage
during  early 1995 at Utilities' nuclear generating station,  the  Duane
Arnold  Energy Center (DAEC).  There was no refueling outage during  the
first nine months of 1996.

      Purchased  power  increased or (decreased)  ($1.3)  million,  $1.7
million  and  ($5.5)  million during the three, nine  and  twelve  month
periods, respectively.  The three and twelve month decreases were due to
decreased  energy purchases with lower capacity costs also  contributing
to  the  twelve  month  decrease.  The nine month increase  was  due  to
increased energy purchases, partially offset by lower capacity costs.

      Gas  purchased for resale increased or (decreased) ($2.9) million,
$4.9  million and $10.6 million during the three, nine and twelve  month
periods,  respectively.  The three month decrease was primarily  due  to
the  timing  of the recovery of gas costs through the PGA and  decreased
gas sales, partially offset by the effects of higher average natural gas
prices.   The nine and twelve month increases were due to higher average
natural  gas prices and increased sales, partially offset by the  timing
of the recovery of gas costs through the PGA.

      Other operating expenses increased $1.8 million, $9.7 million  and
$16.3   million  during  the  three,  nine  and  twelve  month  periods,
respectively.   Contributing  to  the  increase  in  all  periods   were
increased  labor and benefits costs and costs incurred in the  Company's
efforts  to  prepare  for an increasingly competitive  utility  industry
including, among other items, costs relating to the Proposed Merger  and
the  Company's reengineering effort (Process Redesign).   The  nine  and
twelve  month increases were also due to the amortization of  previously
deferred  energy  efficiency  expenditures (which  are  currently  being
recovered  through  rates) and were partially  offset  by  lower  former
manufactured gas plant (FMGP) clean-up costs.

      Maintenance  expenses increased or (decreased) $1.3 million,  $3.3
million  and  ($1.1)  million during the three, nine  and  twelve  month
periods,  respectively.   The  three  and  nine  month  increases   were
primarily due to increased maintenance activities at Utilities'  fossil-
fueled  generating  stations.  The twelve month decrease  was  primarily
caused  by less required maintenance at the DAEC and lower tree trimming
costs,   partially  offset  by  increased  maintenance   activities   at
Utilities' fossil-fueled generating stations.

       Depreciation  and  amortization  increased  during  all   periods
primarily  because  of  increases in  utility  plant  in  service.   The
increases  for  the three and nine month periods were  also  due  to  an
adjustment  recorded  in the third quarter of 1995  to  implement  lower
depreciation  rates as a result of an IUB rate order.  Depreciation  and
amortization   expenses  for  all  periods  included  a  provision   for
decommissioning the DAEC, which is collected through rates.  The current
annual recovery level is $6.0 million.

      During  the  first  quarter  of  1996,  the  Financial  Accounting
Standards  Board  (FASB)  issued an Exposure  Draft  on  Accounting  for
Liabilities  Related to Closure and Removal of Long-Lived  Assets  which
deals  with,  among  other  issues, the accounting  for  decommissioning
costs.   If  current electric utility industry accounting practices  for
such   decommissioning   are   changed:   1)   annual   provisions   for
decommissioning   could  increase  and  2)  the   estimated   cost   for
decommissioning  could  be  recorded as  a  liability,  rather  than  as
accumulated  depreciation,  with  recognition  of  an  increase  in  the
recorded  amount  of  the  related DAEC  plant.   If  such  changes  are
required,  Utilities believes that there would not be an adverse  effect
on its financial position or results of operations based on current rate
making practices.

      Taxes  other  than income taxes decreased ($0.8)  million,  ($2.0)
million  and  ($2.9)  million during the three, nine  and  twelve  month
periods,  respectively, primarily because of decreased  property  taxes,
resulting from lower assessed property values.

Interest Expense and Other      Miscellaneous, net reflects  comparative
decreases in income of ($6.5) million, ($4.7) million and ($6.1) million
for  the  three,  nine  and  twelve month  periods,  respectively.   The
decreases for all three periods were primarily due to approximately $6.5
million  in  costs incurred relating to the successful  defense  of  the
hostile takeover attempt mounted by MAEC.

Income  Taxes    Income taxes increased or (decreased)  ($5.0)  million,
($0.7)  million  and $2.1 million for the three, nine and  twelve  month
periods,  respectively.   The variances for  all  periods  were  due  to
changes  in pre-tax income and a higher effective tax rate.  The  higher
effective tax rate for each period is due to: 1) the effect of  property
related  temporary  differences for which deferred taxes  had  not  been
provided,  pursuant  to rate making principles, that  are  now  becoming
payable and are being recovered from ratepayers, 2) the effect of  prior
period  adjustments,  and  3) the incurrence of  certain  merger-related
expenses, which are not tax deductible.

                     LIQUIDITY AND CAPITAL RESOURCES

      The  Company's capital requirements are primarily attributable  to
its  construction  programs and debt maturities.  The Company's  pre-tax
ratio  of times interest earned was 3.12 and 3.20 for the twelve  months
ended  September  30, 1996 and September 30, 1995,  respectively.   Cash
flows  from  operating activities for the twelve months ended  September
30,  1996  and  September 30, 1995 were $151 million and  $182  million,
respectively.  The decrease was primarily due to the electric rate  case
refund paid to customers in the fourth quarter of 1995 and other changes
in working capital.

      The  Company anticipates that future capital requirements will  be
met by cash generated from operations and external financing.  The level
of  cash  generated from operations is partially dependent upon economic
conditions,  legislative activities, environmental  matters  and  timely
rate  relief  for  Utilities.   See Notes  3  and  6  of  the  Notes  to
Consolidated Financial Statements.

      Access  to the long-term and short-term capital and credit markets
is necessary for obtaining funds externally.  The Company's debt ratings
are as follows:


                             Moody's      Standard & Poor's
                                         
     Long-term debt            A2                 A
     Short-term debt           P1                A1


      Utilities'  credit ratings are under review for potential  upgrade
related to the Proposed Merger.

      The Company's liquidity and capital resources will be affected  by
environmental and legislative issues, including the ultimate disposition
of   remediation   issues   surrounding  the   Company's   environmental
liabilities and the Clean Air Act as amended, as discussed in Note 6  of
the  Notes to Consolidated Financial Statements, and the National Energy
Policy Act of 1992 as discussed in the Other Matters section. Consistent
with  rate  making principles of the IUB, management believes  that  the
costs  incurred  for the above matters will not have a material  adverse
effect  on  the  financial  position or results  of  operations  of  the
Company.

      Current  IUB  rules require Utilities to spend 2% of electric  and
1.5%  of  gas  gross  retail  operating  revenues  annually  for  energy
efficiency programs.  Energy efficiency costs in excess of the amount in
the  most  recent  electric and gas rate cases  are  being  recorded  as
regulatory  assets by Utilities.  At September 30, 1996,  Utilities  had
approximately  $58 million of such costs recorded as regulatory  assets.
On  June  1,  1995,  Utilities began recovery of  those  costs  incurred
through  1993.   See  Note  3(c) of the Notes to Consolidated  Financial
Statements  for  a  discussion of the timing  of  the  filings  for  the
recovery  of  these  costs under IUB rules and  Iowa  statutory  changes
recently enacted relating to these programs.

     Under provisions of the Merger Agreement, there are restrictions on
the  amount of long-term debt the Company can issue pending the  merger.
The  Company does not expect the restrictions to have a material  effect
on its ability to meet its future capital requirements.

                  CONSTRUCTION AND ACQUISITION PROGRAM

      The  Company's  construction and acquisition  program  anticipates
expenditures   of  approximately  $164  million  for  1996,   of   which
approximately  55% represents expenditures for electric, gas  and  steam
transmission  and distribution facilities, 19% represents  fossil-fueled
generation   expenditures,   13%   represents   information   technology
expenditures  and  5% represents nuclear generation  expenditures.   The
remaining 8% represents miscellaneous electric and general expenditures.
In  addition to the $164 million, Utilities anticipates expenditures  of
$13 million in connection with mandated energy efficiency programs.  The
Company  had  construction and acquisition expenditures of approximately
$97 million for the nine months ended September 30, 1996.

       The  Company's  construction  and  acquisition  expenditures  are
projected to be approximately $150 million per year in 1997 - 2000.   It
is  estimated  that  approximately 80% of  Utilities'  construction  and
acquisition  expenditures  will  be  provided  by  cash  from  operating
activities  (after payment of dividends) for the five-year period  1996-
2000.

      Capital expenditure and investment and financing plans are subject
to  continual review and change. The capital expenditure and  investment
programs may be revised significantly as a result of many considerations
including changes in economic conditions, variations in actual sales and
load  growth  compared  to  forecasts,  requirements  of  environmental,
nuclear  and  other  regulatory authorities,  acquisition  and  business
combination  opportunities, the availability  of  alternate  energy  and
purchased power sources, the ability to obtain adequate and timely  rate
relief,  escalations in construction costs and conservation  and  energy
efficiency programs.

     Under provisions of the Merger Agreement, there are restrictions on
the  amount of construction and acquisition expenditures the Company can
make  pending  the merger.  The Company does not expect the restrictions
to  have  a  material effect on its ability to implement its anticipated
construction and acquisition program.

                           LONG-TERM FINANCING

      Other  than  Utilities' periodic sinking fund requirements,  which
Utilities intends to meet by pledging additional property, approximately
$125  million of long-term debt will mature prior to December 31,  2000.
The  Company  intends to refinance the majority of the  debt  maturities
with long-term securities.


      In  September  1996, Utilities repaid at maturity $15  million  of
Series  J,  6.25%  First Mortgage Bonds and, in a separate  transaction,
issued $60 million of Collateral Trust Bonds, 7.25%, due 2006.

      Utilities  has entered into an Indenture of Mortgage and  Deed  of
Trust dated September 1, 1993 (New Mortgage).  The New Mortgage provides
for, among other things, the issuance of Collateral Trust Bonds upon the
basis  of First Mortgage Bonds being issued by Utilities.  The  lien  of
the  New  Mortgage  is  subordinate to  the  lien  of  Utilities'  first
mortgages  until such time as all bonds issued under the first mortgages
have  been  retired and such mortgages satisfied.  Accordingly,  to  the
extent  that  Utilities issues Collateral Trust Bonds on  the  basis  of
First  Mortgage  Bonds,  it must comply with the  requirements  for  the
issuance  of  First  Mortgage  Bonds under Utilities'  first  mortgages.
Under  the  terms of the New Mortgage, Utilities has covenanted  not  to
issue  any  additional First Mortgage Bonds under  its  first  mortgages
except to provide the basis for issuance of Collateral Trust Bonds.

      The  indentures pursuant to which Utilities issues First  Mortgage
Bonds  constitute  direct first mortgage liens  upon  substantially  all
tangible  public utility property and contain covenants  which  restrict
the  amount  of  additional bonds which may  be  issued.   At  September
30,  1996,  such restrictions would have allowed Utilities to  issue  at
least $229 million of additional First Mortgage Bonds.

      In  order  to provide an instrument for the issuance of  unsecured
subordinated debt securities, Utilities entered into an Indenture  dated
December  1, 1995 (Subordinated Indenture).  The Subordinated  Indenture
provides for, among other things, the issuance of unsecured subordinated
debt  securities.   Any  debt securities issued under  the  Subordinated
Indenture  are  subordinate  to all senior  indebtedness  of  Utilities,
including First Mortgage Bonds and Collateral Trust Bonds.

     Utilities has received authority from the Federal Energy Regulatory
Commission  (FERC) and the SEC to issue up to $250 million of  long-term
debt, and has $190 million of remaining authority under the current FERC
docket through April 1998, and $140 million of remaining authority under
the current SEC shelf registration.

      The Articles of Incorporation of Utilities authorize and limit the
aggregate amount of additional shares of Cumulative Preference Stock and
Cumulative Preferred Stock that may be issued.  At September  30,  1996,
Utilities  could have issued an additional 700,000 shares of  Cumulative
Preference Stock and no additional shares of Cumulative Preferred Stock.

      The Company's capitalization ratios at September 30, 1996, were as
follows:

           Long-term debt          48%
           Preferred stock          2
           Common equity           50
                                  100%


     Under provisions of the Merger Agreement, there are restrictions on
the  amount of long-term debt the Company can issue pending the  merger.
The  Company does not expect the restrictions to have a material  effect
on its ability to meet its future capital requirements.

                          SHORT-TERM FINANCING

      For  interim  financing, Utilities is authorized by  the  FERC  to
issue,  through 1996, up to $200 million of short-term notes.  Utilities
will  be  making  a filing with FERC in the fourth quarter  of  1996  to
extend such authorization.  In addition to providing for ongoing working
capital  needs,  this  availability  of  short-term  financing  provides
Utilities  flexibility  in  the issuance of  long-term  securities.   At
September  30, 1996, Utilities had outstanding short-term borrowings  of
$82.2  million,  including $4.2 million of notes payable  to  associated
companies.

      Utilities  has entered into an agreement, which expires  in  1999,
with  a  financial  institution  to  sell,  with  limited  recourse,  an
undivided  fractional  interest of up to $65  million  in  its  pool  of
utility  accounts receivable.  At September 30, 1996,  $65  million  was
sold under the agreement.

      At  September  30,  1996, the Company had  bank  lines  of  credit
aggregating  $121.1  million, of which $78 million  was  being  used  to
support  commercial paper (weighted average interest rate of 5.47%)  and
$11.1   million  to  support  certain  pollution  control   obligations.
Commitment  fees  are  paid to maintain these lines  and  there  are  no
conditions  which restrict the unused lines of credit.  In  addition  to
the above, Utilities has an uncommitted credit facility with a financial
institution whereby it can borrow up to $40 million.  Rates are  set  at
the  time  of borrowing and no fees are paid to maintain this  facility.
At  September 30, 1996, there were no borrowings outstanding under  this
facility.

                          ENVIRONMENTAL MATTERS
                                    
      Utilities has been named as a Potentially Responsible Party  (PRP)
by  various federal and state environmental agencies for 28 FMGP  sites,
but  believes  it  is not responsible for two of these  sites  based  on
extensive  reviews  of the ownership records and historical  information
available  for  the two sites.  Utilities has notified  the  appropriate
regulatory  agency that it believes it does not have any  responsibility
as  relates  to these two sites, but no response has been received  from
the  agency  on this issue.  Utilities is also aware of six other  sites
that  it  may  have owned or operated in the past and for  which,  as  a
result,  it  may be designated as a PRP in the future in the event  that
environmental  concerns  arise at these  sites.   Utilities  is  working
pursuant  to  the  requirements of the various agencies to  investigate,
mitigate,  prevent and remediate, where necessary, damage  to  property,
including damage to natural resources, at and around the sites in  order
to protect public health and the environment.  Utilities believes it has
completed  the remediation of seven sites although it is in the  process
of  obtaining final approval from the applicable environmental  agencies
on  this  issue  for each site.  Utilities is in various stages  of  the
investigation  and/or remediation processes for the remaining  19  sites
and  estimates  the  range  of  additional  costs  to  be  incurred  for
investigation  and/or remediation of the sites to be  approximately  $22
million to $54 million.

      Utilities  has recorded environmental liabilities related  to  the
FMGP  sites  of  approximately $34 million (including  $4.6  million  as
current  liabilities) at September 30, 1996.  These  amounts  are  based
upon  Utilities' best current estimate of the amount to be incurred  for
investigation   and  remediation  costs  for  those  sites   where   the
investigation  process has been or is substantially completed,  and  the
minimum  of  the  estimated  cost  range  for  those  sites  where   the
investigation is in its earlier stages.  It is possible that future cost
estimates   will   be  greater  than  the  current  estimates   as   the
investigation process proceeds and as additional facts become known;  in
addition, Utilities may be required to monitor these sites for a  number
of  years upon completion of remediation, as is the case with several of
the sites for which remediation has been completed.

      In  April 1996, Utilities filed a lawsuit against certain  of  its
insurance  carriers seeking reimbursement for investigation, mitigation,
prevention,  remediation and monitoring costs associated with  the  FMGP
sites.  Settlement discussions are proceeding between Utilities and  its
insurance  carriers regarding the recovery of these FMGP-related  costs.
The  amount of aggregate potential recovery, or the regulatory treatment
of  any  such recoveries, cannot be reasonably determined at  this  time
and,  accordingly, no estimated amounts have been recorded at  September
30, 1996.  Regulatory assets of approximately $34 million, which reflect
the  future  recovery that is being provided through  Utilities'  rates,
have been recorded in the Consolidated Balance Sheets.  Considering  the
current rate treatment allowed by the IUB, management believes that  the
clean-up costs incurred by Utilities for these FMGP sites will not  have
a  material  adverse  effect on its financial  position  or  results  of
operations.

      The  Clean  Air  Act  Amendments of 1990 (Act)  requires  emission
reductions of sulfur dioxide (SO2) and nitrogen oxides (NOx) to  achieve
reductions  of atmospheric chemicals believed to cause acid  rain.   The
provisions of the Act are being implemented in two phases; the  Phase  I
requirements  have been met and the Phase II requirements affect  eleven
other  fossil  units beginning in the year 2000.  Utilities  expects  to
meet  the  requirements of Phase II by switching to lower sulfur  fuels,
capital  expenditures  primarily related to fuel burning  equipment  and
boiler  modifications,  and  the possible purchase  of  SO2  allowances.
Utilities estimates capital expenditures of approximately $23.5 million,
including $7.4 million in 1996 (of which $4.1 million was expended as of
September 30, 1996), in order to meet the acid rain requirements of  the
Act.

      The  acid  rain program under the Act also governs SO2 allowances.
An allowance is defined as an authorization for an owner to emit one ton
of  SO2 into the atmosphere.  Currently, Utilities receives a sufficient
number  of allowances annually to offset its emissions of SO2  from  its
Phase  I units.  It is anticipated that in the year 2000, Utilities  may
have  an  insufficient  number  of allowances  annually  to  offset  its
estimated  emissions and may have to purchase additional allowances,  or
make   modifications  to  the  plants  or  limit  operations  to  reduce
emissions.   Utilities is reviewing its options to ensure that  it  will
have  sufficient  allowances  to offset its  emissions  in  the  future.
Utilities  believes  that  the  potential cost  of  ensuring  sufficient
allowances  will  not have a material adverse effect  on  its  financial
position or results of operations.

      The  Act  and  other federal laws also require the  United  States
Environmental  Protection  Agency  (EPA)  to  study  and  regulate,   if
necessary,  additional  issues  that  potentially  affect  the  electric
utility  industry, including emissions relating to NOx, ozone transport,
mercury   and   particulate  control;  toxic  release  inventories   and
modifications  to  the  PCB  rules.  Currently,  the  impacts  of  these
potential regulations are too speculative to quantify.

     In 1995, the EPA published the Sulfur Dioxide Network Design Review
for Cedar Rapids, Iowa, which, based on the EPA's assumptions and worst-
case  modeling  method  suggests that the Cedar  Rapids  area  could  be
classified  as  "nonattainment" for the  National  Ambient  Air  Quality
Standard  (NAAQS)  established for SO2.  The worst-case  modeling  study
suggested that two of Utilities' generating facilities contribute to the
modeled  exceedences and recommended that additional monitors be located
near  Utilities' sources to assess actual ambient air quality.   In  the
event   that   Utilities'  facilities  contribute  excessive  emissions,
Utilities  would be required to reduce emissions, which would  primarily
entail   capital  expenditures  for  modifications  to  the  facilities.
Utilities is currently exploring its options to modify one of its fossil
generating  facilities to reduce SO2 emissions.  Utilities is  proposing
to resolve the remainder of EPA's nonattainment concerns by installing a
new  stack at the other generating facility contributing to the  modeled
exceedences at a potential aggregate capital cost of up to $4.5  million
over the next four years.

      The  National Energy Policy Act of 1992 requires owners of nuclear
power  plants  to  pay  a special assessment into a "Uranium  Enrichment
Decontamination and Decommissioning Fund."  The assessment is based upon
prior  nuclear fuel purchases and, for the DAEC, averages  $1.4  million
annually  through 2007, of which Utilities' 70% share is  $1.0  million.
Utilities  is  recovering  the  costs associated  with  this  assessment
through  its electric fuel adjustment clauses over the period the  costs
are  assessed.   Utilities'  70% share of the future  assessment,  $10.7
million  payable through 2007, has been recorded as a liability  in  the
Consolidated Balance Sheets, including $0.8 million included in "Current
liabilities  -  Environmental liabilities," with  a  related  regulatory
asset for the unrecovered amount.

     The Nuclear Waste Policy Act of 1982 assigned responsibility to the
U.S. Department of Energy (DOE) to establish a facility for the ultimate
disposition  of  high level waste and spent nuclear fuel and  authorized
the  DOE  to enter into contracts with parties for the disposal of  such
material  beginning  in January 1998.  Utilities  entered  into  such  a
contract  and  has  made the agreed payments to the Nuclear  Waste  Fund
(NWF)  held  by  the U.S. Treasury.  The DOE, however,  has  experienced
significant  delays  in  its  efforts and  material  acceptance  is  now
expected  to occur no earlier than 2010 with the possibility of  further
delay  being likely.  Utilities has been storing spent nuclear fuel  on-
site  since  plant  operations began in 1974  and  has  current  on-site
capability  to  store spent fuel until 2001.  Utilities is  aggressively
reviewing  options for additional spent nuclear fuel storage capability,
including expanding on-site storage.  In July 1996, the IUB initiated  a
Notice  of Inquiry (NOI) on spent nuclear fuel.  One purpose of the  NOI
was  to evaluate whether the current collection of money from Utilities'
customers  for payment to the NWF should be placed in an escrow  account
in  lieu  of  being  paid to the NWF.  Utilities does not  support  this
alternative and cannot predict the outcome of this NOI.

      The  Low-Level  Radioactive Waste Policy Amendments  Act  of  1985
mandated that each state must take responsibility for the storage of low-
level radioactive waste produced within its borders.  The State of  Iowa
has  joined  the Midwest Interstate Low-Level Radioactive Waste  Compact
Commission (Compact), which is planning a storage facility to be located
in Ohio to store waste generated by the Compact's six member states.  At
September  30,  1996,  Utilities  has  prepaid  costs  of  approximately
$1.1  million  to the Compact for the building of such  a  facility.   A
Compact  disposal  facility  is  anticipated  to  be  in  operation   in
approximately  ten years after approval of new enabling  legislation  by
the  member  states.  Such legislation was approved in 1996 by  all  six
states  that  are members of the Compact.  Final approval  by  the  U.S.
Congress  is now required.  On-site storage capability currently  exists
for  low-level  radioactive waste expected to  be  generated  until  the
Compact  facility is able to accept waste materials.  In  addition,  the
Barnwell,  South  Carolina  disposal  facility  has  reopened   for   an
indefinite  time period and Utilities is in the process of  shipping  to
Barnwell  the  majority  of  the  low-level  radioactive  waste  it  has
accumulated on-site, and currently intends to ship the waste it produces
in  the  future  as  long  as the Barnwell site  remains  open,  thereby
minimizing  the  amount  of  low-level waste stored  on-site.   However,
management of the Barnwell site is in the process of modifying  its  fee
schedule  to  include more emphasis on total radioactivity  content,  in
addition  to volume related fees.  Utilities cannot predict the  outcome
of  these changes on its potential future disposal costs at the Barnwell
site  or if such changes would result in a revision to Utilities' future
disposal plans.

     The possibility that exposure to electric and magnetic fields (EMF)
emanating  from  power lines, household appliances  and  other  electric
sources  may  result in adverse health effects has been the  subject  of
increased public, governmental, industry and media attention.  A  recent
study  completed  by  the National Research Council concluded  that  the
current  body of evidence does not support the notion that  exposure  to
these  fields  may  result  in adverse health effects.   Utilities  will
continue to monitor the events in this area, including future scientific
research.

                              OTHER MATTERS

Competition    As  legislative, regulatory, economic  and  technological
changes occur, electric utilities are faced with increasing pressure  to
become  more  competitive.  Such competitive pressures could  result  in
loss of customers and an incurrence of stranded costs (i.e. the cost  of
assets rendered unrecoverable as the result of competitive pricing).  To
the extent stranded costs cannot be recovered from customers, they would
be borne by security holders.

      The  National Energy Policy Act of 1992 addresses several  matters
designed  to  promote  competition  in  the  electric  wholesale   power
generation  market.  In April 1996, the FERC issued  final  rules  (FERC
Orders  888  and  889), largely confirming earlier proposals,  requiring
electric  utilities to open their transmission lines to other  wholesale
buyers  and sellers of electricity.  The rules became effective on  July
9,  1996.  The key provisions of the rules are: 1) utilities must act as
"common carriers" of electricity, reserving capacity on their lines  for
other   wholesale  buyers  and  sellers  of  electricity  and   charging
competitors  no more than they pay themselves for use of the  lines;  2)
utilities must establish electronic bulletin boards to share information
about  transmission  capacity; 3) utilities  must  separate  the  energy
marketing  function from the transmission system operation function,  to
insure  there  is  not inappropriate information being  used  by  energy
marketing;  and 4) utilities can recover "stranded costs" applicable  to
wholesale  sales.   Utilities  filed conforming  pro-forma  open  access
transmission  tariffs  with the FERC which became effective  October  1,
1995.    In  response to FERC Order 888, Utilities filed its final  pro-
forma  tariffs with FERC on July 9, 1996.  These tariffs  have  not  yet
been  approved  by  the  FERC.  The geographic  position  of  Utilities'
transmission  system  could provide revenue opportunities  in  the  open
access   environment.    The  Company  cannot  predict   the   long-term
consequences  of  these rules on its results of operation  or  financial
condition.

      The  final FERC rules do not provide for the recovery of  stranded
costs  resulting  from  retail competition.  The various  states  retain
jurisdiction  over whether to permit retail competition,  the  terms  of
such  retail  competition and the recovery of any  portion  of  stranded
costs  that  are  ultimately determined by FERC and the states  to  have
resulted from retail competition.

      As  part  of  Utilities' strategy for the emerging and competitive
power markets, Utilities, IPC and Wisconsin Power and Light Company (the
utility  subsidiary  of  WPLH), and a number  of  other  utilities  have
proposed  the creation of an independent system operator (ISO)  for  the
companies'   power  transmission  grid.   The  companies  would   retain
ownership and control of the facilities, but the ISO would set rates for
access and assume fair treatment for all companies seeking access.   The
proposal requires approval from state regulators and the FERC.

      The  IUB  initiated a Notice of Inquiry (Docket No.  NOI-95-1)  in
early  1995  on  the subject of "Emerging Competition  in  the  Electric
Utility  Industry."  A one-day roundtable discussion was held to address
all  forms of competition in the electric utility industry and to assist
the   IUB   in  gathering  information  and  perspectives  on   electric
competition  from all persons or entities with an interest or  stake  in
the issues.  Additional discussions were held in December 1995, May 1996
and  July  1996.  In January 1996, the IUB created its own timeline  for
evaluating  industry  restructuring in  Iowa.   Included  in  the  IUB's
process  was  the  creation  of a 22-member  advisory  panel,  of  which
Utilities is a member.  The IUB has established a self-imposed  deadline
of  the  fourth quarter of 1996, for publishing its analysis of  various
restructuring  options  and any advisory panel  comments  on  the  IUB's
options  and  analysis.  The IUB's schedule calls for public information
meetings  to be held around the state of Iowa.  These meetings began  in
September  1996 and are scheduled to be completed in the fourth  quarter
of 1996.

      Utilities  is subject to the provisions of Statement of  Financial
Accounting  Standards  No. 71, "Accounting for the  Effects  of  Certain
Types  of  Regulation" (SFAS 71).  If a portion of Utilities' operations
become  no  longer subject to the provisions of SFAS 71, as a result  of
competitive  restructurings  or  otherwise,  a  write-down  of   related
regulatory assets would be required, unless some form of transition cost
recovery  is established by the appropriate regulatory body.   Utilities
believes that it still meets the requirements of SFAS 71.

      The  Company  cannot predict the long-term consequences  of  these
competitive issues on its results of operations or financial  condition.
The  Company's strategy for dealing with these emerging issues  includes
seeking  growth  opportunities, continuing  to  offer  quality  customer
service,  ongoing  cost  reductions and productivity  enhancements,  the
major  objective of which is to allow Utilities to better prepare for  a
competitive, deregulated electric utility industry.  In this connection,
Utilities has undertaken Process Redesign, an effort to improve  service
levels,  to  reduce its cost structure and to become more market-focused
and customer-oriented.

      Process Redesign is examining the major business processes  within
Utilities, which are: Customer Service Fulfillment, Fossil-Fueled Energy
Supply,   Nuclear  Energy  Supply,  Non-Electric  Fuel   Supply   Chain,
Transmission and Distribution Energy Delivery, and Planning, Budgeting &
Performance Management.  These areas were examined during Phase I of the
effort,  which  lasted  from January 1995 through  May  1995.   Phase  I
recommendations  were designed to make broad-based changes  in  the  way
work  was  performed and results were achieved in each of the processes.
Management  accepted  the recommendations and, in June  1995,  initiated
Phase  II of the project.  The detailed designs resulting from Phase  II
were substantially completed in November 1995 and pilot programs began.

      Examples  of  the Process Redesign changes include,  but  are  not
limited  to:   managing the business in business unit form, rather  than
functionally;  formation of alliances with vendors of certain  types  of
material and/or services rather than opening most purchases to a bidding
process;  changing standards and construction practices in  transmission
and distribution areas; changing certain work practices in power plants;
and  improving the method by which service is delivered to customers  in
all  customer classes.  The specific recommendations range  from  simple
improvements in current operations to radical changes in the way work is
performed  and  service is delivered.  Utilities  currently  intends  to
implement  all  of  the recommendations of the Process  Redesign  teams,
although  the  pilot stage or potential effects of the  Proposed  Merger
could  prove  that  some of the recommendations  are  not  efficient  or
effective  and must be revised or eliminated.  Subject to delays  caused
by  implementing  any  such  revisions, implementation  of  the  Process
Redesign  changes  will  be partially completed in  1996,  but,  certain
results will not be achieved until 1997.  In addition, the Company  must
give  consideration to the potential effects of the Proposed  Merger  as
part  of  the implementation process so that duplication of efforts  are
avoided.

Accounting Pronouncements   SFAS 121, issued in March 1995 by  the  FASB
and  effective  for  1996,  establishes  accounting  standards  for  the
impairment of long-lived assets.  SFAS 121 also requires that regulatory
assets  that are no longer probable of recovery through future  revenues
be charged to earnings.  The Company adopted this standard on January 1,
1996,  and  the  adoption  had no effect on the  financial  position  or
results of operations of the Company.

Financial   Derivatives    The  Company  has  a  policy  that  financial
derivatives are to be used only to mitigate business risks and  not  for
speculative purposes.  At September 30, 1996, the Company did  not  have
any material financial derivatives outstanding.

Inflation    Utilities  does  not expect the  effects  of  inflation  at
current levels to have a significant effect on its financial position or
results of operations.
                                    

                      PART II. - OTHER INFORMATION

Item 1.  Legal Proceedings.

     On April 30, 1996, Utilities filed suit, IES Utilities Inc. v. Home
Ins.  Co.,  et al., No. 4-96-CV-10343 (S.D. Iowa filed Apr.  30,  1996),
against  various  insurers who had sold comprehensive general  liability
policies  to  Iowa  Southern Utilities Company (ISU) and  Iowa  Electric
Light  and Power Company (IE) (Utilities was formed as the result  of  a
merger  of  ISU and IE).  The suit seeks judicial determination  of  the
respective  rights  of the parties, a judgment that  each  defendant  is
obligated  under its respective insurance policies to pay  in  full  all
sums  that  the  Company has become or may become obligated  to  pay  in
connection  with  its  defense  against  allegations  of  liability  for
property  damage at and around FMGP sites, and indemnification  for  all
sums  that  it has or may become obligated to pay for the investigation,
mitigation,  prevention,  remediation  and  monitoring  of   damage   to
property, including damage to natural resources like groundwater, at and
around the FMGP sites.

      On  October  3,  1996,  Lambda Energy  Marketing  Company,  L.  C.
("Lambda")  filed  a request with the IUB that the IUB  initiate  formal
complaint  proceedings against Utilities.  Lambda alleges that Utilities
is discriminating against it by refusing to enter into contracts with it
for  remote  displacement service and by favoring IEA, a  subsidiary  of
Industries,  in  such matters.  On October 17, 1996, Utilities  filed  a
Response  which  denies  the allegations, a Motion  for  Bifurcation,  a
Motion  of  Summary  Judgment,  a Countercomplaint  and  a  Request  for
Temporary  Relief,  alleging,  inter alia,  that  Lambda  is  unlawfully
attempting to provide retail electrical services in Utilities' exclusive
service territory.

      On  October  9, 1996, Industries filed a civil suit  in  the  Iowa
District  Court  in and for Linn County against Lambda,  Robert  Latham,
Louie Ervin, and David Charles (collectively the "Defendants", including
three  former employees of Industries and/or its subsidiaries) alleging,
inter alia, violations of Iowa's trade secret act and interference  with
existing  and prospective business advantage.  On November 1, 1996,  the
Defendants  filed their Answer and Counterclaims alleging,  inter  alia,
violation  of Iowa competition law, tortious interference and commercial
disparagement.   The  Defendants  therewith  also  filed  a  Third-Party
Petition  against  Utilities,  IEA and Lee  Liu  alleging,  inter  alia,
tortious interference and commercial disparagement.

      Reference  is  made to Notes 3 and 6 of the Notes to  Consolidated
Financial  Statements for a discussion of rate matters and environmental
matters,  respectively, and Item 2. Management's Discussion and Analysis
of  the  Results  of Operations and Financial Condition -  Environmental
Matters.

Item 2.  Changes in the Rights of the Company's Security Holders.

None.

Item 3.  Default Upon Senior Securities.

None.

Item 4.  Results of Votes of Security Holders.

(a)  The Company held its Annual Meeting of Shareholders on September 5,
     1996.

(b)  The  following  matters were voted upon at the Annual  Meeting  of
     Shareholders.

     The election of nominees for Directors who will serve a one-year
     term  or  until  their respective successors  shall  be  duly
     elected.  The nominees were as follows:

     C.R.S. Anderson, J. Wayne Bevis, Lee Liu, Jack R. Newman,
     Robert  D.  Ray,  David Q. Reed, Henry Royer, Robert W. Schlutz,
     Anthony R. Weiler.

     IES Industries Inc., the sole shareholder of the Company, voted
     all 13,370,788 shares for the election of the above nominees.

Item 5.  Other Information.

(a)  The  Company has calculated the ratio of earnings to fixed charges
     pursuant  to Item 503 of Regulation S-K of the Securities and
     Exchange Commission as follows:

          For the twelve months ended:

               September 30, 1996            2.93
               December 31, 1995             3.04
               December 31, 1994             3.18
               December 31, 1993             3.41
               December 31, 1992             2.49
               December 31, 1991             2.64

(b)  On November 6, 1996, Larry D. Root, who retired from IES
     Industries  Inc.  in 1995, was named President  &  Chief  Operating
     Officer of the Company.  Lee Liu will continue to serve as Chairman
     of the Board & Chief Executive Officer.

Item 6.  Exhibits and Reports on Form 8-K.

(a)  Exhibits -

     *3(a)  Bylaws of Registrant, as amended November 6, 1996.

      4(a)  Sixty-second Supplemental Indenture, dated as
            of  September  1, 1996, supplementing Utilities' Indenture  of
            Mortgage  and Deed of Trust, dated August 1, 1940.  (Filed  as
            Exhibit  4(f)  to the Company's Current Report  on  Form  8-K,
            dated September 19, 1996).

      4(b)  Fourth Supplemental Indenture, dated as of September
            1,  1996,  supplementing Utilities' Indenture of Mortgage  and
            Deed  of  Trust,  dated September 1, 1993. (Filed  as  Exhibit
            4(c)(i)  to  the Company's Current Report on Form  8-K,  dated
            September 19, 1996).

     10(a)  Executive Change of Control Severance  Agreement  -
            CEO  (Filed as Exhibit 10(a) to Industries' Form 10-Q for  the
            quarter ended September 30, 1996 (File No. 1-9187)).

     10(b)  Executive Change of Control Severance  Agreement  -
            Vice Presidents (Filed as Exhibit 10(b) to Industries' Form 10-
            Q for the quarter ended September 30, 1996 (File No. 1-9187)).

     10(c)  Executive Change of Control Severance  Agreement  -
            Other Officers (Filed as Exhibit 10(c) to Industries' Form 10-
            Q for the quarter ended September 30, 1996 (File No. 1-9187)).

    *12     Ratio of Earnings to Fixed Charges

    *27     Financial Data Schedule.

    *  Exhibits designated by an asterisk are filed herewith.

 (b) Reports on Form 8-K -

          Items Reported      Financial Statements         Date of Report
                                                                 
                5,7                 None               September 19, 1996  (1)
                                    
                                    
                                    
   (1)  The Form 8-K report was filed on September 27, 1996 with
        the earliest event reported occurring on September 19, 1996.


                               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.



                                 IES UTILITIES INC.
                                    (Registrant)




Date:   November 13, 1996        By /s/             Dennis B. Vass
                                                      (Signature)
                                                    Dennis B. Vass
                                       Treasurer & Principal Financial Officer





                                 By /s/            John E. Ebright
                                                     (Signature)
                                                   John E. Ebright
                                       Controller & Chief Accounting Officer