UNITED STATES SECURITIES AND EXCHANGE COMMISSION
                         WASHINGTON, D.C. 20549
                                    
                                FORM 10-K

(Mark One)
(X)   ANNUAL  REPORT PURSUANT TO SECTION 13 OR 15(d) OF  THE  SECURITIES
      EXCHANGE ACT OF 1934 [FEE REQUIRED]
For the fiscal year ended December 31, 1995
                                    OR
( )  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
     EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
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

Securities registered pursuant to Section 12(b) of the Act:
                                                  Name of each exchange on
     Title of each class                              which registered

7-7/8% Quarterly Debt Capital Securities
(Subordinated Deferrable Interest Debentures)     New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:

Cumulative Preferred Stock                      Par Value $50 per share 4.80%
                             (Title of class)

Indicate by check mark whether the registrant (1) has filed all  reports
required  to be filed by Section 13 or 15(d) of the Securities  Exchange
Act  of  1934 during the preceding 12 months (or for such shorter period
that the registrant was required to file such reports), and (2) has been
subject  to such filing requirements for the past 90 days. Yes   X    No
                                                                ---  ---

Indicate  by  check mark if disclosure of delinquent filers pursuant  to
Item  405  of  Regulation S-K is not contained herein, and will  not  be
contained, to the best of registrant's knowledge, in definitive proxy or
information  statements incorporated by reference in Part  III  of  this
Form 10-K or any amendment to this Form 10-K.     X
                                                 ---  

The aggregate market value of the registrant's voting stock held by non-
affiliates, as of January 31, 1996 was $0.

Indicate  the  number of shares outstanding of each of the  registrant's
classes of Common Stock, as of January 31, 1996.

           Common Stock, $2.50 par value -  13,370,788 shares

                                 PART I

Item 1.  Business

      IES  Utilities Inc. (the Company) is a wholly-owned subsidiary  of
IES  Industries  Inc. (Industries). The Company is  primarily  a  public
utility  operating company engaged in providing electric energy, natural
gas  and,  to  a limited extent, steam used for industrial  and  heating
purposes,  in  the  State  of  Iowa.  The Company  provides  service  to
approximately 333,000 electric and 174,000 natural gas retail  customers
as well as 30 resale customers in more than 550 Iowa communities.

     The Company's only wholly-owned subsidiary as of December 31, 1995,
was  IES  Ventures  Inc.  (Ventures), which is  a  holding  company  for
unregulated   investments.    Ventures'   wholly-owned   subsidiary   at
December  31,  1995, was IES Midland Development Inc.  (Midland),  which
owns and operates a landfill in Ottumwa, Iowa.  Ventures also has a  35%
equity  investment  in  Aqua  Ventures L.C.,  which  is  an  aquaculture
facility formed to raise fish for human consumption.

      The  Company's sales of electricity (in Kwh), excluding off-system
sales,  increased  5.3%,  4.3% and 24.9%, during  the  years  1995-1993,
respectively.   The 1995 increase was significantly affected  by  warmer
than  normal  weather during the summer months.  The 1993  increase  was
attributable  to  the acquisition of the Iowa retail  service  territory
from  Union Electric Company (UE) on December 31, 1992, and a return  to
more  normal  weather conditions.  Total gas delivered by  the  Company,
including transported volumes, increased or (decreased) 4.8%, (2.7%) and
5.3% during the years 1995-1993, respectively.

      There  are seasonal variations in the Company's electric  and  gas
businesses, which are principally related to the use of energy  for  air
conditioning  and  heating.  In 1995, 42.1% of  the  Company's  electric
revenues  were earned in June through September, reflecting the  use  of
electricity  for cooling, and 67.6% of the Company's gas  revenues  were
earned  in  the  months  of  January -  March,  November  and  December,
reflecting the use of gas for heating.

      The approximate percentages of the Company's revenue and operating
income  derived  from the sale of electricity and gas during  the  years
1995-1993 are as follows:

                         1995        1994         1993    
Revenues:                                                 
      Electric            79%         78%          77%       
      Gas                 19          20           22        
                                                          
Operating income:                                         
      Electric            92%         93%          90%       
      Gas                  6           6           10        


       The  relationships  between  the  electric  and  gas  percentages
presented  above  are influenced by changes in energy sales,  timing  of
price  proceedings  and changes in the costs of fuel  or  purchased  gas
billed to customers through related adjustment clauses.

      For additional information concerning electric and gas operations,
see  Item  1.  "Other  Information Relating to  the  Company",  Item  7.
"Management's  Discussion and Analysis of the Results of Operations  and
Financial Condition" and the Electric and Gas Operating Comparisons.

      Refer to Note 13 of the Notes to Consolidated Financial Statements
for a further discussion of the Company's segments of business.

Other Information Relating to the Company

      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  (the
Proposed  Merger).   The new holding company will  be  named  Interstate
Energy  Corporation  (Interstate Energy) and Industries  will  cease  to
exist.  The Proposed Merger, which will be accounted for as a pooling of
interests, has been approved by the respective Boards of Directors.   It
is still subject to approval by the shareholders of each company as well
as  several federal and state regulatory agencies.  The companies expect
to  receive the shareholder approvals in the second quarter of 1996  and
the regulatory approvals by the second quarter of 1997.

      The  Merger  Agreement contains certain covenants of  the  parties
pending the consummation of the Proposed Merger.  Generally, the parties
and  their  subsidiaries, including the Company,  must  carry  on  their
businesses in the ordinary course consistent with past practice, may not
increase  dividends on common stock in excess of current levels  in  the
case  of Industries and IPC, and beyond a specific limit in the case  of
WPLH,  and  may not issue any capital stock beyond certain limits.   The
Merger  Agreement  also contains certain restrictions  on,  among  other
things,    charter   and   bylaw   amendments,   acquisitions,   capital
expenditures,   dispositions,  incurrence   of   indebtedness,   certain
increases   in   employee  compensation  and  benefits   and   affiliate
transactions.   The  Company  does  not  expect  these  restrictions  to
materially impact its ongoing operations.

      Interstate  Energy  will be the parent of the  Company,  Wisconsin
Power  and Light Company (WP&L), a wholly-owned subsidiary of WPLH,  and
IPC  and will be registered under the Public Utility Holding Company Act
of  1935,  as  amended (1935 Act).  The Merger Agreement  provides  that
these  operating utility companies will continue to operate as  separate
entities for a minimum of three years beyond the effective date  of  the
merger.  In addition, the non-utility operations of Industries and  WPLH
will  be  combined shortly after the effective date of the merger  under
one entity to manage the diversified operations of Interstate Energy.

      The  1935 Act imposes restrictions on the operations of registered
holding   companies.   Among  these  are  requirements  that  securities
issuances,  and sales and acquisitions of utility assets, securities  of
utility  and other companies and any other interests in any business  be
approved by the SEC.  The 1935 Act also limits the ability of registered
holding  companies  to  engage  in non-utility  ventures  and  regulates
holding  company  service  companies and the rendering  of  services  by
holding  company  affiliates to the affiliated utilities.   The  Company
believes the benefits of the Proposed Merger far outweigh the effects of
such 1935 Act regulation.

      In addition, the SEC historically has interpreted the 1935 Act  to
preclude  registered  holding companies, with limited  exceptions,  from
owning  both  electric and gas utility systems.  Although  the  SEC  has
recently  recommended that registered holding companies  be  allowed  to
hold  both  gas  and electric utility operations if the affected  states
agree,  it  remains possible that the SEC may require as a condition  to
its approval of the Proposed Merger that Industries, WPLH and IPC divest
their  gas utility properties, and possibly certain non-utility ventures
of   Industries  and WPLH, within a reasonable time after the  effective
date  of  the  Proposed Merger.  The Company believes there  are  strong
policy  reasons and prior SEC decisions which support the  retention  of
existing gas utility properties and non-utility ventures.

      Legislation to repeal the 1935 Act was introduced in  Congress  in
1995  and is pending.  No assurance can be given as to when or  if  such
legislation  will be considered or enacted.  The Staff of  the  SEC  has
also  recommended that the SEC "permit combination systems by registered
holding  companies  if  the affected states concur,"  and  the  SEC  has
proposed  rules that would relax current restrictions on  investment  by
registered  holding  companies in certain "energy related,"  non-utility
businesses.  The Company cannot predict the outcome of these legislative
and regulatory proposals.

      See Note 2 of the Notes to Consolidated Financial Statements for a
further discussion of the Proposed Merger.

      CONSTRUCTION AND ACQUISITION PROGRAM AND FINANCING.   The  capital
requirements, including $2.8 million of sinking funds that may be met by
pledging  additional  utility property, for  the  period  1996-2000  are
estimated at $1.0 billion and are summarized as follows:

                                 Capital Requirements
                             1996       1997       1998       1999       2000
                                       (in thousands)
Construction and                                                    
  acquisition expenditures -
    Electric:                                                    
      Generation         $  38,753  $  54,244  $  60,952  $  57,185  $  38,166
      Transmission          34,730     32,975     33,858     32,370     22,968
      Distribution          34,322     47,925     45,370     43,163     46,419
      Other                  8,760      8,926      9,127      9,335      9,548
    Gas                      9,609      8,310      7,549      9,334      9,682
    Steam                   10,992      1,250      1,039        405        645
    Information 
      technology            22,109     25,432     11,824      3,365      3,470
    Other                    5,042      5,900      6,093      6,289      6,492
Total construction and
   acquisition 
     expenditures          164,317    184,962    175,812    161,446    137,390
Energy efficiency                                                   
  expenditures              13,263     14,325     15,221     14,439     13,235
Long-term debt maturities
  and sinking funds         15,770      8,690        690     50,690     67,246
Total capital 
  requirements           $ 193,350  $ 207,977  $ 191,723  $ 226,575  $ 217,871

      The  Company  intends  to refinance the  majority  of  the  debt
maturities with long-term securities.

      Approximately  30% of the Company's construction expenditures  are
related  to  generation.  Of this amount, approximately  83%  represents
capacity expansions and other improvements at fossil generating stations
and  17%  represents  modifications and improvements  at  the  Company's
nuclear generating station, the Duane Arnold Energy Center (DAEC).

      The  1998-2000  construction and acquisition expenditures  in  the
preceding table could be revised significantly upon the consummation  of
the Proposed Merger.

      For  a discussion regarding the Company's assumptions in financing
future  capital requirements, see the "Liquidity and Capital  Resources"
section  of Item 7. "Management's Discussion and Analysis of the Results
of Operations and Financial Condition."

     REGULATION.  The Company operates pursuant to the laws of the State
of Iowa and is thereby subject to the jurisdiction of the Iowa Utilities
Board  (IUB).  The IUB has authority to regulate rates and standards  of
service,  to  prescribe  accounting  requirements  and  to  approve  the
location  and  construction of electric generating facilities  having  a
capacity  in  excess  of  25,000 Kw.  The  IUB  is  comprised  of  three
Commissioners  appointed  by the Governor  and  ratified  by  the  State
Senate.  Requests for price relief are based on historical test periods,
adjusted for certain known and measurable changes.  The IUB must  decide
on  requests  for  price relief within 10 months  of  the  date  of  the
application  for  which  relief is filed or the interim  prices  granted
become  permanent.  Interim prices, if allowed, are permitted to  become
effective,  subject  to refund, no later than 90 days  after  the  price
increase application is filed.

      In  Iowa, non-exclusive franchises, which cover the use of streets
and  alleys  for public utility facilities in incorporated  communities,
are  granted  for a maximum of twenty-five years by a majority  vote  of
local  qualified residents.  In addition, the IUB defines the boundaries
of  mutually  exclusive service territories for all electric  utilities.
The  IUB  has jurisdiction and grants franchises for the use  of  public
highway  rights-of-way for electric and gas facilities outside corporate
limits.

      The  Company is subject to the jurisdiction of the Federal  Energy
Regulatory  Commission (FERC) with respect to wholesale  electric  sales
and  the  issuance of securities.  Revenues derived from  the  Company's
wholesale  and  off-system sales amounted to  6.3%,  6.9%  and  9.0%  of
electric   revenues   for   1995-1993,   respectively.   The   Company's
consolidated subsidiaries are not subject to regulation by  the  IUB  or
the FERC.

      EMPLOYEES.  At December 31, 1995, the Company had a total of 2,204
regular  full-time employees, of which an aggregate of  1,152  employees
were  subject  to  6 collective bargaining arrangements  (824  of  these
employees were part of one arrangement).

      ENVIRONMENTAL MATTERS.  The Company is regulated in  environmental
protection  matters  by a number of federal, state and  local  agencies.
Such  regulations are the result of a number of environmental protection
laws  passed  by  the  U.  S.  Congress,  state  legislature  and  local
governments  and  enforced by federal, state and county  agencies.   The
laws  impacting  the Company's operations include the Clean  Water  Act;
Clean  Air  Act,  as  amended by the Clean Air Act Amendments  of  1990;
National  Environmental Policy Act; Resource Conservation  and  Recovery
Act;  Comprehensive Environmental Response, Compensation  and  Liability
Act  of  1980  (CERCLA),  as  amended by the  Superfund  Amendments  and
Reauthorization  Act  of  1986;  Occupational  Safety  and  Health  Act;
National Energy Policy Act of 1992 and a number of others.  The  Company
regularly secures and renews federal, state and local permits to  comply
with   the   environmental  protection  laws  and  regulations.    Costs
associated with such compliances have increased in recent years and  are
expected to increase moderately in the future.

      At  December 31, 1995, the Company had recorded $46.4  million  of
environmental   liabilities,  which,  pursuant  to  generally   accepted
accounting  principles, represents either the best current  estimate  or
the  minimum  amount  of the estimated range of  such  costs  which  the
Company  expects to incur, depending on the information known  for  each
site.  These estimates are subject to continuing review and actual costs
could ultimately exceed the recorded amounts.

      The  Clean  Air  Act  Amendments  Act  of  1990  (Act)  calls  for
significant  reductions  in  sulfur  dioxide  and  nitrogen  oxide   air
emissions.   The  majority  of such reductions  will  be  required  from
utilities  in  the  United  States.  It is anticipated  that  any  costs
incurred  by  the  Company will be recovered from its  ratepayers  under
current  regulatory principles.  Refer to Notes 11(a) and 11(g)  of  the
Notes  to  Consolidated Financial Statements for additional  information
regarding the Company's expected expenditures.

      The  acid  rain program under the Act also creates sulfur  dioxide
allowances.  An allowance is defined as an authorization for an owner to
emit  one  ton  of sulfur dioxide into the atmosphere.   Currently,  the
Company  receives a sufficient number of allowances annually  to  offset
its  emissions  of  sulfur  dioxide from  its  Phase  I  units.   It  is
anticipated  that in the year 2000, when the Phase II units  participate
in the allowance program, the Company 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.  The Company  is  reviewing  its
options to ensure that it will have sufficient allowances to offset  its
emissions  in  the year 2000 and thereafter.  The Company believes  that
the  potential cost of ensuring sufficient allowances will  not  have  a
material  adverse  effect  on  its  financial  position  or  results  of
operations.

     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  methods, suggests that the Cedar Rapids  area  could  be
classified  as  "nonattainment" for the  National  Ambient  Air  Quality
Standard   (NAAQS)  established  for  sulfur  dioxide.   The  worst-case
modeling  study suggests that two of the Company's generating facilities
contribute  to  the modeled exceedences and recommends  that  additional
monitors be located near the Company's sources to assess actual  ambient
air  quality.   In  the  event that the Company's facilities  contribute
excessive  emissions, the Company would be required to reduce emissions,
which  would primarily entail capital expenditures for modifications  to
the  facilities.   The Company is currently reviewing EPA's  assumptions
and  modeling results and is proposing a strategy to voluntarily  reduce
the  excessive  emissions through modification of its  facilities  at  a
potential capital cost of up to $10 million over the next four years.

     The Company has been named as a Potentially Responsible Party (PRP)
for  certain  former manufactured gas plant (FMGP) sites by  either  the
Iowa  Department  of  Natural Resources (IDNR), the Minnesota  Pollution
Control Agency (MPCA) or the EPA.  The Company is working with the IDNR,
MPCA  and  EPA to investigate its sites and to determine the appropriate
remediation  activities  that  may be  needed  to  mitigate  health  and
environmental concerns.

     The Company is investigating the possibility of insurance and third
party cost sharing for FMGP clean-up costs.  The amount of shared costs,
if  any,  cannot be reasonably determined and, accordingly, no potential
sharing  has been recorded at December 31, 1995.  Considering  the  rate
treatment  allowed  by the IUB, management believes  that  the  clean-up
costs  incurred  by the Company for these FMGP sites  will  not  have  a
material  adverse  effect  on  its  financial  position  or  results  of
operations.  Refer to Note 11(f) of the Notes to Consolidated  Financial
Statements for more information.

     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.  The Company entered  into  such  a
contract and has made the agreed payments to DOE.  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.  The Company 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  2002.   The  Company  is
aggressively reviewing options for additional spent nuclear fuel storage
capability,   including   expanding  on-site  storage   and   supporting
legislation currently before the U.S. Congress, to resolve the  lack  of
progress by the DOE.

      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
December  31,  1995,  the  Company 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 is expected to be considered by the
member states in 1996.  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  the Company is in the process of shipping to  Barnwell  the
majority  of the low-level radioactive waste it has accumulated on-site,
and  intends to ship the waste it produces in the future as long as  the
Barnwell  site  remains open, thereby minimizing  the  amount  of  waste
stored on-site.

      The Company was notified in 1986 that it was designated by the EPA
as  a PRP (there are 832 in total) for the investigation and cleanup  of
the  Maxey Flats Nuclear Disposal site at Morehead, Kentucky.   The  EPA
notice encouraged all PRPs to undertake voluntary clean up activities at
the  site.   A  Steering  Committee was organized  and  the  Company  is
participating  in  its activities.  The Steering Committee  has  reached
settlement  of  the  issues  with the EPA, the  State  of  Kentucky  and
deminimis parties.  Consent Decrees have been submitted to the court for
approval.  Upon approval by the court, the Company's share of the  costs
is  estimated  at  $300,000, which is included in the $46.4  million  of
environmental liabilities the Company has recorded at December 31, 1995.

     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
considerable  amount of scientific research has been conducted  on  this
topic  without definitive results.  Research is continuing in  order  to
resolve  scientific  uncertainties.   The  Company  cannot  predict  the
outcome of this research.

      Refer to Note 11 of the Notes to Consolidated Financial Statements
and  Item  7.  "Management's Discussion and Analysis of the  Results  of
Operations   and   Financial  Condition"  for  further   discussion   of
environmental matters.

      RATE  MATTERS.   Refer  to  Note 3 of the  Notes  to  Consolidated
Financial Statements for a discussion of the Company's rate matters.

      ELECTRIC  OPERATIONS.   The Company's net peak  load  (60  minutes
integrated)  of  1,824,100 kilowatts occurred  on  July  12,  1995,  and
represented  a new energy peak demand record.  At the time of  the  peak
load,   no  interruptible  customers  were  interrupted.   The  Company'
additional  reserve  obligation at the time  of  the  peak  was  256,215
kilowatts  and  the net capability of the Company's generating  stations
was  1,873,300  kilowatts, with an additional  207,100  kilowatts  being
available  under  purchase  contracts, thereby  providing  an  aggregate
capability of 2,080,400 kilowatts.

     The Company projects an electric sales growth rate of approximately
2 to 3 percent per year over the next decade, which will be met by a mix
of  its  existing  generation, capacity purchases and new  construction.
The  construction activities will be undertaken in a fashion  that  best
meets the needs of individual customers and the system as a whole.   See
Note  11(b)  of  the Notes to Consolidated Financial  Statements  for  a
discussion of the Company's firm contracts for the purchase of capacity.

      The  Company is interconnected with other utilities  in  Iowa  and
neighboring states and is a member of the Mid-Continent Area Power  Pool
(MAPP).  MAPP's purpose is to coordinate the planning, construction  and
operation  of  generation and transmission facilities, and the  purchase
and sale of power and energy among its members.

      The  Company is a party to the Twin Cities-Iowa-St. Louis  345  Kv
Interconnection Coordinating Agreement (the Coordinating Agreement) with
five other midwestern utilities, three of which operate in the State  of
Iowa.   The  Coordinating Agreement provides for the interconnection  of
the  respective  systems of the companies through a 345 Kv  transmission
line and for the interchange of power on various bases.  The rates under
the Coordinating Agreement are primarily determined by agreement between
the delivering and receiving companies.

      The  Company  maintains and operates transmission  and  substation
facilities  connecting  with  its  high  voltage  transmission   systems
pursuant   to  a  non-cancelable  operating  agreement  (the   Operating
Agreement)  with Central Iowa Power Cooperative (CIPCO).  The  Operating
Agreement, which will terminate on December 31, 2035, provides  for  the
joint use of certain transmission facilities of the Company and CIPCO.

      Upon  consummation of the Proposed Merger, the Company expects  to
realize reduced electric production costs through the joint dispatch  of
systems  and  increased marketing opportunities  in  the  wholesale  and
interchange  markets  through  electric  interconnections   with   other
utilities.

      For  comments relating to agreements between the Company  and  its
partners  for  the  joint ownership of the DAEC, the Ottumwa  Generating
Station (OGS), and Neal Unit No. 3, see Item 2. "Properties" and Note 12
of the Notes to Consolidated Financial Statements.

      FUEL  SUPPLY.   The  following table details the  sources  of  the
electricity sold by the Company during 1995 and expected sources for the
following three years:


                            Actual     /------------ Expected ------------/
                             1995           1996       1997       1998
                                                 
Fossil, primarily coal        51%            57%        62%        62%
Nuclear                       23             25         26         22
Purchases                     26             18         12         16
                             100%           100%       100%       100%


      The  Company is currently on an eighteen-month cycle  for  nuclear
refueling  outages and the above percentages assume outages  will  occur
during  both 1996 and 1998.  There was also a refueling outage in  1995.
The increase in the expected fossil percentages from the 1995 actual  is
primarily  a  function of lower projected fuel costs for  1996-1998  and
anticipated increases in the availability and efficiency of  its  fossil
generating  stations  due to improvements made at  certain  stations  in
recent years.

     The Company's primary fuel source is coal and the generation mix is
influenced directly by refueling outages at the DAEC.  The average  cost
of  fuel  used for generation by the Company for the years 1995-1993  is
presented below:

                                    1995       1994       1993
                                                   
Average cost of fuel:                              
                                                   
    Nuclear, per million Btu's     $ .76      $ .67      $ .60
    Coal, per million Btu's          .97        .97        .97
    Average for all fuels, 
      per million Btu's              .95        .89        .90


     The increases in the average cost of nuclear fuel are the result of
compounded  interest charges on uranium acquired during the  mid-1980's.
The  Company  expects to use the last of this uranium  during  the  1996
refueling outage.  The Company has entered into an new contract to  meet
its nuclear fuel needs beyond 1996 and the average cost of such fuel  is
expected to be significantly lower than that under the current contract.

     The following table summarizes the Company's  minimum coal contract
commitments at December 31, 1995:


                  Average                      
                   Annual                         Maximum estimated base price
                  Quantity  Termination  Sulfur     per ton of coal delivered
                   (Tons)       Date     Content     1996      1997      1998
Cordero                                                               
  Mining Co.
    (OGS) (1)      774,450    12/31/01     0.6%   $  18.32  $  18.86  $  19.40
                                                                      
Koch Carbon Inc.                                                          
  (Sutherland)     100,000    12/31/99     6.2%   $  19.51  $  19.77  $  20.07
                                                                      
Powder River                                                       
  Coal Co.   
    (OGS or 
     BGS) (2)    1,200,000    12/31/97     0.4%   $  15.57  $  16.04  $   N/A
                                                                    
Thunder Basin                                                       
  (Sutherland)     320,000    12/31/96     0.3%   $  13.95  $   N/A   $   N/A
                                                                    
Caballo Rojo                                                        
  (BGS) (3)        200,000    12/31/96     0.3%   $  15.18  $   N/A   $   N/A
                                                                    
Caballo Rojo                                                        
  (Prairie Creek or
   Sixth Street)
   (3)             640,000    12/31/96     0.3%   $  16.56  $   N/A   $   N/A
                                                                      
Franklin Coal                                                       
  Sales Co. 
    (OGS)          262,500     9/30/97     0.5%   $  12.60  $  12.68  $   N/A


    (1)   Cost  under the contract is comprised of  base  contract
          prices  plus specifically contracted periodic adjustments  for
          increases  in  certain specific costs of producing  the  coal.
          The effect of such adjustments to the base contract prices  of
          future coal cannot currently be predicted with any certainty.

    (2)   The  contract covers 1,200,000 annual tons delivered  to
          either  the  OGS  or the Burlington Generating Station  (BGS).
          The  prices  listed in the table are for BGS.  The OGS  prices
          are $12.80 and $13.19 per ton for 1996 and 1997, respectively.
          The Company anticipates that approximately 65 to 70 percent of
          the  total  1,200,000  annual tons will be  delivered  to  OGS
          during 1996 and 1997.

    (3)   The contract contains an option for a 1 year extension.


      During  1995, the Company purchased a total of 3,728,000  tons  of
coal for its generating plants.  At December 31, 1995, the Company had a
weighted  average of 63 days' usage of coal inventory at  its  principal
generating stations.

     The Company estimates that its existing coal fired generating units
will require approximately 13,531,000 tons of coal to operate during the
period 1996-1998.  The average annual quantities listed in the preceding
table  represent  the  Company's  minimum  commitments.   Many  of   the
contracts contain provisions allowing the Company to purchase additional
tons  of  coal.   The  Company estimates that it has the  capability  to
purchase  over  70%  of  its  1996-1998 coal  requirements  under  these
contracts  and will meet the remainder of its requirements  from  either
future  contracts or purchases in the spot market.  The Company believes
that an ample supply of coal is available in the spot market to meet its
needs.

     Some of the Company's contracted coal supply is provided by surface
mining  operations which are regulated by the Federal  Strip  Mine  Act.
Most  of  the surface mining coal contracts contain clauses  which  pass
reclamation  and royalty costs through to the respective  utility;  such
costs   billed  to  the  Company  are  recoverable  through  its  Energy
Adjustment  Clauses (EAC).  See Note 1(j) of the Notes  to  Consolidated
Financial Statements for discussion of the EAC.

      A  purchase  of uranium in the form of UF6 was made in  1995  from
NUKEM which completes the Company's requirements for the 1996 refueling.
A  new  six  year contract for enrichment services and enriched  uranium
product  was  negotiated  with the United States Enrichment  Corporation
(USEC)  which  will reduce the Company's enrichment and  uranium  costs.
Fabrication  of the nuclear fuel is being performed by General  Electric
Company  for  fuel through the 2008 refueling of the DAEC.  The  Company
believes that an ample supply of uranium and enrichment services will be
available  in  the  future  and intends to  purchase  such  uranium  and
enrichment  services as necessary on the spot market and/or  via  medium
length  (less  than  five  years) contracts to  supplement  its  current
contracts and meet its generation requirements.  See Note 11(f)  of  the
Notes  to  Consolidated Financial Statements for  a  discussion  of  the
Company's  assessment under the National Energy Policy Act of  1992  for
the "Uranium Enrichment Decontamination and Decommissioning Fund," which
is based upon prior nuclear fuel purchases.

      Refer  to  Item  1. "Environmental Matters" for  a  discussion  of
nuclear waste disposal issues.

      NUCLEAR REGULATORY COMMISSION (NRC) AND OTHER NUCLEAR MATTERS.  As
an  owner and the operator of a nuclear generating unit at the DAEC, the
Company  is subject to the jurisdiction of the NRC.  The NRC  has  broad
supervisory  and  regulatory  jurisdiction  over  the  construction  and
operation  of  nuclear  reactors, particularly  with  regard  to  public
health,  safety and environmental considerations.  The Company's current
NRC license for DAEC expires in 2014.

      The operation and design of nuclear power plants is under constant
review  by  the  NRC.  The Company has complied with  and  is  currently
complying with all NRC requests for data relating to these reviews.  The
NRC  also  continues  to review and reduce the backlog  of  general  and
unresolved  safety issues. As a result of such reviews, further  changes
in operations or modifications of equipment may be required, the cost of
which cannot currently be estimated.  The Company's anticipated nuclear-
related construction expenditures for 1996-2000 are $41 million.

     The DAEC received the highest ratings in its 20-year history in the
NRC's recent Systematic Assessment of Licensee Performance (SALP) report
by  earning  the highest score possible (1 on a 3-point  scale)  in  the
areas  of  plant operations, engineering and plant support and a  "good"
rating (2) in the area of maintenance.

      The  Company  conducted an inspection during  the  1995  refueling
outage  of  the  DAEC reactor core internals.  This was in  response  to
cracking identified in similar reactors.  No cracks were identified  and
no  related repairs were required.  The Company continues its efforts to
monitor and maintain the reactor core internals.

      The  large amount of change in regulations, designs and procedures
that  occur  for a nuclear power plant over a period of time presents  a
difficult task to ensure that all affected design information documents,
procedures and specifications are continually updated.  The Company  has
essentially completed a Configuration Management Plan and a Design Basis
Program  which  is  designed to coordinate control of the  updating  and
maintenance  of  plant documents to ensure regulatory  requirements  are
met.   No additional significant expenditures are currently expected  in
1996 or thereafter.

      Under  the Price-Anderson Amendments Act of 1988 (1988  Act),  the
Company  currently has the benefit of $8.9 billion of  public  liability
coverage  which would compensate the public in the event of an  accident
at a commercial nuclear power plant.  The 1988 Act permits such coverage
to  rise  with  increased  availability of  nuclear  insurance  and  the
changing  number  of  operating nuclear plants  subject  to  retroactive
premium  assessments.   The  1988 Act provides  for  inflation  indexing
(Consumer  Price  Index  every fifth year) of  the  retroactive  premium
assessments.

      As an outgrowth of the Three Mile Island Nuclear Power Plant (TMI)
experience, nuclear plant owners have initiated a cooperative  insurance
program   designed  to  help  cover  replacement  power   expenses   for
participating utilities arising from a possible nuclear plant  accident.
The Company is a participant in this program.  This type of insurance is
an  industry response intended to lessen the cost burden on customers in
the event of a lengthy plant shutdown.

      To  provide  this  coverage, a nuclear  utility  mutual  insurance
company  known as Nuclear Electric Insurance Limited (NEIL) was  formed.
Under the Company's policy, following a 21 week waiting period from  the
time  of  an  accident, coverage of up to 100% of estimated  replacement
power costs for an ensuing one year period is provided and up to 80%  of
that  amount will be provided for a second and third year.   The  annual
premium  cost to the Company is estimated to be less than  the  cost  of
replacement power for one week.

      The  Company currently carries primary property insurance coverage
on  the DAEC facility of $500 million with Nuclear Mutual Limited (NML).
Following  the TMI incident, it became apparent to nuclear plant  owners
that  the  commercially  available  property  insurance  was  inadequate
considering  the  cost  of  decontamination. Consequently,  the  Company
obtained  excess property insurance through NEIL.  NEIL excess insurance
provides an additional $1.4 billion of coverage after losses exceed $500
million.    These  policies  bring  the  total  property   coverage   to
$1.9 billion.

      For information concerning the potential assessment of retroactive
premiums  relating to the above described public liability,  replacement
power  and excess property insurance coverages, refer to Note  11(e)  of
the  Notes  to  Consolidated Financial Statements.  The NRC  established
requirements with respect to guaranteeing the ability of owners to  make
such  retroactive  payments  on the public  liability  policy.   Of  the
various  alternatives available, the Company elected to submit certified
financial  statements  showing  that  sufficient  cash  flow  could   be
generated and would be available for payment of the required assessments
within  a  three  month period.  The maximum of the  annual  retroactive
premiums was approximately $7 million at December 31, 1995.

      Refer  to  Item  1. "Environmental Matters" for  a  discussion  of
nuclear waste disposal issues.

        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  which  could  be  rendered
otherwise 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,  including mandated  open  access  to  the  electric
transmission  system.   In  March 1995, the  FERC  issued  a  Notice  of
Proposed   Rulemaking  pursuant  to  which  FERC  proposes  to   promote
competition  in  the  electric utility industry by requiring  that  each
transmission owning utility must 1) implement non-discriminatory tariffs
allowing  open  access  to  that utility's  transmission  facilities  by
wholesale  buyers  and sellers of electricity and 2) charge  itself  the
same  price for transmission and ancillary services as it charges  third
parties under the tariffs.  The Company filed conforming pro-forma  open
access transmission tariffs with the FERC on July 24, 1995.  The tariffs
were  accepted by the FERC and became effective October  1,  1995.   The
geographic  position of the Company's transmission system could  provide
revenue  opportunities in the open access environment.  FERC's  proposal
would  allow  for  recovery  of  certain  wholesale  stranded  costs  in
connection with wholesale transmission.  The Company cannot predict  the
final regulations that may be adopted.

      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.  The IUB
is  expected  to  release a status report on the inquiry  in  the  first
quarter  of  1996.   The  IUB  has not yet taken  a  position  on  these
competitive issues.

      The Company 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  the  Company's
operations  become no longer subject to the provisions  of  SFAS  71,  a
write-down  of related regulatory assets would be required, unless  some
form  of  transition  cost recovery is established  by  the  appropriate
regulatory  body.   The  Company  believes  that  it  still  meets   the
requirements  of  SFAS  71.   Refer  to  Note  1(c)  of  the  Notes   to
Consolidated Financial Statements for a further discussion.

      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.   In
1995, the Company initiated a program called Process Redesign to examine
all  of  the  major  business processes of the Company.   The  goals  of
Process  Redesign include improving customer service and commitment  and
significantly  reducing the Company's cost structure. In  1995,  Process
Redesign  identified many of the changes that the Company should  pursue
and   the   Company  has  begun  implementing  many  of  those  actions.
Implementation will be substantially completed in 1996.

      GAS  OPERATIONS.  With the advent of FERC Order 636  (Order  636),
issued  in  1992, the nature of the Company's gas supply  portfolio  has
changed.   Order  636,  among  other things, eliminated  the  interstate
pipelines' obligation to serve and now requires the Company to  purchase
virtually   100%  of  its  gas  supply  requirements  from  non-pipeline
suppliers.  The Company has enhanced access to competitively priced  gas
supply  and more flexible transportation services as a result  of  Order
636.   However, under Order 636, the Company is required to pay  certain
transition costs incurred and billed by its pipeline suppliers.

      The  Company  began paying the transition costs  in  1993  and  at
December  31, 1995, has recorded a liability of $5.0 million  for  those
transition  costs that have been incurred, but not yet  billed,  by  the
pipelines to date, including $1.9 million expected to be billed  through
1996.  The Company 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  the  Company   could
approximate $7.0 million.  The ultimate level of costs to be  billed  to
the  Company depends on the pipelines' future filings with the FERC  and
other  future  events,  including  the  market  price  of  natural  gas.
However,  the Company believes any transition costs that the FERC  would
allow the pipelines to collect from the Company 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.

      Contracts with the pipelines subsequent to Order 636 are comprised
primarily  of  firm transportation, firm storage and no-notice  service.
Firm  transportation contracts grant the Company access to firm pipeline
capacity  which  is  used  to transport gas supplies  from  non-pipeline
suppliers  on  peak  day.  Firm storage service allows  the  Company  to
purchase  gas during off-peak periods and place this gas in  an  account
with the pipelines.  When the gas is needed for peak day deliveries, the
Company requests and the pipelines deliver the gas back on a firm basis.
No-notice service grants the Company the right to take more or less  gas
than  is  actually scheduled up to the level of no-notice service.   No-
notice  service  takes the form of transportation balancing  or  storage
service depending on the pipeline.

     The Company's portfolio of firm transportation, firm storage and no-
notice service from pipelines is as follows:

                                     Firm           Firm            
                                Transportation     Storage      No-Notice
                                                     
   Northern:                                       
     Volume (Dekatherm/day)        142,996        48,218        10,000
     Expiration date              10/31/97       10/31/97      10/31/97

   Natural:   
     Volume (Dekatherm/day)         28,605         35,010          -
     Expiration date              11/30/2000      11/30/98         -

   ANR:                                            
     Volume (Dekatherm/day)         60,737         19,180        5,000
     Expiration date              10/31/2003     10/31/2003   10/31/2003


      In  addition  to  firm storage with pipelines,  the  Company  also
contracts  for  firm storage from Llano, Inc.  This contract  calls  for
peak  day  deliveries of 18,667 Dekatherm(Dth)/day and expires  May  31,
1997.

      Gas  supply is purchased from a variety of non-pipeline  suppliers
located  in the United States and Canada having access to virtually  all
major  natural gas producing regions.  For the calendar year  1995,  the
Company's  maximum daily load occurred on January 4,  1995,  with  total
system  flow  of approximately 270,000 dekatherms, including transported
volumes,  and  total  contract  availability  of  approximately  276,000
dekatherms.

      As  a  result  of  Order 636, the Company accepted  assignment  of
certain  gas  supply  contracts previously held by Northern.   Accepting
assignment  of  these contracts resulted in lower costs to  the  Company
than would have been incurred had Northern bought out the agreements and
billed the Company for its share of such costs.

      Contracts  assigned  to  the Company from  Northern  have  maximum
delivery  requirements of 13,631 Dth, and minimum take  requirements  of
2,726  Dth.   Additional firm gas supply agreements  were  independently
negotiated  by  the Company with various non-pipeline suppliers.   These
gas  supply agreements have maximum and minimum obligations and will  be
delivered through gas transmission pipelines as follows:


                               Maximum          Minimum 
                           Daily Quantity   Daily Quantity
                             (Dth/day)        (Dth/day)
                                          
               Northern       56,681           37,939
               Natural        24,575           19,575
               ANR            28,000           20,000


      These gas supply contracts have expiration dates ranging from five
months to six years.

      Rates charged by the Company's suppliers are subject to regulation
by the FERC.  A purchased gas adjustment clause (PGA) allows the Company
to  adjust  customer rates as a result of changes in  the  cost  of  gas
purchased.   See  Note  1(j)  of  the Notes  to  Consolidated  Financial
Statements for discussion of the PGA.


<TABLE>

                                   ELECTRIC OPERATING COMPARISON
<CAPTION>                                                                                                    FIVE-YEAR
                                                                                                              COMPOUND
                                                                                                               RATE OF
                                     1995         1994         1993         1992         1991         1990     GROWTH (1)
<S>                            <C>          <C>          <C>          <C>          <C>          <C>         <C>
Operating revenue (000's):
  Residential and rural           $ 216,270    $ 199,587    $ 203,870    $ 176,811    $ 188,504    $ 184,662
  General service                    97,496       97,454       99,221       87,202       86,744       83,634
  Large general service             199,840      191,601      184,657      140,496      138,213      134,000
  Street lighting                     8,810        8,521        8,404        7,241        7,118        7,180
    Total from ultimate consumers   522,416      497,163      496,152      411,750      420,579      409,476
  Sales for resale                   17,554       19,195       20,254       18,602       19,745       19,582
  Off-system                         17,802       18,077       29,400       28,304       36,596       31,144
  Other                               2,699        2,892        4,715        4,343        5,658        3,047
                                  $ 560,471    $ 537,327    $ 550,521    $ 462,999    $ 482,578    $ 463,249

Energy sales (000's Kwh):
  Residential and rural           2,680,340    2,484,089    2,518,580    2,146,079    2,362,847    2,248,126        3.6%
  General service                 1,242,373    1,170,923    1,166,072    1,061,444    1,069,956    1,031,167        3.8%
  Large general service           5,283,694    4,990,890    4,581,590    3,320,439    3,174,972    2,981,890       12.1%
  Street lighting                    77,388       77,952       78,004       75,957       79,254       80,276       -0.7%
    Total to ultimate consumers   9,283,795    8,723,854    8,344,246    6,603,919    6,687,029    6,341,459        7.9%
  Sales for resale                  499,719      567,721      561,276      528,752      557,180      538,677       -1.5%
    Sales of electricity to 
      customers                   9,783,514    9,291,575    8,905,522    7,132,671    7,244,209    6,880,136        7.3%
  Off-system                      1,086,121    1,137,219    2,068,015    2,275,616    2,738,159    2,282,204      -13.8%
                                 10,869,635   10,428,794   10,973,537    9,408,287    9,982,368    9,162,340        3.5%

Sources of electric energy (000's Kwh):
  Generation:
    Fossil, primarily coal        5,775,002    5,522,966    5,356,930    4,317,154    4,758,720    4,354,697
    Nuclear  (2)                  2,610,979    2,875,867    2,264,507    2,402,501    2,902,768    2,108,100
    Hydro                             7,690        8,205        7,201        7,579        6,547        4,195
                                  8,393,671    8,407,038    7,628,638    6,727,234    7,668,035    6,466,992
    Purchases                     3,012,934    2,646,673    3,949,296    3,322,182    2,994,216    3,282,886
                                 11,406,605   11,053,711   11,577,934   10,049,416   10,662,251    9,749,878

Net capability at time of peak load (Kw):
    Generating capability         1,873,300    1,741,100    1,733,700    1,718,600    1,719,150    1,684,700
    Purchase capability             207,100      280,000      248,000      207,000      227,000      179,000
    Capacity credits (3)                  0            0            0            0            0       18,960
                                  2,080,400    2,021,100    1,981,700    1,925,600    1,946,150    1,882,660        2.0%

    Net peak load (Kw) (4)        1,824,100    1,779,627    1,716,380    1,425,441    1,607,606    1,547,826        3.3%


Number of customers at year-end     333,489      330,405      327,265      325,172      305,663      304,265        1.7%

Revenue per Kwh (excluding
  off-system) in cents                 5.55         5.59         5.85         6.09         6.16         6.28       -2.4%



(1)  The five-year compound growth rates include the effect of the acquisition
     of the Iowa service territory from Union Electric Company on 
     December 31, 1992.
(2)  Represents IES Utilities' 70% undivided interest in the Duane Arnold 
     Energy Center,  which is operated by IES Utilities Inc.
(3)  Represents capacity credits from municipals served by IES Utilities Inc.
(4)  60 minutes integrated.
</TABLE>

<TABLE>

                                                     GAS OPERATING COMPARISON
<CAPTION>
                                                                                                                    Five-year
                                                                                                                     compound
                                                                                                                     rate of
                                              1995        1994       1993         1992         1991         1990     growth
<S>                                     <C>         <C>         <C>         <C>         <C>          <C>           <C>

Operating revenue (000's):
  Residential                             $  84,562   $  82,795   $  90,462   $  78,685    $  74,114    $  66,513
  Commercial                                 40,390      40,912      45,528      39,780       37,613       35,378
  Industrial                                  8,790      12,515      15,593      18,649       17,383       21,500
                                            133,742     136,222     151,583     137,114      129,110      123,391
  Other                                       3,550       2,811       2,735       2,341        1,908        1,884
                                          $ 137,292   $ 139,033   $ 154,318   $ 139,455    $ 131,018    $ 125,275




Energy sales (000's dekatherms):
  Residential                                16,302      15,766      16,971      15,098       15,571       14,315          2.6%
  Commercial                                  9,534       9,298      10,133       8,479        9,389        8,798          1.6%
  Industrial                                  3,098       4,010       4,618       6,175        5,980        6,640        -14.1%
                                             28,934      29,074      31,722      29,752       30,940       29,753         -0.6%
  Industrial - transported volumes           10,871       8,901       7,284       7,283        6,189        6,733         10.1%
    Total volumes delivered                  39,805      37,975      39,006      37,035       37,129       36,486          1.8%




Operating statistics:
  Cost per dekatherm of gas
    purchased for resale                  $    3.13   $    3.31   $    3.49   $    3.36    $    3.10    $    3.23

  Peak daily sendout in dekatherms          269,545     288,352     268,419     254,989      266,344      272,089         -0.2%



Number of customers at year-end             174,470     172,829     170,719     167,813      164,078      161,794          1.5%


Revenue per dekatherm sold
  (excluding transported volumes)              4.62        4.69        4.78        4.61         4.17         4.15          2.2%
</TABLE>

Item 2. Properties

      The  Company's  principal electric generating stations at December
31, 1995, are as follows:

     Name and Location               Major Fuel       Net Kilowatts Accredited
        of Station                      Type           Generating Capability
                                                                       
Duane Arnold Energy Center, 
  Palo, Iowa                          Nuclear                      364,000 (1)
                                                                       
Ottumwa Generating Station, 
  Ottumwa, Iowa                       Coal            343,440 (2)          
Prairie Creek Station, 
  Cedar Rapids, Iowa                  Coal            212,500               
Sutherland Station, 
  Marshalltown, Iowa                  Coal            143,000               
Sixth Street Station, 
  Cedar Rapids, Iowa                  Coal             71,000                
Burlington Generating Station, 
  Burlington, Iowa                    Coal            211,800               
George Neal Unit 3, 
  Sioux City, Iowa                    Coal            144,200 (3)          
    Total Coal                                                   1,125,940   
                                                     
Peaking Turbines, 
  Marshalltown, Iowa                  Oil             162,500               
Centerville Combustion Turbines, 
  Centerville, Iowa                   Oil              48,000                
  Diesel Stations, all in Iowa        Oil              12,200                
    Total Oil                                                      222,700
                                                                       
Grinnell Station, 
  Grinnell, Iowa                      Gas              47,200                
Agency Street Combustion Turbines,
  West Burlington, Iowa               Gas              63,750                
Burlington Combustion Turbines,
  Burlington, Iowa                    Gas              47,400                
    Total Gas                                                      158,350
                                                                       
  Total generating capability                                    1,870,990


     (1)  Represents  the  Company's  70%  ownership  interest  in  this
          520,000 Kw generating station.  The plant is operated  by  the
          Company.
     
     (2)  Represents  the  Company's  48%  ownership  interest  in  this
          715,500 Kw generating station.  The plant is operated  by  the
          Company.
          
     (3)  Represents  the  Company's  28%  ownership  interest  in  this
          515,000  Kw  generating  station  which  is  operated  by   an
          unaffiliated utility.
     

      At  December  31,  1995, the transmission lines  of  the  Company,
operating from 34,000 to 345,000 volts, approximated 4,409 circuit miles
(all  located in Iowa).  The Company owned 108 transmission  substations
(all located in Iowa) with a total installed capacity of 8,597.1 MVa and
468  distribution  substations  (all  located  in  Iowa)  with  a  total
installed capacity of 2,593.1 MVa.

      The Company's principal properties are suitable for their intended
use.   The  Company's principal properties are held subject to liens  of
indentures relating to its Bonds.

Item 3.  Legal Proceedings

      Reference  is made to Notes 3 and 11 of the Notes to  Consolidated
Financial  Statements for a discussion of the Company's rate proceedings
and  environmental matters, respectively.  Also see Item 1. "Business  -
Environmental  Matters"  and  Item  7.   "Management's  Discussion   and
Analysis of the Results of Operations and Financial Condition."

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

     None.


                                 PART II

Item   5.    Market  for  the  Registrant's  Common  Stock  and  Related
             Stockholder Matters

      All  outstanding common stock of the Company is held by its parent
(Industries) and is not traded.

     The dividends declared for the last two years are as follows:

                 Quarter
                                                 Dividends Declared
                                                      (000's)     
                  1995                                        
                              First Quarter       $   13,000
                              Second Quarter          10,000
                              Third Quarter           10,000
                              Fourth Quarter          10,000
                                                  $   43,000
                                              
                  1994                          
                              First Quarter       $    7,000
                              Second Quarter          15,000
                              Third Quarter           15,000
                              Fourth Quarter          15,000
                                                  $   52,000


      The  Company  has  the right under the terms of  the  Subordinated
Deferrable Interest Debentures, so long as an Event of Default  has  not
occurred and is not continuing, to extend the interest payment period at
any  time  and from time to time on the Subordinated Deferrable Interest
Debentures  to a period not exceeding 20 consecutive quarters.   If  the
Company  exercises its right to extend the interest payment period,  the
Company  may  not,  during  any such extended interest  payment  period,
declare or pay dividends on, or redeem, purchase or acquire, or make any
liquidation  payment with respect to, any of its capital stock  or  make
any  guarantee payment with respect to the foregoing.  The Company  does
not intend to exercise its right to extend the interest payment period.

Item 6.  Selected Consolidated Financial Data

      The following selected consolidated financial data, in the opinion
of  the Company, includes adjustments, which are normal and recurring in
nature, necessary for the fair presentation of the results of operations
and  financial  position.   See  Item 7.  "Management's  Discussion  and
Analysis  of  the Results of Operations and Financial Condition"  for  a
discussion  of transactions that affect the comparability of  the  years
1995-1993.

      The  1995  results were affected by the impact of  the  IUB  price
reduction  order  in  the  Company's  recent  electric  rate  case   and
significantly  warmer  than  normal  weather.   The  1993  results  were
affected  by  the acquisition of the Iowa service territory  from  Union
Electric Company on December 31, 1992.

      The  Selected  Consolidated  Financial  Data  should  be  read  in
conjunction  with the Consolidated Financial Statements,  the  Notes  to
Consolidated  Financial  Statements  and  Management's  Discussion   and
Analysis  of the Results of Operations and Financial Condition contained
elsewhere in this report.


<TABLE>
                                        SELECTED CONSOLIDATED FINANCIAL DATA
<CAPTION>

                                                           Year Ended December 31
                                                1995         1994         1993         1992         1991
                                                              ($ in thousands)

<S>                                     <C>          <C>          <C>          <C>          <C>        
Operating revenues                        $   709,826  $   685,366  $   713,750  $   610,262  $   621,993

Operating income                              142,265      135,591      143,329      100,361      101,600

Net income                                     59,278       61,210       67,970       45,291       47,563

Net income available for common stock          58,364       60,296       67,056       43,562       45,393

Cash dividends declared on common stock        43,000       52,000       31,300       24,721       45,321

Total assets                                1,708,635    1,645,368    1,546,978    1,440,891    1,304,110

Long-term obligations                         519,991      532,927      535,101      492,149      446,499

Times interest earned before income taxes        3.26         3.39         3.64         2.67         2.93

Capitalization ratios:
   Common equity                                   51%          50%          50%          48%          49%
   Preferred and preference stock                   2            2            2            2            4
   Long-term debt                                  47           48           48           50           47
                                                  100%         100%         100%         100%         100%
</TABLE>

Item 7.


                  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'  only   wholly-owned
subsidiary at December 31, 1995 was IES Ventures Inc.

                      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 (the Proposed  Merger).   The  new
holding  company will be named Interstate Energy Corporation (Interstate
Energy) and Industries will cease to exist.  The Proposed Merger,  which
will  be  accounted for as a pooling of interests, has been approved  by
the respective Boards of Directors.  It is still subject to approval  by
the  shareholders of each company as well as several federal  and  state
regulatory  agencies.  The companies expect to receive  the  shareholder
approvals in the second quarter of 1996 and the regulatory approvals  by
the second quarter of 1997.

       The  business  of  Interstate  Energy  will  consist  of  utility
operations and various non-utility enterprises, and it is expected  that
its utility subsidiaries will serve more than 870,000 electric customers
and  360,000  natural  gas  customers in Iowa, Illinois,  Minnesota  and
Wisconsin.

      The operating revenues, net income from continuing operations  and
total assets of the companies were as follows:
                                                                    PRO FORMA
                                    IES                             COMBINED
                                 INDUSTRIES     WPLH       IPC     (Unaudited)
                                                (in thousands)
                                                                
1995 operating revenues     $   851,010  $   807,255  $   318,542  $ 1,976,807
                                                               
1995 net income from 
  continuing operations          64,176       71,618       25,198      160,992
                                                                
Assets at December 31, 1995   1,985,591    1,872,414      634,316    4,492,321


      Under the terms of the Merger Agreement, the outstanding shares of
WPLH's  common stock will remain unchanged and outstanding as shares  of
Interstate  Energy.   Each outstanding share of the  Industries'  common
stock  will  be  converted to .98 shares of Interstate  Energy's  common
stock.   Each  share  of IPC's common stock will be converted   to  1.11
shares  of  Interstate Energy's common stock.  It  is  anticipated  that
Interstate Energy will retain WPLH's common share dividend payment level
as  of the effective time of the merger.  On January 24, 1996, the Board
of  Directors of WPLH declared a quarterly dividend of 49.25  cents  per
share.   This represents an equivalent annual rate of $1.97  per  share.
Under  provisions of the Merger Agreement, Industries'  annual  dividend
payment cannot exceed $2.10 per share, the current annual payment level,
pending the Proposed Merger.

      Interstate  Energy  will  be  the  parent  company  of  Utilities,
Wisconsin  Power and Light Company and IPC and will be registered  under
the  Public Utility Holding Company Act of 1935, as amended (1935  Act).
The  Merger  Agreement provides  that these operating utility  companies
will  continue  to operate as separate entities for a minimum  of  three
years  beyond the effective date of the merger.  In addition,  the  non-
utility operations of Industries and WPLH will be combined shortly after
the  effective  date  of  the merger under  one  entity  to  manage  the
diversified operations of Interstate Energy.

      The  SEC  historically has interpreted the 1935  Act  to  preclude
registered holding companies, with limited exceptions, from owning  both
electric  and  gas  utility  systems.  Although  the  SEC  has  recently
recommended  that registered holding companies be allowed to  hold  both
gas  and  electric utility operations if the affected states  agree,  it
remains possible that the SEC may require as a condition to its approval
of  the  Proposed Merger that Industries, WPLH and IPC divest their  gas
utility  properties,  and  possibly  certain  non-utility  ventures   of
Industries  and WPLH, within a reasonable time after the effective  date
of the Proposed Merger.

      Legislation to repeal the 1935 Act was introduced in  Congress  in
1995  and is pending.  No assurance can be given as to when or  if  such
legislation  will be considered or enacted.  The Staff of  the  SEC  has
also  recommended that the SEC "permit combination systems by registered
holding  companies  if  the affected states concur,"  and  the  SEC  has
proposed  rules that would relax current restrictions on  investment  by
registered  holding  companies in certain "energy related,"  non-utility
businesses.   No  prediction can be made as  to  the  outcome  of  these
legislative and regulatory proposals.

      See Note 2 of the Notes to Consolidated Financial Statements for a
further discussion of the Proposed Merger.


                          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
($1.9)  million  and ($6.8) million during 1995 and 1994,  respectively.
The  1995  results reflect the impact of the Iowa Utilities Board  (IUB)
price  reduction  order in Utilities' recent electric  rate  case.   The
effect  of  the  lower electric prices, including the  required  refund,
reduced  the 1995 net income by approximately $9.7 million.   (See  Note
3(b)  of  the Notes to Consolidated Financial Statements for  a  further
discussion  of  the  electric rate case).  Warmer  than  normal  weather
conditions  during the summer months and an aggressive cost  containment
program  partially offset the negative effects of the  IUB  order.   The
1994  results  were affected by milder than normal weather, particularly
during  the  summer  months.   The 1993 results  reflect  fairly  normal
weather conditions in Utilities' service territory.

      The  Company's  operating  income increased  or  (decreased)  $6.7
million  and ($7.7) million during 1995 and 1994, respectively.  Reasons
for  the  changes  in  the results of operations are  explained  in  the
following discussion.

Electric  Revenues    Electric  revenues and  Kwh  sales  for  Utilities
increased or (decreased) as compared with the prior year as follows:

                                                    1995       1994
                                                    ($ in millions)
                                         
Total electric revenues                           $ 23.1    $ (13.2)
Change in off-system sales revenues                 (0.3)     (11.3)
Electric revenues (excluding off-system sales)    $ 23.4    $  (1.9)

Electric sales (excluding off-system sales): 
  Residential and Rural                              7.9%      (1.4%)
  General Service                                     6.1       0.4
  Large General Service                               5.9       8.9
Total                                                 5.3       4.3

      Warmer than normal weather during the summer of 1995 significantly
increased  sales.   Utilities  set  new  usage  records  several  times,
culminated by a new energy peak demand record of 1,824 megawatts on July
12,  1995.   The 1994 Kwh sales were adversely affected by  milder  than
normal  weather,  particularly during the summer  months.   The  largest
effect  of  weather  each  year was on sales to  residential  and  rural
customers.   Under historically normal weather conditions,  total  sales
(excluding  off-system sales) during 1995 and 1994 would have  increased
3.6% and 4.8%, respectively.  Sales during 1995 also benefited from  the
effects of Utilities' annual true-up adjustment to unbilled sales.   The
growth  in general service and large general service sales continues  to
reflect  the underlying strength of the economy as industrial expansions
in Utilities' service territory continued during 1995.

     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 to customers.  See Note 1(j) of  the
Notes to Consolidated Financial Statements for discussion of the EAC.

     The increase in the 1995 electric revenues was primarily due to the
increased   sales  (excluding  off-system  sales),  higher  fuel   costs
collected  through  the  EAC, the unbilled revenue  adjustment  and  the
recovery of expenditures for energy efficiency programs pursuant  to  an
IUB  order.  The effect of the warmer than normal weather increased 1995
electric  revenues  by  approximately  $9  million.   These  items  were
partially offset by a reduction in revenues of approximately $17 million
during   1995   as  the  result  of  the  IUB  price  reduction   order.
Approximately  $3.5 million of the price reduction decrease  related  to
revenues  collected in the fourth quarter of 1994.  See Notes  3(b)  and
3(c)  of  the Notes to Consolidated Financial Statements for  a  further
discussion  of  the  electric rate case and the energy  efficiency  cost
recovery case, respectively.

      The  decrease  in the 1994 electric revenues was  attributable  to
lower  fuel costs collected through the EAC, lower off-system  sales  to
other  utilities and the effect of the mix of sales between lower margin
industrial  customers and higher margin residential and rural customers.
Increased total 1994 sales (excluding off-system sales) partially offset
the effects of the above items.

Gas  Revenues   Gas revenues decreased ($1.7) and ($15.3) million during
1995  and  1994,  respectively. Utilities'  gas  sales  and  transported
volumes  in therms increased or (decreased) as compared with  the  prior
period as follows:

                           1995            1994
                                        
Residential                3.4%            (7.1%)
Commercial                 2.5             (8.2)
Industrial               (22.7)           (13.2)
                                  
Sales to consumers        (0.5)            (8.3)
                                  
Transported volumes       22.1             22.2
                                  
Total                      4.8             (2.7)
                                  


      Under historically normal weather conditions, Utilities' gas sales
and  transported volumes would have increased 3.5% and 0.7% in 1995  and
1994, respectively.

      Utilities'  gas  tariffs include purchased gas adjustment  clauses
(PGA) that are designed to currently recover the cost of gas sold.   See
Note  1(j)  of  the  Notes  to  Consolidated  Financial  Statements  for
discussion of the PGA.

      On  August  4,  1995, Utilities applied to the IUB for  an  annual
increase in gas rates of $8.8 million, or 6.2%.  An interim increase  of
$7.1  million  became  effective October 11, 1995,  subject  to  refund.
Utilities,  the  Office of Consumer Advocate and  all  three  industrial
intervenor  groups have entered into a settlement agreement, subject  to
IUB  approval,  which allows Utilities a $6.3 million  annual  increase.
Utilities expects that the IUB will rule on the settlement agreement  no
later than the second quarter of 1996.

      Utilities'  gas  revenues decreased in 1995 primarily  because  of
lower  gas costs recovered through the PGA, and was substantially offset
by  the  effects of the interim rate increase, recovery of  expenditures
for   the  energy  efficiency  programs  and  increased  revenues   from
transported gas volumes.  The 1994 revenue decrease was primarily due to
lower  gas costs recovered through the PGA and, to a lesser extent,  the
effect of the lower sales.

Other  Revenues   Other revenues increased $3.1 million and $0.1 million
during  1995  and 1994, respectively.  The 1995 increase  was  primarily
related to new industrial-use steam customers.

Operating Expenses   Fuel for production increased $10.3 million  during
1995  due  to  higher fuel cost recoveries through the  EAC,  which  are
included in fuel for production, and a higher average fuel cost.   Total
1995  Kwh generation at Utilities' generating stations was flat compared
to  1994.   The  Duane  Arnold Energy Center (DAEC), Utilities'  nuclear
generating  facility, generated less Kwhs in 1995 because  it  was  down
from  late  February  1995 to late April 1995 for a scheduled  refueling
outage.  There was no refueling outage in 1994.  Increased generation at
Utilities' fossil-fueled generating stations, due to the increased sales
and  the  DAEC  outage, virtually offset the decreased DAEC  generation.
Fuel for production decreased ($1.8) million in 1994 largely because  of
lower  average fuel prices and the effect of lower fuel cost  recoveries
through the EAC.  Generation at Utilities' generating stations increased
during  1994  primarily  because of increased sales  and  the  increased
availability of DAEC as there was a scheduled refueling outage  in  1993
also.

      Purchased  power decreased ($1.9) million and ($24.7)  million  in
1995  and  1994, respectively.  The 1995 decrease was primarily  due  to
lower  capacity  costs  of ($6.6) million, partially  offset  by  higher
energy purchases of $4.7 million due to the increased sales to customers
and  flat generation, as discussed above.  The 1994 decrease was  caused
by  lower  off-system sales to other utilities, increased generation  at
Utilities' generating stations and the expiration, in April 1993,  of  a
purchase power agreement with the City of Muscatine.

      Gas  purchased  for  resale decreased ($4.1) million  and  ($13.8)
million  during 1995 and 1994, respectively.  The decrease in  1995  was
primarily  due  to  lower natural gas prices, partially  offset  by  the
timing of the recovery of gas costs through the PGA.  Gas purchased  for
resale decreased in 1994 because of lower gas costs and lower gas sales.

      Other  operating expenses increased $13.0 million and $9.1 million
in  1995 and 1994, respectively. The 1995 increase was primarily related
to increased labor and benefit costs, costs associated with a project to
review   and   redesign   Utilities'  major  business   processes,   the
amortization  of  previously  deferred  energy  efficiency  expenditures
(which  are currently being recovered through rates) and costs  relating
to  the  Proposed  Merger.   These increases were  partially  offset  by
decreased  nuclear  operating  costs  and  lower  insurance  costs.   In
addition,  following  the  receipt of the  IUB  price  reduction  order,
Utilities  took  action  and  successfully reduced  1995  operating  and
maintenance  costs by about $8 million from budgeted levels.   The  1994
increase was also attributable to higher nuclear operating costs, former
manufactured  gas plant (FMGP) clean-up costs and increased  information
technology costs.

      Maintenance expenses increased or (decreased) ($6.0)  million  and
$3.3 million during 1995 and 1994, respectively.  The 1995 decrease  was
due  to  less  required  maintenance  activities  at  the  DAEC  and  at
Utilities'  fossil-fueled generating stations and the  cost  containment
actions  discussed  above.  The 1994 increase was primarily  because  of
increased  labor costs and maintenance at the DAEC, partially offset  by
lower maintenance at Utilities' fossil-fueled generating stations.

      Depreciation and amortization increased during both years  because
of  increases  in  utility  plant in service.   The  1995  increase  was
partially offset by lower depreciation rates implemented at Utilities as
a  result  of the IUB electric price reduction order.  Depreciation  and
amortization   expenses  for  all  periods  include  a   provision   for
decommissioning the DAEC, which is collected through rates.  The  annual
recovery  level was increased to $6.0 million in 1995 from $5.5 million,
as a result of Utilities' recent electric rate case.

      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 relative to 1995 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.  (See Note 1(g) of the Notes to Consolidated Financial
Statements  for  a  discussion of the recovery of decommissioning  costs
allowed in Utilities' most recent rate case).

       Taxes  other  than  income  taxes  increased  $2.5  million   and
$1.2  million  during 1995 and 1994, respectively,  largely  because  of
increased  property  taxes  caused by  increases  in  assessed  property
values.

Interest  Expense  and Other   Interest expense increased  $2.9  million
during  1995 primarily because of an increase in the average  amount  of
short-term debt outstanding and interest related to Utilities'  electric
rate  refund.  Lower average interest rates, attributable to refinancing
$100  million of long-term debt at lower rates and the mix of  long-term
and short-term debt, partially offset the increase.

     Miscellaneous, net reflected a decrease in income of ($2.1) million
during 1995 primarily because of an increase in fees related to the sale
of utility accounts receivable as the average amount of receivables sold
during the year increased.

      Federal and state income taxes increased $3.1 million in 1995  and
were  constant in 1994.  The increase for 1995 was due to 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.   In  addition, adjustments to tax reserves in  1995  and  1994
affected comparability of income taxes between the years.  A decrease in
income before taxes in 1994 was offset by a higher effective income  tax
rate.

                     LIQUIDITY AND CAPITAL RESOURCES

      The  Company's capital requirements are primarily attributable  to
its  construction  programs and debt maturities.  The  Company's  pretax
ratio  of  times interest earned was 3.26, 3.39 and 3.64  in  1995-1993,
respectively.   In  1995,  cash  flows from  operating  activities  were
$161  million  versus $195 million in 1994.  The decrease was  primarily
due  to  expenditures related to the effect of the 1995  DAEC  refueling
outage 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  11  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.  Utilities' debt  ratings
are as follows:


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


      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 11 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.  It is not certain if, and how, the Proposed Merger may  affect
the Company's debt ratings.

      The  IUB has current rules which 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 December 31, 1995, Utilities had
approximately  $50 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.

     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's levels of construction and acquisition expenditures
are  projected  to  be  $185  million in 1997,  $176  million  in  1998,
$161  million  in 1999 and $137 million in 2000.  It is  estimated  that
approximately  80%  of  these 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 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
$140  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  December  1995, Utilities issued $50 million  of  Subordinated
Deferrable Interest Debentures, 7-7/8%, due 2025.  The proceeds from the
issuance of the debentures were used to retire short-term borrowings which
were incurred in October 1995 to repay at maturity, $50 million of Series
X, 9.42%  First  Mortgage Bonds.

      In  March 1995, Utilities repaid at maturity $50 million of Series
W, 9.75% First Mortgage Bonds and, in a separate transaction, issued $50
million of Collateral Trust Bonds, 7.65%, due 2000.

      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
December  31,  1995, such restrictions would have allowed  Utilities  to
issue at least $258 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 Regulation
Commission  (FERC) and the SEC to issue up to $250 million of  long-term
debt, and has $150 million of remaining authority under the current FERC
docket  and  $200 million of remaining authority under the  current  SEC
shelf  registration.  Utilities expects to replace one series  of  First
Mortgage Bonds that mature in 1996 with other long-term securities.

      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 December  31,  1995,
Utilities  could have issued an additional 700,000 shares of  Cumulative
Preference  Stock and 100,000 additional shares of Cumulative  Preferred
Stock.

     The Company's capitalization ratios at year-end were as follows:

                               1995          1994
                                      
     Long-term debt             47%           48%
     Preferred stock             2             2
     Common equity              51            50
                               100%          100%


               The  1995  and 1994 ratios include $15 million  and
        $100  million, respectively, of long-term debt due in less
        than  one  year because it was the Company's intention  to
        refinance the debt with long-term securities.

     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.   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 December 31, 1995,  Utilities
had  outstanding  short-term  borrowings of  $109.9  million,  including
$8.9 million of notes payable to associated companies.

     Utilities has 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 December 31, 1995, Utilities had sold $58 million  under
the agreement.

      At  December  31,  1995,  the Company had  bank  lines  of  credit
aggregating  $121.1 million, of which $101 million  was  being  used  to
support  commercial paper (weighted average interest rate of 5.81%)  and
$11.1  million  was  being  used 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  December 31, 1995, there were no borrowings  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.   There  are
also  six  other sites for which it may be designated as a  PRP  in  the
future.   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
five  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 19 sites and expects to begin the investigation process in
1996  for the other  two sites.  Utilities estimates the range of  costs
to  be incurred for investigation and/or remediation of the sites to  be
approximately $22 million to $55 million.

      Utilities  has recorded environmental liabilities related  to  the
FMGP  sites  of  approximately $35 million (including  $4.6  million  as
current liabilities) at December 31, 1995.  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 or has  not  started.   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.  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.

      Utilities  has begun pursuing claims under its prior coverage  for
investigation, mitigation, prevention, remediation and monitoring  costs
from its insurance carriers and is investigating the potential for third
party  cost  sharing  for FMGP investigation and  clean-up  costs.   The
amount  of  shared costs, if any, can not be reasonably determined  and,
accordingly,    no    potential   sharing   has   been    recorded    at
December  31,  1995.   Regulatory assets of approximately  $35  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 Act of 1990 (Act) requires  emission
reductions  of  sulfur  dioxide 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 with  Phase  I
affecting  two  of  Utilities' units beginning  in  1995  and  Phase  II
affecting all units beginning in the year 2000.  Utilities has completed
the  modifications  necessary to meet the Phase I requirements  and  has
installed continuous emission monitors on all affected units as required
by  the Act.  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  sulfur  dioxide allowances.  Utilities  estimates  capital
expenditures at approximately $20 million, including $4 million in 1996,
in order to meet the acid rain requirements of the Act.

      The  acid  rain program under the Act also creates sulfur  dioxide
allowances.  An allowance is defined as an authorization for an owner to
emit  one  ton  of  sulfur  dioxide  into  the  atmosphere.   Currently,
Utilities receives a sufficient number of allowances annually to  offset
its  emissions  of  sulfur  dioxide from  its  Phase  I  units.   It  is
anticipated  that in the year 2000, when the Phase II units  participate
in  the allowance program, 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 year 2000 and thereafter.  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  also requires 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  nitrogen  oxides  (NOx),  ozone  transport  and  mercury.
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  methods, suggests that the Cedar Rapids  area  could  be
classified  as  "nonattainment" for the  National  Ambient  Air  Quality
Standard   (NAAQS)  established  for  sulfur  dioxide.   The  worst-case
modeling  study  suggests that two of Utilities'  generating  facilities
contribute  to  the modeled exceedences and recommends  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 reviewing  EPA's  assumptions  and
modeling  results and is proposing a strategy to voluntarily reduce  the
excessive  emissions  through  modification  of  its  facilities  at   a
potential capital cost of up to $10 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,
$10.9 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 DOE.  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  2002.   Utilities   is
aggressively reviewing options for additional spent nuclear fuel storage
capability,   including   expanding  on-site  storage   and   supporting
legislation currently before the U.S. Congress, to resolve the  lack  of
progress by the DOE.

      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
December   31,  1995,  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 is expected to be considered by the
member states in 1996.  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  intends to ship the waste it produces in the future as long as  the
Barnwell  site  remains open, thereby minimizing  the  amount  of  waste
stored on-site.

     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
considerable  amount of scientific research has been conducted  on  this
topic  without definitive results.  Research is continuing in  order  to
resolve scientific uncertainties.


                              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 which could be rendered otherwise 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,  including mandated  open  access  to  the  electric
transmission  system.   In  March 1995, the  FERC  issued  a  Notice  of
Proposed   Rulemaking  pursuant  to  which  FERC  proposes  to   promote
competition  in  the  electric utility industry by requiring  that  each
transmission owning utility must 1) implement non-discriminatory tariffs
allowing  open  access  to  that utility's  transmission  facilities  by
wholesale  buyers  and sellers of electricity and 2) charge  itself  the
same  price for transmission and ancillary services as it charges  third
parties  under  the tariffs.  Utilities filed conforming pro-forma  open
access transmission tariffs with the FERC on July 24, 1995.  The tariffs
were  accepted by the FERC and became effective October  1,  1995.   The
geographic  position  of Utilities' transmission  system  could  provide
revenue  opportunities in the open access environment.  FERC's  proposal
would  allow  for  recovery  of  certain  wholesale  stranded  costs  in
connection with wholesale transmission.  The Company cannot predict  the
final regulations that may be adopted.

      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.  The IUB
is  expected  to  release a status report on the inquiry  in  the  first
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, 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.   Refer  to  Note  1(c)  of  the  Notes  to  Consolidated  Financial
Statements for a further discussion.

      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.   In
1995, the Company initiated a program called Process Redesign to examine
all  of the major business processes of Utilities.  The goals of Process
Redesign   include  improving  customer  service  and   commitment   and
significantly  reducing  Utilities' cost  structure.  In  1995,  Process
Redesign identified many of the changes that Utilities should pursue and
Utilities  has begun implementing many of those actions.  Implementation
will be substantially completed in 1996.

Accounting  Pronouncements    SFAS 121, issued  in  March  1995  by  the
Financial  Accounting  Standards Board (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.   SFAS 121 is not expected to have an impact on the  financial
position or results of operations of the Company upon adoption.

Inflation  Under the rate making principles prescribed by the regulatory
commissions to which Utilities is subject, only the historical  cost  of
plant  is  recoverable  in  revenues  as  depreciation.   As  a  result,
Utilities  has  experienced economic losses equivalent  to  the  current
year's  impact  of  inflation  on  utility  plant.   In  addition,   the
regulatory process imposes a substantial time lag between the time  when
operating  and  capital costs are incurred and when they are  recovered.
Utilities does not expect the effects of inflation at current levels  to
have  a  significant  effect on its financial  position  or  results  of
operations.


       Selected Consolidated Quarterly Financial Data (unaudited)

     The following unaudited consolidated quarterly data, in the opinion
of  the Company, includes adjustments, which are normal and recurring in
nature, necessary for the fair presentation of the results of operations
and  financial  position.  The quarterly amounts were  affected  by  the
Company's  rate activities and seasonal weather conditions.   The  first
quarter  net  income in 1995 was significantly lower than  1994  as  the
Company  recorded  an  $8.0 million pre-tax reserve  for  electric  rate
refund in the first quarter of 1995.  Approximately $3.5 million of  the
reserve  related  to revenues collected in the fourth quarter  of  1994.
Milder  weather in 1995 also contributed to the decrease.  The Company's
rate  activities  are discussed in Note 3 of the Notes  to  Consolidated
Financial Statements.  Refer to Management's Discussion and Analysis for
a discussion of the impacts of weather.

                                                 Quarter Ended
                                 March        June      September    December
                                  31           30          30           31
                                                 (in thousands)
1995                                                            
  Operating revenues         $  172,839   $  157,671   $  200,448   $  178,868
  Operating income               19,896       30,444       61,360       30,565
  Net income                      6,161       11,067       29,842       12,208
  Net income available
    for common stock              5,932       10,838       29,613       11,981
                                                                  
1994                                                              
  Operating revenues         $  192,013   $  148,019   $  179,477   $  165,857
  Operating income               34,248       24,777       51,777       24,789
  Net income                     14,944        9,255       25,733       11,278
  Net income available
    for common stock             14,715        9,026       25,504       11,051


Item 8.  Financial Statements and Supplementary Data

     Information required by Item 8. begins on page 62.

                     REPORT OF MANAGEMENT
                               
      The Company's management has prepared and is responsible
for   the  presentation,  integrity  and  objectivity  of  the
consolidated  financial  statements  and  related  information
included   in   this   report.   The  consolidated   financial
statements  have  been prepared in conformity  with  generally
accepted  accounting principles applied on a consistent  basis
and,  in  some  cases, include estimates that are  based  upon
management's  judgment  and  the best  available  information,
giving due consideration to materiality. Financial information
contained elsewhere in this report is consistent with that  in
the consolidated financial statements.

      The  Company  maintains a system of internal  accounting
controls  which it believes is adequate to provide  reasonable
assurance  that  assets  are  safeguarded,  transactions   are
executed in accordance with management authorization  and  the
financial  records are reliable for preparing the consolidated
financial  statements.   The  system  of  internal  accounting
controls is supported by written policies and procedures, by a
staff  of  internal auditors and by the selection and training
of  qualified  personnel.  The internal audit  staff  conducts
comprehensive  audits  of  the Company's  system  of  internal
accounting  controls.   Management  strives  to  maintain   an
adequate  system  of internal controls, recognizing  that  the
cost  of such a system should not exceed the benefits derived.
In  accordance with generally accepted auditing standards, the
independent public accountants (Arthur Andersen LLP)  obtained
a  sufficient understanding of the Company's internal controls
to  plan  their  audit and determine the  nature,  timing  and
extent  of  other  tests to be performed.  Management  is  not
aware of any material internal control weaknesses.

      The  Board  of  Directors, through its  Audit  Committee
comprised  entirely  of outside directors, meets  periodically
with management, the internal auditor and Arthur Andersen  LLP
to  discuss financial reporting matters, internal control  and
auditing.   To  ensure their independence, both  the  internal
auditor  and Arthur Andersen LLP have full and free access  to
the Audit Committee.


            REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS



To the Board of Directors of
IES Utilities Inc.:

We  have  audited  the  accompanying  consolidated  balance  sheets  and
statements of capitalization of IES Utilities Inc. (an Iowa corporation)
and  subsidiary  companies as of December 31, 1995  and  1994,  and  the
related  consolidated statements of income, retained earnings  and  cash
flows for each of the three years in the period ended December 31, 1995.
These financial statements and the financial statement schedule referred
to  below  are  the  responsibility of the  Company's  management.   Our
responsibility  is  to express an opinion on these financial  statements
and schedule based on our audits.

We  conducted our audits in accordance with generally accepted  auditing
standards.  Those standards require that we plan and perform  the  audit
to  obtain  reasonable assurance about whether the financial  statements
are  free of material misstatement.  An audit includes examining,  on  a
test  basis,  evidence  supporting the amounts and  disclosures  in  the
financial  statements.  An audit also includes assessing the  accounting
principles used and significant estimates made by management, as well as
evaluating  the  overall financial statement presentation.   We  believe
that our audits provide a reasonable basis for our opinion.

In  our  opinion,  the financial statements referred  to  above  present
fairly,  in  all  material  respects,  the  financial  position  of  IES
Utilities  Inc.  and subsidiary companies as of December  31,  1995  and
1994, and the results of their operations and their cash flows for  each
of  the three years in the period ended December 31, 1995, in conformity
with generally accepted accounting principles.

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

As  discussed  in  Note  7  to  the consolidated  financial  statements,
effective  January 1, 1993, IES Utilities Inc. and subsidiary  companies
changed  their  method of accounting for postretirement  benefits  other
than pensions.


                        /s/   ARTHUR ANDERSEN LLP
                              ARTHUR ANDERSEN LLP

Chicago, Illinois,
February 2, 1996



CONSOLIDATED STATEMENTS OF INCOME
                                                 Year Ended December 31
                                           1995           1994           1993
                                                     (in thousands)

Operating revenues:
    Electric                           $ 560,471      $ 537,327      $ 550,521
    Gas                                  137,292        139,033        154,318
    Other                                 12,063          9,006          8,911
                                         709,826        685,366        713,750


Operating expenses:
    Fuel for production                   96,256         85,952         87,702
    Purchased power                       66,874         68,794         93,449
    Gas purchased for resale              91,198         95,340        109,122
    Other operating expenses             145,250        132,281        123,210
    Maintenance                           43,586         49,542         46,219
    Depreciation and amortization         79,384         75,316         69,407
    Taxes other than income taxes         45,013         42,550         41,312
                                         567,561        549,775        570,421


Operating income                         142,265        135,591        143,329


Interest expense and other:
   Interest expense                       44,460         41,572         40,169
   Allowance for funds used  
     during construction                  -3,424         -3,910         -1,972
   Miscellaneous, net                        856         -1,247           -801
                                          41,892         36,415         37,396


Income before income taxes               100,373         99,176        105,933


Federal and state income taxes            41,095         37,966         37,963


Net income                                59,278         61,210         67,970
Preferred dividend requirements              914            914            914
Net income available for common 
  stock                                $  58,364      $  60,296      $  67,056



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

CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
                                                 Year Ended December 31
                                           1995           1994           1993
                                                     (in thousands)

Balance at beginning of year           $ 197,158      $ 188,862      $ 153,106
Add:
     Net income                           59,278         61,210         67,970

Deduct:
     Cash dividends declared -
          Common stock                    43,000         52,000         31,300
          Preferred stock, at 
            stated rates                     914            914            914

Balance at end of year                 $ 212,522      $ 197,158      $ 188,862


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

CONSOLIDATED BALANCE SHEETS


                                                            December 31
ASSETS                                                 1995             1994
                                                           (in thousands)
Property, plant and equipment:
  Utility -
    Plant in service -
        Electric                                  $ 1,900,157      $ 1,798,059
        Gas                                           165,825          158,115
        Other                                         106,396           86,005
                                                    2,172,378        2,042,179
    Less - Accumulated depreciation                   950,324          880,888
                                                    1,222,054        1,161,291
    Leased nuclear fuel, net of amortization           36,935           49,731
    Construction work in progress                      52,772           73,339
                                                    1,311,761        1,284,361
  Other, net of accumulated depreciation and 
    amortization of $1,166,000 and $1,277,000, 
    respectively                                        5,477            2,686
                                                    1,317,238        1,287,047


Current assets:
  Cash and temporary cash investments                   2,734            2,135
  Accounts receivable -
    Customer, less reserve                             18,619           12,051
    Other                                               8,912            9,763
  Income tax refunds receivable                           846            3,450
  Production fuel, at average cost                     12,155           13,988
  Materials and supplies, at average cost              27,229           26,699
  Adjustment clause balances                                0            1,433
  Regulatory assets                                    22,791           20,145
  Prepayments and other                                18,556           19,630
                                                      111,842          109,294


Investments:
  Nuclear decommissioning trust funds                  47,028           33,779
  Cash surrender value of life insurance policies       3,582            2,915
  Other                                                   475              223
                                                       51,085           36,917


Other assets:
  Regulatory assets                                   207,202          192,955
  Deferred charges and other                           21,268           19,155
                                                      228,470          212,110
                                                  $ 1,708,635      $ 1,645,368



                                                            December 31
CAPITALIZATION AND LIABILITIES                         1995             1994
                                                           (in thousands)
Capitalization (See Consolidated Statements of Capitalization):
  Common stock                                    $    33,427      $    33,427
  Paid-in surplus                                     279,042          279,042
  Retained earnings                                   212,522          197,158
      Total common equity                             524,991          509,627
  Cumulative preferred stock                           18,320           18,320
  Long-term debt (excluding current portion)          465,463          380,404
                                                    1,008,774          908,351


Current liabilities:
  Notes payble to associated companies                  8,888           18,495
  Short-term borrowings                               101,000           37,000
  Capital lease obligations                            15,717           14,385
  Maturities and sinking funds                         15,140          100,140
  Accounts payable                                     64,564           70,354
  Accrued interest                                      8,038            9,438
  Accrued taxes                                        50,369           47,188
  Accumulated refueling outage provision                7,690           15,196
  Adjustment clause balances                            3,148                0
  Environmental liabilities                             5,521            5,428
  Other                                                17,300           18,324
                                                      297,375          335,948


Long-term liabilities:
  Pension and other benefit obiligations               41,866           36,826
  Capital lease obligations                            21,218           35,346
  Environmental liabilities                            40,905           37,853
  Other                                                 8,719            9,898
                                                      112,708          119,923


Deferred credits:
  Accumulated deferred income taxes                   252,663          241,345
  Accumulated deferred investment tax credits          37,115           39,801
                                                      289,778          281,146


Commitments and contingencies (Note 11)


                                                  $ 1,708,635      $ 1,645,368

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



CONSOLIDATED STATEMENTS OF CAPITALIZATION

                                                             December 31
                                                       1995              1994
                                                           (in thousands)

Common equity:
    Common stock - par value $2.50 per 
      share - authorized 24,000,000 shares; 
      outstanding 13,370,788 shares              $    33,427       $    33,427
    Paid-in surplus                                  279,042           279,042
    Retained earnings                                212,522           197,158
                                                     524,991           509,627



Cumulative preferred stock                            18,320            18,320


Long-term debt:
    Collateral Trust Bonds -
        7.65% series, due 2000                        50,000                 0
        6% series, due 2008                           50,000            50,000
        7% series, due 2023                           50,000            50,000
        5.5% series, due 2023                         19,400            19,400
                                                     169,400           119,400

     First Mortgage Bonds-
       Series J, 6-1/4%, due 1996                     15,000            15,000
       Series L, 7-7/8%, due 2000                     15,000            15,000
       Series M, 7-5/8%, due 2002                     30,000            30,000
       Series W, 9-3/4%, retired in 1995                   0            50,000
       Series X, 9.42%, retired in 1995                    0            50,000
       Series Y, 8-5/8%, due 2001                     60,000            60,000
       Series Z, 7.60%, due 1999                      50,000            50,000
       6-1/8% series, due 1997                         8,000             8,000
       9-1/8% series, due 2001                        21,000            21,000
       7-3/8% series, due 2003                        10,000            10,000
       7-1/4% series, due 2007                        30,000            30,000
                                                     239,000           339,000

     Pollution control obligations-
        5.75%, due serially 1996 to 2003               3,556             3,696
        5.95%, due 2007, secured by First 
          Mortgage Bonds                              10,000            10,000
        Variable rate (5.10%-5.95% at 
          December 31, 1995), due 2000 to 2010        11,100            11,100
                                                      24,656            24,796

     Subordinated Deferrable Interest 
       Debentures, 7-7/8%, due 2025                   50,000                 0

     Unamortized debt premium and (discount), net     -2,453            -2,652
                                                     480,603           480,544
         Less-Amount due within one year              15,140           100,140
                                                     465,463           380,404
                                                 $ 1,008,774       $   908,351



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

<TABLE>
  CONSOLIDATED STATEMENTS OF CASH FLOWS
<CAPTION>
                                                                                   Year Ended December 31
                                                                            1995            1994            1993
                                                                                       (in thousands)
<S>                                                                   <C>             <C>             <C>
  Cash flows from operating activities:
    Net income                                                          $  59,278       $  61,210       $  67,970
    Adjustments to reconcile net income to net cash
     flows from operating activities -
       Depreciation and amortization                                       79,384          75,316          69,407
       Amortization of principal under capital lease obligations           15,714          16,246          11,429
       Deferred taxes and investment tax credits                            7,628            -410          10,531
       Refueling outage provision                                          -7,506          12,536          -4,889
       Amortization of other assets                                         7,391           2,228           2,083
       Other                                                                  184          -1,232          -1,294
    Other changes in assets and liabilities -
       Accounts receivable                                                 -9,717          10,395          -8,553
       Production fuel, materials and supplies                              1,658             404           5,909
       Accounts payable                                                    -4,395          20,444           5,620
       Accrued taxes                                                        5,785           7,057         -10,991
       Provision for rate refunds                                             106          -8,670            -350
       Adjustment clause balances                                           4,581          -6,582           6,366
       Gas in storage                                                       2,429           1,919          -2,309
       Other                                                               -1,085           4,171           1,942
         Net cash flows from operating activities                         161,435         195,032         152,871


  Cash flows from financing activities:
    Dividends declared on common stock                                    -43,000         -52,000         -31,300
    Dividends declared on preferred stock                                    -914            -914            -914
    Equity infusion from parent company                                         0               0          50,000
    Proceeds from issuance of long-term debt                              100,000               0         119,400
    Reductions in long-term debt                                         -100,140            -224         -79,624
    Net change in short-term borrowings                                    54,393          31,495         -68,560
    Principal payments under capital lease obligations                    -14,463         -16,304         -11,276
    Sale of utility accounts receivable                                     4,000             800          10,490
    Other                                                                  -1,831          -5,144           3,251
      Net cash flows from financing activities                             -1,955         -42,291          -8,533


  Cash flows from investing activities:
    Construction and acquisition expenditures -
      Utility                                                            -126,104        -146,240        -113,212
      Other                                                                -3,340          -1,863               0
    Deferred energy efficiency expenditures                               -18,029         -16,157          -9,747
    Nuclear decommissioning trust funds                                    -6,100          -5,532          -5,532
    Other                                                                  -5,308             873             723
      Net cash flows from investing activities                           -158,881        -168,919        -127,768


  Net increase (decrease) in cash and temporary cash investments              599         -16,178          16,570


  Cash and temporary cash investments at beginning of year                  2,135          18,313           1,743


  Cash and temporary cash investments at end of year                    $   2,734       $   2,135       $  18,313


  Supplemental cash flow information:
    Cash paid during the year for -
      Interest                                                          $  44,569       $  40,005       $  37,484
      Income taxes                                                      $  29,083       $  34,479       $  40,130

    Noncash investing and financing activities -
      Capital lease obligations incurred                                $   2,918       $  14,297       $  14,605


The accompanying Notes to Consolidated Financial Statements
are an integral part of these statements.
</TABLE>


               NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




(1)  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
          (a)  Basis of Consolidation -

      IES Utilities Inc. (Utilities) is a wholly-owned subsidiary of IES
Industries  Inc.  (Industries).  The Consolidated  Financial  Statements
include  the  accounts  of  Utilities and its consolidated  subsidiaries
(collectively  the  Company).  Utilities is engaged principally  in  the
generation, transmission, distribution and sale of electric energy,  the
purchase,  distribution, transportation and sale of natural gas  and  to
provide  steam  for  industrial  and heating  purposes.   The  Company's
markets are located in the state of Iowa.

      All  subsidiaries for which Utilities owns directly or  indirectly
more  than  50%  of  the  voting  stock  are  included  as  consolidated
subsidiaries.  Utilities' only wholly-owned subsidiary at  December  31,
1995   was   IES   Ventures  Inc.  (Ventures).   Ventures'  wholly-owned
subsidiary  at December 31, 1995 was IES Midland Development  Inc.   All
significant intercompany balances and transactions have been  eliminated
from the Consolidated Financial Statements.

      Investments for which the Company has at least a 20% interest  are
generally  accounted for under the equity method of  accounting.   These
investments  are stated at acquisition cost, increased or decreased  for
the  Company's  equity in undistributed net income  or  loss,  which  is
included  in  "Miscellaneous,  net" in the  Consolidated  Statements  of
Income.  Investments that do not meet the criteria for the consolidating
or equity methods of accounting are accounted for under the cost method.

       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.

      Certain  prior period amounts have been reclassified  on  a  basis
consistent with the 1995 presentation.

     (b)  Regulation -

      Utilities  is  subject to regulation by the Iowa  Utilities  Board
(IUB)  and  the Federal Energy Regulatory Commission (FERC).  Utilities'
consolidated subsidiaries are not subject to regulation by  the  IUB  or
the FERC.

      Refer  to  Note  2  for  a discussion of the  proposed  merger  of
Industries.

     (c)  Regulatory Assets -

      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).   The  regulatory  assets  represent
probable  future  revenue to Utilities associated with certain  incurred
costs as these costs are recovered through  the rate making process.  At
December 31, regulatory assets  as reflected in the Consolidated Balance
Sheets were  comprised  of  the following items:

                                                        1995       1994
                                                         (in millions)
                                                 
Deferred income taxes (Note 1(d))                    $  91.1    $  90.1
Energy efficiency program costs (Note 3(c)) -
 . Currently being recovered through rates              18.3       20.3
 . Recovery has not yet been requested                  31.4       14.4
Environmental liabilities (Note 11(f))                  46.9       43.8
Employee pension and benefit costs (Note 7)             27.5       25.0
Unamortized loss on reacquired debt                      5.7        6.1
FERC Order No. 636 transition costs (Note 11(h))         5.0        8.0
Other                                                    4.1        5.4
                                                       230.0      213.1
Classified as "Current assets - regulatory assets"      22.8       20.1
Classified as "Other assets - regulatory assets"    $  207.2    $ 193.0

      Refer  to the individual footnotes referenced above for a  further
discussion of certain items reflected in regulatory assets.

      If a portion of Utilities' operations become no longer subject  to
the  provisions  of  SFAS 71, a write-off of related  regulatory  assets
would  be  required,  unless some form of transition  cost  recovery  is
established by the appropriate regulatory body.

      SFAS  121,  issued  in  March  1995 by  the  Financial  Accounting
Standards  Board  (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.   SFAS  121  is  not
expected  to  have  an impact on the financial position  or  results  of
operations of the Company upon adoption.

     (d)  Income Taxes -

     The Company follows the liability method of accounting for deferred
income   taxes,  which  requires  the  establishment  of  deferred   tax
liabilities  and  assets, as appropriate, for all temporary  differences
between the tax basis of assets and liabilities and the amounts reported
in   the  financial  statements.   Deferred  taxes  are  recorded  using
currently enacted tax rates.

      Except as noted below, income tax expense includes provisions  for
deferred  taxes  to  reflect the tax effects  of  temporary  differences
between  the  time when certain costs are recorded in the  accounts  and
when   they   are  deducted  for  tax  return  purposes.   As  temporary
differences reverse, the related accumulated deferred income  taxes  are
reversed  to  income.   Investment tax credits for Utilities  have  been
deferred and are subsequently credited to income over the average  lives
of the related property.

      Consistent with rate making practices for Utilities, deferred  tax
expense  is  not  recorded for certain temporary differences  (primarily
related  to  utility property, plant and equipment).   As  the  deferred
taxes  become  payable,  over  periods  exceeding  30  years  for   some
generating   plant  differences,  they  are  recovered  through   rates.
Accordingly,  Utilities  has  recorded  deferred  tax  liabilities   and
regulatory assets, as identified in Note 1(c).

      (e)  Temporary Cash Investments -

      Temporary  cash investments are stated at cost, which approximates
market  value, and are considered cash equivalents for the  Consolidated
Statements  of  Cash  Flows.  These investments  consist  of  short-term
liquid  investments that have maturities of less than 90 days  from  the
date of acquisition.

    (f)  Depreciation of Utility Property, Plant and Equipment -

     The depreciation life of Utilities' nuclear generating station, the
Duane  Arnold Energy Center (DAEC), was increased from 36  years  to  40
years  based on an extension of the Nuclear Regulatory Commission  (NRC)
license  life  to  2014, using the remaining life  method,  as  part  of
Utilities' most recent rate case as discussed in note 3(b).  The average
rates  of  depreciation  for electric and gas properties  of  Utilities,
consistent with current rate making practices, were as follows:

                        1995       1994        1993
                                                     
        Electric        3.4%       3.6%        3.5%
        Gas             3.5%       3.8%        3.5%


      The electric and gas depreciation rates declined in 1995 from 1994
because of revised depreciation rates approved in Utilities' most recent
electric and gas rate proceedings.

     (g)  Decommissioning of the DAEC -

      Pursuant  to the recent electric rate case order, the IUB  allowed
Utilities  to increase the recovery of anticipated costs to decommission
the  DAEC  from   $5.5 million to $6.0 million annually. Decommissioning
expense   is  included  in  "Depreciation  and  amortization"   in   the
Consolidated Statements of Income and the cumulative amount is  included
in  "Accumulated depreciation" in the Consolidated Balance Sheets to the
extent recovered through rates.  The current recovery figures are  based
on the following assumptions: 1) cost to decommission the DAEC of $252.8
million in 1993 dollars, based on the NRC minimum formula (which exceeds
the  amount  in the current site-specific study completed in  1994);  2)
inflation of 4.91% annually through 1997; 3) the prompt dismantling  and
removal method of decommissioning, which is assumed to begin in the year
2014;  4) monthly funding of all future collections into external  trust
funds and funded on a tax-qualified basis to the extent possible; and 5)
an  average after-tax return of 6.82% for all external investments.  All
of  these  assumptions  are  subject  to  change  in  future  regulatory
proceedings.  At December 31, 1995, Utilities had $47.0 million invested
in external decommissioning trust funds as indicated in the Consolidated
Balance  Sheets,  and  also had an internal decommissioning  reserve  of
$21.7  million  recorded as accumulated depreciation.  Earnings  on  the
external  trust funds, which were $1.0 million in 1995, are recorded  as
interest  income  and a corresponding interest expense  payable  to  the
funds  is recorded.  The earnings accumulate in the external trust  fund
balances and in accumulated depreciation on utility plant.

      See  "Management's  Discussion and  Analysis  of  the  Results  of
Operations  and  Financial Condition" for a discussion of  the  Exposure
Draft  on  Accounting for Liabilities Related to Closure and Removal  of
Long-Lived  Assets,  issued by the FASB in the first  quarter  of  1996,
which deals with, among other issues, the accounting for decommissioning
costs.

     (h)  Property, Plant and Equipment -

      Utility plant (excluding acquisition adjustments of $30.6 million,
net  of  accumulated  amortization, recorded at  cost)  is  recorded  at
original cost.  The allowance for funds used during construction  (AFC),
which  represents the cost during the construction period of funds  used
for construction purposes, is capitalized by Utilities as a component of
the  cost of utility plant.  The amount of AFC applicable to debt  funds
and  to other (equity) funds, a non-cash item, is computed in accordance
with  the  prescribed FERC formula.  The aggregate gross rates  used  by
Utilities  for 1995-1993 were 6.5%, 9.3% and 5.7%, respectively.   These
capitalized costs are recovered by Utilities in rates as the cost of the
utility plant is depreciated.

      Other  property, plant and equipment is recorded  at  cost.   Upon
retirement or sale of other property and equipment, the cost and related
accumulated depreciation are removed from the accounts and any  gain  or
loss  is included in "Miscellaneous, net" in the Consolidated Statements
of Income.

      Normal  repairs, maintenance and minor items of utility plant  and
other  property, plant and equipment are expensed.  Ordinary retirements
of  utility  plant,  including removal costs  less  salvage  value,  are
charged  to  accumulated depreciation upon removal  from  utility  plant
accounts, and no gain or loss is recognized.

     (i)  Operating Revenues -

      The Company accrues revenues for services rendered but unbilled at
month-end in order to more properly match revenues with expenses.

     (j)  Adjustment Clauses -

      Utilities'  tariffs  provide  for subsequent  adjustments  to  its
electric  and  natural gas rates for changes in the  cost  of  fuel  and
purchased  energy and in the cost of natural gas purchased  for  resale.
Changes  in  the under/over collection of these costs are  reflected  in
"Fuel for production" and "Gas purchased for resale" in the Consolidated
Statements  of  Income.  The cumulative effects  are  reflected  in  the
Consolidated  Balance  Sheets as a current asset or  current  liability,
pending automatic reflection in future billings to customers.

     (k)  Accumulated Refueling Outage Provision -

      The IUB allows Utilities to collect, as part of its base revenues,
funds  to  offset other operating and maintenance expenditures  incurred
during  refueling outages at the DAEC.  As these revenues are collected,
an  equivalent  amount  is  charged to other operating  and  maintenance
expenses  with a corresponding credit to a reserve.  During a  refueling
outage,  the  reserve  is  reversed  to  offset  the  refueling   outage
expenditures.

(2)  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, 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.  The
Proposed  Merger, which will be accounted for as a pooling of interests,
has  been  approved by the respective Boards of Directors.  It is  still
subject  to  approval by the shareholders of each  company  as  well  as
several federal and state regulatory agencies.  The companies expect  to
receive the shareholder approvals in the second quarter of 1996 and  the
regulatory approvals by the second quarter of 1997.

      The operating revenues, net income from continuing operations  and
total assets of the companies were as follows:

                                                                    PRO FORMA
                                  IES                               COMBINED
                              INDUSTRIES       WPLH        IPC     (Unaudited)
                                               (in thousands)
                                                               
1995 operating revenues      $   851,010  $   807,255  $  318,542  $ 1,976,807
                                                                
1995 net income from                                              
  continuing operations           64,176       71,618      25,198      160,992
                                                                
Assets at December 31, 1995    1,985,591    1,872,414     634,316    4,492,321


      Under the terms of the Merger Agreement, the outstanding shares of
WPLH's  common stock will remain unchanged and outstanding as shares  of
Interstate  Energy.  Each outstanding share of Industries' common  stock
will  be  converted to .98 shares of Interstate Energy's  common  stock.
Each  share  of IPC's common stock will be converted to 1.11  shares  of
Interstate  Energy's  common stock.  It is anticipated  that  Interstate
Energy will retain WPLH's common share dividend payment level as of  the
effective  time  of  the  merger.  On January 24,  1996,  the  Board  of
Directors  of  WPLH  declared a quarterly dividend of  49.25  cents  per
share.  This represents an equivalent annual rate of $1.97 per share.

      WPLH is a holding company headquartered in Madison, Wisconsin, and
is  the  parent company of Wisconsin Power and Light Company (WP&L)  and
Heartland Development Corporation (HDC).  WP&L supplies electric and gas
service to approximately 377,000 and 146,000 customers, respectively, in
south  and  central Wisconsin.  HDC and its principal  subsidiaries  are
engaged  in  businesses in three major areas: environmental  engineering
and  consulting,  affordable  housing  and  energy  services.   IPC,  an
operating  public  utility  headquartered  in  Dubuque,  Iowa,  supplies
electric  and gas service to approximately 163,000 and 49,000 customers,
respectively,  in  northeast  Iowa,  northwest  Illinois  and   southern
Minnesota.

     Interstate Energy will be the parent company of Utilities, WP&L and
IPC  and will be registered under the Public Utility Holding Company Act
of  1935,  as  amended (1935 Act).  The Merger Agreement  provides  that
these  operating utility companies will continue to operate as  separate
entities for a minimum of three years beyond the effective date  of  the
merger.  In addition, the non-utility operations of Industries and  WPLH
will  be  combined shortly after the effective date of the merger  under
one  entity  to manage the diversified operations of Interstate  Energy.
The corporate headquarters of Interstate Energy will be in Madison.

      The  SEC  historically has interpreted the 1935  Act  to  preclude
registered holding companies, with limited exceptions, from owning  both
electric  and  gas  utility  systems.  Although  the  SEC  has  recently
recommended  that registered holding companies be allowed to  hold  both
gas  and  electric utility operations if the affected states  agree,  it
remains possible that the SEC may require as a condition to its approval
of  the  Proposed Merger that Industries, WPLH and IPC divest their  gas
utility  properties,  and  possibly  certain  non-utility  ventures   of
Industries  and WPLH, within a reasonable time after the effective  date
of the Proposed Merger.

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

      On  August  4,  1995, Utilities applied to the 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.  Utilities, the Office of Consumer Advocate and  all
three  industrial  intervenor  groups have  entered  into  a  settlement
agreement,  subject  to  IUB approval, which  allows  Utilities  a  $6.3
million  annual increase.  Utilities expects that the IUB will  rule  on
the settlement agreement no later than the second quarter of 1996.

     (b)  1994 Electric Rate Case -

      In  1994,  Utilities applied to the IUB for an increase in  retail
electric rates of approximately $26 million annually, or 5.2%.  The  IUB
issued  its  final order on June 30, 1995, which resulted in  an  annual
retail  rate reduction of approximately $14.4 million.  The Board  ruled
against  Utilities  on issues of increased recovery  levels  of  nuclear
depreciation  expense and nuclear decommissioning expense, and  recovery
of the full purchase price of Union Electric Company's (UE) Iowa service
territory.

      On  August 16, 1995, Utilities received approval from the  IUB  to
implement  final prices.  Northern and Southeastern zone  price  changes
became effective on that date.  A price design change was implemented in
the  Southern zone effective January 1, 1996.  As a result  of  the  IUB
order,   Utilities  refunded  approximately  $12.8  million,   including
interest, in the fourth quarter of 1995.

     (c)  Energy Efficiency Cost Recovery -

      The  IUB has current rules that 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
applied  in 1994 to the IUB for recovery of costs incurred through  1993
for such programs.  In April 1995, the IUB issued its Final Decision and
Order concerning Utilities' energy efficiency expenditures, which allows
Utilities  to  recover its direct expenditures, carrying  costs,  and  a
return  on  its  expenditures,  as well as  a  reward  of  approximately
$4  million  for a total allowed recovery of approximately $32  million.
Recovery of energy efficiency costs will be over a four-year period  and
began on June 1, 1995.  In 1996, under provisions of the IUB rules,  the
Company will file for recovery of the costs incurred after December  31,
1993 ($31.4 million as of December 31, 1995).

(4)  LEASES:

      Utilities has a capital lease covering its 70% undivided  interest
in  nuclear fuel purchased for the DAEC.  Future purchases of  fuel  may
also  be  added  to  the  fuel lease.  This lease  provides  for  annual
one-year  extensions and Utilities intends to exercise  such  extensions
through  the DAEC's operating life. Interest costs under the  lease  are
based  on  commercial paper costs incurred by the lessor.  Utilities  is
responsible for the payment of taxes, maintenance, operating cost,  risk
of loss and insurance relating to the leased fuel.

      The  lessor  has  a  $65  million credit  agreement  with  a  bank
supporting the nuclear fuel lease.  The agreement continues on a year-to-
year basis, unless either party provides at least a three-year notice of
termination; no such notice of termination has been provided  by  either
party.

      Annual nuclear fuel lease expenses include the cost of fuel, based
on  the quantity of heat produced for the generation of electric energy,
plus  the  lessor's interest costs related to fuel in  the  reactor  and
administrative  expenses.   These  expenses  (included  in   "Fuel   for
production" in the Consolidated Statements of Income) for 1995-1993 were
$18.0 million, $17.8 million and $12.4 million, respectively.

      The  Company's operating lease rental expenses for 1995-1993  were
$9.0 million, $9.8 million and $8.4 million, respectively.

     The Company's future minimum lease payments by year are as follows:

                                             Capital       Operating
        Year                                  Lease         Leases
                                                (in thousands)
                                                  
        1996                                $ 15,515      $  6,824
        1997                                  13,787         6,056
        1998                                   6,389         5,788
        1999                                   3,865         4,133
        2000                                     824         1,562
        2001                                     149           -
                                              40,529      $ 24,363
        Less:  Amount representing 
               interest                        3,594          
        Present value of net                      
          minimum capital lease payments    $ 36,935         


(5)  UTILITY ACCOUNTS RECEIVABLE:

      Customer  accounts receivable, including unbilled revenues,  arise
primarily from the sale of electricity and natural gas.  At December 31,
1995,   Utilities  was  serving  a  diversified  base  of   residential,
commercial and industrial customers consisting of approximately  333,000
electric and 174,000 gas customers.

      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 December 31, 1995, $58 million was sold
under the agreement.

 (6) INCOME TAXES:

      The  components of federal and state income taxes  for  the  years
ended December 31, were as follows:

                                           1995        1994         1993
                                                  (in millions)
                                                  
Current tax expense                       $ 33.5      $ 38.4      $ 27.5
Deferred tax expense                        10.3         2.2        15.4
Amortization and adjustment
  of investment tax credits                 (2.7)       (2.6)       (4.9)
                                          $ 41.1      $ 38.0      $ 38.0


      The  overall effective income tax rates shown below for the  years
ended December 31, were computed by dividing total income tax expense by
income before income taxes.

                                             1995       1994       1993
                                                          
Statutory federal income tax rate            35.0%      35.0%      35.0%
Add (deduct):                                             
  State income taxes, net of federal 
    benefits                                  5.9        6.1        5.8
  Effect of rate making on property
    related differences                       2.8        1.7       (0.2)
  Amortization of investment 
    tax credits                              (2.7)      (2.7)      (2.5)
  Adjustment of prior period taxes           (0.1)      (1.9)      (2.0)
  Other items, net                             -         0.1       (0.3)
Overall effective income tax rate            40.9%      38.3%      35.8%

      The  accumulated deferred income taxes as set forth below  in  the
Consolidated  Balance Sheets at December 31, arise  from  the  following
temporary differences:

                                             1995       1994
                                              (in millions)
                                         
Property related                            $ 282      $ 276
Investment tax credit related                 (26)       (28)
Decommissioning related                       (14)       (13)
Other                                          11          6
                                            $ 253      $ 241


(7)  BENEFIT PLANS:
     (a)  Pension Plans -

       The   Company  has  two  non-contributory  pension  plans   that,
collectively,  cover substantially all of its employees.  Plan  benefits
are  generally  based  on years of service and compensation  during  the
employees'  latter years of employment.  Payments made from the  pension
funds  to  retired  employees  and  beneficiaries  during  1995  totaled
$9.0 million.

      The Company's policy is to fund the pension cost at an amount that
is  at  least equal to the minimum funding requirements mandated by  the
Employee Retirement Income Security Act (ERISA) and that does not exceed
the  maximum  tax deductible amount for the year.  The  Company  has  an
investment policy governing asset allocation guidelines for its  pension
plans.   The target ranges are as follows: 1) 37%-43% in large and  mid-
sized  domestic  company equity securities, 2) 7%-13% in foreign  equity
securities, 3) 7%-13% in small domestic company equity securities, 4) 0-
5%  in real estate, and 5) the remainder in fixed income securities.  As
of  December 31, 1995, the plan's investment mix was consistent with the
policy guidelines.

      Pursuant  to  the  provisions of SFAS 71, certain  adjustments  to
Utilities' pension provision are necessary to reflect the accounting for
pension costs allowed in its most recent rate cases.

      The  components  of  the pension provision  for  the  years  ended
December 31, were as follows:

                                                1995        1994        1993
                                                       (in thousands)
                                                       
Service cost                                $   4,721   $   5,786   $   4,275
Interest cost on projected benefit 
  obligation                                   11,577      11,265      11,131
Assumed return on plans' assets               (12,340)    (12,426)    (12,177)
Amortization of unrecognized gain                (741)       (180)       (763)
Amortization of prior service cost              1,328       1,335       1,195
Amortization of unrecognized plans'
  assets as of January 1, 1987                   (327)       (329)       (384)
Pension cost                                    4,218       5,451       3,277
Adjustment to funding level                    (4,218)     (5,340)     (2,867)
Total pension costs paid to the Trustee     $     -     $     111   $     410
                                                       
Actual return on plans' assets              $  35,947   $    (101)  $  12,718


      The reduction in the service cost for 1995 was primarily due to an
increase in the discount rate at December 31, 1994.

      A  reconciliation of the funded status of the plans to the amounts
recognized  in  the  Consolidated Balance  Sheets  at  December  31,  is
presented below:
                                                           1995         1994
                                                             (in thousands)
                                                       
Fair market value of plans' assets                     $ 191,782    $ 165,267
Actuarial present value of benefits                    
  rendered to date -
    Accumulated benefits based on                      
      compensation to date, including vested
      benefits of $117,624,000 and
      $96,968,000, respectively                          128,674      107,017
    Additional benefits based on estimated
      future salary levels                                40,790       39,565
Projected benefit obligation                             169,464      146,582
Plans' assets in excess of projected benefit
  obligation                                              22,318       18,685
Remaining unrecognized net asset existing at
  January 1, 1987, being amortized over 20 years          (3,451)      (3,792)
Unrecognized prior service cost                           16,564       17,991
Unrecognized net gain                                    (40,707)     (33,942)
Accrued pension cost recognized in the                 
  Consolidated Balance Sheets                          $  (5,276)   $  (1,058)
                                                       
Assumed rate of return, all plans                           8.00%        8.00%
Weighted average discount rate of projected 
  benefit obligation, all plans                             7.50%        8.25%
Range of assumed rates of increase in future 
  compensation levels for the plans                         4.75%   4.00-5.75%


      The increase in the projected benefit obligation was primarily due
to  changes  in  the mortality rate assumptions and a reduction  in  the
discount rate at December 31, 1995.

     (b)  Other Postemployment Benefit Plans -

     The Company provides certain benefits to retirees (primarily health
care  benefits).   Effective January 1, 1993, the Company  adopted  SFAS
106,  which  requires the accrual of the expected cost of postretirement
benefits  other  than pensions during the employees' years  of  service.
The  IUB  adopted rules stating that postretirement benefits other  than
pensions will be included in Utilities' rates pursuant to the provisions
of  SFAS  106.   The rules permit Utilities to amortize  the  transition
obligation  as  of January 1, 1993, over 20 years and require  that  all
amounts  collected  are  to  be funded into an  external  trust  to  pay
benefits  as  they become due.  The gas and electric portions  of  these
costs  are  being recovered through rates beginning in  1993  and  1995,
respectively,  including  amounts that  were  deferred  by  the  Company
between when SFAS 106 was adopted and when recovery through rates began.
The  amounts deferred are being amortized as they are collected  through
rates  over  a  three-year  period.  The unamortized  balance  of  these
deferred costs was $3.4 million at December 31, 1995.

      Pursuant  to  the  provisions of SFAS 71, certain  adjustments  to
Utilities'  other  postretirement benefit provisions  are  necessary  to
reflect the accounting for other postretirement benefit costs allowed in
its most recent rate cases.

      The components of postretirement benefit costs for the years ended
December 31, were as follows:

                                                 1995       1994        1993
                                                        (in thousands)
                                                         
Service cost                                  $  1,227   $  1,785    $  1,685
Interest cost on accumulated 
  postretirement benefit obligation              3,049      3,175       3,247
Assumed return on plans' assets                    (56)       (60)        -
Amortization of transition obligation 
  existing at January 1, 1993                    2,024      2,024       2,024
Amortization of unrecognized gain                 (221)        (4)        -
Amortization of prior service cost                  19         19         -
Postretirement benefit costs                     6,042      6,939       6,956
Amortized/(deferred) postretirement 
  benefit costs                                  2,220     (2,732)     (2,858)
Costs billed to affiliate                         (265)       -           -
Adjustment to funding level                      1,162        -           -
Net postretirement benefit costs              $  9,159   $  4,207    $  4,098
                                                          
Actual return on plans' assets                $    273   $     47    $    -


      The reduction in the service cost for 1995 was primarily due to an
increase in the discount rate at December 31, 1994.

      A  reconciliation of the funded status of the plans to the amounts
recognized  in  the  Consolidated Balance  Sheets  at  December  31,  is
presented below:

                                                           1995         1994
                                                            (in thousands)
                                                  
Fair market value of plans' assets                     $   6,515    $   1,127
Accumulated postretirement benefit obligation -
  Active employees not yet eligible                       20,936       18,216
  Active employees eligible                                6,148        5,119
  Retirees                                                21,846       18,161
Total accumulated postretirement benefit
  obligation                                              48,930       41,496
Accumulated postretirement benefit obligation
  in excess of plans' assets                             (42,415)     (40,369)
Unrecognized transition obligation                        34,415       36,439
Unrecognized net (gain)/loss                                 268       (5,358)
Unrecognized prior service cost                              151          170
Accrued postretirement benefit cost in the
  Consolidated Balance Sheets                          $  (7,581)   $  (9,118)
                                                  
Assumed rate of return                                      8.00%        8.00%
Weighted average discount rate of accumulated
  postretirement benefit obligation                         7.50%        8.25%
Medical trend on paid charges:                    
  Initial trend rate                                       10.00%       11.00%
  Ultimate trend rate                                       6.50%        6.50%

      The  increase in the accumulated postretirement benefit obligation
was  primarily due to a reduction in the discount rate at  December  31,
1995,  as  well  as  changes  made  for  mortality,  turnover  and   age
assumptions.   The assumed medical trend rates are critical  assumptions
in   determining   the  service  and  interest  cost   and   accumulated
postretirement  benefit  obligation related  to  postretirement  benefit
costs.   A  1%  change  in the medical trend rates,  holding  all  other
assumptions  constant, would have changed the 1995 service and  interest
cost  by  $0.9 million (21%) and the accumulated postretirement  benefit
obligation at December 31, 1995, by $8.3 million (17%).

(8)  PREFERRED AND PREFERENCE STOCK:

     Utilities has 466,406 shares of Cumulative Preferred Stock, $50 par
value, authorized for issuance at December 31, 1995, of which the 6.10%,
4.80%  and  4.30%  Series  had  100,000,  146,406  and  120,000  shares,
respectively,  outstanding at both December 31, 1995  and  1994.   These
shares are redeemable at the option of Utilities upon 30 days notice  at
$51.00,   $50.25  and  $51.00  per  share,  respectively,  plus  accrued
dividends.    In  addition,  there  are  700,000  shares  of   Utilities
Cumulative Preference Stock ($100 par value) authorized for issuance, of
which none were outstanding at December 31, 1995.

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

      In  December  1995, Utilities issued $50 million  of  Subordinated
Deferrable Interest Debentures, 7-7/8%, due 2025.  The proceeds from the
issuance of the debentures were used to retire short-term borrowings which
were incurred in October 1995 to  repay  at  maturity, $50 million of 
Series X, 9.42%  First  Mortgage Bonds.

      In  March 1995, Utilities repaid at maturity $50 million of Series
W,  9.75%  First  Mortgage Bonds and, in a separate transaction,  issued
$50 million of Collateral Trust Bonds, 7.65%, due 2000.

      Utilities'  Indentures  and  Deeds of  Trust  securing  its  First
Mortgage Bonds constitute direct first mortgage liens upon substantially
all tangible public utility property.  Utilities' Indenture and Deed  of
Trust  securing its Collateral Trust Bonds constitutes a second lien  on
substantially all tangible public utility property while First  Mortgage
Bonds remain outstanding.

     Total sinking fund requirements, which Utilities intends to meet by
pledging  additional  property under the terms of Utilities'  Indentures
and Deeds of Trust, and debt maturities for 1996-2000 are as follows:

                                           Debt Maturities
                                            (in thousands)
                                                                       
Debt Issue                   1996       1997       1998       1999       2000
                                                                          
  Sinking fund 
    requirements          $    630   $    550   $    550   $    550   $    550
  Pollution control            140        140        140        140      1,696
  Series J                  15,000        -          -          -          -
  6-1/8% Series                -        8,000        -          -          -
  Series Z                     -          -          -       50,000        -
  Series L                     -          -          -          -       15,000
  7.65% Series                 -          -          -          -       50,000
Total                     $ 15,770   $  8,690   $    690   $ 50,690   $ 67,246



      The  Company  intends  to  refinance  the  majority  of  the  debt
maturities with long-term securities.


     (b)  Short-Term Debt -

      At  December  31,  1995,  the Company had  bank  lines  of  credit
aggregating  $121.1 million, of which $101 million  was  being  used  to
support  commercial paper (weighted average interest rate of 5.81%)  and
$11.1  million  was  being  used 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  December 31, 1995, there were no borrowings  outstanding
under this facility.

(10) ESTIMATED FAIR VALUE OF FINANCIAL INSTRUMENTS:

       The   estimated   fair   values  of  financial   instruments   at
December 31, 1995, and December 31, 1994, and the basis upon which  they
were estimated are as follows:

     (a)  Current Assets and Current Liabilities -

      The  carrying amount approximates fair value because of the  short
maturity of such financial instruments.

     (b)  Nuclear Decommissioning Trust Funds -

     The carrying amount represents the fair value of these trust funds,
as reported by the trustee.  The balance of the "Nuclear decommissioning
trust  funds" as shown in the Consolidated Balance Sheets included  $5.3
million  of  unrealized gains at December 31, 1995, and $0.8 million  of
unrealized losses at December 31, 1994, on the investments held  in  the
trust  funds.   The  accumulated reserve for decommissioning  costs  was
adjusted by a corresponding amount.

     (c)  Cumulative Preferred Stock of Utilities -

      The  estimated fair value of this stock of $11.3 million and $10.2
million  at  December 31, 1995, and December 31, 1994, respectively,  is
based  upon  the  market yield of similar securities and  quoted  market
prices.

     (d)  Long-Term Debt -

     At December 31, 1995, and December 31, 1994, the carrying amount of
long-term  debt was $483 million for both periods, compared to estimated
fair  values  of  $507  million  and $459  million,  respectively.   The
estimated fair value of long-term debt is based upon the market yield of
similar securities and quoted market prices.

      Since  Utilities  is subject to regulation, any  gains  or  losses
related to the difference between the carrying amount and the fair value
of financial instruments may not be realized by the Company's parent.

(11) COMMITMENTS AND CONTINGENCIES:
     (a)  Construction Program -

      The  Company's  construction and acquisition  program  anticipates
expenditures  of  approximately $164 million for  1996,  and  additional
expenditures of approximately $13 million for mandated energy efficiency
programs.   These  energy  efficiency  expenditures  will  be   deferred
pursuant   to   IUB  rules  as  discussed  in  Note  3(c).   Substantial
commitments have been made in connection with these expenditures.

     (b)  Purchase Power Contracts -

      Utilities  is  purchasing  power from UE  under  a  firm  capacity
contract with 1996 and 1997 requirements of 80 Mw and 60 Mw of delivered
capacity,  respectively.   Utilities will also  purchase  an  additional
annual  maximum interruptible capacity of up to 54 Mw of  25  Hz  power,
which  extends through 1998.  The costs of capacity purchases for  these
contracts  are  reflected  in  "Purchased  power"  in  the  Consolidated
Statements of Income.

      Utilities  has also entered into an agreement with Basin  Electric
Power  Cooperative to purchase capacity of 50 Mw, 75 Mw, 100 Mw and  100
Mw  during the annual six-month summer season for the years 1996 through
1999, respectively.

      Total  capacity charges expected to be incurred under all existing
contracts  will approximate $14.1 million, $11.1 million, $3.3  million,
$3.4 million and $0.4 million for the years 1996-2000, respectively.

     (c)  Coal Contract Commitments -

      Utilities  has  entered  into coal supply contracts  which  expire
between  1996  and 2001 for its fossil-fueled generating  stations.   At
December  31,  1995, the contracts cover approximately $158  million  of
coal over the life of the contracts, which includes $55 million expected
to  be  incurred  in 1996.  Utilities expects to supplement  these  coal
contracts  with spot market purchases to fulfill its future fossil  fuel
needs.

     (d)  Information Technology Services -

      The  Company  entered into an agreement, expiring  in  2004,  with
Electronic  Data  Systems Corporation (EDS) for  information  technology
services.   The contract is subject to declining termination fees.   The
Company's  anticipated  operating and  capital  expenditures  under  the
agreement  for 1996 are estimated to total approximately $12.5  million.
Future costs under the agreement are variable and are dependent upon the
Company's level of usage of technological services from EDS.

     (e)  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  $3.1 million under NML, $9.8 million for NEIL property  and
$0.7 million for NEIL replacement power if losses exceed the accumulated
reserves  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.

     (f)  Environmental Liabilities -

     The Company has recorded environmental liabilities of approximately
$46.4  million in its Consolidated Balance Sheets at December 31,  1995.
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.   There  are
also  six  other sites for which it may be designated as a  PRP  in  the
future.   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
five  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 19 sites and expects to begin the investigation process in
1996 for the two other sites.  Utilities estimates the range of costs to
be  incurred  for investigation and/or remediation of the  sites  to  be
approximately $22 million to $55 million.

      Utilities  has recorded environmental liabilities related  to  the
FMGP  sites  of  approximately $35 million (including  $4.6  million  as
current liabilities) at December 31, 1995.  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 or has  not  started.   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.  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.

      Utilities  has begun pursuing claims under its prior coverage  for
investigation, mitigation, prevention, remediation, and monitoring costs
from its insurance carriers and is investigating the potential for third
party  cost  sharing  for FMGP investigation and  clean-up  costs.   The
amount  of  shared costs, if any, cannot be reasonably  determined  and,
accordingly,  no  potential  sharing  has  been  recorded  at   December
31, 1995.  Regulatory assets of approximately $35 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 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,  $10.9
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.

     (g)  Air Quality Issues -

      The  Clean Air Act Amendments Act of 1990 (Act) requires  emission
reductions  of  sulfur  dioxide 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 with  Phase  I
affecting  two  of  Utilities' units beginning  in  1995  and  Phase  II
affecting all units beginning in the year 2000.  Utilities has completed
the  modifications  necessary to meet the Phase I requirements  and  has
installed continuous emission monitors on all affected units as required
by  the Act.  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  sulfur  dioxide allowances.  Utilities  estimates  capital
expenditures at approximately $20 million, including $4 million in 1996,
in order to meet the acid rain requirements of the Act.

      The  acid  rain program under the Act also creates sulfur  dioxide
allowances.  An allowance is defined as an authorization for an owner to
emit  one  ton  of  sulfur  dioxide  into  the  atmosphere.   Currently,
Utilities receives a sufficient number of allowances annually to  offset
its  emissions  of  sulfur  dioxide from  its  Phase  I  units.   It  is
anticipated  that in the year 2000, when the Phase II units  participate
in  the allowance program, 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 year 2000 and thereafter.  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  also requires 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  nitrogen  oxides  (NOx),  ozone  transport  and  mercury.
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  methods, suggests that the Cedar Rapids  area  could  be
classified  as  "nonattainment" for the  National  Ambient  Air  Quality
Standard   (NAAQS)  established  for  sulfur  dioxide.   The  worst-case
modeling  study  suggests that two of Utilities'  generating  facilities
contribute  to  the modeled exceedences and recommends  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 reviewing  EPA's  assumptions  and
modeling  results and is proposing a strategy to voluntarily reduce  the
excessive  emissions  through  modification  of  its  facilities  at   a
potential capital cost of up to $10 million over the next four years.

     (h)  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 December
31,  1995, has recorded a liability of $5.0 million for those transition
costs  that have been incurred, but not yet billed, by the pipelines  to
date,  including  $1.9  million expected  to  be  billed  through  1996.
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
$7.0  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.

 (12)     JOINTLY-OWNED ELECTRIC UTILITY PLANT:

      Under  joint  ownership  agreements  with  other  Iowa  utilities,
Utilities  has  undivided ownership interests in jointly-owned  electric
generating  stations and related transmission facilities.  Each  of  the
respective owners is responsible for the financing of its portion of the
construction costs.  Kilowatt-hour generation and operating expenses are
divided  on  the same basis as ownership with each owner reflecting  its
respective  costs in its Statements of Income.  Information relative  to
Utilities' ownership interest in these facilities at December  31,  1995
is as follows:
 
                                                Ottumwa      Neal
                                      DAEC       Unit 1     Unit 3
                                            ($ in millions)
                                             
Utility plant in service            $ 498.0     $ 189.3     $  56.2
Accumulated depreciation            $ 201.2     $  86.0     $  27.1
Construction work in progress       $   2.7     $   1.7     $   0.7
Plant capacity - Mw                     520         716         515
Percent ownership                        70%         48%         28%
In-service date                        1974        1981        1975


(13) SEGMENTS OF BUSINESS:

      The principal business segments of the Company are the generation,
transmission, distribution and sale of electric energy and the purchase,
distribution, transportation and sale of natural gas.  Certain financial
information  relating to the Company's significant segments of  business
is presented below:

                                          Year Ended December 31
                                             1995           1994       1993
                                                (in thousands)
Operating results:                                                     
  Revenues -                                                           
    Electric                            $   560,471   $   537,327   $  550,521
    Gas                                     137,292       139,033      154,318
                                                                       
  Operating income -                                                   
    Electric                                130,390       125,487      128,994
    Gas                                       9,208         8,135       13,750
                                                                       
Other information:                                                     
  Depreciation and amortization -
    Electric                                 72,487        68,640       63,832
    Gas                                       6,176         6,214        5,186
                                                                       
  Construction and acquisition 
  expenditures -
    Electric                                108,902       120,180       96,736
    Gas                                       9,368        10,066       15,428
                                                                       
  Assets -                                                             
    Identifiable assets -                                               
      Electric                           1,395,666     1,347,024     1,288,505
      Gas                                  192,045       186,911       164,773
                                         1,587,711     1,533,935     1,453,278
    Other corporate assets                 120,924       111,433        93,700
        Total consolidated             $ 1,708,635   $ 1,645,368   $ 1,546,978


Item 9. Changes and Disagreements with Accountants on Accounting and 
        Financial Disclosure

        None.


                                PART III

Item  10.  Directors, Executive Officers, Promoters and Control  Persons
           of the Registrant

      Information regarding the identification of directors is  included
in  Exhibit 99 and is incorporated herein by reference.  Exhibit  99  is
primarily  an  excerpt  from the IES Industries  Inc.  definitive  proxy
statement  prepared  for the 1996 annual meeting of stockholders,  which
will  be  filed  within 120 days of December 31,  1995.   The  executive
officers of the registrant are as follows:

Executive Officers of the Registrant  (Effective February 6, 1996)

     
     Lee  Liu,  62,  Chairman  of the Board & Chief  Executive  Officer.
     First elected officer in 1975. (1)


     Blake  O.  Fisher,  Jr., 51, President, Chief Operating  Officer  &
     Chief  Financial  Officer and Director. First  elected  officer  in
     1991. (2)


     James E. Hoffman, 43, Executive Vice President, Customer Service  &
     Energy Delivery.  First elected officer in 1995. (3)
     
     
     Stephen  W.  Southwick,  49,  Vice  President,  General  Counsel  &
     Secretary.  First elected officer in 1982.


     John F.  Franz,  Jr., 56, Vice President, Nuclear.   First  elected
     officer in 1992. (4)


     Philip  D.  Ward,  55,  Vice President, Engineering  &  Generation.
     First elected officer in 1990.
     
     
     Harold  W.  Rehrauer, 58, Vice President, Field Operations.   First
     elected officer in 1987.


     Richard  A. Gabbianelli, 39, Controller & Chief Accounting Officer.
     First elected officer in 1994.
     
     
     Dennis B. Vass, 46, Treasurer.  First elected officer in 1995. (5)



     Officers are elected annually by the Board of Directors and each of
the  officers named above, except James E. Hoffman, John F.  Franz,  Jr.
and  Dennis B. Vass, have been employed by the Company as an officer  or
in  other  responsible positions at such companies  for  at  least  five
years.   There are no family relationships among these officers.   There
are  no  arrangements or understandings with respect to election of  any
person as an officer.

      (1)   Lee Liu was elected Chairman of the Board, President & Chief
            Executive Officer effective February 21, 1996.

      (2)   Blake  O.  Fisher,  Jr.  resigned  as  President,  Chief
            Operating  Officer & Chief Financial Officer and  Director  of
            IES Utilities Inc. effective February 21, 1996.

      (3)   Prior to the appointment of James E. Hoffman as Executive Vice
            President, Customer Service & Energy Delivery in 1995, he  was
            employed  by  MCI Communications as Chief Information  Officer
            from  1990  to  1995  and by Telecom*USA  as  Vice  President,
            Information Services from 1988 to 1990.
     
      (4)   Prior  to  the  appointment of John  F.  Franz,  Jr.  as  Vice
            President,  Nuclear in 1992, he was employed  by  Philadelphia
            Electric  Company as Plant Manager, Peach Bottom Atomic  Power
            Station.
     
      (5)   Dennis  B. Vass was elected as Treasurer & Principal Financial
            Officer effective February 21, 1996.  Prior to the appointment
            of  Mr. Vass as Treasurer of the Company in February 1995,  he
            was  employed by Consumers Power Company as Financial Projects
            Director  and  by  the Company in April 1991,  as  Manager  of
            Finance.
     
     
Item 11.  Executive Compensation

      Information  regarding executive compensation and transactions  is
included in Exhibit 99 and is incorporated herein by reference.


Item 12.  Security Ownership of Certain Beneficial Owners and Management

      Information  regarding security ownership  of  certain  beneficial
owners  and  management is included in Exhibit 99  and  is  incorporated
herein by reference.


Item 13.  Certain Relationships and Related Transactions

       Information   regarding   certain   relationships   and   related
transactions  is  included in Exhibit 99 and is incorporated  herein  by
reference.

                            PART IV


Item  14.  Exhibits, Financial Statement Schedules and Reports on Form 8-K

                                                                     Page No.

(a)  1.   Financial Statements -

          Included in Part II of this report -

          Report of Management.                                       59 - 60

          Report of Independent Public Accountants.                      61

          Consolidated Statements of Income for the
          years ended December 31, 1995, 1994 and 1993.                  62

          Consolidated Statements of Retained Earnings
          for the years ended December 31, 1995, 1994 and 1993.          63

          Consolidated Balance Sheets at December 31, 1995 
          and 1994.                                                   64 - 65

          Consolidated Statements of Capitalization at
          December 31, 1995 and 1994.                                    66

          Consolidated Statements of Cash Flows for the
          years ended December 31, 1995, 1994 and 1993.                  67

          Notes to Consolidated Financial Statements.                 68 - 97


(a)  2.   Financial Statement Schedules -

          Included in Part IV of this report -

          Schedule II -  Valuation and Qualifying Accounts 
                         and Reserves for the years ended 
                         December 31, 1995, 1994 and 1993.              103


          Other schedules are omitted as not required under 
          Rules of Regulation S-X.

(a)  3.   Exhibits -

          See Exhibit Index beginning on page 106.


(b)       Reports on Form 8-K -


          Items Reported   Financial Statements        Date of Report    
                                                               
                5,7              None               February 9, 1996  (1)
                 7               None               December 8, 1995  (2)
                5,7              None               November 10, 1995 (3)
                                    
                                    
(1)  The  Form  8-K  report  was filed on February  20,  1996  with  the
     earliest event reported occurring on February 9, 1996.

(2)  The  Form  8-K  report  was filed on December  11,  1995  with  the
     earliest event reported occurring on December 8, 1995.

(3)  The  Form  8-K  report  was filed on November  21,  1995  with  the
     earliest event reported occurring on November 10, 1995.



                           IES UTILITIES INC.

       SCHEDULE II--VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

          FOR THE YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993



          Column A                                 Column B         Column E

                                                   Balance           Balance
         Description                              January 1        December 31
                                                          (in thousands)
                                                                    
1995:
   Accumulated provision for
    uncollectible accounts                        $    650           $    676

   Accumulated provision for rate refunds         $     -            $    106

1994:
   Accumulated provision for
    uncollectible accounts                        $    409           $    650

   Accumulated provision for rate refunds         $  8,670           $     -

1993:
   Accumulated provision for
    uncollectible accounts                        $    567           $    409

   Accumulated provision for rate refunds         $  9,020           $  8,670




                           SIGNATURES

      Pursuant  to  the  requirements of Section  13  or  15(d)  of  the
Securities  Exchange Act of 1934, the registrant has  duly  caused  this
report  to  be  signed on its behalf by the undersigned, thereunto  duly
authorized, on the 8th day of March 1996.


                                   IES UTILITIES INC.
                                      (Registrant)



                                   By /s/           Lee Liu
                                                    Lee Liu
                                        Chairman of the Board, President &
                                              Chief Executive Officer



      Pursuant  to  the requirements of the Securities Exchange  Act  of
1934,  this  report  has been signed below by the following  persons  on
behalf   of   the  registrant  and  in  the  capacities   indicated   on
March 8, 1996:




/s/  Lee Liu                        Chairman of  the  Board, President &
     Lee Liu                        Chief Executive Officer
                                    (Principal Executive Officer)


/s/  Dennis B. Vass                 Treasurer and  Principal Financial Officer
     Dennis B. Vass                 (Principal  Financial Officer)



/s/  Richard A. Gabbianelli         Controller  &  Chief Accounting Officer
     Richard A. Gabbianelli         (Principal Accounting Officer)



/s/  C.R.S. Anderson                Director
     C.R.S. Anderson


/s/  J. Wayne Bevis                 Director
     J. Wayne Bevis


                                    Director
     Dr. George Daly


/s/  G. Sharp Lannom, IV            Director
     G. Sharp Lannom, IV


/s/  Jack R. Newman                 Director
     Jack R. Newman


/s/  Robert D. Ray                  Director
     Robert D. Ray


/s/  David Q. Reed                  Director
     David Q. Reed


/s/  Henry Royer                    Director
     Henry Royer


/s/  Robert W. Schlutz              Director
     Robert W. Schlutz


/s/  Anthony R. Weiler              Director
     Anthony R. Weiler

                              EXHIBIT INDEX


The  Exhibits designated by an asterisk are filed herewith and all other
Exhibits as stated to be filed are incorporated herein by reference.

Exhibit


     3(a)  Articles  of  Incorporation of  the  Registrant,
           Amended and Restated as of January 6, 1994 (Filed as Exhibit 4(b)
           to Company's Current Report on Form 8-K, dated January 7, 1994).

  *  3(b)  Bylaws of Registrant, as amended February 6, 1996.

     4(a)  Indenture of Mortgage and Deed of Trust, dated as
           of September 1, 1993, between the Company (formerly Iowa Electric
           Light  and  Power  Company (IE)) and The First National  Bank  of
           Chicago,  as  Trustee (Mortgage) (Filed as Exhibit 4(c)  to  IE's
           Form 10-Q for the quarter ended September 30, 1993).

     4(b)  Supplemental Indentures to the Mortgage:

       Number           Dated as of        IE File Reference    Exhibit
                                                                
   First             October 1, 1993      Form 10-Q, 11/12/93   4(d)
   Second            November 1, 1993     Form 10-Q, 11/12/93   4(e)
   Third             March 1, 1995        Form 10-Q, 5/12/95    4(b)

     4(c)  Indenture of Mortgage and Deed of Trust, dated as
           of  August  1, 1940, between the Company (formerly  IE)  and  The
           First  National Bank of Chicago, Trustee (1940 Indenture)  (Filed
           as  Exhibit  2(a)  to IE's Registration Statement,  File  No.  2-
           25347).

     4(d)  Supplemental Indentures to the 1940 Indenture:


  Number             Dated as of          IE File Reference     Exhibit
                                                                
  First              March 1, 1941        2-25347               2(a)
  Second             July 15, 1942        2-25347               2(a)
  Third              August 2, 1943       2-25347               2(a)
  Fourth             August 10, 1944      2-25347               2(a)
  Fifth              November 10, 1944    2-25347               2(a)
  Sixth              August 8, 1945       2-25347               2(a)
  Seventh            July 1, 1946         2-25347               2(a)
  Eighth             July 1, 1947         2-25347               2(a)
  Ninth              December 15, 1948    2-25347               2(a)
  Tenth              November 1, 1949     2-25347               2(a)
  Eleventh           November 10, 1950    2-25347               2(a)
  Twelfth            October 1, 1951      2-25347               2(a)
  Thirteenth         March 1, 1952        2-25347               2(a)
  Fourteenth         November 5, 1952     2-25347               2(a)
  Fifteenth          February 1, 1953     2-25347               2(a)
  Sixteenth          May 1, 1953          2-25347               2(a)
  Seventeenth        November 3, 1953     2-25347               2(a)
  Eighteenth         November 8, 1954     2-25347               2(a)
  Nineteenth         January 1, 1955      2-25347               2(a)
  Twentieth          November 1, 1955     2-25347               2(a)
  Twenty-first       November 9, 1956     2-25347               2(a)
  Twenty-second      November 6, 1957     2-25347               2(a)
  Twenty-third       November 4, 1958     2-25347               2(a)
  Twenty-fourth      November 3, 1959     2-25347               2(a)
  Twenty-fifth       November 1, 1960     2-25347               2(a)
  Twenty-sixth       January 1, 1961      2-25347               2(a)
  Twenty-seventh     November 7, 1961     2-25347               2(a)
  Twenty-eighth      November 6, 1962     2-25347               2(a)
  Twenty-ninth       November 5, 1963     2-25347               2(a)
  Thirtieth          November 4, 1964     2-25347               2(a)
  Thirty-first       November 2, 1965     2-25347               2(a)
  Thirty-second      September 1, 1966    Form 10-K, 1966       4.10
  Thirty-third       November 30, 1966    Form 10-K, 1966       4.10
  Thirty-fourth      November 7, 1967     Form 10-K, 1967       4.10
  Thirty-fifth       November 5, 1968     Form 10-K, 1968       4.10
  Thirty-sixth       November 1, 1969     Form 10-K, 1969       4.10
  Thirty-seventh     December 1, 1970     Form 8-K, 12/70       1
  Thirty-eighth      November 2, 1971     2-43131               2(g)
  Thirty-ninth       May 1, 1972          Form 8-K, 5/72        1
  Fortieth           November 7, 1972     2-56078               2(i)
  Forty-first        November 7, 1973     2-56078               2(j)
  Forty-second       September 10, 1974   2-56078               2(k)
  Forty-third        November 5, 1975     2-56078               2(l)
  Forty-fourth       July 1, 1976         Form 8-K, 7/76        1
  Forty-fifth        November 1, 1976     Form 8-K, 12/76       1
  Forty-sixth        December 1, 1977     2-60040               2(o)
  Forty-seventh      November 1, 1978     Form 10-Q, 6/30/79    1
  Forty-eighth       December 1, 1979     Form S-16, 2-65996    2(q)
  Forty-ninth        November 1, 1981     Form 10-Q, 3/31/82    2
  Fiftieth           December 1, 1980     Form 10-K, 1981       4(s)
  Fifty-first        December 1, 1982     Form 10-K, 1982       4(t)
  Fifty-second       December 1, 1983     Form 10-K, 1983       4(u)
  Fifty-third        December 1, 1984     Form 10-K, 1984       4(v)
  Fifty-fourth       March 1, 1985        Form 10-K, 1984       4(w)
  Fifty-fifth        March 1, 1988        Form 10-Q, 5/12/88    4(b)
  Fifty-sixth        October 1, 1988      Form 10-Q, 11/10/88   4(c)
  Fifty-seventh      May 1, 1991          Form 10-Q, 8/13/91    4(d)
  Fifty-eighth       March 1, 1992        Form 10-K, 1991       4(c)
  Fifty-ninth        October 1, 1993      Form 10-Q, 11/12/93   4(a)
  Sixtieth           November 1, 1993     Form 10-Q, 11/12/93   4(b)
  Sixty-first        March 1, 1995        Form 10-Q, 5/12/95    4(a)


     4(e)  Indenture or Deed of Trust dated as of February 1,
           1923,  between the Company (successor to Iowa Southern  Utilities
           Company  (IS) as result of merger of IS and IE) and The  Northern
           Trust Company (The First National Bank of Chicago, successor) and
           Harold  H. Rockwell (Richard D. Manella, successor), as  Trustees
           (1923 Indenture) (Filed as Exhibit B-1 to File No. 2-1719).

     4(f)  Supplemental Indentures to the 1923 Indenture:


   Dated as of            File Reference    Exhibit
                                            
   May 1, 1940            2-4921            B-1-k
   May 2, 1940            2-4921            B-1-l
   October 1, 1945        2-8053            7(m)
   October 2, 1945        2-8053            7(n)
   January 1, 1948        2-8053            7(o)
   September 1, 1950      33-3995           4(e)
   February 1, 1953       2-10543           4(b)
   October 2, 1953        2-10543           4(q)
   August 1, 1957         2-13496           2(b)
   September 1, 1962      2-20667           2(b)
   June 1, 1967           2-26478           2(b)
   February 1, 1973       2-46530           2(b)
   February 1, 1975       2-53860           2(aa)
   July 1, 1975           2-54285           2(bb)
   September 2, 1975      2-57510           2(bb)
   March 10, 1976         2-57510           2(cc)
   February 1, 1977       2-60276           2(ee)
   January 1, 1978        0-849             2
   March 1, 1979          0-849             2
   March 1, 1980          0-849             2
   May 31, 1986           33-3995           4(g)
   July 1, 1991           0-849             4(h)
   September 1, 1992      0-849             4(m)
   December 1, 1994       0-4117-1          4(f)


     4(g)  Indenture (For Unsecured Subordinated Debt Securities),
           dated  as of December 1, 1995, between the Company and The  First
           National  Bank  of  Chicago, as Trustee (Subordinated  Indenture)
           (Filed  as  Exhibit  4(i) to the Company's  Amendment  No.  1  to
           Registration Statement, File No. 33-62259).

     4(h)  Officer's Certificate establishing the terms  of  new
           Series  of  Subordinated  Debentures  (Filed  as  Exhibit  4   to
           Utilities' Current Report on Form 8-K, dated December 8, 1995).

    10(a)  Operating  and Transmission Agreement between  Central  Iowa
           Power Cooperative and IE (Filed as Exhibit 10(q) to IE's Form 10-
           K for the year 1990).

    10(b)  Duane Arnold Energy Center Ownership Participation
           Agreement   dated  June  1,  1970  between  Central  Iowa   Power
           Cooperative,  Corn  Belt Power Cooperative  and  IE.   (Filed  as
           Exhibit 5(kk) to IE's Registration Statement, File No. 2-38674).

    10(c)  Duane  Arnold Energy Center Operating  Agreement
           dated  June 1, 1970 between Central Iowa Power Cooperative,  Corn
           Belt  Power Cooperative and IE.  (Filed as Exhibit 5(ll) to  IE's
           Registration Statement, File No. 2-38674).

    10(d)  Duane  Arnold  Energy  Center  Agreement   for
           Transmission,  Transformation, Switching and  Related  Facilities
           dated  June 1, 1970 between Central Iowa Power Cooperative,  Corn
           Belt  Power Cooperative and IE.  (Filed as Exhibit 5(mm) to  IE's
           Registration Statement, File No. 2-38674).

    10(e)  Basic Generating Agreement dated April 16,  1975
           between  Iowa  Public  Service  Company,  Iowa  Power  and  Light
           Company,  Iowa-Illinois Gas and Electric Company and IS  for  the
           joint  ownership  of Ottumwa Generating Station-Unit  1  (OGS-1).
           (Filed as Exhibit 1 to IE's Form 10-K for the year 1977).

    10(f)  Addendum  Agreement  to  the  Basic  Generating
           Agreement  for OGS-1 dated December 7, 1977 between  Iowa  Public
           Service  Company,  Iowa-Illinois Gas and Electric  Company,  Iowa
           Power  and  Light  Company, IS and IE for  the  purchase  of  15%
           ownership  in OGS-1.  (Filed as Exhibit 3 to IE's Form  10-K  for
           the year 1977).

    10(g)  Second Amended and Restated Credit Agreement dated
           as  of September 17, 1987 between Arnold Fuel, Inc. and the First
           National Bank of Chicago and the Amended and Restated Consent and
           Agreement  dated  as  of September 17, 1987  by  IE.   (Filed  as
           Exhibit 10(j) to IE's Form 10-K for the year 1987).


Management Contracts and/or Compensatory Plans (Exhibits 10(h) through 10(q))


    10(h)  Supplemental Retirement Plan.  (Filed as Exhibit
           10(l) to Industries' Form 10-K for the year 1987).

    10(i)  Management Incentive Compensation Plan.  (Filed as
           Exhibit 10(m) to Industries' Form 10-K for the year 1987).

    10(j)  Key Employee Deferred Compensation Plan.  (Filed
           as Exhibit 10(n) to Industries' Form 10-K for the year 1987).

    10(k)  Long-Term Incentive Plan.  (Filed as Exhibit A to
           Industries' Proxy Statement dated March 20, 1995).

    10(l)  Executive Guaranty Plan.  (Filed as Exhibit 10(p)
           to Industries' Form 10-K for the year 1987).

    10(m)  Executive Change of Control Severance Agreement.
           (Filed  as  Exhibit 10(s) to Industries' Form 10-K for  the  year
           1989).

    10(n)  Amendments to Key Employee Deferred Compensation
           Agreement  for Directors.  (Filed as Exhibit 10(u) to Industries'
           Form 10-Q for the quarter ended March 31, 1990).

    10(o)  Amendments to Key Employee Deferred Compensation
           Agreement  for  Key  Employees.   (Filed  as  Exhibit  10(v)   to
           Industries' Form 10-Q for the quarter ended March 31, 1990).

    10(p)  Amendments to Management Incentive  Compensation
           Plan.   (Filed as Exhibit 10(y) to Industries' Form 10-Q for  the
           quarter ended March 31, 1990).

    10(q)  Director Retirement Plan.  (Filed as Exhibit 10(t)
           to Industries' Form 10-K for the year 1993).

    10(r)  Agreement for Purchase and Sale of Certain Assets
           and  Real Estate and Assignment of Easements, Leases and Licenses
           between Union Electric Company (Seller) and IE (Buyer). (Filed as
           Exhibit 10(t) to IE's Form 10-K for the year 1991).

    10(s)  Receivables Purchase and Sale Agreement dated as of June 30,
           1989,  as  Amended and Restated as of April 15, 1994,  among  IES
           Utilities Inc. (as Seller) and CIESCO L.P. (as the Investor)  and
           Citicorp North America, Inc. (as Agent).  (Filed as Exhibit 10(a)
           to the Company's Form 10-Q for the quarter ended March 31, 1994).
  
    10(t)  Guaranty (IES Utilities Trust No. 1994-A) from IES Utilities
           Inc.,  dated as of June 29, 1994. (Filed as Exhibit 10(b) to  the
           Company's Form 10-Q for the quarter ended June 30, 1994 (File No.
           0-4117-1)).
  
    10(u)  Agreement and Plan of Merger between IE and IS dated  as  of
           June  4, 1993 (Agreement and Plan of Merger) (Filed as Exhibit  2
           to  the Company's Current Report on Form 8-K, dated June 4,  1993
           (File No. 0-4117-1)).
  
    10(v)  Amendment 1 dated June 16, 1993, to the Agreement  and  Plan
           of Merger (Filed as Exhibit 2(b) to the IE Registration Statement
           on Form S-3, dated September 14, 1993 (File No. 33-68796)).
  
    10(w)  Amendment  2  dated September 8, 1993, to the Agreement  and
           Plan  of  Merger  (Filed as Exhibit 2(c) to the  IE  Registration
           Statement  on  Form  S-3,  dated September  14,  1993  (File  No.
           33-68796)).
  
    10(x)  Amendment  3 dated September 27, 1993, to the Agreement  and
           Plan of Merger (Filed as Exhibit 2(d) to the IE Current Report on
           Form 8-K, dated December 9, 1993 (File No. 0-4117-1)).
  
    10(y)  Copy  of Coal Supply Agreement, dated July 27, 1977, between
           IS  and  Sunoco  Energy  Development Co. (former parent of Cordero 
           Mining Co.), and  letter  memorandum thereto, dated October 29,
           1984, relating to the purchase of coal supplies  for  the  fuel
           requirements at the  Ottumwa  Generating Station.  (Filed as
           Exhibit 10-A-4 to File No. 33-3995).

 *  12     Ratio of Earnings to Fixed Charges.

 *  23     Consent of Independent Public Accountants.

 *  27     Financial Data Schedule.

 *  99     Director and Officer Information.


  Note:    Pursuant to (b)(4)(iii)(A) of Item 601  of  Regulation
           S-K,  the  Company has not filed as an exhibit to this Form  10-K
           certain  instruments with respect to long-term debt that has  not
           been  registered  if  the total amount of  securities  authorized
           thereunder does not exceed 10% of total assets of the Company but
           hereby  agrees to furnish to the Commission on request  any  such
           instruments.