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 1-9187

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


                 Iowa                              42-1271452
 (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

Common Stock, no par value                      New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:  None

Indicate by check mark whether the registrant (1) has filed all  reports
required  to be filed by Section 13 or 15(d) of the Securities  Exchange
Act  of  1934 during the preceding 12 months (or for such shorter period
that the registrant was required to file such reports), and (2) 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 approximately $840,387,024  based
upon  the  Composite Tape closing price as reported in The  Wall  Street
Journal.  (For this purpose only, the individuals listed under "Security
Ownership  of Management" in the Definitive Proxy Statement incorporated
herein by reference are considered to be affiliates.)

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

              Common Stock, no par value - 29,614,679 shares

                   Documents Incorporated by Reference

                                              Part of this Form 10-K into
        Document                             Which Document is Incorporated

Definitive proxy statement to be filed
within 120 days of December 31, 1995                       III

                            PART I

Item l.  Business

      IES Industries Inc.

      IES  Industries  Inc. (Industries) is a holding  company
which  is  incorporated under the laws  of  Iowa.  Industries'
wholly-owned  subsidiaries are IES Utilities Inc.  (Utilities)
and IES Diversified Inc. (Diversified). Utilities is primarily
an  electric and natural gas utility company operating in  the
State of Iowa which serves approximately 333,000 electric  and
174,000  natural  gas retail customers as well  as  30  resale
customers in more than 550 Iowa communities.  Diversified is a
holding   company  for  non-utility  subsidiaries  which   are
primarily  engaged  in the energy-related, transportation  and
real  estate development businesses.  Industries' consolidated
assets and earnings are predominantly those of Utilities.

     Utilities

     Utilities 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.

      Utilities'  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.

      Utilities' 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   Utilities,
including  transported  volumes, increased  or (decreased)  4.8%,
(2.7%) and 5.3% during the years 1995-1993, respectively.

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

      The  approximate percentages of Utilities'  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
Utilities Only", Item 7. "Management's Discussion and Analysis
of  the Results of Operations and Financial Condition" and the
Electric and Gas Operating Comparisons.

      Diversified

      Other than Utilities' unregulated investments, the  non-
utility   operations  of  the  Company  are  organized   under
Diversified.   Diversified is a holding company whose  wholly-
owned  subsidiaries  include  IES  Transportation  Inc.   (IES
Transportation),  IES  Energy  Inc.  (IES  Energy)   and   IES
Investments Inc. (IES Investments).

      IES  Transportation is a holding company  whose  wholly-
owned  subsidiaries at December 31, 1995, included  the  Cedar
Rapids  and  Iowa  City  Railway  Company  (CRANDIC)  and  IES
Transfer  Services  Inc. (Transfer).  The  operations  of  IES
Railcar  Service  Center Inc. (Railcar) were  discontinued  on
December  31,  1995,  and the company was dissolved.   CRANDIC
assumed ownership of the Railcar assets which will allow it to
expand  the  scope of its services.  CRANDIC is  a  short-line
railway which renders freight service between Cedar Rapids and
Iowa  City.   Transfer's operations include  transloading  and
storage  services.  IES Transportation also has a  75%  equity
investment in IEI Barge Services, Inc. (Barge) which  provides
barge  terminal and hauling service on the Mississippi  River.
In  addition, IES Transportation has investments in  two  Iowa
railroad   companies.   IES  Transportation's  1995  operating
revenues and assets at December 31, 1995 were as follows:

                            Operating           
                            Revenues         Assets
                                   (in 000's)
                                         
     CRANDIC                $ 16,786        $ 37,811
     Railcar *                 4,690             -
     Barge                     2,014           8,177
     Transfer                    157             833
     Other (including 
            eliminations)        -               380
                            $ 23,647        $ 47,201

      *  Operations were discontinued as of December 31, 1995.


      IES  Energy  is  a  holding company  whose  wholly-owned
subsidiaries at December 31, 1995, included Industrial  Energy
Applications,  Inc.  (IEA) and Whiting  Petroleum  Corporation
(Whiting).   IEA offers commodities-based and facilities-based
energy  services  for customers, including purchasing  energy,
standby  generation,  cogeneration, steam production,  propane
air  systems  and  pipeline bypass.  Whiting is  organized  to
purchase,  develop and produce crude oil and natural  gas,  in
part   through   the  formation  and  operation   of   limited
partnerships.   (IES Investments also has several  investments
in  foreign entities, including equity ownerships in  two  New
Zealand  electric  distribution entities,  a  loan  to  a  New
Zealand  company and an investment in an international venture
capital fund.  These investments are considered energy-related
investments for management purposes and therefore are included
in  the following schedule as Foreign Entities).  IES Energy's
1995  operating revenues and assets at December 31, 1995  were
as follows:

                             Operating           
                             Revenues          Assets
                                     (in 000's)
                                        
     IEA                    $  60,071        $  29,124
     Whiting                   48,423          116,731
     Foreign Entities             -             24,770
     Other (including 
            eliminations)        (285)            (447)
                            $ 108,209        $ 170,178

     IES Investments is a holding company whose primary wholly-
owned  subsidiaries at December 31, 1995, included  Iowa  Land
and Building Company (Iowa Land), IES Investco Inc. (Investco)
and  Village  Lakeshares,  Inc. (Lakeshares).   Iowa  Land  is
organized  to  pursue  real  estate and  economic  development
activities  in  Utilities' service territory.  Investco  is  a
holding  company for certain equity investments and  currently
has  no operating revenues.  The gains and losses on the  sale
of  such  investments are recorded in "Miscellaneous, net"  in
the  Consolidated  Statements  of  Income.   Lakeshares  is  a
holding company for resort properties in Iowa.  Southern  Iowa
Manufacturing Company was sold by IES Investments during 1995.

      IES Investments had a $9.2 million investment in McLeod,
Inc.,   a   holding  company  for  various  telecommunications
businesses,  at December 31, 1995.  IES Investments  also  has
direct  and  indirect equity interests in various real  estate
ventures,  primarily concentrated in Cedar Rapids,  and  holds
other  passive  investments.  IES Investments' 1995  operating
revenues  and  assets  at December 31, 1995,  other  than  the
energy-related  investments  in  foreign  entities,  were   as
follows:

                             Operating           
                             Revenues          Assets
                                     (in 000's)
                                        
     Iowa Land               $  2,362        $  8,360
     Investco                     -             2,379
     Lakeshares                 4,696          12,250
     Real estate ventures       3,519          24,850
     Other (including 
            eliminations)         615           6,770
                             $ 11,192        $ 54,609

      Refer  to Note 14 of the Notes to Consolidated Financial
Statements for a further discussion of Industries' segments of
business.


Other Information Relating to the Company

      PROPOSED  MERGER  OF  THE  COMPANY.   The  Company,  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
Utilities,  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  company   of
Utilities, 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  the Company 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 the Company, WPLH and
IPC  divest their gas utility properties, and possibly certain
non-utility  ventures  of   the Company  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 $1.6 billion  and  are
summarized as follows:

                                           Capital  Requirements
                             1996       1997       1998       1999       2000
                                              (in thousands)
Construction and                                                    
   acquisition expenditures -
Utilities -                                                         
  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 Utilities'
  expenditures             164,317    184,962    175,812    161,446    137,390

                                                                    
Diversified and subsidiaries -
  Whiting                   28,575     29,300     26,300     26,800     25,150
  IEA                        8,100     20,000     29,400     31,000     31,000
  Foreign entities          38,700     47,000     20,000     20,000     20,000
  Other                      5,670      1,756      3,922      7,939      1,858
Total Diversified 
expenditures                81,045     98,056     79,622     85,739     78,008
Total construction                                                  
  and acquisition 
  expenditures             245,362    283,018    255,434    247,185    215,398
                                                                    
Energy efficiency                                                   
  expenditures              13,263     14,325     15,221     14,439     13,235
Long-term debt maturities
  and sinking funds:
    Utilities               15,770      8,690        690     50,690     67,246
    Diversified                -          -          -      124,245        -
    Other subsidiaries         307        333        360     10,366         35
                            16,077      9,023      1,050    185,301     67,281
Total capital 
  requirements           $ 274,702  $ 306,366  $ 271,705  $ 446,925  $ 295,914

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


     Approximately 30% of Utilities' 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 Utilities' nuclear generating station, the
Duane Arnold Energy Center (DAEC).

     The Diversified construction and acquisition expenditures
for  the  five year period 1996-2000 are primarily related  to
domestic   and   international   energy-related   expenditures
relating  to  business  expansions  and  the  acquisition   of
additional properties and businesses.

      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.   Because  of  its ownership  of  Utilities,
Industries is a "holding company" as defined by the 1935  Act.
However, Industries claims exemption from regulation under the
1935  Act  (except for Section 9(a)2 thereof,  which  requires
that  any  acquisition of securities of a utility  company  by
Industries   be  approved  by  the  Securities  and   Exchange
Commission)  on  the basis that Industries and  Utilities  are
both  organized in the same state and Utilities  conducts  its
business  in that state.  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.

      Utilities 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.

      Utilities 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  Utilities'  wholesale  and  off-system   sales
amounted to 6.3%, 6.9% and 9.0% of electric revenues for 1995-
1993,  respectively. Utilities' consolidated subsidiaries  are
not subject to regulation by the IUB or the FERC.

     Following consummation of the Proposed Merger, Interstate
Energy  will be subject to regulation by the Wisconsin  Public
Service  Commission  (WPSC), as WPLH and WP&L  are  currently.
The WPSC regulates, among other things, the type and amount of
investments in non-utility businesses.  The Company  does  not
expect  such  regulation to have a materially  adverse  effect
upon Interstate Energy following the Proposed Merger.

     EMPLOYEES.  At December 31, 1995, the Company had a total
of 2,635 (2,204 at Utilities) regular full-time employees.  At
December 31, 1995, Utilities had 1,152 employees subject to  6
collective  bargaining arrangements (824  of  these  employees
were  part  of  one  arrangement), CRANDIC  had  66  employees
subject to 4 collective bargaining arrangements and Barge  had
6 employees subject to 1 collective bargaining 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
$48.7  million of environmental liabilities ($46.4 million  at
Utilities),  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  Utilities  will  be
recovered   from  its  ratepayers  under  current   regulatory
principles.   Refer to Notes 12(a) and 12(g) of the  Notes  to
Consolidated  Financial Statements for additional  information
regarding  Utilities' 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,  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.

      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.

      Utilities  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.   Utilities  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.

      Utilities 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 Utilities for these FMGP sites will not have
a material adverse effect on its financial position or results
of   operations.   Refer  to  Note  12(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.  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.

      Utilities 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   Utilities   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, Utilities' share of the costs is estimated at $300,000,
which  is  included  in  the  $48.7 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.

      Whiting  is  responsible for certain  dismantlement  and
abandonment  costs related to various off-shore  oil  and  gas
properties, the most significant of which is located  off  the
coast  of California.  Whiting accrues these costs as reserves
are extracted and such costs are included in "Depreciation and
amortization"  in the Consolidated Statements  of  Income.   A
corresponding   environmental  liability,  $1.7   million   at
December  31,  1995, has been recognized in  the  Consolidated
Balance Sheets for the cumulative amount expensed.

      Refer  to Note 12 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.

Other Information Relating to Utilities Only

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

      ELECTRIC  OPERATIONS.   Utilities'  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.  Utilities' additional reserve obligation at  the
time  of the peak was 256,215 kilowatts and the net capability
of  Utilities'  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.

      Utilities 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
12(b) of the Notes to Consolidated Financial Statements for  a
discussion  of Utilities' firm contracts for the  purchase  of
capacity.

      Utilities 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.

      Utilities  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.

       Utilities  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 Utilities and CIPCO.

      Upon  consummation  of  the Proposed  Merger,  Utilities
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 Utilities 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  13  of  the  Notes  to  Consolidated
Financial Statements.

      FUEL SUPPLY.  The following table details the sources of
the  electricity  sold by Utilities 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%


      Utilities  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.

     Utilities' 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 Utilities 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.  Utilities expects to use the last  of
this uranium during the 1996 refueling outage.  Utilities  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 Utilities' 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, Utilities purchased a total  of  3,728,000
tons of coal for its generating plants.  At December 31, 1995,
Utilities  had  a weighted average of 63 days' usage  of  coal
inventory at its principal generating stations.

       Utilities  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
Utilities' minimum commitments.  Many of the contracts contain
provisions allowing Utilities to purchase additional  tons  of
coal.   Utilities  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.  Utilities believes that an ample supply of coal
is available in the spot market to meet its needs.

      Some of Utilities' 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
Utilities   are  recoverable  through  its  Energy  Adjustment
Clauses  (EAC).   See Note 1(k) 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 Utilities' 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
Utilities'  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.   Utilities
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 12(f) of the Notes  to
Consolidated   Financial  Statements  for  a   discussion   of
Utilities' 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, Utilities 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.   Utilities'  current  NRC
license for DAEC expires in 2014.

     The operation and design of nuclear power plants is under
constant  review by the NRC.  Utilities 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.  Utilities' 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.

       Utilities  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.
Utilities  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.  Utilities 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),  Utilities 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.   Utilities  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 Utilities' 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  Utilities is estimated to be less than the  cost  of
replacement power for one week.

      Utilities  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,  Utilities  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 12(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, Utilities 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.   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.  IEA
received  approval  in  the  same FERC  proceeding  to  market
electric  power  at  market based rates.  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.

      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.

     GAS OPERATIONS.  With the advent of FERC Order 636 (Order
636),  issued  in  1992, the nature of Utilities'  gas  supply
portfolio  has  changed.   Order  636,  among  other   things,
eliminated the interstate pipelines' obligation to  serve  and
now  requires Utilities to purchase virtually 100% of its  gas
supply requirements from non-pipeline suppliers. Utilities has
enhanced  access to competitively priced gas supply  and  more
flexible  transportation services as a result  of  Order  636.
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.

      Contracts with the pipelines subsequent to Order 636 are
comprised  primarily of firm transportation, firm storage  and
no-notice   service.   Firm  transportation  contracts   grant
Utilities  access to firm pipeline capacity which is  used  to
transport  gas  supplies from non-pipeline suppliers  on  peak
day.   Firm  storage service allows Utilities 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,  Utilities requests and the pipelines deliver  the
gas  back on a firm basis.  No-notice service grants Utilities
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.

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

      Contracts  assigned  to  Utilities  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  Utilities  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 Utilities' suppliers are  subject  to
regulation  by  the  FERC.  A purchased gas adjustment  clause
(PGA) allows Utilities to adjust customer rates as a result of
changes  in the cost of gas purchased.  See Note 1(k)  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):
    IES Utilities Inc.:
       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
           Total revenues             137,292    139,033    154,318    139,455    131,018    125,275
    Industrial Energy 
      Applications, Inc.               53,047     26,536     27,605     27,627     15,219      6,808
                                    $ 190,339  $ 165,569  $ 181,923  $ 167,082  $ 146,237  $ 132,083


Energy sales (000's dekatherms):
   IES Utilities Inc.:
      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%
   Industrial Energy 
     Applications, Inc.*               31,916     14,443     12,493     14,830      7,666      4,465      48.2%
                                       71,721     52,418     51,499     51,865     44,795     40,951      11.9%
   *IEA energy sales that are 
      also transported volumes  
      of IES Utilities Inc.             4,232      3,134      2,883      2,955      1,824      1,336


Operating statistics for 
  IES Utilities Inc.:
    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
  for IES Utilities Inc.
  (excluding transported volumes)   $    4.62  $    4.69  $    4.78  $    4.61  $    4.17  $    4.15       2.2%

</TABLE>

Item 2. Properties

     Industries has no significant properties other than common stock of
affiliates,  temporary  cash investments and  cash  surrender  value  of
corporate life insurance policies.

      Utilities'  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  Utilities' 70% ownership interest in this  520,000
          Kw generating station.  The plant is operated by Utilities.
     
     (2)  Represents  Utilities' 48% ownership interest in this  715,500
          Kw generating station.  The plant is operated by Utilities.
          
     (3)  Represents  Utilities' 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  Utilities,
operating from 34,000 to 345,000 volts, approximated 4,409 circuit miles
(all  located  in  Iowa).  Utilities 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.

     Subsidiaries other than Utilities also own property which primarily
represents investments in transportation, energy-related and real estate
properties.

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

Item 3.  Legal Proceedings

      Industries,  Diversified, IES Energy, MicroFuel  Corporation  (the
Corporation)  now known as Ely, Inc. in which IES Energy  has  a  69.40%
equity  ownership,  and  other parties have been  sued  in  Linn  County
District  Court  in Cedar Rapids, Iowa, by Allen C.  Wiley.   Mr.  Wiley
claims  money damages on various tort and contract theories arising  out
of  the  1992 sale of the assets of the Corporation, of which Mr.  Wiley
was  a  director and shareholder.  All of the defendants in Mr.  Wiley's
suit  answered  the  complaint  and  denied  liability.  Industries  and
Diversified  were  dismissed  from the suit  in  a  motion  for  summary
judgment.   In addition a motion for summary judgement has  reduced  Mr.
Wiley's  claims  against the remaining parties to  breach  of  fiduciary
duty.   All of the defendants believe that the claims are without  merit
and  are  vigorously contesting them.  The trial has been  continued  to
April 8, 1996,  but will likely be continued again given the decision in
the appeal related to a separate suit discussed below.

      The  Corporation commenced a separate suit to determine  the  fair
value of Mr. Wiley's shares under Iowa Code section 490.  A decision was
issued on August 31, 1994, by the Linn County District Court ruling that
the  value  of Mr. Wiley's shares was $377,600 based on a  40  cent  per
share valuation. The Corporation contended that the value of Mr. Wiley's
shares  was 2.5 cents per share.  The Decision was appealed to the  Iowa
Supreme  Court  by the Corporation on a number of issues, including  the
Corporation's position that the trial court erred as a matter of law  in
discounting the testimony of the Corporation's expert witness.  The Iowa
Supreme  Court  assigned  the case to the  Iowa  Court  of  Appeals.  On
February 2, 1996, the Iowa Court of Appeals reversed the District  Court
ruling   after  determining the District Court erred in discounting  the
expert  testimony.   Mr.  Wiley  has  a  limited  time  period  to  make
application  to  the Supreme Court for further review of  the  Court  of
Appeals  ruling,  otherwise the case is remanded back  to  the  District
Court  for consideration of the expert testimony, but with no additional
evidence  being taken. Neither Mr. Wiley or his counsel  have  indicated
whether they will ask for further review.

      Reference  is made to Notes 3 and 12 of the Notes to  Consolidated
Financial Statements for a discussion of Utilities' rate proceedings and
the  Company's 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

      (a)    Price Range of Common Stock and Dividends Declared

      IES  Industries  Common Stock is listed  on  the  New  York  Stock
Exchange (NYSE) under the symbol "IES."  The table below sets forth, for
the  calendar quarters indicated, the reported high and low sales prices
of  IES  Industries Common Stock as reported on the NYSE Composite  Tape
based  on  published financial sources, and the dividends  declared  per
share on IES Industries Common Stock.

IES Industries Common Stock

                            High Sale       Low Sale       Dividend (i)
1995                                                       
    First Quarter           $ 27 5/8     $ 24 5/8          $ .525   
    Second Quarter            26 3/8       20 3/8            .525   
    Third Quarter             26 3/4       21 3/8            .525   
    Fourth Quarter            28 1/2       25 7/8            .525   
                                                           
1994                                                       
    First Quarter             31 3/8       27                .525   
    Second Quarter            29           25 1/2            .525   
    Third Quarter             28 3/8       24 7/8            .525   
    Fourth Quarter            26 5/8       24 3/4            .525   



          (i)   The Company has paid regular quarterly dividends on  its
          common  stock  since  April 1, 1950.  Although  the  Company's
          practice  has been to pay dividends quarterly, the  timing  of
          payment   and  amount  of  future  dividends  are  necessarily
          dependent  upon  earnings, financial  requirements  and  other
          factors.


     (b)  Approximate Number of Equity Security Holders

                                           Approximate Number of Record
            Title of Class               Holders (as of December 31, 1995)
                              
       Common Stock, no par value                       29,731



     (c)  Restriction on Payment of Dividends

      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.


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  Utilities'  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 1990 results were  affected
by a pre-tax gain of $66 million on the sale of Telecom*USA stock.

      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>

                                            1995         1994         1993         1992          1991         1990
<S>                                   <C>          <C>          <C>          <C>           <C>          <C>
Income statement data (000's):
    Operating revenue                  $   851,010  $   785,864  $   801,266  $   678,296   $   661,538  $   624,214
    Operating income                       151,712      147,933      151,269      109,024       103,357       98,043
    Net income                              64,176       66,818       67,938       48,711        44,657       80,330 (1)

Common stock data (per share
    except percentages):
       Earnings                        $      2.20  $      2.34  $      2.45  $      1.92   $      1.85  $      3.37 (1)
       Dividends declared                     2.10         2.10         2.10         2.10          2.03         1.82
       Return on average common equity        10.7%        11.5%        12.4%        10.3%          9.7%        18.4%
       Market price at year-end        $     26.50  $     25.25  $     31.25  $     29.50   $     27.25  $     27.75
       Book value at year-end                20.75        20.56        20.21        18.89         19.07        19.15
       Ratio of market price to book 
          value at year-end                    128%         123%         155%         156%          143%         145%

Capitalization:
    Common equity                               49%          50%          51%          48%           50%          53%
    Preferred and preference stock               2            2            2            2             3            3
    Long-term debt                              49           48           47           50            47           44
                                               100%         100%         100%         100%          100%         100%


Other selected financial data:
    Total assets (000's)               $ 1,985,591  $ 1,849,093  $ 1,699,819  $ 1,594,382   $ 1,448,492  $ 1,400,802
    Non-utility assets (000's) (2)         282,433      206,411      153,853      153,491       144,382      144,591
    Long-term obligations (000's)          656,543      626,011      577,611      553,257       507,921      462,798
    Construction and acquisition
       expenditures (000's)                218,099      206,548      169,017      192,520 (3)   120,218      104,194
    Times interest earned before
       income taxes                           3.12         3.38         3.38         2.63          2.69         4.45

Selected financial data for
    IES Utilities Inc.:
       Utility plant in 
         service (000's)               $ 2,172,378  $ 2,042,179  $ 1,932,558  $ 1,852,733   $ 1,680,108  $ 1,587,886
       Accumulated depreciation of
          utility plant in 
            service (000's)                950,324      880,888      813,312      759,754       691,015      639,211
       Construction and acquisition
          expenditures (000's) (4)         129,444      148,103      113,212      171,013 (3)   105,009       95,075
       Times interest earned before
          income taxes                        3.26         3.39         3.64         2.67          2.93         3.04
       Electric Kwh sales (excluding 
          off-system) (000's)            9,783,514    9,291,575    8,905,522    7,132,671     7,244,209    6,880,136
       Gas Dth sales (including
          transported volumes) (000's)      39,805       37,975       39,006       37,035        37,129       36,486

(1)  Includes the effects of a $66 million pre-tax gain on sale 
     of Telecom*USA stock.
(2)  Includes non-utility assets of IES Utilities Inc.
(3)  Includes $61 million for the acquisition of the Iowa service 
     territory from Union Electric Company.
(4)  Includes acquisitions from affiliated companies and Utilities' 
     non-utility expenditures.
</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  Industries  Inc.  (Industries)  and   its
consolidated   subsidiaries  (collectively   the   Company).
Industries' wholly-owned subsidiaries are IES Utilities Inc.
(Utilities) and IES Diversified Inc. (Diversified).

               PROPOSED MERGER OF THE COMPANY
                              
      The  Company, 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 Company's 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 the Company 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 the Company,  WPLH
and  IPC  divest their gas utility properties, and  possibly
certain  non-utility  ventures of   the  Company  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 and financial condition from
the prior periods for the Company:

      The Company's net income decreased ($2.6) million  and
($1.1) million during 1995 and 1994, respectively.  Earnings
per  average  common share declined to $2.20  in  1995  from
$2.34  in 1994.  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
($0.33  per  share).   (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, which added  $0.18  to
earnings,   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  the  recording of certain property  write-downs  at
Diversified  and  a  $2.5 million contribution  to  the  IES
Industries Charitable Foundation.

     The Company's operating income increased or (decreased)
$3.8  million  and  ($3.3) 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(k)  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,
$0.07 per share, 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 increased or  (decreased)  as
compared with the prior year as follows:


                                          1995       1994
                                           (in millions)
                                            
Gas revenues:                               
    Utilities                          $  (1.7)    $ (15.3)
    Industrial Energy 
      Applications, Inc. (IEA)            26.5        (1.1)
                                       $  24.8     $ (16.4)


      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(k)  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.

      IEA's gas revenues increased in 1995 primarily due  to
an  increase  of  121% in gas volumes, partially  offset  by
lower  unit  gas  costs.  The significant  increase  in  gas
volumes  was due to heightened marketing efforts as well  as
expanding into additional regional markets.  IEA,  which  is
based in Cedar Rapids, IA, opened branch offices in Phoenix,
Denver,  St.  Louis and Atlanta in 1995.   The  decrease  in
IEA's  1994  gas  revenues  was  due  to  lower  gas  costs,
partially offset by a 16% increase in gas volumes.

Other Revenues   Other revenues increased $17.2 million  and
$14.1  million during 1995 and 1994, respectively, primarily
because  of increased revenues at Whiting Petroleum  Company
(Whiting).  Whiting's operations have expanded significantly
the last several years as a result of continued acquisitions
of  oil  and gas properties.  These increases were partially
offset as the result of the sale of several of Diversified's
subsidiaries  during 1994 and 1995.  The operations  of  the
subsidiaries  that  were sold were not  significant  to  the
results  of operations or financial position of the Company.
An increase in Utilities' steam revenues also contributed to
the 1995 increase.

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 Kwh 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 increased $20.9  million  in
1995 due to the increased gas sales at IEA and the timing of
the  recovery  of  gas costs through the PGA  at  Utilities,
partially offset by lower natural gas prices.  Gas purchased
for  resale  decreased ($15.0) million in  1994  because  of
lower gas costs and lower gas sales at Utilities.

      Other  operating expenses increased $24.5 million  and
$14.2  million  in  1995  and 1994, respectively.  Increased
labor  and benefits costs and increased operating activities
at Whiting contributed to both increases.  The 1995 increase
was  also  due to costs associated with a project to  review
and   redesign  Utilities'  major  business  processes,  the
amortization   of  previously  deferred  energy   efficiency
expenditures   at  Utilities  (which  are  currently   being
recovered through rates), increased operating activities  at
IEA  and  costs  relating  to the  Proposed  Merger.   These
increases   were  partially  offset  by  decreased   nuclear
operating  costs,  lower insurance costs  at  Utilities  and
decreased  costs resulting from the sale of  the Diversified
subsidiaries.  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 at Utilities.

      Maintenance  expenses increased or (decreased)  ($6.7)
million and $3.9 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  and
the  acquisition  of oil and gas operating properties.   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 $2.7  million
and $1.9 million during 1995 and 1994, respectively, largely
because  of increased property taxes at Utilities caused  by
increases in assessed property values.

Interest Expense and Other   Interest expense increased $4.7
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
($0.3) million during 1995 and an increase in income of $6.4
million during 1994.  The 1995 decrease was primarily due to
an  increase in fees related to the sale of utility accounts
receivable as the average amount of receivables sold  during
the   year   increased.   Gains  on  the  sale  of   several
investments  by Diversified's subsidiaries partially  offset
these  fees.   The 1994 increase was primarily  due  to  the
effect of transactions recorded in 1993 for certain property
write-downs  at  Diversified,  a  contribution  to  the  IES
Charitable  Foundation  and  a loss  on  the  defeasance  of
Industries' debentures.

      Federal and state income taxes increased $0.9  million
and  $4.5  million  in  1995 and  1994,  respectively.   The
increases  for both years are 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.  Adjustments to tax reserves also
contributed to the increased taxes in 1995.

               LIQUIDITY AND CAPITAL RESOURCES

       The  Company's  capital  requirements  are  primarily
attributable to Utilities' construction programs,  its  debt
maturities   and   the   level  of  Diversified's   business
opportunities.  The Company's pretax ratio of times interest
earned  was  3.12, 3.38 and 3.38 in 1995-1993, respectively.
In   1995,   cash  flows  from  operating  activities   were
$196 million versus $216 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 12 of the Notes
to Consolidated Financial Statements.

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


                                     Moody's      Standard & Poor's
                                         
     Utilities - Long-term debt         A2               A
               - Short-term debt        P1              A1
                                         
     Diversified - Short-term debt      P2              A2


      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 12 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 common stock  and  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 $245 million  for
1996,   of   which  approximately  $164  million  represents
expenditures  at  Utilities  and approximately  $81  million
represents expenditures at Diversified.  Of the $164 million
of  Utilities' expenditures, 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.
Diversified's anticipated expenditures include approximately
$75  million  for domestic and international  energy-related
construction and acquisition expenditures.

      The  Company's levels of construction and  acquisition
expenditures  are  projected to be  $283  million  in  1997,
$255  million in 1998, $247 million in 1999 and $215 million
in   2000.   It  is  estimated  that  approximately  80%  of
Utilities' construction and acquisition expenditures will be
provided by cash from operating activities (after payment of
dividends)  for  the five-year period 1996-2000.   Financing
plans for Diversified's construction and acquisition program
will  vary,  depending  primarily on the  level  of  energy-
related acquisitions.

      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,  the  following  long-term  debt  will
mature prior to December 31, 2000:

                                        (in millions)
         Utilities                         $ 140.3
         Diversified's variable 
           rate credit facility              124.2
         Other subsidiaries' debt             11.4
                                           $ 275.9


      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.

      Diversified  has a variable rate credit facility  that
extends  through November 9, 1998, with a one-year extension
available  to Diversified.  The facility also  serves  as  a
stand-by   agreement  for  Diversified's  commercial   paper
program.   The agreement provides for a combined maximum  of
$150   million   of  borrowings  under  the  agreement   and
commercial  paper  to  be  outstanding  at  any  one   time.
Interest  rates  and  maturities are  set  at  the  time  of
borrowing for direct borrowings under the agreement and  for
issuances  of  commercial paper.  The interest rate  options
are  based  upon quoted market rates and the maturities  are
less  than  one year.  At December 31, 1995, there  were  no
borrowings outstanding under this facility.  Diversified had
$124.2  million of commercial paper outstanding at  December
31,  1995, with interest rates ranging from 5.85%  to  6.50%
and   maturity   dates  in  the  first  quarter   of   1996.
Diversified intends to continue borrowing under the  renewal
options  of the facility and no conditions exist at December
31,  1995, that would prevent such borrowings.  Accordingly,
this  debt  is  classified as long-term in the  Consolidated
Balance Sheets.  The facility contains covenants that  could
restrict  the  amount  of  borrowings  available  under  the
facility.

      Refer  to  Note  6(b)  of the  Notes  to  Consolidated
Financial   Statements  for  a  discussion  of  a  guarantee
associated with debt issued by McLeod, Inc.

      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.   In  addition, Industries  had  5,000,000
shares   of  Cumulative  Preferred  Stock,  no  par   value,
authorized  for issuance, none of which were outstanding  at
December 31, 1995.

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

                         1995          1994
                                      
     Long-term debt       49%           48%
     Preferred stock       2             2
     Common equity        49            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 common stock  and  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  $131.1  million  (Industries  -   $1.5
million,  Utilities  - $121.1 million,  Diversified  -  $7.5
million  and  Whiting - $1.0 million). Utilities  was  using
$101  million to support commercial paper (weighted  average
interest rate of 5.81%) and $11.1 million to support certain
pollution control obligations.  Commitment fees are paid  to
maintain  these  lines  and there are  no  conditions  which
restrict  the  unused lines of credit.  In addition  to  the
above,  Utilities has an uncommitted credit facility with  a
financial   institution  whereby  it  can   borrow   up   to
$40 million.  Rates are set at the time of borrowing and  no
fees    are   paid   to   maintain   this   facility.     At
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.

      Whiting  is responsible for certain dismantlement  and
abandonment costs related to various off-shore oil  and  gas
properties, the most significant of which is located off the
coast  of  California.   Whiting  accrues  these  costs   as
reserves  are  extracted  and such  costs  are  included  in
"Depreciation   and   amortization"  in   the   Consolidated
Statements   of   Income.   A  corresponding   environmental
liability,  $1.7  million at December  31,  1995,  has  been
recognized  in  the  Consolidated  Balance  Sheets  for  the
cumulative amount expensed.

                        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.
IEA  received approval in the same FERC proceeding to market
electric  power  at market based rates.  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.

Financial Derivatives   The Company has a policy that
financial derivatives are to be used only to mitigate
business risks and not for speculative purposes.
Derivatives have been used by the Company on a very limited
basis.  At December 31, 1995, the Company had no financial
derivatives outstanding.

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.    Utilities'  results   of   operations   are   a
significant  portion  of  the  consolidated  results.    The
quarterly   amounts   were  affected  by   Utilities'   rate
activities and seasonal weather conditions. The first quarter
net income in 1995 was significantly lower than 1994 as Utilities
recorded a $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.   Utilities' 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, except per share amounts)
1995                                                          
  Operating revenues       $ 206,392  $  189,447  $  238,467   $ 216,704
  Operating income            22,115      33,456      63,710      32,431
  Net income                   6,740      12,508      31,120      13,808
  Earnings per average                                                
    common share                0.23        0.43        1.06        0.48
                                                              
1994                                                          
  Operating revenues       $ 211,621  $  171,117  $  207,345   $ 195,781
  Operating income            35,694      28,436      56,700      27,103
  Net income                  15,144      10,858      28,009      12,807
  Earnings per average
    common share                0.53        0.38        0.98        0.45


Item 8.   Financial Statements and Supplementary Data

          Information required by Item 8. begins on page 70.

                     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 Industries Inc.:

We  have audited the accompanying consolidated balance  sheets
and  statements of capitalization of IES Industries  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 Industries 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 are 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  8  to  the  consolidated   financial
statements, effective January 1, 1993, IES Industries 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, except per share amounts)
Operating revenues:
  Electric                                 $ 560,471    $ 537,327    $ 550,521
  Gas                                        190,339      165,569      181,923
  Other                                      100,200       82,968       68,822
                                             851,010      785,864      801,266


Operating expenses:
  Fuel for production                         96,256       85,952       87,702
  Purchased power                             66,874       68,794       93,449
  Gas purchased for resale                   141,716      120,795      135,830
  Other operating expenses                   201,390      176,863      162,642
  Maintenance                                 46,093       52,841       48,913
  Depreciation and amortization               97,958       86,378       77,012
  Taxes other than income taxes               49,011       46,308       44,449
                                             699,298      637,931      649,997


Operating income                             151,712      147,933      151,269


Interest expense and other:
  Interest expense                            50,727       46,010       44,440
  Allowance for funds used during 
    construction                              -3,424       -3,910       -1,972
  Preferred dividend requirements 
    of IES Utilities Inc.                        914          914          914
  Miscellaneous, net                          -3,170       -3,472        2,908
                                              45,047       39,542       46,290


Income before income taxes                   106,665      108,391      104,979


Federal and state income taxes                42,489       41,573       37,041


Net income                                 $  64,176    $  66,818    $  67,938


Average number of common shares 
  outstanding                                 29,202       28,560       27,764


Earnings per average common share          $    2.20    $    2.34    $    2.45


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               $ 218,293    $ 211,750    $ 202,919
Add:
    Net income                                64,176       66,818       67,938

Deduct:
    Cash dividends declared on common 
      stock, at a per share rate of 
      $2.10 for all years                     61,392       60,065       59,107
    Other                                          0          210            0
Balance at end of year                     $ 221,077    $ 218,293    $ 211,750


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 $53,026,000 and 
      $35,767,000, respectively                          193,215       154,657
                                                       1,504,976     1,439,018


Current assets:
    Cash and temporary cash investments                    6,942         4,993
    Accounts receivable -
        Customer, less reserve                            37,214        26,098
        Other                                             10,493        10,388
    Income tax refunds receivable                            982         6,434
    Production fuel, at average cost                      12,155        13,988
    Materials and supplies, at average cost               28,354        30,216
    Adjustment clause balances                                 0         1,433
    Regulatory assets                                     22,791        20,145
    Oil and gas properties held for resale                 9,843             0
    Prepayments and other                                 23,099        24,692
                                                         151,873       138,387


Investments:
    Nuclear decommissioning trust funds                   47,028        33,779
    Investment in foreign entities                        24,770           473
    Cash surrender value of life insurance policies        9,838         8,867
    Investment in McLeod, Inc.                             9,200         7,500
    Other                                                  3,897         4,274
                                                          94,733        54,893


Other assets:
    Regulatory assets                                    207,202       192,955
    Deferred charges and other                            26,807        23,840
                                                         234,009       216,795
                                                     $ 1,985,591   $ 1,849,093


                                                             December 31
CAPITALIZATION AND LIABILITIES                            1995          1994
                                                            (in thousands)
Capitalization (See Consolidated Statements of Capitalization):
    Common stock                                     $   391,269   $   373,490
    Retained earnings                                    221,077       218,293
        Total common equity                              612,346       591,783
    Cumulative preferred stock of IES Utilities Inc.      18,320        18,320
    Long-term debt (excluding current portion)           601,708       473,206
                                                       1,232,374     1,083,309


Current liabilities:
    Short-term borrowings                                101,000        37,000
    Capital lease obligations                             15,717        14,385
    Maturities and sinking funds                          15,447       100,422
    Accounts payable                                      80,089        78,582
    Dividends payable                                     16,244        15,839
    Accrued interest                                       8,051         9,494
    Accrued taxes                                         53,983        50,001
    Accumulated refueling outage provision                 7,690        15,196
    Adjustment clause balances                             3,148             0
    Environmental liabilities                              5,634         5,428
    Other                                                 21,800        21,680
                                                         328,803       348,027


Long-term liabilities:
    Pension and other benefit obligations                 44,619        38,643
    Capital lease obligations                             21,218        35,346
    Environmental liabilities                             43,087        38,288
    Other                                                 21,097        20,314
                                                         130,021       132,591


Deferred credits:
    Accumulated deferred income taxes                    257,278       245,365
    Accumulated deferred investment tax credits           37,115        39,801
                                                         294,393       285,166


Commitments and contingencies (Note 12)


                                                     $ 1,985,591   $ 1,849,093

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 - no par value - authorized 
      48,000,000 shares; outstanding 29,508,415 
      and 28,777,046 shares, respectively           $   391,269    $   373,490
    Retained earnings                                   221,077        218,293
                                                        612,346        591,783


Cumulative preferred stock of IES Utilities Inc.         18,320         18,320


Long-term debt:
    IES Utilities Inc. -
        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

        Total IES Utilities Inc.                        483,056        483,196

    IES Diversified Inc. -
        Variable rate credit facility                   124,245         80,500
        Other subsidiaries' debt maturing 
          through 2013                                   12,307         12,584
                                                        619,608        576,280
    Unamortized debt premium and (discount), net         -2,453         -2,652
                                                        617,155        573,628
            Less - Amount due within one year            15,447        100,422
                                                        601,708        473,206
                                                    $ 1,232,374    $ 1,083,309


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                                                                 $    64,176    $    66,818    $    67,938
    Adjustments to reconcile net income to net cash flows
        from operating activities -
           Depreciation and amortization                                            97,958         86,378         77,012
           Amortization of principal under capital lease obligations                15,714         16,246         11,429
           Deferred taxes and investment tax credits                                 7,757          4,050          9,254
           Refueling outage provision                                               -7,506         12,536         -4,889
           Amortization of other assets                                              7,391          2,228          2,083
           Other                                                                       712            387          5,857
    Other changes in assets and liabilities -
           Accounts receivable                                                     -15,221          6,777         -8,861
           Production fuel, materials and supplies                                   4,050         -1,184          5,836
           Accounts payable                                                          2,902         21,871          7,984
           Accrued taxes                                                             9,434          4,575          7,549
           Provision for rate refunds                                                  106         -8,670           -350
           Adjustment clause balances                                                4,581         -6,582          6,366
           Gas in storage                                                            3,245          1,135         -2,300
           Other                                                                       532          9,340         -5,781
              Net cash flows from operating activities                             195,831        215,905        179,127


Cash flows from financing activities:
    Dividends declared on common stock                                             -61,392        -60,065        -59,107
    Proceeds from issuance of common stock                                          15,616         16,426         79,746
    Purchase of treasury stock                                                           0         -6,233              0
    Proceeds from issuance of long-term debt                                       143,752         60,140        146,734
    Reductions in long-term debt                                                  -100,424         -9,790       -126,803
    Net change in short-term borrowings                                             64,000         13,000        -68,000
    Principal payments under capital lease obligations                             -14,463        -16,304        -11,276
    Sale of utility accounts receivable                                              4,000            800         10,490
    Other                                                                           -1,438            -46          1,086
        Net cash flows from financing activities                                    49,651         -2,072        -27,130


Cash flows from investing activities:
    Construction and acquisition expenditures -
        Utility                                                                   -125,558       -138,829       -113,212
        Other                                                                      -92,541        -67,719        -55,805
    Oil and gas properties held for resale                                          -9,843              0              0
    Deferred energy efficiency expenditures                                        -18,029        -16,157         -9,747
    Nuclear decommissioning trust funds                                             -6,100         -5,532         -5,532
    Proceeds from disposition of assets                                             14,271          8,803         28,790
    Other                                                                           -5,733          3,129          3,633
        Net cash flows from investing activities                                  -243,533       -216,305       -151,873


Net increase (decrease) in cash and temporary cash investments                       1,949         -2,472            124


Cash and temporary cash investments at beginning of year                             4,993          7,465          7,341


Cash and temporary cash investments at end of year                             $     6,942    $     4,993    $     7,465


Supplemental cash flow information:
    Cash paid during the year for -
        Interest                                                               $    50,877    $    44,421    $    42,890
        Income taxes                                                           $    26,478    $    36,097    $    22,179

    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 -

      The  Consolidated  Financial  Statements  include  the
accounts  of  IES  Industries  Inc.  (Industries)  and   its
consolidated   subsidiaries  (collectively   the   Company).
Industries  is  an  investor-owned  holding  company   whose
primary  operating company, IES Utilities Inc.  (Utilities),
is  engaged  principally  in  the generation,  transmission,
distribution  and sale of electric energy and the  purchase,
distribution, transportation and sale of natural  gas.   The
Company's  principal markets are located  in  the  state  of
Iowa.  The Company also has various non-utility subsidiaries
which   are   primarily   engaged  in  the   energy-related,
transportation and real estate development businesses.

      All subsidiaries for which Industries owns directly or
indirectly more than 50% of the voting stock are included as
consolidated    subsidiaries.    Industries'    wholly-owned
subsidiaries   are   Utilities  and  IES  Diversified   Inc.
(Diversified).   All significant intercompany  balances  and
transactions,   other   than   energy-related   transactions
affecting   Utilities,  have  been   eliminated   from   the
Consolidated   Financial  Statements.   Such  energy-related
transactions  are  made  at prices that  approximate  market
value   and  the  associated  costs  are  recoverable   from
Utilities' customers through the rate making process.

      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 -

      Because of its ownership of Utilities, Industries is a
holding company under the Public Utility Holding Company Act
of 1935, but claims an exemption from all provisions thereof
except  Section  9(a)(2), which applies to the  purchase  of
stock  of other utility companies.  Utilities is subject  to
regulation by the Iowa Utilities Board (IUB) and the Federal
Energy Regulatory Commission (FERC).

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

     (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 12(f))                         46.9       43.8
Employee pension and benefit costs (Note 8)                    27.5       25.0
Unamortized loss on reacquired debt                             5.7        6.1
FERC Order No. 636 transition costs (Note 12(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)  Oil and Gas Properties -

     Whiting Petroleum Corporation (Whiting), a wholly-owned
subsidiary under Diversified, uses the full cost  method  of
accounting for its oil and gas properties.  Accordingly, all
costs   of  acquisition,  exploration  and  development   of
properties are capitalized.  Amortization of proved oil  and
gas  properties is calculated using the units of  production
method.   At  December  31,  1995,  capitalized  costs  less
related accumulated amortization did not exceed the  sum  of
(1)  the  present value of future net revenue from estimated
production of proved oil and gas reserves (calculated  using
current  prices); plus (2) the cost of properties not  being
amortized,  if any; plus (3) the lower of cost or  estimated
fair  value  of unproved properties included  in  the  costs
being amortized, if any; less (4) income tax effects related
to  differences  in the book and tax basis of  oil  and  gas
properties.    The   Company  has  $9.8   million   on   its
Consolidated Balance Sheet at December 31, 1995, relating to
specific oil and gas properties purchased by Whiting in  the
fourth quarter of 1995 that it intends to sell during 1996.

     (j)  Operating Revenues -

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

     (k)  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.

     (l)  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 THE COMPANY:

      The  Company, 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 the Company with and into  WPLH,
which  merger will result in the combination of the  Company
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 the Company's 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  the Company 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 the Company,  WPLH
and  IPC  divest their gas utility properties, and  possibly
certain non-utility ventures of the Company 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   $10.4   million,   $11.1   million    and
$9.1 million, respectively.

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

                                                Capital      Operating
        Year                                     Lease         Leases
                                                    (in thousands)
                                                    
        1996                                   $ 15,515      $  8,083
        1997                                     13,787         7,241
        1998                                      6,389         6,932
        1999                                      3,865         5,220
        2000                                        824         2,403
        2001                                        149           178
                                                 40,529      $ 30,057
        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)  INVESTMENTS:
     (a)  Foreign Entities -

      At December 31, 1995, the Company had $24.8 million of
investments in foreign entities on its Consolidated  Balance
Sheet  that  included  1) investments  in  two  New  Zealand
electric  distribution entities, 2) a loan to a New  Zealand
company,  and  3) an investment in an international  venture
capital  fund.   The Company accounts for these  investments
under the cost method.

     (b)  McLeod, Inc. -

      At  December 31, 1995, Diversified had a $9.2  million
investment in Class B Common Stock of McLeod, Inc. (McLeod),
which  is  accounted  for  under the  cost  method.   McLeod
provides  local and long-distance telecommunication services
to  business customers and other services related  to  fiber
optics.   In  1994,  Diversified entered into  an  agreement
whereby it will guarantee $6 million under a credit facility
between  McLeod  and its bankers.  Diversified  is  paid  an
annual  commitment  fee  and receives  options  to  purchase
additional shares of Class B Common Stock for as long as the
guarantee remains outstanding.  At December 31, 1995, McLeod
had   $3.6  million  of  borrowings  outstanding  under  its
facility.

(7)  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                           $ 34.7      $ 37.5       $ 27.8
Deferred tax expense                            10.5         6.7         14.1
Amortization and adjustment 
  of investment tax credits                     (2.7)       (2.6)        (4.9)
                                              $ 42.5      $ 41.6       $ 37.0


      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                              5.5        5.9        5.5
    Effect of rate making on                              
      property related differences                  2.6        1.6       (0.2)
    Amortization of investment tax credits         (2.5)      (2.5)      (2.6)
    Adjustment of prior period taxes               (0.4)      (1.6)      (2.3)
    Other items, net                               (0.4)        -        (0.1)
Overall effective income tax rate                  39.8%      38.4%      35.3%


      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                    $ 296        $ 288
Investment tax credit related         (26)         (28)
Decommissioning related               (14)         (13)
Other                                   1           (2)
                                    $ 257        $ 245


(8)  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
$9.2 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                                 $   5,215  $   5,863   $   4,342
Interest cost on projected benefit
  obligation                                    11,811     11,431      11,314
Assumed return on plans' assets                (12,567)   (12,593)    (12,363)
Amortization of unrecognized gain                 (754)      (180)       (767)
Amortization of prior service cost               1,355      1,354       1,213
Amortization of unrecognized plans'
  assets as of January 1, 1987                    (333)      (333)       (389)
Pension cost                                     4,727      5,542       3,350
Adjustment to funding level                     (4,727)    (5,431)     (2,940)
Total pension costs paid to 
  the Trustee                                $     -    $     111   $     410
                                                       
Actual return on plans' assets               $  36,614  $     (97)  $  12,880


      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                     $ 195,329    $ 167,535
Actuarial present value of benefits rendered
  to date -
    Accumulated benefits based on                      
      compensation to date, including vested 
      benefits of $119,996,000 and $98,384,000, 
      respectively                                       131,274      108,585
    Additional benefits based on estimated 
      future salary levels                                41,581       40,146
Projected benefit obligation                             172,855      148,731
Plans' assets in excess of projected benefit 
  obligation                                              22,474       18,804
Remaining unrecognized net asset existing at                       
  January 1, 1987, being amortized over 20 years          (3,511)      (3,844)
Unrecognized prior service cost                           16,905       18,260
Unrecognized net gain                                    (41,795)     (34,420)
Accrued pension cost recognized in the                 
  Consolidated Balance Sheets                          $  (5,927)   $  (1,200)
                                                       
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.   Utilities' unamortized  balance  of
these deferred costs was $3.4 million at December 31, 1995.

       The   transition  obligation  for  the  non-regulated
operations  was expensed in 1993 and is reflected  in  other
operating expenses.

       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                                  $  1,387    $ 1,838    $  1,744
Interest cost on accumulated                              
  postretirement benefit obligation              3,175      3,275       3,363
Assumed return on plans' assets                    (56)       (60)        -
Amortization of transition obligation 
  existing at January 1, 1993, for 
  regulated operations                           2,024      2,024       2,024
Amortization of unrecognized gain                 (230)        (6)        -
Amortization of prior service cost                  19         19         -
Write-off of transition obligation 
  existing at January 1, 1993, for
  non-regulated operations                         -          -         1,434
Postretirement benefit costs                     6,319      7,090       8,565
Amortized/(deferred) postretirement 
  benefit costs                                  2,220     (2,732)     (2,858)
Adjustment to funding level                      1,162        -           -
Net postretirement benefit costs              $  9,701   $  4,358    $  5,707
                                                          
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                     22,254       18,896
    Active employees eligible                              6,282        5,306
    Retirees                                              22,575       18,602
Total accumulated postretirement 
  benefit obligation                                      51,111       42,804
Accumulated postretirement benefit 
  obligation in excess of plans' assets                  (44,596)     (41,677)
Unrecognized transition obligation                        34,415       36,439
Unrecognized net (gain)/loss                                 349       (5,703)
Unrecognized prior service cost                              151          170
Accrued postretirement benefit cost in the
    Consolidated Balance Sheets                        $  (9,681)   $ (10,771)
                                                  
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
$8.7 million (17%).

(9)  COMMON, PREFERRED AND PREFERENCE STOCK:
     (a)  Common Stock -

      The  following table presents information relating  to
the changes in common stock.

                                                     Common Stock
                                         Number of Shares            Amount
                                           Outstanding          (in thousands)

Balance, December 31, 1992                  25,556,963             $ 279,810
    Public offering                          2,300,000                66,555
    Stock plan issuances*                      447,225                13,936
Balance, December 31, 1993                  28,304,188               360,301
    Shares issued in connection  
      with acquisition of oil and  
      gas companies                            139,102                 4,027
    Purchases of treasury stock               (213,300)               (6,233)
    Stock plan issuances*                      547,056                15,395
Balance, December 31, 1994                  28,777,046               373,490
    Shares issued in connection                      
      with acquisition of oil and
      gas companies                             75,638                 1,925
    Stock plan issuances*                      655,731                15,854
Balance, December 31, 1995                  29,508,415             $ 391,269
                                                     
Shares reserved for issuance 
  pursuant to the Company's stock 
  plans at December 31, 1995*                2,201,666      


          *    Dividend  Reinvestment  and  Stock
               Purchase  Plan, Employee Stock  Purchase
               Plan,  Employee Savings Plan,  Long-Term
               Incentive   Plan,   IES   Bonus    Stock
               Ownership Plan and Whiting Stock  Option Plans


      In  March 1995, Industries issued 75,638 shares of its
common  stock  for  the purchase of oil and  gas  companies,
which are now wholly-owned subsidiaries of Whiting.

      During  1994, Industries reacquired 213,300 shares  of
its common stock on the open market, at an average price  of
$29.22  per  share, which were subsequently  issued  to  the
Dividend Reinvestment Plan and certain of its benefit plans.
At  December  31, 1995, no shares remained held as  treasury
stock.

     (b)  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.

      There  are  5,000,000 shares of Industries  Cumulative
Preferred  Stock  (no  par  value)  and  700,000  shares  of
Utilities  Cumulative  Preference  Stock  ($100  par  value)
authorized  for issuance, of which none were outstanding  at
December 31, 1995.

(10) 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.

      Diversified  has a variable rate credit facility  that
extends  through November 9, 1998, with a one-year extension
available  to Diversified.  The facility also  serves  as  a
stand-by   agreement  for  Diversified's  commercial   paper
program.   The agreement provides for a combined maximum  of
$150   million   of  borrowings  under  the  agreement   and
commercial paper to be outstanding at any one time. Interest
rates  and  maturities are set at the time of borrowing  for
direct  borrowings under the agreement and for issuances  of
commercial paper.  The interest rate options are based  upon
quoted  market  rates and the maturities are less  than  one
year.   At  December  31,  1995, there  were  no  borrowings
outstanding   under   this   facility.    Diversified    had
$124.2   million   of   commercial  paper   outstanding   at
December 31, 1995, with interest rates ranging from 5.85% to
6.50%  and  maturity  dates in the first  quarter  of  1996.
Diversified intends to continue borrowing under the  renewal
options  of the facility and no conditions exist at December
31,  1995, that would prevent such borrowings.  Accordingly,
this  debt  is  classified as long-term in the  Consolidated
Balance Sheets.

      Refer  to  Note 6 (b) for a discussion of a  guarantee
associated with debt issued by McLeod.

       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
Utilities -                                                               
  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
                                                                          
Diversified -                                                             
  Variable rate 
    credit facility           -          -          -       124,245        -
  Other subsidiaries' 
    debt                      307        333        360      10,366         35
Total                   $  16,077  $   9,023  $   1,050   $ 185,301  $  67,281



      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  $131.1  million  (Industries  -   $1.5
million,  Utilities  - $121.1 million,  Diversified  -  $7.5
million  and  Whiting - $1.0 million). Utilities  was  using
$101  million to support commercial paper (weighted  average
interest rate of 5.81%) and $11.1 million to support certain
pollution control obligations.  Commitment fees are paid  to
maintain  these  lines  and there are  no  conditions  which
restrict  the  unused lines of credit.  In addition  to  the
above,  Utilities has an uncommitted credit facility with  a
financial  institution  whereby it  can  borrow  up  to  $40
million. Rates are set at the time of borrowing and no  fees
are  paid to maintain this facility.  At December 31,  1995,
there were no borrowings outstanding under this facility.

(11) 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 $620 million and  $576
million, respectively, compared to estimated fair values  of
$644  million and $551 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 shareholders.

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

      The  Company's  construction and  acquisition  program
anticipates  expenditures of approximately $245 million  for
1996,  which  includes  $164 million at  Utilities  and  $81
million  at  Diversified.  In addition to the $164  million,
Utilities  anticipates  expenditures  of  approximately  $13
million  for  mandated  energy  efficiency  programs,  which
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  $13  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  $48.7  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.

            Oil   and   Gas  Properties  Dismantlement   and
            Abandonment Costs

      Whiting  is responsible for certain dismantlement  and
abandonment costs related to various off-shore oil  and  gas
properties, the most significant of which is located off the
coast  of  California.   Whiting  accrues  these  costs   as
reserves  are  extracted  and such  costs  are  included  in
"Depreciation   and   amortization"  in   the   Consolidated
Statements   of   Income.   A  corresponding   environmental
liability,  $1.7  million at December  31,  1995,  has  been
recognized  in  the  Consolidated  Balance  Sheets  for  the
cumulative amount expensed.

     (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.

 (13)     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

(14) SEGMENTS OF BUSINESS:

      The principal business segments of Industries are  the
generation, transmission, distribution and sale of  electric
energy   by   Utilities  and  the  purchase,   distribution,
transportation  and  sale of natural gas  by  Utilities  and
Industrial   Energy  Applications,  Inc.,   a   wholly-owned
subsidiary under Diversified.  Certain financial information
relating to Industries' 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                                   190,339       165,569       181,923
                                                                       
  Operating income -                                                   
    Electric                              130,390       125,487       128,994
    Gas                                    11,056         8,762        13,673
                                                                       
Other information:                                                     
  Depreciation and amortization -
    Electric                               72,487        68,640        63,832
    Gas                                     6,176         6,214         5,186
                                                                       
  Construction and acquisition 
  expenditures -
    Electric *                            108,356       112,773        96,736
    Gas                                     9,368        10,066        15,428
                                                                       
  Assets -                                                             
    Identifiable assets -                                              
      Electric                          1,395,666     1,347,024     1,288,505
      Gas                                 199,050       192,397       168,800
                                        1,594,716     1,539,421     1,457,305
    Other corporate assets                390,875       309,672       242,514
        Total consolidated assets     $ 1,985,591   $ 1,849,093   $ 1,699,819

          *  Excludes intercompany acquisitions which are eliminated for
             consolidated financial statement purposes.


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 of
Industries   and  compliance  with  Section  16(a)   reporting
requirements  of  the  Securities and Exchange  Commission  is
included  in  Industries' definitive proxy statement  prepared
for the 1996 annual meeting of stockholders, which will be filed 
within 120 days of December 31, 1995, (Proxy Statement under
the  captions  "Election of IES Directors"  and  "Certain  SEC
Filings")  and  is  incorporated  herein  by  reference.   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, President  &  Chief
     Executive Officer.  First elected officer in 1975.


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


     Stephen W. Southwick, 49, Vice President, General Counsel
     & Secretary.  First elected officer in 1982.


     Dean E.  Ekstrom,  48,  Vice  President,  Administration.
     First elected officer in 1991.


     Peter   W.   Dietrich,  56,  Vice  President,   Corporate
     Development.  First elected officer in 1988.


     Richard A. Gabbianelli, 39, Controller & Chief Accounting
     Officer.  First elected officer in 1994.


     Dennis B. Vass, 46, Treasurer.  First elected officer  in
     1995. (ii)


     Officers  are elected annually  by the Board of Directors
and  each of the officers named above, except Dennis B.  Vass,
has  been  employed  by Industries or one of  its  significant
subsidiaries  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.

     (i)  Blake  O.  Fisher,  Jr.  resigned  as Executive Vice
          President & Chief Financial Officer and Director  of
          IES Industries Inc. effective February 21,1996.

     (ii) 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.
     
      Larry  D.  Root, Executive Vice President, retired
effective December 31, 1995.


Item 11.  Executive Compensation

       Information   regarding  executive   compensation   and
transactions  is  included in the Proxy  Statement  under  the
captions  "Compensation of Directors",  "Summary  Compensation
Table"   and  "IES  Plans"  and  is  incorporated  herein   by
reference,   except  for  the  "Report  of  the   Compensation
Committee  on  Executive Compensation"  and  the  "Performance
Graph", which are not 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  the  Proxy
Statement under the captions "Security Ownership of Beneficial
Owners"  and  "Security  Ownership  of  Management"   and   is
incorporated herein by reference.


Item 13.  Certain Relationships and Related Transactions

      Information regarding certain relationships and  related
transactions  is  included in the Proxy  Statement  under  the
captions  "Other Transactions" and "Compensation of Directors"
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.                                       67 - 68

          Report of Independent Public Accountants.                      69

          Consolidated Statements of Income for the
          years ended December 31, 1995, 1994 and 1993.                  70

          Consolidated Statements of Retained Earnings
          for the years ended December 31, 1995, 1994 and 1993.          71

          Consolidated Balance Sheets at December 31, 1995 and
          1994.                                                       72 - 73

          Consolidated Statements of Capitalization at
          December 31, 1995 and 1994.                                   74

          Consolidated Statements of Cash Flows for the
          years ended December 31, 1995, 1994 and 1993.                 75

          Notes to Consolidated Financial Statements.                76 - 110

(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.            116


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

(a)  3.   Exhibits -

          See Exhibit Index beginning on page 119.


(b)       Reports on Form 8-K -


          Items Reported      Financial Statements          Date of Report
                                                               
                5,7                None                  February 9, 1996  (1)
                5,7                None                  November 10, 1995 (2)

                               
                               
(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 November 17, 1995  with
     the  earliest  event reported occurring on  November  10,
     1995.

                           IES INDUSTRIES 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)
IES Utilities Inc.:

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



Non-utility Subsidiaries:

1995:
   Accumulated provision for uncollectible
     accounts and other                           $    372          $    685

1994:
   Accumulated provision for uncollectible
     accounts and other                           $    506          $    372

1993:
   Accumulated provision for uncollectible
     accounts and other                           $    247          $    506

                           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  7th  day  of
March 1996.

 
                                   IES INDUSTRIES 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 7, 1996:



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


/s/   Dennis B. Vass                  Treasurer & 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  Registrant,  Amended  and
         Restated  as of May 4, 1993 (Filed as Exhibit 3(a) to Company's
         Form 10-K for the year 1993).

   3(b)  Bylaws of Registrant, as amended  November  2, 1994
         (Filed as Exhibit 3 to Company's Registration  Statement,
         File No. 33-56981).

   4(a)  Indenture of Mortgage and Deed of Trust, dated
         as  of  September  1,  1993, between Utilities  (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 Utilities (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  Utilities  (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)  Second  Amended and Restated Credit  Agreement
         dated  as  of  November 9, 1994 among IES Diversified  Inc.  as
         Borrower,  certain banks and Citibank, N.A., as  Agent.  (Filed
         as Exhibit 4(i) to the Company's Form 10-K for the year 1994).

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

   4(i)  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 the Company's Form 10-K for the year 1987).

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

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

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

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

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

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

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

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

  10(r)  Agreement  and Plan of  Merger,  dated  as  of
         February  27, 1991, by and between IE Industries Inc. and  Iowa
         Southern  Inc.  (Filed as Exhibit 2 to the Company's  Form  8-K
         dated February 27, 1991).

  10(s)  IES Industries Inc. Shareholders' Rights  Plan.
         (Filed  as  Exhibit I-2 to the Company's Registration Statement
         on Form 8-A filed November 13, 1991).

  10(t)  Restated Agreement and Plan of Merger among IES
         Industries  Inc.,  WPC Acquisition Corp. and Whiting  Petroleum
         Corporation dated November 15, 1991. (Filed as Annex A  to  the
         Company's Form S-4 Registration Statement No. 33-44495).

  10(u)  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(v)  Lease   and   Security   Agreement,   dated
         October  1, 1993, between IES Diversified Inc., as lessee,  and
         Sumitomo Bank Leasing and Finance, Inc., as lessor.  (Filed  as
         Exhibit 10(z) to the Company's Form 10-K for the year 1993).

  10(w)  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 Utilities' Form 10-Q for the quarter ended
         March 31, 1994 (File No. 0-4117-1)).
  
  10(x)  Agreement  and  Plan of Merger among IES Industries  Inc.,
         WOC  Acquisition Company, Okie Crude Company, Elba Gas Company,
         Kimble  Gas Gathering Company, Thomas M. Atkinson and  Joan  B.
         Atkinson,  dated as of March 25, 1994. (Filed as Exhibit  10(b)
         to Company's Form 10-Q for the quarter ended March 31, 1994).
  
  10(y)  IES  Diversified  Inc. Guaranty with McLeod,  Inc.,  dated
         May  16,  1994 (Filed as Exhibit 10(c) to Company's  Form  10-Q
         for the quarter ended June 30, 1994).
  
  10(z)  Agreement Regarding Guaranty Between McLeod, Inc. and  IES
         Diversified  Inc., dated May 16, 1994 (Filed as  Exhibit  10(d)
         to Company's Form 10-Q for the quarter ended June 30, 1994).
  
  10(aa) Guaranty  (IES  Utilities  Trust  No.  1994-A)  from  IES
         Utilities  Inc., dated as of June 29, 1994. (Filed  as  Exhibit
         10(b)  to  Utilities' Form 10-Q for the quarter ended June  30,
         1994 (File No. 0-4117-1)).
  
  10(ab) 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).
  
  10(ac) 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(ad) 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(ae) Amendment  3  dated September 27, 1993, to  the  Agreement
         and  Plan  of  Merger (Filed as Exhibit 2(d) to  the  Company's
         Current Report on Form 8-K, dated December 9, 1993).

  10(af) Agreement  and  Plan  of  Merger  among   IES
         Industries Inc., WOK Acquisition Company, Okie Energy  Company,
         Keener   Energy  Company,  Thomas  M.  Atkinson  and  Joan   B.
         Atkinson,  dated as of March 15, 1995 (Filed as  Exhibit  10(a)
         to  the  Company's Form 10-Q for the quarter  ended  March  31,
         1995).

  10(ag) Agreement  and Plan of  Merger,  dated  as  of
         November  10,  1995,  by  and among  WPL  Holdings,  Inc.,  IES
         Industries  Inc., Interstate Power Company and AMW Acquisition,
         Inc.  (Filed  as Exhibit 2.1 to the Company's Form  8-K,  dated
         November 10, 1995).

  10(ah) 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).

* 21    Subsidiaries of the Registrant.

* 23    Consent of Independent Public Accountants.

* 27    Financial Data Schedule.


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.