UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K/A
(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 Exhibit 99 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
None.
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 is included
in Exhibit 99 and is incorporated herein by reference. Exhibit 99
is primarily an excerpt from Industries' definitive proxy statement
that is being prepared for the 1996 annual meeting of stockholders.
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 Exhibit 99 and is incorporated herein by reference.
Item 12. Security Ownership of Certain Beneficial Owners and
Management
Information regarding security ownership of certain
beneficial owners and management is included in Exhibit 99
and is incorporated herein by reference.
Item 13. Certain Relationships and Related Transactions
Information regarding certain relationships and related
transactions is included in Exhibit 99 and is incorporated
herein by reference.
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports
on Form 8-K
Page No.
(a) 1. Financial Statements -
Included in Part II of this report -
Report of Management. 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 29th day of
April 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 April 29, 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
/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
* By: /s/ Lee Liu
(Attorney-in-fact)
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.
* 99 Director and Officer Information
Note: Pursuant to (b)(4)(iii)(A) of Item 601 of Regulation
S-K, the Company has not filed as an exhibit to this Form 10-K
certain instruments with respect to long-term debt that has
not been registered if the total amount of securities
authorized thereunder does not exceed 10% of total assets of
the Company but hereby agrees to furnish to the Commission on
request any such instruments.
EXHIBIT 21
IES INDUSTRIES INC.
SUBSIDIARIES OF THE REGISTRANT
The following are deemed to be significant subsidiaries of Industries --
Name of Subsidiary State of Incorporation
IES Utilities Inc. Iowa
IES Diversified Inc. Iowa
Exhibit 23
ARTHUR ANDERSEN LLP
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the
incorporation of our report included in this Form 10-K/A into IES
Industries Inc.'s (the "Company") previously filed Form S-8
Registration Statement (File No. 33-57088) for the Company's
Employee Stock Purchase Plan, Form S-8 Registration Statement
(File No. 33-32468) for the Company's Employee Savings Plan and
Form S-3 Registration Statement (File No. 33-56981) for the
Company's Dividend Reinvestment and Stock Purchase Plan.
/s/ ARTHUR ANDERSEN LLP
ARTHUR ANDERSEN LLP
Chicago, Illinois
April 26, 1996
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
The schedule contains summary financial information extracted from the
Consolidated Balance Sheet at December 31, 1995 and the Consolidated Statement
of Income and the Consolidated Statement of Cash Flows for the twelve months
ended December 31, 1995 and is qualified in its entirety by reference to such
financial statements.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-END> DEC-31-1995
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,311,761
<OTHER-PROPERTY-AND-INVEST> 287,948
<TOTAL-CURRENT-ASSETS> 151,873
<TOTAL-DEFERRED-CHARGES> 26,807
<OTHER-ASSETS> 207,202
<TOTAL-ASSETS> 1,985,591
<COMMON> 391,269
<CAPITAL-SURPLUS-PAID-IN> 0
<RETAINED-EARNINGS> 221,077
<TOTAL-COMMON-STOCKHOLDERS-EQ> 612,346
0
18,320
<LONG-TERM-DEBT-NET> 601,708
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 101,000
<LONG-TERM-DEBT-CURRENT-PORT> 15,447
0
<CAPITAL-LEASE-OBLIGATIONS> 21,218
<LEASES-CURRENT> 15,717
<OTHER-ITEMS-CAPITAL-AND-LIAB> 599,835
<TOT-CAPITALIZATION-AND-LIAB> 1,985,591
<GROSS-OPERATING-REVENUE> 851,010
<INCOME-TAX-EXPENSE> 42,489<F1>
<OTHER-OPERATING-EXPENSES> 699,298
<TOTAL-OPERATING-EXPENSES> 699,298<F1>
<OPERATING-INCOME-LOSS> 151,712
<OTHER-INCOME-NET> 6,594
<INCOME-BEFORE-INTEREST-EXPEN> 158,306
<TOTAL-INTEREST-EXPENSE> 50,727
<NET-INCOME> 64,176<F2>
914<F2>
<EARNINGS-AVAILABLE-FOR-COMM> 64,176
<COMMON-STOCK-DIVIDENDS> 61,392
<TOTAL-INTEREST-ON-BONDS> 35,424
<CASH-FLOW-OPERATIONS> 195,831
<EPS-PRIMARY> 2.20
<EPS-DILUTED> 0
<FN>
<F1>Income tax expense is not included in Operating Expense in the Consolidated
Statements of Income for IES Industries Inc. (Industries).
<F2> Since the preferred dividends are for a subsidiary of Industries, they are
considered a fixed charge on Industries' Consolidated Statement of Income.
</FN>
</TABLE>
DIRECTOR AND OFFICER INFORMATION EXHIBIT 99
ELECTION OF IES DIRECTORS
Nine directors will be elected by the IES shareholders at the IES
Meeting to serve until the next annual meeting or until their
respective successors have been duly elected and qualified. All nine
of the nominees have previously been elected as directors by the
shareholders.
In the event that any nominee should become unavailable for
election, which is not now contemplated, the IES Board reserves
discretionary authority to designate a substitute nominee. Proxies
will be voted for the election of such other nominee or nominees as
may be so designated by the IES Board.
Nominees For Election As Directors
Year First
Name and Age Elected a Director
C.R.S. ANDERSON, 68 1978
Insert Picture #1
Mr. Anderson is the retired Chairman of the
Board of IES after serving in that position following
the merger of IE Industries Inc. and Iowa Southern Inc.
Prior to the merger, Mr. Anderson was Chairman and
President of Iowa Southern Inc., and had served in
various positions at Iowa Southern Utilities Company
since 1956. He is a past chairman of the Missouri
Valley Electric Association and the Iowa Association of
Business and Industry; and a former director of IMG
Bond Accumulation Fund, IMG Stock Accumulation Fund,
Midwest Gas Association and the Iowa Business
Development Credit Corporation. Mr. Anderson has been
a director of IES since 1991 and was first elected to
the Iowa Southern Utilities Company board in 1978. Mr.
Anderson serves on the Executive Committee and chairs
the Audit Committee.
J. WAYNE BEVIS, 61 1987
Insert Picture #2
Mr. Bevis is Vice Chairman of Pella
Corporation, a window and door manufacturing company in
Pella, Iowa. Mr. Bevis retired on December 31, 1995 as
Chief Executive Officer of Pella Corporation. He has
served in various positions at Pella Corporation since
1973. Mr. Bevis is Chairman of several Pella
Corporation subsidiaries and a member of the Policy
Advisory Board of the Joint Center of Housing Studies
of Harvard University and the University of Iowa
College of Business Board of Visitors. He is a member
and past chairman of the Iowa Business Council. Mr.
Bevis has been a director of IES since 1991 and was
first elected to the IE Industries Inc. board in 1987.
Mr. Bevis serves on the Audit Committee.
LEE LIU, 62 1981
Insert Picture #3
Mr. Liu is Chairman of the Board, President &
Chief Executive Officer of IES and is Chairman of the
Board, President & Chief Executive Officer of
Utilities. Mr. Liu has held a number of professional,
management and executive positions since joining Iowa
Electric Light and Power Company in 1957. He is a
director of: HON Industries Inc., an office equipment
manufacturer in Muscatine, Iowa; Principal Financial
Group, an insurance company in Des Moines, Iowa; and
Eastman Chemical Company, a diversified chemical
company in Kingsport, Tennessee. He also serves as a
trustee for Mercy Medical Center, a hospital in Cedar
Rapids, Iowa and is a member of the Iowa Business
Council, the Iowa Utility Association and the
University of Iowa College of Business Board of
Visitors. Mr. Liu has been a director of IES since
1991 and was first elected to the board of Iowa
Electric Light and Power Company in 1981. Mr. Liu
chairs the Executive Committee and serves on the
Nominating Committee.
JACK R. NEWMAN, 62 1994
Insert Picture #4
Mr. Newman has been a Partner of Morgan,
Lewis & Bockius, an international law firm based in
Washington, D.C., specializing in energy matters since
December 1, 1994. Mr. Newman has been engaged in
private practice since 1967 and was previously a
partner in the law firms Newman & Holtzinger and
Newman, Bouknight & Edgar. He has served as nuclear
legal counsel to IES since 1968. Prior to 1967, Mr.
Newman served as Secretary and General Counsel of the
Nuclear Materials and Equipment Corporation and as
Staff Counsel to the Joint Congressional Committee on
Atomic Energy. He advises a number of utility
companies on nuclear power matters, including many
European and Asian companies. Mr. Newman is a member
of the Bar of the State of New York, the Bar
Association of the District of Columbia, the
Association of the Bar of the City of New York, the
Federal Bar Association and the Lawyers Committee of
the Edison Electric Institute. He was first appointed
to the board of IES in August 1994. Mr. Newman serves
on the Compensation Committee.
ROBERT D. RAY, 67 1987
Insert Picture #5
Mr. Ray is President and Chief Executive
Officer of IASD Health Services Inc. (formerly Blue
Cross and Blue Shield of Iowa, Western Iowa and South
Dakota) ("IASD"), an insurance firm in Des Moines,
Iowa. From 1983 until 1989 he was President and Chief
Executive Officer of Life Investors, Inc., an insurance
firm in Cedar Rapids, Iowa. Mr. Ray served as Governor
of the State of Iowa for fourteen years, and was the
United States Delegate to the United Nations in 1984.
He is a director of the Maytag Company, an appliance
manufacturer in Newton, Iowa and a director of Norwest
Bank of Iowa in Des Moines, Iowa. He also serves as
Chairman of the National Leadership Commission on
Health Care Reform and the National Advisory Committee
on Rural Health Care. Mr. Ray is a member of the Board
of Governors Drake University, Des Moines, Iowa, and
the Iowa Business Council. He has been a director of
IES since 1991 and was first elected to the IE
Industries Inc. board in 1987. Mr. Ray serves on the
Audit and Nominating Committees.
DAVID Q. REED, 64 1967
Insert Picture #6
Mr. Reed is an independent practitioner of
law in Kansas City, Missouri. Mr. Reed has been
engaged in the private practice of law since 1960.
From 1972 until 1988, he was a senior member of the
firm of Kodas, Reed & McFadden, P.C. in Kansas City,
Missouri. Mr. Reed is a member of the American Bar
Association, the Association of Trial Lawyers of
America, the Missouri Association of Trial Attorneys,
the Missouri Bar and the Kansas City Metropolitan Bar
Association. He served in the Missouri General
Assembly from 1972 until 1974. Mr. Reed has been a
director of IES since 1991 and was first elected to the
Iowa Electric Light and Power Company board in 1967.
Mr. Reed serves on the Executive Committee and chairs
the Nominating Committee.
HENRY ROYER, 64 1984
Insert Picture #7
Mr. Royer has been President and Chief
Executive Officer of River City Bank in Sacramento,
California since August 1994. He served as Chairman of
the Board and President of Firstar Bank of Cedar
Rapids, N.A. from 1983 until 1994. Mr. Royer is a
director of CRST, Inc., a trucking company in Cedar
Rapids, Iowa and has served on numerous Cedar Rapids
community organization boards. He has been a director
of IES since 1991 and was first elected to the board of
Iowa Electric Light and Power Company in 1984. Mr.
Royer serves on the Executive Committee and chairs the
Compensation Committee.
ROBERT W. SCHLUTZ, 60 1989
Insert Picture #8
Mr. Schlutz is President of Schlutz
Enterprises, a diversified farming and retailing
business in Columbus Junction, Iowa. He is a director
of Agri-Nutritional Group Inc., an animal health
business, in St. Louis, Missouri and the Iowa
Foundation for Agricultural Advancement. Mr. Schlutz
is a President of the Iowa State Fair Board and a
member of various community organizations. He also
served on the National Advisory Council for the
Kentucky Fried Chicken Corporation. He is a past
chairman of the Environmental Protection Commission for
the State of Iowa. Mr. Schlutz has been a director of
IES since 1991 and was first elected to the Iowa
Southern Inc. board in 1989. Mr. Schlutz serves on the
Audit Committee.
ANTHONY R. WEILER, 59 1979
Insert Picture #9
Mr. Weiler is Senior Vice President,
Merchandising, for Heilig-Meyers Company, a national
furniture retailer with more than 750 stores
headquartered in Richmond, Virginia. Mr. Weiler was
previously Chairman and Chief Executive Officer of
Chittenden & Eastman Company, a national manufacturer
of mattresses in Burlington, Iowa. He was with
Chittenden & Eastman from 1960 until 1995, and held
various management positions. Mr. Weiler is Chairman
of the National Home Furnishings Association and a
director of the Retail Home Furnishings Foundation. He
is a trustee of NHFA Insurance and a past director of
the Burlington Area Development Corporation, the
Burlington Area Chamber of Commerce and various
community organizations. Mr. Weiler has been a
director of IES since 1991 and was first elected to the
Iowa Southern Utilities Company board in 1979. Mr.
Weiler serves on the Nominating Committee.
Except as otherwise noted, all nominees have served in their current
positions for five years or more as of the date of this proxy. All
other information is as of January 1, 1996. All nominees are also the
current directors of Utilities.
THE IES BOARD RECOMMENDS A VOTE "FOR" THE ELECTION OF ALL NOMINEES.
____________________________
SECURITY OWNERSHIP OF BENEFICIAL OWNERS
Set forth below is certain information with respect to beneficial
ownership of the IES Common Stock by each person known by IES to own
5% or more of the outstanding IES Common Stock as of February 1, 1996:
Name of Beneficial Amount and Nature of Percent
Owner Beneficial Ownership (1) of Class (1)
WPLH 5,861,115 16.6%
IPC 5,861,115 16.6%
(1)By reason of the Stock Option Agreements, each of WPLH and IPC may
be deemed to have sole voting and dispositive power with respect
to the shares listed above which are subject to their respective
Options from IES and, accordingly, each of WPLH and IPC may be
deemed to beneficially own all of such shares (assuming exercise
of its Option and the nontriggering of the other party's right to
exercise its Option for IES Common Stock). However, each of WPLH
and IPC expressly disclaim any beneficial ownership of such shares
because the Options are exercisable only in certain circumstances.
See "The Stock Option Agreements."
SECURITY OWNERSHIP OF MANAGEMENT
Set forth below is certain information with respect to beneficial
ownership of the IES Common Stock as of February 1, 1996 by each
director and nominee for director, certain Executive Officers and by
all directors and listed Executive Officers of IES as a group:
Name of Beneficial Owner Amount and Nature of Percent
Beneficial Ownership (1) of Class
C.R.S. Anderson 19,000 .06%
J. Wayne Bevis 500 (2)
Dr. George Daly 3,000 .01%
Blake O. Fisher, Jr. 16,165 .05%
John F. Franz, Jr. 13,025 .04%
James E. Hoffman 0 (2)
G. Sharp Lannom, IV 480 (2)
Lee Liu 38,262 .13%
Rene H. Males 8,993 .03%
Jack R. Newman 0 (2)
Robert D. Ray 1,500 (2)
David Q. Reed 4,002 .01%
Larry D. Root 17,371 .06%
Henry Royer 1,825 (2)
Robert W. Schlutz 1,385 (2)
Anthony R. Weiler 2,251 (2)
All Executive Officers and Directors 173,789 .58%
of IES and Utilities as
a group (24 persons)
(1)Includes ownership of shares by family members even though
beneficial ownership of such shares may be disclaimed.
(2)Less than .01% of the Class (IES Common Stock).
OTHER TRANSACTIONS
IES has a contract with IASD for administration of its employee
health insurance plan, as it has for many prior years. In 1995, IES
paid $291,285 to IASD. Beginning in 1995, IES also contracted with
IASD for administration of its dental insurance plan and paid $63,925
to IASD for those services. As previously stated, Mr. Ray is
President and Chief Executive Officer of IASD.
COMPENSATION OF DIRECTORS
Non-employee directors of IES receive fees of $12,000 per year plus
$700 per meeting attended. Non-employee directors receive $700 per
Committee meeting attended. If a Committee meeting is the same day as
a meeting of the IES Board as a whole or if a Committee meeting is by
telephone conference, each participating non-employee director
receives $350, one-half the regular Committee meeting fee. In
addition, non-employee directors serving as chairman of a Committee
receive an annual fee of $1,500 for serving in such capacity. In
1993, the IES Board decided that directors who are officers would not
receive an annual fee or any fees for attendance at Board meetings or
meetings of committees of which they are members. Robert F. Brewer
and Dr. Salomon Levy, who served as directors until May 17, 1994,
served as emeritus directors of IES until May 16, 1995. Mr. Brewer
received $1,400 in meeting fees in 1995 as an emeritus director.
Under the Director Retirement Plan, IES provides a retirement or
death benefit to directors, including directors who are employees of
IES, in an amount equal to 80% of the annual directors fee. Such
amount is payable annually, based upon length of service, to directors
who have served at least four years, with a maximum payment period of
eight years. Mr. Brewer and Dr. Levy each received payments of $8,000
under the Director Retirement Plan in 1995.
S. Levy, Incorporated, an engineering and management consulting
firm of which Dr. Salomon Levy, a director emeritus until May 16,
1995, is Chairman, performed consulting services for Utilities in 1995
for which it was paid $125,554. Dr. Levy has retired as Chief
Executive Officer of S. Levy, Incorporated and does not participate in
the day to day management of the company. Utilities has a service
contract with S. Levy, Incorporated pursuant to which it supplied
these services and under which it will provide services in 1996. Dr.
Salomon Levy was appointed as the Nuclear Advisor to the Board of
Directors on May 17, 1994 and received $5,771 for his services in 1995
as Nuclear Advisor. Dr. Levy also serves on the IES Utilities Nuclear
Safety Committee.
Director Jack R. Newman has served as nuclear legal counsel to IES
since 1968. Mr. Newman's firm, Morgan, Lewis & Bockius, was paid
$453,002 for legal services provided to IES in 1995.
IES makes available to members of the Board of Directors a business
travel accident insurance policy at an annual cost to IES of $10 per
director. No director received any payments under such policy in
1995.
EXECUTIVE COMPENSATION
The following table shows, for the fiscal years ending December 31,
1993-1995, the cash compensation paid by IES and its subsidiaries as
well as certain other compensation paid or accrued for those years, to
the Chief Executive Officer and to each of the four most highly
compensated Executive Officers of IES and its subsidiaries and to Rene
H. Males who would have been among the four most highly compensated
executive officers if he was employed by IES on December 31, 1995:
<TABLE>
SUMMARY COMPENSATION TABLE
<CAPTION>
Annual Compensation Long-Term
Compensation All
Name and Principal Year Salary Bonus Other Restricted Other
Position (1) (3) (4) Stock Awards Compensation
(5) (6)
<S> <C> <C> <C> <C> <C> <C>
Lee Liu 1995 $340,000 $142,800 $1,588 * $ 13,507
Chairman of the Board 1994 324,375 161,798 1,114 298,127 13,604
President & Chief 1993 307,450(2) 157,500 1,625 237,341 10,571
Executive Officer
Blake O. Fisher, Jr. 1995 241,861 76,440 160 - 6,945
Executive Vice President 1994 210,060 88,800 160 88,894 7,138
& Chief Financial Officer 1993 212,475(2) 81,974 720 74,049 4,392
James E. Hoffman 1995 89,583 206,500 51,523 * 324
Executive Vice President
Larry D. Root 1995 220,822(2) 62,606 566 - 208,038
Executive Vice President 1994 197,765 70,935 483 83,690 7,820
1993 200,694(2) 77,176 2,168 69,724 5,948
John F. Franz, Jr. 1995 144,050 25,213 418 * 4,893
Vice President 1994 127,379 30,062 57 257,473 1,863
1993 114,425 32,577 171 28,634 1,035
Rene H. Males 1995 141,624(2) 38,084 780 - 358,244
Executive Vice President 1994 162,750 57,534 1,761 - 4,910
1993 179,024(2) 65,100 404 - 25,817
</TABLE>
____________________
* The grants of restricted stock pursuant to the long-term
incentive plan for the 1995 plan year have not been determined as
of the date of this Joint Proxy Statement/Prospectus. See
footnote (5) below for a discussion of restricted stock awards.
(1) Messrs. Hoffman, Males and Franz are not officers of IES, but are
officers of Utilities. Mr. Hoffman commenced employment with
Utilities effective August 1, 1995. Mr. Fisher resigned his
employment with IES effective February 21, 1996. Mr. Root
retired effective December 31, 1995. Mr. Males retired effective
September 30, 1995.
(2) The amounts reported as salary include director's fees and
payments in lieu of director's fees for each of Messrs. Liu,
Fisher, Root and Males, of $11,200 in 1993, and accrued vacation
pay for Mr. Root of $20,162 and Mr. Males of $19,561 in 1995.
(3) The amounts listed represent plan year awards pursuant to the
Management Incentive Compensation Plan, IES's annual incentive
plan, with cash payment made in the subsequent calendar year.
The amount reported as bonus for Mr. Hoffman includes a one-time
payment of $185,000 when he commenced employment with Utilities.
(4) The 1995 amounts shown as Other Annual compensation represent the
earnings for the Key Employee Deferred Compensation Plan in
excess of 120% of the applicable federal long-term rate provided
under Section 1274(d) of the Code. Also included are relocation
and moving expenses for Mr. Hoffman in the amount of $51,523.
(5) The awards of restricted stock have been made on June 1st since
1988, with one-third of the award being restricted for one year,
one-third being restricted for two years and one-third being
restricted for three years. In addition, in June 1993 Mr. Liu
received a grant of 4,000 shares, in June 1994 Mr. Liu received a
grant of 3,000 shares and in December 1995 Mr. Liu received a
grant of 4,000 shares, all of which will vest at retirement. In
June 1995, Mr. Franz received a grant of 10,000 shares. The
restrictions on 1,000 shares will lapse each year beginning in
June 1996 with the restrictions on the remainder lapsing at
retirement but not prior to Mr. Franz becoming age 60.
Restricted stock is considered outstanding upon award date and
dividends are paid to the eligible officers on these shares while
restricted. The amounts shown in the table above represent the
value of the awards based upon closing price of IES Common Stock
on the award date. The award date is in the calendar year
following the plan year. Messrs. Fisher and Root will not
receive any awards in 1996 since they are no longer IES
employees. At December 31, 1995, the listed officers had
restricted stock for which restrictions had not lapsed (based
upon the December 29, 1995 closing price of IES Common Stock) as
follows:
Shares Value
Lee Liu 27,761 $735,667
Blake O. Fisher, Jr. 6,084 161,226
James E. Hoffman - -
Larry D. Root 5,700 151,050
John F. Franz, Jr. 12,160 322,240
Rene H. Males - -
No stock options or stock appreciation rights have been
awarded to the Executive Officers listed above.
(6) Amounts shown for 1995 represent: (a) contributions by IES
to the applicable employee savings plan in the following
amounts: Mr. Liu - $4,648, Mr. Fisher - $4,436, Mr. Root -
$4,210, Mr. Franz - $2,730 and Mr. Males - $3,063; (b)
amount included in W-2 earnings for life insurance coverage
in excess of $50,000 in the following amounts: Mr. Liu -
$8,859, Mr. Fisher - $2,509, Mr. Hoffman - $324, Mr. Root -
$3,168, Mr. Franz - $2,163 and Mr. Males - $3,286; (c)
severance pay to be paid in 1996 in the following amounts:
Mr. Root - $200,660 and Mr. Males - $332,180; and (d)
supplemental retirement pay of $19,715 for Mr. Males.
IES PLANS
IES Pension Plans: IES, Utilities and the Cedar Rapids and Iowa
City Railway Company have non-contributory retirement plans covering
employees who have at least one year of accredited service. Directors
who are not officers do not participate in the plans. Maximum annual
benefits payable at age 65 to participants who retire at age 65,
calculated on the basis of straight life annuity, are illustrated in
the following table:
PENSION PLAN TABLE
Average of Highest Annual Estimated Maximum Annual Retirement Benefits
Salary (Remuneration) Based on Service Years
for 3 Consecutive
Years of the last 10 15 20 25 30 35
125,000 27,119 36,158 45,198 54,237 63,277
150,000 32,931 43,908 54,885 65,862 76,839
175,000 36,941 49,460 61,980 74,499 87,018
200,000 41,816 56,210 70,605 84,999 99,393
225,000 46,691 62,960 79,230 95,499 111,768
250,000 47,466 64,033 80,600 97,168 113,735
300,000 47,466 64,033 80,600 97,168 113,735
400,000 47,466 64,033 80,600 97,168 113,735
450,000 47,466 64,033 80,600 97,168 113,735
500,000 47,466 64,033 80,600 97,168 113,735
For 1995, $120,000 is the maximum benefits allowable under the
retirement plans prescribed by Section 415 of the Code.
With respect to the officers named in the Summary Compensation
Table, the remuneration for retirement plan purposes would be
substantially the same as that shown as "Salary." As of December 31,
1995, the officers had accredited years of service for the retirement
plan as follows: Lee Liu, 38 years; Blake O. Fisher, Jr., 5 years;
James E. Hoffman, 0 years; Larry D. Root, 25 years; and John F. Franz,
Jr., 4 years.
Supplemental Retirement Plans: IES has a non-qualified Supplemental
Retirement Plan for eligible officers of IES and Utilities, including
Messrs. Hoffman and Franz. The plan provides for payment of
supplemental retirement benefits equal to 69% of the officer's base
salary in effect at the date of retirement, reduced by benefits
receivable under the qualified retirement plan, for a period not to
exceed 18 years following the date of retirement. In the event of the
death of the officer following retirement, similar payments reduced by
the joint and survivor annuity of the qualified retirement plan will
be made to his designated beneficiary (surviving spouse or dependent
children), if any, for a period not to exceed 12 years from the date
of the officer's retirement. Thus, if an officer died 12 years after
retirement, no payment to the beneficiary would be made. Death
benefits are provided on the same basis to a designated beneficiary
for a period not to exceed 12 years from the date of death should the
officer die prior to retirement. The Supplemental Retirement Plan
further provides that if, at the time of the death of an officer, the
officer is entitled to receive, is receiving, or has received
supplemental retirement benefits by virtue of having taken retirement,
a death benefit shall be paid to the officer's designated beneficiary
or to the officer's estate in an amount equal to 100% of the officer's
annual salary in effect at the date of retirement. Under certain
circumstances, an officer who takes early retirement will be entitled
to reduced benefits under the Supplemental Retirement Plan. The
Supplemental Retirement Plan also provides for benefits in the event
an officer becomes disabled under the terms of the qualified
retirement plan. IES has purchased life insurance on the participants
sufficient in amount to finance actuarially all of its future
liabilities under the Supplemental Retirement Plan and IES is the
owner and beneficiary of all such life insurance. The Supplemental
Retirement Plan has been designed so that if the assumptions made as
to mortality, experience, policy dividends, tax credits and other
factors are realized, IES will fully recover all of its premium
payments over the life of the Supplemental Retirement Plan.
The following table shows the estimated annual benefits payable
under the Supplemental Retirement Plan equal to 69% of the officer*s
base salary in effect at the date of retirement:
IES Industries Inc.
Supplemental Retirement Plan Payments
69% SRP Benefit
Final Annual Service Years
Salary 15 20 25 30 35
125,000 59,131 50,092 41,052 32,013 22,973
150,000 70,569 59,592 48,615 37,638 26,661
175,000 83,809 71,290 58,770 46,251 33,732
200,000 96,184 81,790 67,395 53,001 38,607
225,000 108,559 92,290 76,020 59,751 43,482
250,000 125,034 108,467 91,900 75,332 58,765
300,000 159,534 142,967 126,400 109,832 93,265
400,000 228,534 211,967 195,400 178,832 162,265
450,000 263,034 246,467 229,900 213,332 196,765
500,000 297,534 280,967 264,400 247,832 231,265
Mr. Liu has elected to continue under the supplemental retirement
agreement previously provided to him by IES with provisions for
payment of benefits equal to 75% of the officer's base salary, for a
period not to exceed 15 years following the date of retirement, and
payment to the surviving spouse or dependent children for a period not
to exceed 10 years following the date of retirement.
The following table shows the estimated annual benefits payable
under the Supplemental Retirement Plan equal to 75% of the officer*s
base salary in effect at the date of retirement:
IES Industries Inc.
Supplemental Retirement Plan Payments
75% SRP Benefit
Final Annual Service Years
Salary 15 20 25 30 35
125,000 66,631 57,592 48,552 39,513 30,473
150,000 79,569 68,592 57,615 46,638 35,661
175,000 94,309 81,790 69,270 56,751 44,232
200,000 108,184 93,790 79,395 65,001 50,607
225,000 122,059 105,790 89,520 73,251 56,982
250,000 140,034 123,467 106,900 90,332 73,765
300,000 177,534 160,967 144,400 127,832 111,265
400,000 252,534 235,967 219,400 202,832 186,265
450,000 290,034 273,467 256,900 240,332 223,765
500,000 327,534 310,967 294,400 277,832 261,265
Mr. Males retired under a supplemental retirement agreement
previously provided to him by Iowa Southern Utilities Company with
provisions for payment of benefits equal to 65% of base salary for
life, subject to consumer price index adjustment, and payments to
survivors after death of the officer for a period not to exceed 15
years following the date of retirement.
The following table shows the estimated annual benefits payable
under the Supplemental Retirement Plan equal to 65% of the officer's
base salary in effect at the date of retirement:
IES Industries Inc.
Supplemental Retirement Plan Payments
65% SRP Benefit
Final Annual Service Years
Salary 15 20 25 30 35
125,000 54,131 45,092 36,052 27,013 17,973
150,000 64,569 53,592 42,615 31,638 20,661
175,000 76,809 64,290 51,770 39,251 26,732
200,000 88,184 73,790 59,395 45,001 30,607
225,000 99,559 83,290 67,020 50,751 34,482
250,000 115,034 98,467 81,900 65,332 48,765
300,000 147,534 130,967 114,400 97,832 81,265
400,000 212,534 195,967 179,400 162,832 146,265
450,000 245,034 228,467 211,900 195,332 178,765
500,000 277,534 260,967 244,400 227,832 211,265
Executive Guaranty Plan: The IES Board has approved an Executive
Guaranty Plan (the "Guaranty Plan") for officers of IES and its
principal subsidiary, Utilities. The purpose of the Guaranty Plan is
to promote flexibility in financial planning of participating officers
and to provide an inducement to new officers in order to retain and
attract the best possible executive management team. Under the
Guaranty Plan, IES guarantees loans within defined limits, based on
salary level and years of service made to participating officers for
various specified purposes, including real estate acquisitions and
purchases of IES Common Stock. As of December 31, 1995, guarantees of
$76,653, $49,125 and $50,000, were outstanding for Messrs. Liu, Root
and Fisher, respectively.
Executive Change of Control Agreements: IES has severance
agreements with thirteen of its executives, including Messrs. Liu,
Hoffman and Franz. Mr. Fisher had a severance agreement with IES
which is described in this section. The severance agreements run for
terms of one year (three years in the case of Mr. Liu), subject to
automatic renewal unless either party gives notice of non-renewal to
the other party at least 60 days prior to the annual renewal date.
Each agreement provides for salary continuation and certain other
benefits in the event the covered executive is terminated within a
three-year period following a change of control of IES. For these
purposes, a "change of control" is described in the IES Charter and,
in addition, will be deemed to have occurred, if following a merger,
consolidation or reorganization, the owners of the capital stock
entitled to vote in the election of directors of IES prior to the
transaction own less than 75% of the resulting entity's voting stock
or during any period of two consecutive years, individuals who, at the
beginning of such period constitute the Board of Directors of the
parent company, cease for any reason to constitute at least a majority
of the Board of Directors of any successor organization. Accordingly,
the Mergers will constitute a change of control for purposes of each
of the IES severance agreements. Specifically, the agreements provide
that following termination of a covered executive's employment, except
terminations for just cause, death, retirement, disability or
voluntary resignation (other than resignation for "good reason"), the
executive's salary will be continued, at a level equal to his salary
just prior to termination, for a period ranging from eighteen to
thirty-six months (depending on the executive involved and, in certain
cases, his length of service). Additionally, certain benefits will be
continued during the applicable severance period, including life and
health insurance, and the executive will continue to receive annual
incentive award payments equal to the average annual incentive awards
paid to executives of the same or comparable designation during the
three years prior to the change of control. In the event the
executive dies during the severance period, the salary and benefit
payments described above shall be payable during the remainder of the
term to the executive's surviving spouse or his estate. The executive
will also become immediately vested and entitled to receive awards of
restricted stock or other rights granted to the executive under IES's
Long-Term Incentive Plan. With respect to a covered executive who is
age 56 or older at the time of the change of control, the severance
agreement further provides that the change of control will cause the
executive to become fully vested in his supplemental retirement plan
benefit ("SERP"), and that if the executive is terminated within three
years following the change of control, he will be able to commence his
SERP payments on the earlier of the date he attains age 65 or the date
salary continuation payments cease under his severance agreement.
In November 1995, IES approved certain amendments to the existing
severance agreements which will take effect no later than the next
annual renewal of each agreement, subject to each executive's
execution of an amended form of agreement. The amendments to the
severance agreements for Messrs. Liu and Fisher provide, among other
things, that during the applicable severance period Messrs. Liu and
Fisher will be entitled to receive payments equal to the average value
of both the long-term and the annual incentive awards received by
executives of the same or comparable designation during the three
years prior to the change of control. In addition, the amendments for
all covered executives provide reimbursement, in an amount not to
exceed 15% of the executive's base salary, for outplacement services
and legal fees incurred by the executive in connection with his
termination, and also provide severance benefits in the event of
certain employment terminations within 180 days prior to a change of
control.
The provisions of the severance agreement covering Mr. Liu has been
incorporated into the Employment Agreement to be executed between Mr.
Liu and Interstate Energy in connection with the Mergers (See "The
Mergers -- Employment Agreements" and Annex H). After the Effective
Time, his Employment Agreement will supersede his existing severance
agreement.
IES believes that these agreements enable IES to employ key
executives who can approach major business decisions objectively and
without concern for their personal situations.
Termination of Employment Arrangement: Larry D. Root, IES
Executive Vice President, elected to take early retirement effective
as of December 31, 1995, following 25 years of service to IES. In
connection with Mr. Root's retirement, IES entered into an early
retirement agreement with Mr. Root which, among other things, provided
for certain payments and other financial considerations. Under the
terms of Mr. Root's early retirement agreement, IES paid Mr. Root a
lump sum cash payment of $200,660 on January 4, 1996. IES agreed to
accelerate the vesting of restricted stock grants previously granted
to Mr. Root so that such grants became vested on December 31, 1995.
IES also agreed that Mr. Root was eligible to receive an award under
the Management Incentive Compensation Plan for 1995 performance, which
was awarded to him in February 1996. Mr. Root shall receive, as an
unfunded supplemental pension benefit, $11,306.11 per month for a
period of fifteen (15) years. IES shall also pay, within three months
of Mr. Root's death, a death benefit of $200,660 to his beneficiaries.
Mr. Root shall be eligible for the medical coverage generally offered
by IES to retiring employees, in accordance with the terms of the IES
Health Care Plan. Blake O. Fisher, Jr., IES Executive Vice President
& Chief Financial Officer, resigned from IES effective February 21,
1996. IES and Mr. Fisher entered into an agreement which provided for
certain payments and other financial considerations as set forth in
Mr. Fisher's Executive Change of Control Agreement, details of which
are set forth in the section above entitled "Executive Change of
Control Agreements."
IOWA SOUTHERN UTILITIES PLANS
Iowa Southern Utilities Pension Plan: Iowa Southern Utilities
Company ("Iowa Southern Utilities") provided a contributory pension
plan which covered substantially all non-collective bargaining
employees who have completed the minimum eligibility requirements of
1,000 hours in a year. The plan was amended effective January 1, 1991
to be non-contributory. As of his retirement on September 30, 1995,
Mr. Males had 4 years of accredited service under the Pension Plan.
Participants contributed one percent of annual compensation to the
Pension Plan through 1990.
Iowa Southern Utilities Senior Executive Severance Agreements:
Individual agreements providing for severance pay were entered into by
Iowa Southern Utilities and four senior executives, including Mr.
Males. The benefits to be provided were generally as follows: a lump
sum payment equal to the executive's salary for a payment period equal
to the greater of 24 months, or one month multiplied by years of
service with a limit of 30 months. Mr. Males's agreement provides for
the greater of 24 months or the period between the date his employment
terminates and January 28, 1996. In addition, each covered senior
executive was entitled to continuation of life and health insurance
coverage during the payment period and reimbursement of certain other
expenses. The only agreement still in effect in 1995 was with Mr.
Males. Mr. Males' retirement was a qualified termination under the
agreement. Mr. Males will receive payments under the severance
agreement beginning in 1996.
EMPLOYMENT AGREEMENT
IE Industries Inc. and Iowa Electric Light and Power Company, the
predecessor companies of IES Industries and Utilities, entered into an
employment agreement (the "Liu Agreement") with Lee Liu, which became
effective July 1, 1991. The Liu Agreement provides that Mr. Liu shall
be employed as President, Chief Executive Officer and Chairman of the
Executive Committee of IES and as Chief Executive Officer and Chairman
of Utilities from July 1, 1991 until April 1995, which period shall be
automatically extended unless at least six months prior to any
expiration thereof either IES or Utilities or Mr. Liu shall give
notice that they do not wish to extend such time (the "Period of
Employment"). To date, neither party has given such notice. The Liu
Agreement also provides that he shall become Chairman of the Board at
such time as C.R.S. Anderson ceases to serve in such position. This
occurred on July 1, 1993. The Liu Agreement provides that Mr. Liu
shall provide consulting services to IES for three years ( the "Period
of Consulting") after the conclusion of the Period of Employment.
During the Period of Employment, Mr. Liu will be paid a base annual
salary of at least $275,000, and will be entitled to participate in
all incentive compensation plans applicable to the positions he holds
and all retirement and employee welfare benefit plans. During the
Period of Employment, Mr. Liu's incentive compensation shall be at
least equal to that paid to the Chairman of the Board of IES.
If Mr. Liu's employment is terminated without his consent by IES or
Utilities during the Period of Employment for other than an unremedied
material breach or just cause or by his resignation if such
resignation occurs after IES fails to cause him to be employed in or
elected to the positions specified in the Liu Agreement or after a
material diminution in his duties, responsibilities or status, then
Mr. Liu shall be entitled to an amount equal to the sum of his base
annual salary as of the date of termination plus his average incentive
compensation during the three years immediately preceding the date of
termination multiplied by the number of years (and fractions thereof)
then remaining in the Period of Employment. Mr. Liu also would be
entitled to continued insurance coverages and an amount equal to the
then present value of the actuarially determined difference between
the aggregate retirement benefits actually to be received by him as of
the date of termination and those that would have been received by him
had he continued to be employed at the base salary in effect at
termination through the expiration of the Period of Employment. All
his shares of IES Restricted Stock would also vest at that time.
During the Period of Consulting, Mr. Liu will make himself
available for up to 30 days per year, report to the Chief Executive
Officer of IES and will earn an annual consulting fee equal to 13.33%
of his highest annual base salary during his Period of Employment. If
Mr. Liu's consulting services are terminated for reasons other than
material breach or just cause, he will be entitled to a lump sum
payment equal to the amount of the consulting fee he would otherwise
have earned during the Period of Consulting.
The Employment Agreement which Mr. Liu will enter into with
Interstate Energy in connection with the Mergers will supersede the
Liu Agreement described above. See "The Mergers -- Employment
Agreements."
CERTAIN SEC FILINGS
Section 16(a) of the Securities Exchange Act of 1934 requires
IES's officers and directors and persons who own more than 10% of the
registered class of IES's equity securities to file reports of
ownership and changes in ownership with the SEC. Such officers,
directors and shareholders are required by SEC regulations to furnish
IES with copies of all such reports that they file.
Based solely on a review of copies of reports filed with the SEC
with respect to 1995 and of written representations by certain
officers and directors, all persons subject to the reporting
requirements of Section 16(a) filed the required reports on a timely
basis.
