UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(Mark One)
(X) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 [FEE REQUIRED]
For the fiscal year ended December 31, 1995
OR
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
For the transition period from to
Commission file number 0-4117-1
IES UTILITIES INC.
(Exact name of registrant as specified in its charter)
Iowa 42-0331370
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
IES Tower, Cedar Rapids, Iowa 52401
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code 319-398-4411
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange on
Title of each class which registered
7-7/8% Quarterly Debt Capital Securities
(Subordinated Deferrable Interest Debentures) New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
Cumulative Preferred Stock Par Value $50 per share 4.80%
(Title of class)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange
Act of 1934 during the preceding 12 months (or for such shorter period
that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days. Yes X No
--- ---
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be
contained, to the best of registrant's knowledge, in definitive proxy or
information statements incorporated by reference in Part III of this
Form 10-K or any amendment to this Form 10-K. X
---
The aggregate market value of the registrant's voting stock held by non-
affiliates, as of January 31, 1996 was $0.
Indicate the number of shares outstanding of each of the registrant's
classes of Common Stock, as of January 31, 1996.
Common Stock, $2.50 par value - 13,370,788 shares
PART I
Item 1. Business
IES Utilities Inc. (the Company) is a wholly-owned subsidiary of
IES Industries Inc. (Industries). The Company is primarily a public
utility operating company engaged in providing electric energy, natural
gas and, to a limited extent, steam used for industrial and heating
purposes, in the State of Iowa. The Company provides service to
approximately 333,000 electric and 174,000 natural gas retail customers
as well as 30 resale customers in more than 550 Iowa communities.
The Company's only wholly-owned subsidiary as of December 31, 1995,
was IES Ventures Inc. (Ventures), which is a holding company for
unregulated investments. Ventures' wholly-owned subsidiary at
December 31, 1995, was IES Midland Development Inc. (Midland), which
owns and operates a landfill in Ottumwa, Iowa. Ventures also has a 35%
equity investment in Aqua Ventures L.C., which is an aquaculture
facility formed to raise fish for human consumption.
The Company's sales of electricity (in Kwh), excluding off-system
sales, increased 5.3%, 4.3% and 24.9%, during the years 1995-1993,
respectively. The 1995 increase was significantly affected by warmer
than normal weather during the summer months. The 1993 increase was
attributable to the acquisition of the Iowa retail service territory
from Union Electric Company (UE) on December 31, 1992, and a return to
more normal weather conditions. Total gas delivered by the Company,
including transported volumes, increased or (decreased) 4.8%, (2.7%) and
5.3% during the years 1995-1993, respectively.
There are seasonal variations in the Company's electric and gas
businesses, which are principally related to the use of energy for air
conditioning and heating. In 1995, 42.1% of the Company's electric
revenues were earned in June through September, reflecting the use of
electricity for cooling, and 67.6% of the Company's gas revenues were
earned in the months of January - March, November and December,
reflecting the use of gas for heating.
The approximate percentages of the Company's revenue and operating
income derived from the sale of electricity and gas during the years
1995-1993 are as follows:
1995 1994 1993
Revenues:
Electric 79% 78% 77%
Gas 19 20 22
Operating income:
Electric 92% 93% 90%
Gas 6 6 10
The relationships between the electric and gas percentages
presented above are influenced by changes in energy sales, timing of
price proceedings and changes in the costs of fuel or purchased gas
billed to customers through related adjustment clauses.
For additional information concerning electric and gas operations,
see Item 1. "Other Information Relating to the Company", Item 7.
"Management's Discussion and Analysis of the Results of Operations and
Financial Condition" and the Electric and Gas Operating Comparisons.
Refer to Note 13 of the Notes to Consolidated Financial Statements
for a further discussion of the Company's segments of business.
Other Information Relating to the Company
PROPOSED MERGER OF INDUSTRIES. Industries, WPL Holdings, Inc.
(WPLH) and Interstate Power Company (IPC) have entered into an Agreement
and Plan of Merger (Merger Agreement), dated November 10, 1995 (the
Proposed Merger). The new holding company will be named Interstate
Energy Corporation (Interstate Energy) and Industries will cease to
exist. The Proposed Merger, which will be accounted for as a pooling of
interests, has been approved by the respective Boards of Directors. It
is still subject to approval by the shareholders of each company as well
as several federal and state regulatory agencies. The companies expect
to receive the shareholder approvals in the second quarter of 1996 and
the regulatory approvals by the second quarter of 1997.
The Merger Agreement contains certain covenants of the parties
pending the consummation of the Proposed Merger. Generally, the parties
and their subsidiaries, including the Company, must carry on their
businesses in the ordinary course consistent with past practice, may not
increase dividends on common stock in excess of current levels in the
case of Industries and IPC, and beyond a specific limit in the case of
WPLH, and may not issue any capital stock beyond certain limits. The
Merger Agreement also contains certain restrictions on, among other
things, charter and bylaw amendments, acquisitions, capital
expenditures, dispositions, incurrence of indebtedness, certain
increases in employee compensation and benefits and affiliate
transactions. The Company does not expect these restrictions to
materially impact its ongoing operations.
Interstate Energy will be the parent of the Company, Wisconsin
Power and Light Company (WP&L), a wholly-owned subsidiary of WPLH, and
IPC and will be registered under the Public Utility Holding Company Act
of 1935, as amended (1935 Act). The Merger Agreement provides that
these operating utility companies will continue to operate as separate
entities for a minimum of three years beyond the effective date of the
merger. In addition, the non-utility operations of Industries and WPLH
will be combined shortly after the effective date of the merger under
one entity to manage the diversified operations of Interstate Energy.
The 1935 Act imposes restrictions on the operations of registered
holding companies. Among these are requirements that securities
issuances, and sales and acquisitions of utility assets, securities of
utility and other companies and any other interests in any business be
approved by the SEC. The 1935 Act also limits the ability of registered
holding companies to engage in non-utility ventures and regulates
holding company service companies and the rendering of services by
holding company affiliates to the affiliated utilities. The Company
believes the benefits of the Proposed Merger far outweigh the effects of
such 1935 Act regulation.
In addition, the SEC historically has interpreted the 1935 Act to
preclude registered holding companies, with limited exceptions, from
owning both electric and gas utility systems. Although the SEC has
recently recommended that registered holding companies be allowed to
hold both gas and electric utility operations if the affected states
agree, it remains possible that the SEC may require as a condition to
its approval of the Proposed Merger that Industries, WPLH and IPC divest
their gas utility properties, and possibly certain non-utility ventures
of Industries and WPLH, within a reasonable time after the effective
date of the Proposed Merger. The Company believes there are strong
policy reasons and prior SEC decisions which support the retention of
existing gas utility properties and non-utility ventures.
Legislation to repeal the 1935 Act was introduced in Congress in
1995 and is pending. No assurance can be given as to when or if such
legislation will be considered or enacted. The Staff of the SEC has
also recommended that the SEC "permit combination systems by registered
holding companies if the affected states concur," and the SEC has
proposed rules that would relax current restrictions on investment by
registered holding companies in certain "energy related," non-utility
businesses. The Company cannot predict the outcome of these legislative
and regulatory proposals.
See Note 2 of the Notes to Consolidated Financial Statements for a
further discussion of the Proposed Merger.
CONSTRUCTION AND ACQUISITION PROGRAM AND FINANCING. The capital
requirements, including $2.8 million of sinking funds that may be met by
pledging additional utility property, for the period 1996-2000 are
estimated at $1.0 billion and are summarized as follows:
Capital Requirements
1996 1997 1998 1999 2000
(in thousands)
Construction and
acquisition expenditures -
Electric:
Generation $ 38,753 $ 54,244 $ 60,952 $ 57,185 $ 38,166
Transmission 34,730 32,975 33,858 32,370 22,968
Distribution 34,322 47,925 45,370 43,163 46,419
Other 8,760 8,926 9,127 9,335 9,548
Gas 9,609 8,310 7,549 9,334 9,682
Steam 10,992 1,250 1,039 405 645
Information
technology 22,109 25,432 11,824 3,365 3,470
Other 5,042 5,900 6,093 6,289 6,492
Total construction and
acquisition
expenditures 164,317 184,962 175,812 161,446 137,390
Energy efficiency
expenditures 13,263 14,325 15,221 14,439 13,235
Long-term debt maturities
and sinking funds 15,770 8,690 690 50,690 67,246
Total capital
requirements $ 193,350 $ 207,977 $ 191,723 $ 226,575 $ 217,871
The Company intends to refinance the majority of the debt
maturities with long-term securities.
Approximately 30% of the Company's construction expenditures are
related to generation. Of this amount, approximately 83% represents
capacity expansions and other improvements at fossil generating stations
and 17% represents modifications and improvements at the Company's
nuclear generating station, the Duane Arnold Energy Center (DAEC).
The 1998-2000 construction and acquisition expenditures in the
preceding table could be revised significantly upon the consummation of
the Proposed Merger.
For a discussion regarding the Company's assumptions in financing
future capital requirements, see the "Liquidity and Capital Resources"
section of Item 7. "Management's Discussion and Analysis of the Results
of Operations and Financial Condition."
REGULATION. The Company operates pursuant to the laws of the State
of Iowa and is thereby subject to the jurisdiction of the Iowa Utilities
Board (IUB). The IUB has authority to regulate rates and standards of
service, to prescribe accounting requirements and to approve the
location and construction of electric generating facilities having a
capacity in excess of 25,000 Kw. The IUB is comprised of three
Commissioners appointed by the Governor and ratified by the State
Senate. Requests for price relief are based on historical test periods,
adjusted for certain known and measurable changes. The IUB must decide
on requests for price relief within 10 months of the date of the
application for which relief is filed or the interim prices granted
become permanent. Interim prices, if allowed, are permitted to become
effective, subject to refund, no later than 90 days after the price
increase application is filed.
In Iowa, non-exclusive franchises, which cover the use of streets
and alleys for public utility facilities in incorporated communities,
are granted for a maximum of twenty-five years by a majority vote of
local qualified residents. In addition, the IUB defines the boundaries
of mutually exclusive service territories for all electric utilities.
The IUB has jurisdiction and grants franchises for the use of public
highway rights-of-way for electric and gas facilities outside corporate
limits.
The Company is subject to the jurisdiction of the Federal Energy
Regulatory Commission (FERC) with respect to wholesale electric sales
and the issuance of securities. Revenues derived from the Company's
wholesale and off-system sales amounted to 6.3%, 6.9% and 9.0% of
electric revenues for 1995-1993, respectively. The Company's
consolidated subsidiaries are not subject to regulation by the IUB or
the FERC.
EMPLOYEES. At December 31, 1995, the Company had a total of 2,204
regular full-time employees, of which an aggregate of 1,152 employees
were subject to 6 collective bargaining arrangements (824 of these
employees were part of one arrangement).
ENVIRONMENTAL MATTERS. The Company is regulated in environmental
protection matters by a number of federal, state and local agencies.
Such regulations are the result of a number of environmental protection
laws passed by the U. S. Congress, state legislature and local
governments and enforced by federal, state and county agencies. The
laws impacting the Company's operations include the Clean Water Act;
Clean Air Act, as amended by the Clean Air Act Amendments of 1990;
National Environmental Policy Act; Resource Conservation and Recovery
Act; Comprehensive Environmental Response, Compensation and Liability
Act of 1980 (CERCLA), as amended by the Superfund Amendments and
Reauthorization Act of 1986; Occupational Safety and Health Act;
National Energy Policy Act of 1992 and a number of others. The Company
regularly secures and renews federal, state and local permits to comply
with the environmental protection laws and regulations. Costs
associated with such compliances have increased in recent years and are
expected to increase moderately in the future.
At December 31, 1995, the Company had recorded $46.4 million of
environmental liabilities, which, pursuant to generally accepted
accounting principles, represents either the best current estimate or
the minimum amount of the estimated range of such costs which the
Company expects to incur, depending on the information known for each
site. These estimates are subject to continuing review and actual costs
could ultimately exceed the recorded amounts.
The Clean Air Act Amendments Act of 1990 (Act) calls for
significant reductions in sulfur dioxide and nitrogen oxide air
emissions. The majority of such reductions will be required from
utilities in the United States. It is anticipated that any costs
incurred by the Company will be recovered from its ratepayers under
current regulatory principles. Refer to Notes 11(a) and 11(g) of the
Notes to Consolidated Financial Statements for additional information
regarding the Company's expected expenditures.
The acid rain program under the Act also creates sulfur dioxide
allowances. An allowance is defined as an authorization for an owner to
emit one ton of sulfur dioxide into the atmosphere. Currently, the
Company receives a sufficient number of allowances annually to offset
its emissions of sulfur dioxide from its Phase I units. It is
anticipated that in the year 2000, when the Phase II units participate
in the allowance program, the Company may have an insufficient number of
allowances annually to offset its estimated emissions and may have to
purchase additional allowances, or make modifications to the plants or
limit operations to reduce emissions. The Company is reviewing its
options to ensure that it will have sufficient allowances to offset its
emissions in the year 2000 and thereafter. The Company believes that
the potential cost of ensuring sufficient allowances will not have a
material adverse effect on its financial position or results of
operations.
In 1995, the EPA published the Sulfur Dioxide Network Design Review
for Cedar Rapids, Iowa, which, based on the EPA's assumptions and worst-
case modeling methods, suggests that the Cedar Rapids area could be
classified as "nonattainment" for the National Ambient Air Quality
Standard (NAAQS) established for sulfur dioxide. The worst-case
modeling study suggests that two of the Company's generating facilities
contribute to the modeled exceedences and recommends that additional
monitors be located near the Company's sources to assess actual ambient
air quality. In the event that the Company's facilities contribute
excessive emissions, the Company would be required to reduce emissions,
which would primarily entail capital expenditures for modifications to
the facilities. The Company is currently reviewing EPA's assumptions
and modeling results and is proposing a strategy to voluntarily reduce
the excessive emissions through modification of its facilities at a
potential capital cost of up to $10 million over the next four years.
The Company has been named as a Potentially Responsible Party (PRP)
for certain former manufactured gas plant (FMGP) sites by either the
Iowa Department of Natural Resources (IDNR), the Minnesota Pollution
Control Agency (MPCA) or the EPA. The Company is working with the IDNR,
MPCA and EPA to investigate its sites and to determine the appropriate
remediation activities that may be needed to mitigate health and
environmental concerns.
The Company is investigating the possibility of insurance and third
party cost sharing for FMGP clean-up costs. The amount of shared costs,
if any, cannot be reasonably determined and, accordingly, no potential
sharing has been recorded at December 31, 1995. Considering the rate
treatment allowed by the IUB, management believes that the clean-up
costs incurred by the Company for these FMGP sites will not have a
material adverse effect on its financial position or results of
operations. Refer to Note 11(f) of the Notes to Consolidated Financial
Statements for more information.
The Nuclear Waste Policy Act of 1982 assigned responsibility to the
U.S. Department of Energy (DOE) to establish a facility for the ultimate
disposition of high level waste and spent nuclear fuel and authorized
the DOE to enter into contracts with parties for the disposal of such
material beginning in January 1998. The Company entered into such a
contract and has made the agreed payments to DOE. The DOE, however, has
experienced significant delays in its efforts and material acceptance is
now expected to occur no earlier than 2010 with the possibility of
further delay being likely. The Company has been storing spent nuclear
fuel on-site since plant operations began in 1974 and has current on-
site capability to store spent fuel until 2002. The Company is
aggressively reviewing options for additional spent nuclear fuel storage
capability, including expanding on-site storage and supporting
legislation currently before the U.S. Congress, to resolve the lack of
progress by the DOE.
The Low-Level Radioactive Waste Policy Amendments Act of 1985
mandated that each state must take responsibility for the storage of low-
level radioactive waste produced within its borders. The State of Iowa
has joined the Midwest Interstate Low-Level Radioactive Waste Compact
Commission (Compact), which is planning a storage facility to be located
in Ohio to store waste generated by the Compact's six member states. At
December 31, 1995, the Company has prepaid costs of approximately
$1.1 million to the Compact for the building of such a facility. A
Compact disposal facility is anticipated to be in operation in
approximately ten years after approval of new enabling legislation by
the member states. Such legislation is expected to be considered by the
member states in 1996. On-site storage capability currently exists for
low-level radioactive waste expected to be generated until the Compact
facility is able to accept waste materials. In addition, the Barnwell,
South Carolina disposal facility has reopened for an indefinite time
period and the Company is in the process of shipping to Barnwell the
majority of the low-level radioactive waste it has accumulated on-site,
and intends to ship the waste it produces in the future as long as the
Barnwell site remains open, thereby minimizing the amount of waste
stored on-site.
The Company was notified in 1986 that it was designated by the EPA
as a PRP (there are 832 in total) for the investigation and cleanup of
the Maxey Flats Nuclear Disposal site at Morehead, Kentucky. The EPA
notice encouraged all PRPs to undertake voluntary clean up activities at
the site. A Steering Committee was organized and the Company is
participating in its activities. The Steering Committee has reached
settlement of the issues with the EPA, the State of Kentucky and
deminimis parties. Consent Decrees have been submitted to the court for
approval. Upon approval by the court, the Company's share of the costs
is estimated at $300,000, which is included in the $46.4 million of
environmental liabilities the Company has recorded at December 31, 1995.
The possibility that exposure to electric and magnetic fields (EMF)
emanating from power lines, household appliances and other electric
sources may result in adverse health effects has been the subject of
increased public, governmental, industry and media attention. A
considerable amount of scientific research has been conducted on this
topic without definitive results. Research is continuing in order to
resolve scientific uncertainties. The Company cannot predict the
outcome of this research.
Refer to Note 11 of the Notes to Consolidated Financial Statements
and Item 7. "Management's Discussion and Analysis of the Results of
Operations and Financial Condition" for further discussion of
environmental matters.
RATE MATTERS. Refer to Note 3 of the Notes to Consolidated
Financial Statements for a discussion of the Company's rate matters.
ELECTRIC OPERATIONS. The Company's net peak load (60 minutes
integrated) of 1,824,100 kilowatts occurred on July 12, 1995, and
represented a new energy peak demand record. At the time of the peak
load, no interruptible customers were interrupted. The Company'
additional reserve obligation at the time of the peak was 256,215
kilowatts and the net capability of the Company's generating stations
was 1,873,300 kilowatts, with an additional 207,100 kilowatts being
available under purchase contracts, thereby providing an aggregate
capability of 2,080,400 kilowatts.
The Company projects an electric sales growth rate of approximately
2 to 3 percent per year over the next decade, which will be met by a mix
of its existing generation, capacity purchases and new construction.
The construction activities will be undertaken in a fashion that best
meets the needs of individual customers and the system as a whole. See
Note 11(b) of the Notes to Consolidated Financial Statements for a
discussion of the Company's firm contracts for the purchase of capacity.
The Company is interconnected with other utilities in Iowa and
neighboring states and is a member of the Mid-Continent Area Power Pool
(MAPP). MAPP's purpose is to coordinate the planning, construction and
operation of generation and transmission facilities, and the purchase
and sale of power and energy among its members.
The Company is a party to the Twin Cities-Iowa-St. Louis 345 Kv
Interconnection Coordinating Agreement (the Coordinating Agreement) with
five other midwestern utilities, three of which operate in the State of
Iowa. The Coordinating Agreement provides for the interconnection of
the respective systems of the companies through a 345 Kv transmission
line and for the interchange of power on various bases. The rates under
the Coordinating Agreement are primarily determined by agreement between
the delivering and receiving companies.
The Company maintains and operates transmission and substation
facilities connecting with its high voltage transmission systems
pursuant to a non-cancelable operating agreement (the Operating
Agreement) with Central Iowa Power Cooperative (CIPCO). The Operating
Agreement, which will terminate on December 31, 2035, provides for the
joint use of certain transmission facilities of the Company and CIPCO.
Upon consummation of the Proposed Merger, the Company expects to
realize reduced electric production costs through the joint dispatch of
systems and increased marketing opportunities in the wholesale and
interchange markets through electric interconnections with other
utilities.
For comments relating to agreements between the Company and its
partners for the joint ownership of the DAEC, the Ottumwa Generating
Station (OGS), and Neal Unit No. 3, see Item 2. "Properties" and Note 12
of the Notes to Consolidated Financial Statements.
FUEL SUPPLY. The following table details the sources of the
electricity sold by the Company during 1995 and expected sources for the
following three years:
Actual /------------ Expected ------------/
1995 1996 1997 1998
Fossil, primarily coal 51% 57% 62% 62%
Nuclear 23 25 26 22
Purchases 26 18 12 16
100% 100% 100% 100%
The Company is currently on an eighteen-month cycle for nuclear
refueling outages and the above percentages assume outages will occur
during both 1996 and 1998. There was also a refueling outage in 1995.
The increase in the expected fossil percentages from the 1995 actual is
primarily a function of lower projected fuel costs for 1996-1998 and
anticipated increases in the availability and efficiency of its fossil
generating stations due to improvements made at certain stations in
recent years.
The Company's primary fuel source is coal and the generation mix is
influenced directly by refueling outages at the DAEC. The average cost
of fuel used for generation by the Company for the years 1995-1993 is
presented below:
1995 1994 1993
Average cost of fuel:
Nuclear, per million Btu's $ .76 $ .67 $ .60
Coal, per million Btu's .97 .97 .97
Average for all fuels,
per million Btu's .95 .89 .90
The increases in the average cost of nuclear fuel are the result of
compounded interest charges on uranium acquired during the mid-1980's.
The Company expects to use the last of this uranium during the 1996
refueling outage. The Company has entered into an new contract to meet
its nuclear fuel needs beyond 1996 and the average cost of such fuel is
expected to be significantly lower than that under the current contract.
The following table summarizes the Company's minimum coal contract
commitments at December 31, 1995:
Average
Annual Maximum estimated base price
Quantity Termination Sulfur per ton of coal delivered
(Tons) Date Content 1996 1997 1998
Cordero
Mining Co.
(OGS) (1) 774,450 12/31/01 0.6% $ 18.32 $ 18.86 $ 19.40
Koch Carbon Inc.
(Sutherland) 100,000 12/31/99 6.2% $ 19.51 $ 19.77 $ 20.07
Powder River
Coal Co.
(OGS or
BGS) (2) 1,200,000 12/31/97 0.4% $ 15.57 $ 16.04 $ N/A
Thunder Basin
(Sutherland) 320,000 12/31/96 0.3% $ 13.95 $ N/A $ N/A
Caballo Rojo
(BGS) (3) 200,000 12/31/96 0.3% $ 15.18 $ N/A $ N/A
Caballo Rojo
(Prairie Creek or
Sixth Street)
(3) 640,000 12/31/96 0.3% $ 16.56 $ N/A $ N/A
Franklin Coal
Sales Co.
(OGS) 262,500 9/30/97 0.5% $ 12.60 $ 12.68 $ N/A
(1) Cost under the contract is comprised of base contract
prices plus specifically contracted periodic adjustments for
increases in certain specific costs of producing the coal.
The effect of such adjustments to the base contract prices of
future coal cannot currently be predicted with any certainty.
(2) The contract covers 1,200,000 annual tons delivered to
either the OGS or the Burlington Generating Station (BGS).
The prices listed in the table are for BGS. The OGS prices
are $12.80 and $13.19 per ton for 1996 and 1997, respectively.
The Company anticipates that approximately 65 to 70 percent of
the total 1,200,000 annual tons will be delivered to OGS
during 1996 and 1997.
(3) The contract contains an option for a 1 year extension.
During 1995, the Company purchased a total of 3,728,000 tons of
coal for its generating plants. At December 31, 1995, the Company had a
weighted average of 63 days' usage of coal inventory at its principal
generating stations.
The Company estimates that its existing coal fired generating units
will require approximately 13,531,000 tons of coal to operate during the
period 1996-1998. The average annual quantities listed in the preceding
table represent the Company's minimum commitments. Many of the
contracts contain provisions allowing the Company to purchase additional
tons of coal. The Company estimates that it has the capability to
purchase over 70% of its 1996-1998 coal requirements under these
contracts and will meet the remainder of its requirements from either
future contracts or purchases in the spot market. The Company believes
that an ample supply of coal is available in the spot market to meet its
needs.
Some of the Company's contracted coal supply is provided by surface
mining operations which are regulated by the Federal Strip Mine Act.
Most of the surface mining coal contracts contain clauses which pass
reclamation and royalty costs through to the respective utility; such
costs billed to the Company are recoverable through its Energy
Adjustment Clauses (EAC). See Note 1(j) of the Notes to Consolidated
Financial Statements for discussion of the EAC.
A purchase of uranium in the form of UF6 was made in 1995 from
NUKEM which completes the Company's requirements for the 1996 refueling.
A new six year contract for enrichment services and enriched uranium
product was negotiated with the United States Enrichment Corporation
(USEC) which will reduce the Company's enrichment and uranium costs.
Fabrication of the nuclear fuel is being performed by General Electric
Company for fuel through the 2008 refueling of the DAEC. The Company
believes that an ample supply of uranium and enrichment services will be
available in the future and intends to purchase such uranium and
enrichment services as necessary on the spot market and/or via medium
length (less than five years) contracts to supplement its current
contracts and meet its generation requirements. See Note 11(f) of the
Notes to Consolidated Financial Statements for a discussion of the
Company's assessment under the National Energy Policy Act of 1992 for
the "Uranium Enrichment Decontamination and Decommissioning Fund," which
is based upon prior nuclear fuel purchases.
Refer to Item 1. "Environmental Matters" for a discussion of
nuclear waste disposal issues.
NUCLEAR REGULATORY COMMISSION (NRC) AND OTHER NUCLEAR MATTERS. As
an owner and the operator of a nuclear generating unit at the DAEC, the
Company is subject to the jurisdiction of the NRC. The NRC has broad
supervisory and regulatory jurisdiction over the construction and
operation of nuclear reactors, particularly with regard to public
health, safety and environmental considerations. The Company's current
NRC license for DAEC expires in 2014.
The operation and design of nuclear power plants is under constant
review by the NRC. The Company has complied with and is currently
complying with all NRC requests for data relating to these reviews. The
NRC also continues to review and reduce the backlog of general and
unresolved safety issues. As a result of such reviews, further changes
in operations or modifications of equipment may be required, the cost of
which cannot currently be estimated. The Company's anticipated nuclear-
related construction expenditures for 1996-2000 are $41 million.
The DAEC received the highest ratings in its 20-year history in the
NRC's recent Systematic Assessment of Licensee Performance (SALP) report
by earning the highest score possible (1 on a 3-point scale) in the
areas of plant operations, engineering and plant support and a "good"
rating (2) in the area of maintenance.
The Company conducted an inspection during the 1995 refueling
outage of the DAEC reactor core internals. This was in response to
cracking identified in similar reactors. No cracks were identified and
no related repairs were required. The Company continues its efforts to
monitor and maintain the reactor core internals.
The large amount of change in regulations, designs and procedures
that occur for a nuclear power plant over a period of time presents a
difficult task to ensure that all affected design information documents,
procedures and specifications are continually updated. The Company has
essentially completed a Configuration Management Plan and a Design Basis
Program which is designed to coordinate control of the updating and
maintenance of plant documents to ensure regulatory requirements are
met. No additional significant expenditures are currently expected in
1996 or thereafter.
Under the Price-Anderson Amendments Act of 1988 (1988 Act), the
Company currently has the benefit of $8.9 billion of public liability
coverage which would compensate the public in the event of an accident
at a commercial nuclear power plant. The 1988 Act permits such coverage
to rise with increased availability of nuclear insurance and the
changing number of operating nuclear plants subject to retroactive
premium assessments. The 1988 Act provides for inflation indexing
(Consumer Price Index every fifth year) of the retroactive premium
assessments.
As an outgrowth of the Three Mile Island Nuclear Power Plant (TMI)
experience, nuclear plant owners have initiated a cooperative insurance
program designed to help cover replacement power expenses for
participating utilities arising from a possible nuclear plant accident.
The Company is a participant in this program. This type of insurance is
an industry response intended to lessen the cost burden on customers in
the event of a lengthy plant shutdown.
To provide this coverage, a nuclear utility mutual insurance
company known as Nuclear Electric Insurance Limited (NEIL) was formed.
Under the Company's policy, following a 21 week waiting period from the
time of an accident, coverage of up to 100% of estimated replacement
power costs for an ensuing one year period is provided and up to 80% of
that amount will be provided for a second and third year. The annual
premium cost to the Company is estimated to be less than the cost of
replacement power for one week.
The Company currently carries primary property insurance coverage
on the DAEC facility of $500 million with Nuclear Mutual Limited (NML).
Following the TMI incident, it became apparent to nuclear plant owners
that the commercially available property insurance was inadequate
considering the cost of decontamination. Consequently, the Company
obtained excess property insurance through NEIL. NEIL excess insurance
provides an additional $1.4 billion of coverage after losses exceed $500
million. These policies bring the total property coverage to
$1.9 billion.
For information concerning the potential assessment of retroactive
premiums relating to the above described public liability, replacement
power and excess property insurance coverages, refer to Note 11(e) of
the Notes to Consolidated Financial Statements. The NRC established
requirements with respect to guaranteeing the ability of owners to make
such retroactive payments on the public liability policy. Of the
various alternatives available, the Company elected to submit certified
financial statements showing that sufficient cash flow could be
generated and would be available for payment of the required assessments
within a three month period. The maximum of the annual retroactive
premiums was approximately $7 million at December 31, 1995.
Refer to Item 1. "Environmental Matters" for a discussion of
nuclear waste disposal issues.
COMPETITION. As legislative, regulatory, economic and
technological changes occur, electric utilities are faced with
increasing pressure to become more competitive. Such competitive
pressures could result in loss of customers and an incurrence of
stranded costs (i.e. the cost of assets which could be rendered
otherwise unrecoverable as the result of competitive pricing). To the
extent stranded costs cannot be recovered from customers, they would be
borne by security holders.
The National Energy Policy Act of 1992 addresses several matters
designed to promote competition in the electric wholesale power
generation market, including mandated open access to the electric
transmission system. In March 1995, the FERC issued a Notice of
Proposed Rulemaking pursuant to which FERC proposes to promote
competition in the electric utility industry by requiring that each
transmission owning utility must 1) implement non-discriminatory tariffs
allowing open access to that utility's transmission facilities by
wholesale buyers and sellers of electricity and 2) charge itself the
same price for transmission and ancillary services as it charges third
parties under the tariffs. The Company filed conforming pro-forma open
access transmission tariffs with the FERC on July 24, 1995. The tariffs
were accepted by the FERC and became effective October 1, 1995. The
geographic position of the Company's transmission system could provide
revenue opportunities in the open access environment. FERC's proposal
would allow for recovery of certain wholesale stranded costs in
connection with wholesale transmission. The Company cannot predict the
final regulations that may be adopted.
The IUB initiated a Notice of Inquiry (Docket No. NOI-95-1) in
early 1995 on the subject of "Emerging Competition in the Electric
Utility Industry." A one-day roundtable discussion was held to address
all forms of competition in the electric utility industry and to assist
the IUB in gathering information and perspectives on electric
competition from all persons or entities with an interest or stake in
the issues. Additional discussions were held in December 1995. The IUB
is expected to release a status report on the inquiry in the first
quarter of 1996. The IUB has not yet taken a position on these
competitive issues.
The Company is subject to the provisions of Statement of Financial
Accounting Standards No. 71, "Accounting for the Effects of Certain
Types of Regulation" (SFAS 71). If a portion of the Company's
operations become no longer subject to the provisions of SFAS 71, a
write-down of related regulatory assets would be required, unless some
form of transition cost recovery is established by the appropriate
regulatory body. The Company believes that it still meets the
requirements of SFAS 71. Refer to Note 1(c) of the Notes to
Consolidated Financial Statements for a further discussion.
The Company cannot predict the long-term consequences of these
competitive issues on its results of operations or financial condition.
The Company's strategy for dealing with these emerging issues includes
seeking growth opportunities, continuing to offer quality customer
service, ongoing cost reductions and productivity enhancements. In
1995, the Company initiated a program called Process Redesign to examine
all of the major business processes of the Company. The goals of
Process Redesign include improving customer service and commitment and
significantly reducing the Company's cost structure. In 1995, Process
Redesign identified many of the changes that the Company should pursue
and the Company has begun implementing many of those actions.
Implementation will be substantially completed in 1996.
GAS OPERATIONS. With the advent of FERC Order 636 (Order 636),
issued in 1992, the nature of the Company's gas supply portfolio has
changed. Order 636, among other things, eliminated the interstate
pipelines' obligation to serve and now requires the Company to purchase
virtually 100% of its gas supply requirements from non-pipeline
suppliers. The Company has enhanced access to competitively priced gas
supply and more flexible transportation services as a result of Order
636. However, under Order 636, the Company is required to pay certain
transition costs incurred and billed by its pipeline suppliers.
The Company began paying the transition costs in 1993 and at
December 31, 1995, has recorded a liability of $5.0 million for those
transition costs that have been incurred, but not yet billed, by the
pipelines to date, including $1.9 million expected to be billed through
1996. The Company is currently recovering the transition costs from its
customers through its Purchased Gas Adjustment Clauses as such costs are
billed by the pipelines. Transition costs, in addition to the recorded
liability, that may ultimately be charged to the Company could
approximate $7.0 million. The ultimate level of costs to be billed to
the Company depends on the pipelines' future filings with the FERC and
other future events, including the market price of natural gas.
However, the Company believes any transition costs that the FERC would
allow the pipelines to collect from the Company would be recovered from
its customers, based upon regulatory treatment of these costs currently
and similar past costs by the IUB. Accordingly, regulatory assets, in
amounts corresponding to the recorded liabilities, have been recorded to
reflect the anticipated recovery.
Contracts with the pipelines subsequent to Order 636 are comprised
primarily of firm transportation, firm storage and no-notice service.
Firm transportation contracts grant the Company access to firm pipeline
capacity which is used to transport gas supplies from non-pipeline
suppliers on peak day. Firm storage service allows the Company to
purchase gas during off-peak periods and place this gas in an account
with the pipelines. When the gas is needed for peak day deliveries, the
Company requests and the pipelines deliver the gas back on a firm basis.
No-notice service grants the Company the right to take more or less gas
than is actually scheduled up to the level of no-notice service. No-
notice service takes the form of transportation balancing or storage
service depending on the pipeline.
The Company's portfolio of firm transportation, firm storage and no-
notice service from pipelines is as follows:
Firm Firm
Transportation Storage No-Notice
Northern:
Volume (Dekatherm/day) 142,996 48,218 10,000
Expiration date 10/31/97 10/31/97 10/31/97
Natural:
Volume (Dekatherm/day) 28,605 35,010 -
Expiration date 11/30/2000 11/30/98 -
ANR:
Volume (Dekatherm/day) 60,737 19,180 5,000
Expiration date 10/31/2003 10/31/2003 10/31/2003
In addition to firm storage with pipelines, the Company also
contracts for firm storage from Llano, Inc. This contract calls for
peak day deliveries of 18,667 Dekatherm(Dth)/day and expires May 31,
1997.
Gas supply is purchased from a variety of non-pipeline suppliers
located in the United States and Canada having access to virtually all
major natural gas producing regions. For the calendar year 1995, the
Company's maximum daily load occurred on January 4, 1995, with total
system flow of approximately 270,000 dekatherms, including transported
volumes, and total contract availability of approximately 276,000
dekatherms.
As a result of Order 636, the Company accepted assignment of
certain gas supply contracts previously held by Northern. Accepting
assignment of these contracts resulted in lower costs to the Company
than would have been incurred had Northern bought out the agreements and
billed the Company for its share of such costs.
Contracts assigned to the Company from Northern have maximum
delivery requirements of 13,631 Dth, and minimum take requirements of
2,726 Dth. Additional firm gas supply agreements were independently
negotiated by the Company with various non-pipeline suppliers. These
gas supply agreements have maximum and minimum obligations and will be
delivered through gas transmission pipelines as follows:
Maximum Minimum
Daily Quantity Daily Quantity
(Dth/day) (Dth/day)
Northern 56,681 37,939
Natural 24,575 19,575
ANR 28,000 20,000
These gas supply contracts have expiration dates ranging from five
months to six years.
Rates charged by the Company's suppliers are subject to regulation
by the FERC. A purchased gas adjustment clause (PGA) allows the Company
to adjust customer rates as a result of changes in the cost of gas
purchased. See Note 1(j) of the Notes to Consolidated Financial
Statements for discussion of the PGA.
<TABLE>
ELECTRIC OPERATING COMPARISON
<CAPTION> FIVE-YEAR
COMPOUND
RATE OF
1995 1994 1993 1992 1991 1990 GROWTH (1)
<S> <C> <C> <C> <C> <C> <C> <C>
Operating revenue (000's):
Residential and rural $ 216,270 $ 199,587 $ 203,870 $ 176,811 $ 188,504 $ 184,662
General service 97,496 97,454 99,221 87,202 86,744 83,634
Large general service 199,840 191,601 184,657 140,496 138,213 134,000
Street lighting 8,810 8,521 8,404 7,241 7,118 7,180
Total from ultimate consumers 522,416 497,163 496,152 411,750 420,579 409,476
Sales for resale 17,554 19,195 20,254 18,602 19,745 19,582
Off-system 17,802 18,077 29,400 28,304 36,596 31,144
Other 2,699 2,892 4,715 4,343 5,658 3,047
$ 560,471 $ 537,327 $ 550,521 $ 462,999 $ 482,578 $ 463,249
Energy sales (000's Kwh):
Residential and rural 2,680,340 2,484,089 2,518,580 2,146,079 2,362,847 2,248,126 3.6%
General service 1,242,373 1,170,923 1,166,072 1,061,444 1,069,956 1,031,167 3.8%
Large general service 5,283,694 4,990,890 4,581,590 3,320,439 3,174,972 2,981,890 12.1%
Street lighting 77,388 77,952 78,004 75,957 79,254 80,276 -0.7%
Total to ultimate consumers 9,283,795 8,723,854 8,344,246 6,603,919 6,687,029 6,341,459 7.9%
Sales for resale 499,719 567,721 561,276 528,752 557,180 538,677 -1.5%
Sales of electricity to
customers 9,783,514 9,291,575 8,905,522 7,132,671 7,244,209 6,880,136 7.3%
Off-system 1,086,121 1,137,219 2,068,015 2,275,616 2,738,159 2,282,204 -13.8%
10,869,635 10,428,794 10,973,537 9,408,287 9,982,368 9,162,340 3.5%
Sources of electric energy (000's Kwh):
Generation:
Fossil, primarily coal 5,775,002 5,522,966 5,356,930 4,317,154 4,758,720 4,354,697
Nuclear (2) 2,610,979 2,875,867 2,264,507 2,402,501 2,902,768 2,108,100
Hydro 7,690 8,205 7,201 7,579 6,547 4,195
8,393,671 8,407,038 7,628,638 6,727,234 7,668,035 6,466,992
Purchases 3,012,934 2,646,673 3,949,296 3,322,182 2,994,216 3,282,886
11,406,605 11,053,711 11,577,934 10,049,416 10,662,251 9,749,878
Net capability at time of peak load (Kw):
Generating capability 1,873,300 1,741,100 1,733,700 1,718,600 1,719,150 1,684,700
Purchase capability 207,100 280,000 248,000 207,000 227,000 179,000
Capacity credits (3) 0 0 0 0 0 18,960
2,080,400 2,021,100 1,981,700 1,925,600 1,946,150 1,882,660 2.0%
Net peak load (Kw) (4) 1,824,100 1,779,627 1,716,380 1,425,441 1,607,606 1,547,826 3.3%
Number of customers at year-end 333,489 330,405 327,265 325,172 305,663 304,265 1.7%
Revenue per Kwh (excluding
off-system) in cents 5.55 5.59 5.85 6.09 6.16 6.28 -2.4%
(1) The five-year compound growth rates include the effect of the acquisition
of the Iowa service territory from Union Electric Company on
December 31, 1992.
(2) Represents IES Utilities' 70% undivided interest in the Duane Arnold
Energy Center, which is operated by IES Utilities Inc.
(3) Represents capacity credits from municipals served by IES Utilities Inc.
(4) 60 minutes integrated.
</TABLE>
<TABLE>
GAS OPERATING COMPARISON
<CAPTION>
Five-year
compound
rate of
1995 1994 1993 1992 1991 1990 growth
<S> <C> <C> <C> <C> <C> <C> <C>
Operating revenue (000's):
Residential $ 84,562 $ 82,795 $ 90,462 $ 78,685 $ 74,114 $ 66,513
Commercial 40,390 40,912 45,528 39,780 37,613 35,378
Industrial 8,790 12,515 15,593 18,649 17,383 21,500
133,742 136,222 151,583 137,114 129,110 123,391
Other 3,550 2,811 2,735 2,341 1,908 1,884
$ 137,292 $ 139,033 $ 154,318 $ 139,455 $ 131,018 $ 125,275
Energy sales (000's dekatherms):
Residential 16,302 15,766 16,971 15,098 15,571 14,315 2.6%
Commercial 9,534 9,298 10,133 8,479 9,389 8,798 1.6%
Industrial 3,098 4,010 4,618 6,175 5,980 6,640 -14.1%
28,934 29,074 31,722 29,752 30,940 29,753 -0.6%
Industrial - transported volumes 10,871 8,901 7,284 7,283 6,189 6,733 10.1%
Total volumes delivered 39,805 37,975 39,006 37,035 37,129 36,486 1.8%
Operating statistics:
Cost per dekatherm of gas
purchased for resale $ 3.13 $ 3.31 $ 3.49 $ 3.36 $ 3.10 $ 3.23
Peak daily sendout in dekatherms 269,545 288,352 268,419 254,989 266,344 272,089 -0.2%
Number of customers at year-end 174,470 172,829 170,719 167,813 164,078 161,794 1.5%
Revenue per dekatherm sold
(excluding transported volumes) 4.62 4.69 4.78 4.61 4.17 4.15 2.2%
</TABLE>
Item 2. Properties
The Company's principal electric generating stations at December
31, 1995, are as follows:
Name and Location Major Fuel Net Kilowatts Accredited
of Station Type Generating Capability
Duane Arnold Energy Center,
Palo, Iowa Nuclear 364,000 (1)
Ottumwa Generating Station,
Ottumwa, Iowa Coal 343,440 (2)
Prairie Creek Station,
Cedar Rapids, Iowa Coal 212,500
Sutherland Station,
Marshalltown, Iowa Coal 143,000
Sixth Street Station,
Cedar Rapids, Iowa Coal 71,000
Burlington Generating Station,
Burlington, Iowa Coal 211,800
George Neal Unit 3,
Sioux City, Iowa Coal 144,200 (3)
Total Coal 1,125,940
Peaking Turbines,
Marshalltown, Iowa Oil 162,500
Centerville Combustion Turbines,
Centerville, Iowa Oil 48,000
Diesel Stations, all in Iowa Oil 12,200
Total Oil 222,700
Grinnell Station,
Grinnell, Iowa Gas 47,200
Agency Street Combustion Turbines,
West Burlington, Iowa Gas 63,750
Burlington Combustion Turbines,
Burlington, Iowa Gas 47,400
Total Gas 158,350
Total generating capability 1,870,990
(1) Represents the Company's 70% ownership interest in this
520,000 Kw generating station. The plant is operated by the
Company.
(2) Represents the Company's 48% ownership interest in this
715,500 Kw generating station. The plant is operated by the
Company.
(3) Represents the Company's 28% ownership interest in this
515,000 Kw generating station which is operated by an
unaffiliated utility.
At December 31, 1995, the transmission lines of the Company,
operating from 34,000 to 345,000 volts, approximated 4,409 circuit miles
(all located in Iowa). The Company owned 108 transmission substations
(all located in Iowa) with a total installed capacity of 8,597.1 MVa and
468 distribution substations (all located in Iowa) with a total
installed capacity of 2,593.1 MVa.
The Company's principal properties are suitable for their intended
use. The Company's principal properties are held subject to liens of
indentures relating to its Bonds.
Item 3. Legal Proceedings
Reference is made to Notes 3 and 11 of the Notes to Consolidated
Financial Statements for a discussion of the Company's rate proceedings
and environmental matters, respectively. Also see Item 1. "Business -
Environmental Matters" and Item 7. "Management's Discussion and
Analysis of the Results of Operations and Financial Condition."
Item 4. Submission of Matters to a Vote of Security Holders
None.
PART II
Item 5. Market for the Registrant's Common Stock and Related
Stockholder Matters
All outstanding common stock of the Company is held by its parent
(Industries) and is not traded.
The dividends declared for the last two years are as follows:
Quarter
Dividends Declared
(000's)
1995
First Quarter $ 13,000
Second Quarter 10,000
Third Quarter 10,000
Fourth Quarter 10,000
$ 43,000
1994
First Quarter $ 7,000
Second Quarter 15,000
Third Quarter 15,000
Fourth Quarter 15,000
$ 52,000
The Company has the right under the terms of the Subordinated
Deferrable Interest Debentures, so long as an Event of Default has not
occurred and is not continuing, to extend the interest payment period at
any time and from time to time on the Subordinated Deferrable Interest
Debentures to a period not exceeding 20 consecutive quarters. If the
Company exercises its right to extend the interest payment period, the
Company may not, during any such extended interest payment period,
declare or pay dividends on, or redeem, purchase or acquire, or make any
liquidation payment with respect to, any of its capital stock or make
any guarantee payment with respect to the foregoing. The Company does
not intend to exercise its right to extend the interest payment period.
Item 6. Selected Consolidated Financial Data
The following selected consolidated financial data, in the opinion
of the Company, includes adjustments, which are normal and recurring in
nature, necessary for the fair presentation of the results of operations
and financial position. See Item 7. "Management's Discussion and
Analysis of the Results of Operations and Financial Condition" for a
discussion of transactions that affect the comparability of the years
1995-1993.
The 1995 results were affected by the impact of the IUB price
reduction order in the Company's recent electric rate case and
significantly warmer than normal weather. The 1993 results were
affected by the acquisition of the Iowa service territory from Union
Electric Company on December 31, 1992.
The Selected Consolidated Financial Data should be read in
conjunction with the Consolidated Financial Statements, the Notes to
Consolidated Financial Statements and Management's Discussion and
Analysis of the Results of Operations and Financial Condition contained
elsewhere in this report.
<TABLE>
SELECTED CONSOLIDATED FINANCIAL DATA
<CAPTION>
Year Ended December 31
1995 1994 1993 1992 1991
($ in thousands)
<S> <C> <C> <C> <C> <C>
Operating revenues $ 709,826 $ 685,366 $ 713,750 $ 610,262 $ 621,993
Operating income 142,265 135,591 143,329 100,361 101,600
Net income 59,278 61,210 67,970 45,291 47,563
Net income available for common stock 58,364 60,296 67,056 43,562 45,393
Cash dividends declared on common stock 43,000 52,000 31,300 24,721 45,321
Total assets 1,708,635 1,645,368 1,546,978 1,440,891 1,304,110
Long-term obligations 519,991 532,927 535,101 492,149 446,499
Times interest earned before income taxes 3.26 3.39 3.64 2.67 2.93
Capitalization ratios:
Common equity 51% 50% 50% 48% 49%
Preferred and preference stock 2 2 2 2 4
Long-term debt 47 48 48 50 47
100% 100% 100% 100% 100%
</TABLE>
Item 7.
MANAGEMENT'S DISCUSSION AND ANALYSIS
OF THE RESULTS OF OPERATIONS AND FINANCIAL CONDITION
The Consolidated Financial Statements include the accounts of IES
Utilities Inc. (Utilities) and its consolidated subsidiaries
(collectively the Company). Utilities is a wholly-owned subsidiary of
IES Industries Inc. (Industries). Utilities' only wholly-owned
subsidiary at December 31, 1995 was IES Ventures Inc.
PROPOSED MERGER OF INDUSTRIES
Industries, WPL Holdings, Inc. (WPLH) and Interstate Power Company
(IPC) have entered into an Agreement and Plan of Merger (Merger
Agreement), dated November 10, 1995 (the Proposed Merger). The new
holding company will be named Interstate Energy Corporation (Interstate
Energy) and Industries will cease to exist. The Proposed Merger, which
will be accounted for as a pooling of interests, has been approved by
the respective Boards of Directors. It is still subject to approval by
the shareholders of each company as well as several federal and state
regulatory agencies. The companies expect to receive the shareholder
approvals in the second quarter of 1996 and the regulatory approvals by
the second quarter of 1997.
The business of Interstate Energy will consist of utility
operations and various non-utility enterprises, and it is expected that
its utility subsidiaries will serve more than 870,000 electric customers
and 360,000 natural gas customers in Iowa, Illinois, Minnesota and
Wisconsin.
The operating revenues, net income from continuing operations and
total assets of the companies were as follows:
PRO FORMA
IES COMBINED
INDUSTRIES WPLH IPC (Unaudited)
(in thousands)
1995 operating revenues $ 851,010 $ 807,255 $ 318,542 $ 1,976,807
1995 net income from
continuing operations 64,176 71,618 25,198 160,992
Assets at December 31, 1995 1,985,591 1,872,414 634,316 4,492,321
Under the terms of the Merger Agreement, the outstanding shares of
WPLH's common stock will remain unchanged and outstanding as shares of
Interstate Energy. Each outstanding share of the Industries' common
stock will be converted to .98 shares of Interstate Energy's common
stock. Each share of IPC's common stock will be converted to 1.11
shares of Interstate Energy's common stock. It is anticipated that
Interstate Energy will retain WPLH's common share dividend payment level
as of the effective time of the merger. On January 24, 1996, the Board
of Directors of WPLH declared a quarterly dividend of 49.25 cents per
share. This represents an equivalent annual rate of $1.97 per share.
Under provisions of the Merger Agreement, Industries' annual dividend
payment cannot exceed $2.10 per share, the current annual payment level,
pending the Proposed Merger.
Interstate Energy will be the parent company of Utilities,
Wisconsin Power and Light Company and IPC and will be registered under
the Public Utility Holding Company Act of 1935, as amended (1935 Act).
The Merger Agreement provides that these operating utility companies
will continue to operate as separate entities for a minimum of three
years beyond the effective date of the merger. In addition, the non-
utility operations of Industries and WPLH will be combined shortly after
the effective date of the merger under one entity to manage the
diversified operations of Interstate Energy.
The SEC historically has interpreted the 1935 Act to preclude
registered holding companies, with limited exceptions, from owning both
electric and gas utility systems. Although the SEC has recently
recommended that registered holding companies be allowed to hold both
gas and electric utility operations if the affected states agree, it
remains possible that the SEC may require as a condition to its approval
of the Proposed Merger that Industries, WPLH and IPC divest their gas
utility properties, and possibly certain non-utility ventures of
Industries and WPLH, within a reasonable time after the effective date
of the Proposed Merger.
Legislation to repeal the 1935 Act was introduced in Congress in
1995 and is pending. No assurance can be given as to when or if such
legislation will be considered or enacted. The Staff of the SEC has
also recommended that the SEC "permit combination systems by registered
holding companies if the affected states concur," and the SEC has
proposed rules that would relax current restrictions on investment by
registered holding companies in certain "energy related," non-utility
businesses. No prediction can be made as to the outcome of these
legislative and regulatory proposals.
See Note 2 of the Notes to Consolidated Financial Statements for a
further discussion of the Proposed Merger.
RESULTS OF OPERATIONS
The following discussion analyzes significant changes in the
components of net income available for common stock and financial
condition from the prior periods for the Company:
The Company's net income available for common stock decreased
($1.9) million and ($6.8) million during 1995 and 1994, respectively.
The 1995 results reflect the impact of the Iowa Utilities Board (IUB)
price reduction order in Utilities' recent electric rate case. The
effect of the lower electric prices, including the required refund,
reduced the 1995 net income by approximately $9.7 million. (See Note
3(b) of the Notes to Consolidated Financial Statements for a further
discussion of the electric rate case). Warmer than normal weather
conditions during the summer months and an aggressive cost containment
program partially offset the negative effects of the IUB order. The
1994 results were affected by milder than normal weather, particularly
during the summer months. The 1993 results reflect fairly normal
weather conditions in Utilities' service territory.
The Company's operating income increased or (decreased) $6.7
million and ($7.7) million during 1995 and 1994, respectively. Reasons
for the changes in the results of operations are explained in the
following discussion.
Electric Revenues Electric revenues and Kwh sales for Utilities
increased or (decreased) as compared with the prior year as follows:
1995 1994
($ in millions)
Total electric revenues $ 23.1 $ (13.2)
Change in off-system sales revenues (0.3) (11.3)
Electric revenues (excluding off-system sales) $ 23.4 $ (1.9)
Electric sales (excluding off-system sales):
Residential and Rural 7.9% (1.4%)
General Service 6.1 0.4
Large General Service 5.9 8.9
Total 5.3 4.3
Warmer than normal weather during the summer of 1995 significantly
increased sales. Utilities set new usage records several times,
culminated by a new energy peak demand record of 1,824 megawatts on July
12, 1995. The 1994 Kwh sales were adversely affected by milder than
normal weather, particularly during the summer months. The largest
effect of weather each year was on sales to residential and rural
customers. Under historically normal weather conditions, total sales
(excluding off-system sales) during 1995 and 1994 would have increased
3.6% and 4.8%, respectively. Sales during 1995 also benefited from the
effects of Utilities' annual true-up adjustment to unbilled sales. The
growth in general service and large general service sales continues to
reflect the underlying strength of the economy as industrial expansions
in Utilities' service territory continued during 1995.
Utilities' electric tariffs include energy adjustment clauses (EAC)
that are designed to currently recover the costs of fuel and the energy
portion of purchased power billings to customers. See Note 1(j) of the
Notes to Consolidated Financial Statements for discussion of the EAC.
The increase in the 1995 electric revenues was primarily due to the
increased sales (excluding off-system sales), higher fuel costs
collected through the EAC, the unbilled revenue adjustment and the
recovery of expenditures for energy efficiency programs pursuant to an
IUB order. The effect of the warmer than normal weather increased 1995
electric revenues by approximately $9 million. These items were
partially offset by a reduction in revenues of approximately $17 million
during 1995 as the result of the IUB price reduction order.
Approximately $3.5 million of the price reduction decrease related to
revenues collected in the fourth quarter of 1994. See Notes 3(b) and
3(c) of the Notes to Consolidated Financial Statements for a further
discussion of the electric rate case and the energy efficiency cost
recovery case, respectively.
The decrease in the 1994 electric revenues was attributable to
lower fuel costs collected through the EAC, lower off-system sales to
other utilities and the effect of the mix of sales between lower margin
industrial customers and higher margin residential and rural customers.
Increased total 1994 sales (excluding off-system sales) partially offset
the effects of the above items.
Gas Revenues Gas revenues decreased ($1.7) and ($15.3) million during
1995 and 1994, respectively. Utilities' gas sales and transported
volumes in therms increased or (decreased) as compared with the prior
period as follows:
1995 1994
Residential 3.4% (7.1%)
Commercial 2.5 (8.2)
Industrial (22.7) (13.2)
Sales to consumers (0.5) (8.3)
Transported volumes 22.1 22.2
Total 4.8 (2.7)
Under historically normal weather conditions, Utilities' gas sales
and transported volumes would have increased 3.5% and 0.7% in 1995 and
1994, respectively.
Utilities' gas tariffs include purchased gas adjustment clauses
(PGA) that are designed to currently recover the cost of gas sold. See
Note 1(j) of the Notes to Consolidated Financial Statements for
discussion of the PGA.
On August 4, 1995, Utilities applied to the IUB for an annual
increase in gas rates of $8.8 million, or 6.2%. An interim increase of
$7.1 million became effective October 11, 1995, subject to refund.
Utilities, the Office of Consumer Advocate and all three industrial
intervenor groups have entered into a settlement agreement, subject to
IUB approval, which allows Utilities a $6.3 million annual increase.
Utilities expects that the IUB will rule on the settlement agreement no
later than the second quarter of 1996.
Utilities' gas revenues decreased in 1995 primarily because of
lower gas costs recovered through the PGA, and was substantially offset
by the effects of the interim rate increase, recovery of expenditures
for the energy efficiency programs and increased revenues from
transported gas volumes. The 1994 revenue decrease was primarily due to
lower gas costs recovered through the PGA and, to a lesser extent, the
effect of the lower sales.
Other Revenues Other revenues increased $3.1 million and $0.1 million
during 1995 and 1994, respectively. The 1995 increase was primarily
related to new industrial-use steam customers.
Operating Expenses Fuel for production increased $10.3 million during
1995 due to higher fuel cost recoveries through the EAC, which are
included in fuel for production, and a higher average fuel cost. Total
1995 Kwh generation at Utilities' generating stations was flat compared
to 1994. The Duane Arnold Energy Center (DAEC), Utilities' nuclear
generating facility, generated less Kwhs in 1995 because it was down
from late February 1995 to late April 1995 for a scheduled refueling
outage. There was no refueling outage in 1994. Increased generation at
Utilities' fossil-fueled generating stations, due to the increased sales
and the DAEC outage, virtually offset the decreased DAEC generation.
Fuel for production decreased ($1.8) million in 1994 largely because of
lower average fuel prices and the effect of lower fuel cost recoveries
through the EAC. Generation at Utilities' generating stations increased
during 1994 primarily because of increased sales and the increased
availability of DAEC as there was a scheduled refueling outage in 1993
also.
Purchased power decreased ($1.9) million and ($24.7) million in
1995 and 1994, respectively. The 1995 decrease was primarily due to
lower capacity costs of ($6.6) million, partially offset by higher
energy purchases of $4.7 million due to the increased sales to customers
and flat generation, as discussed above. The 1994 decrease was caused
by lower off-system sales to other utilities, increased generation at
Utilities' generating stations and the expiration, in April 1993, of a
purchase power agreement with the City of Muscatine.
Gas purchased for resale decreased ($4.1) million and ($13.8)
million during 1995 and 1994, respectively. The decrease in 1995 was
primarily due to lower natural gas prices, partially offset by the
timing of the recovery of gas costs through the PGA. Gas purchased for
resale decreased in 1994 because of lower gas costs and lower gas sales.
Other operating expenses increased $13.0 million and $9.1 million
in 1995 and 1994, respectively. The 1995 increase was primarily related
to increased labor and benefit costs, costs associated with a project to
review and redesign Utilities' major business processes, the
amortization of previously deferred energy efficiency expenditures
(which are currently being recovered through rates) and costs relating
to the Proposed Merger. These increases were partially offset by
decreased nuclear operating costs and lower insurance costs. In
addition, following the receipt of the IUB price reduction order,
Utilities took action and successfully reduced 1995 operating and
maintenance costs by about $8 million from budgeted levels. The 1994
increase was also attributable to higher nuclear operating costs, former
manufactured gas plant (FMGP) clean-up costs and increased information
technology costs.
Maintenance expenses increased or (decreased) ($6.0) million and
$3.3 million during 1995 and 1994, respectively. The 1995 decrease was
due to less required maintenance activities at the DAEC and at
Utilities' fossil-fueled generating stations and the cost containment
actions discussed above. The 1994 increase was primarily because of
increased labor costs and maintenance at the DAEC, partially offset by
lower maintenance at Utilities' fossil-fueled generating stations.
Depreciation and amortization increased during both years because
of increases in utility plant in service. The 1995 increase was
partially offset by lower depreciation rates implemented at Utilities as
a result of the IUB electric price reduction order. Depreciation and
amortization expenses for all periods include a provision for
decommissioning the DAEC, which is collected through rates. The annual
recovery level was increased to $6.0 million in 1995 from $5.5 million,
as a result of Utilities' recent electric rate case.
During the first quarter of 1996, the Financial Accounting
Standards Board (FASB) issued an Exposure Draft on Accounting for
Liabilities Related to Closure and Removal of Long-Lived Assets which
deals with, among other issues, the accounting for decommissioning
costs. If current electric utility industry accounting practices for
such decommissioning are changed: (1) annual provisions for
decommissioning could increase relative to 1995 and, (2) the estimated
cost for decommissioning could be recorded as a liability, rather than
as accumulated depreciation, with recognition of an increase in the
recorded amount of the related DAEC plant. If such changes are
required, Utilities believes that there would not be an adverse effect
on its financial position or results of operations based on current rate
making practices. (See Note 1(g) of the Notes to Consolidated Financial
Statements for a discussion of the recovery of decommissioning costs
allowed in Utilities' most recent rate case).
Taxes other than income taxes increased $2.5 million and
$1.2 million during 1995 and 1994, respectively, largely because of
increased property taxes caused by increases in assessed property
values.
Interest Expense and Other Interest expense increased $2.9 million
during 1995 primarily because of an increase in the average amount of
short-term debt outstanding and interest related to Utilities' electric
rate refund. Lower average interest rates, attributable to refinancing
$100 million of long-term debt at lower rates and the mix of long-term
and short-term debt, partially offset the increase.
Miscellaneous, net reflected a decrease in income of ($2.1) million
during 1995 primarily because of an increase in fees related to the sale
of utility accounts receivable as the average amount of receivables sold
during the year increased.
Federal and state income taxes increased $3.1 million in 1995 and
were constant in 1994. The increase for 1995 was due to the effect of
property related temporary differences for which deferred taxes had not
been provided, pursuant to rate making principles, that are now becoming
payable. In addition, adjustments to tax reserves in 1995 and 1994
affected comparability of income taxes between the years. A decrease in
income before taxes in 1994 was offset by a higher effective income tax
rate.
LIQUIDITY AND CAPITAL RESOURCES
The Company's capital requirements are primarily attributable to
its construction programs and debt maturities. The Company's pretax
ratio of times interest earned was 3.26, 3.39 and 3.64 in 1995-1993,
respectively. In 1995, cash flows from operating activities were
$161 million versus $195 million in 1994. The decrease was primarily
due to expenditures related to the effect of the 1995 DAEC refueling
outage and other changes in working capital.
The Company anticipates that future capital requirements will be
met by cash generated from operations and external financing. The level
of cash generated from operations is partially dependent upon economic
conditions, legislative activities, environmental matters and timely
rate relief for Utilities. See Notes 3 and 11 of the Notes to
Consolidated Financial Statements.
Access to the long-term and short-term capital and credit markets
is necessary for obtaining funds externally. Utilities' debt ratings
are as follows:
Moody's Standard & Poor's
Long-term debt A2 A
Short-term debt P1 A1
The Company's liquidity and capital resources will be affected by
environmental and legislative issues, including the ultimate disposition
of remediation issues surrounding the Company's environmental
liabilities and the Clean Air Act as amended, as discussed in Note 11 of
the Notes to Consolidated Financial Statements, and the National Energy
Policy Act of 1992 as discussed in the Other Matters section. Consistent
with rate making principles of the IUB, management believes that the
costs incurred for the above matters will not have a material adverse
effect on the financial position or results of operations of the
Company. It is not certain if, and how, the Proposed Merger may affect
the Company's debt ratings.
The IUB has current rules which require Utilities to spend 2% of
electric and 1.5% of gas gross retail operating revenues annually for
energy efficiency programs. Energy efficiency costs in excess of the
amount in the most recent electric and gas rate cases are being recorded
as regulatory assets by Utilities. At December 31, 1995, Utilities had
approximately $50 million of such costs recorded as regulatory assets.
On June 1, 1995, Utilities began recovery of those costs incurred
through 1993. See Note 3(c) of the Notes to Consolidated Financial
Statements for a discussion of the timing of the filings for the
recovery of these costs under IUB rules.
Under provisions of the Merger Agreement, there are restrictions on
the amount of long-term debt the Company can issue pending the merger.
The Company does not expect the restrictions to have a material effect
on its ability to meet its future capital requirements.
CONSTRUCTION AND ACQUISITION PROGRAM
The Company's construction and acquisition program anticipates
expenditures of approximately $164 million for 1996, of which
approximately 55% represents expenditures for electric, gas and steam
transmission and distribution facilities, 19% represents fossil-fueled
generation expenditures, 13% represents information technology
expenditures and 5% represents nuclear generation expenditures. The
remaining 8% represents miscellaneous electric and general expenditures.
In addition to the $164 million, Utilities anticipates expenditures of
$13 million in connection with mandated energy efficiency programs.
The Company's levels of construction and acquisition expenditures
are projected to be $185 million in 1997, $176 million in 1998,
$161 million in 1999 and $137 million in 2000. It is estimated that
approximately 80% of these construction and acquisition expenditures
will be provided by cash from operating activities (after payment of
dividends) for the five-year period 1996-2000.
Capital expenditure and investment and financing plans are subject
to continual review and change. The capital expenditure and investment
programs may be revised significantly as a result of many considerations
including changes in economic conditions, variations in actual sales and
load growth compared to forecasts, requirements of environmental,
nuclear and other regulatory authorities, acquisition opportunities, the
availability of alternate energy and purchased power sources, the
ability to obtain adequate and timely rate relief, escalations in
construction costs and conservation and energy efficiency programs.
Under provisions of the Merger Agreement, there are restrictions on
the amount of construction and acquisition expenditures the Company can
make pending the merger. The Company does not expect the restrictions
to have a material effect on its ability to implement its anticipated
construction and acquisition program.
LONG-TERM FINANCING
Other than Utilities' periodic sinking fund requirements, which
Utilities intends to meet by pledging additional property, approximately
$140 million of long-term debt will mature prior to December 31, 2000.
The Company intends to refinance the majority of the debt maturities
with long-term securities.
In December 1995, Utilities issued $50 million of Subordinated
Deferrable Interest Debentures, 7-7/8%, due 2025. The proceeds from the
issuance of the debentures were used to retire short-term borrowings which
were incurred in October 1995 to repay at maturity, $50 million of Series
X, 9.42% First Mortgage Bonds.
In March 1995, Utilities repaid at maturity $50 million of Series
W, 9.75% First Mortgage Bonds and, in a separate transaction, issued $50
million of Collateral Trust Bonds, 7.65%, due 2000.
Utilities has entered into an Indenture of Mortgage and Deed of
Trust dated September 1, 1993 (New Mortgage). The New Mortgage provides
for, among other things, the issuance of Collateral Trust Bonds upon the
basis of First Mortgage Bonds being issued by Utilities. The lien of
the New Mortgage is subordinate to the lien of Utilities' first
mortgages until such time as all bonds issued under the first mortgages
have been retired and such mortgages satisfied. Accordingly, to the
extent that Utilities issues Collateral Trust Bonds on the basis of
First Mortgage Bonds, it must comply with the requirements for the
issuance of First Mortgage Bonds under Utilities' first mortgages.
Under the terms of the New Mortgage, Utilities has covenanted not to
issue any additional First Mortgage Bonds under its first mortgages
except to provide the basis for issuance of Collateral Trust Bonds.
The indentures pursuant to which Utilities issues First Mortgage
Bonds constitute direct first mortgage liens upon substantially all
tangible public utility property and contain covenants which restrict
the amount of additional bonds which may be issued. At
December 31, 1995, such restrictions would have allowed Utilities to
issue at least $258 million of additional First Mortgage Bonds.
In order to provide an instrument for the issuance of unsecured
subordinated debt securities, Utilities entered into an Indenture dated
December 1, 1995 (Subordinated Indenture). The Subordinated Indenture
provides for, among other things, the issuance of unsecured subordinated
debt securities. Any debt securities issued under the Subordinated
Indenture are subordinate to all senior indebtedness of Utilities,
including First Mortgage Bonds and Collateral Trust Bonds.
Utilities has received authority from the Federal Energy Regulation
Commission (FERC) and the SEC to issue up to $250 million of long-term
debt, and has $150 million of remaining authority under the current FERC
docket and $200 million of remaining authority under the current SEC
shelf registration. Utilities expects to replace one series of First
Mortgage Bonds that mature in 1996 with other long-term securities.
The Articles of Incorporation of Utilities authorize and limit the
aggregate amount of additional shares of Cumulative Preference Stock and
Cumulative Preferred Stock that may be issued. At December 31, 1995,
Utilities could have issued an additional 700,000 shares of Cumulative
Preference Stock and 100,000 additional shares of Cumulative Preferred
Stock.
The Company's capitalization ratios at year-end were as follows:
1995 1994
Long-term debt 47% 48%
Preferred stock 2 2
Common equity 51 50
100% 100%
The 1995 and 1994 ratios include $15 million and
$100 million, respectively, of long-term debt due in less
than one year because it was the Company's intention to
refinance the debt with long-term securities.
Under provisions of the Merger Agreement, there are restrictions on
the amount of long-term debt the Company can issue pending the merger.
The Company does not expect the restrictions to have a material effect
on its ability to meet its future capital requirements.
SHORT-TERM FINANCING
For interim financing, Utilities is authorized by the FERC to
issue, through 1996, up to $200 million of short-term notes. In
addition to providing for ongoing working capital needs, this
availability of short-term financing provides Utilities flexibility in
the issuance of long-term securities. At December 31, 1995, Utilities
had outstanding short-term borrowings of $109.9 million, including
$8.9 million of notes payable to associated companies.
Utilities has an agreement, which expires in 1999, with a financial
institution to sell, with limited recourse, an undivided fractional
interest of up to $65 million in its pool of utility accounts
receivable. At December 31, 1995, Utilities had sold $58 million under
the agreement.
At December 31, 1995, the Company had bank lines of credit
aggregating $121.1 million, of which $101 million was being used to
support commercial paper (weighted average interest rate of 5.81%) and
$11.1 million was being used to support certain pollution control
obligations. Commitment fees are paid to maintain these lines and there
are no conditions which restrict the unused lines of credit. In
addition to the above, Utilities has an uncommitted credit facility with
a financial institution whereby it can borrow up to $40 million. Rates
are set at the time of borrowing and no fees are paid to maintain this
facility. At December 31, 1995, there were no borrowings under this
facility.
ENVIRONMENTAL MATTERS
Utilities has been named as a Potentially Responsible Party (PRP)
by various federal and state environmental agencies for 28 FMGP sites,
but believes it is not responsible for two of these sites. There are
also six other sites for which it may be designated as a PRP in the
future. Utilities is working pursuant to the requirements of the
various agencies to investigate, mitigate, prevent and remediate, where
necessary, damage to property, including damage to natural resources, at
and around the sites in order to protect public health and the
environment. Utilities believes it has completed the remediation of
five sites although it is in the process of obtaining final approval
from the applicable environmental agencies on this issue for each site.
Utilities is in various stages of the investigation and/or remediation
processes for 19 sites and expects to begin the investigation process in
1996 for the other two sites. Utilities estimates the range of costs
to be incurred for investigation and/or remediation of the sites to be
approximately $22 million to $55 million.
Utilities has recorded environmental liabilities related to the
FMGP sites of approximately $35 million (including $4.6 million as
current liabilities) at December 31, 1995. These amounts are based upon
Utilities' best current estimate of the amount to be incurred for
investigation and remediation costs for those sites where the
investigation process has been or is substantially completed, and the
minimum of the estimated cost range for those sites where the
investigation is in its earlier stages or has not started. It is
possible that future cost estimates will be greater than the current
estimates as the investigation process proceeds and as additional facts
become known. Utilities may be required to monitor these sites for a
number of years upon completion of remediation, as is the case with
several of the sites for which remediation has been completed.
Utilities has begun pursuing claims under its prior coverage for
investigation, mitigation, prevention, remediation and monitoring costs
from its insurance carriers and is investigating the potential for third
party cost sharing for FMGP investigation and clean-up costs. The
amount of shared costs, if any, can not be reasonably determined and,
accordingly, no potential sharing has been recorded at
December 31, 1995. Regulatory assets of approximately $35 million,
which reflect the future recovery that is being provided through
Utilities' rates, have been recorded in the Consolidated Balance Sheets.
Considering the current rate treatment allowed by the IUB, management
believes that the clean-up costs incurred by Utilities for these FMGP
sites will not have a material adverse effect on its financial position
or results of operations.
The Clean Air Act Amendments Act of 1990 (Act) requires emission
reductions of sulfur dioxide and nitrogen oxides (NOx) to achieve
reductions of atmospheric chemicals believed to cause acid rain. The
provisions of the Act are being implemented in two phases with Phase I
affecting two of Utilities' units beginning in 1995 and Phase II
affecting all units beginning in the year 2000. Utilities has completed
the modifications necessary to meet the Phase I requirements and has
installed continuous emission monitors on all affected units as required
by the Act. Utilities expects to meet the requirements of Phase II by
switching to lower sulfur fuels, capital expenditures primarily related
to fuel burning equipment and boiler modifications and the possible
purchase of sulfur dioxide allowances. Utilities estimates capital
expenditures at approximately $20 million, including $4 million in 1996,
in order to meet the acid rain requirements of the Act.
The acid rain program under the Act also creates sulfur dioxide
allowances. An allowance is defined as an authorization for an owner to
emit one ton of sulfur dioxide into the atmosphere. Currently,
Utilities receives a sufficient number of allowances annually to offset
its emissions of sulfur dioxide from its Phase I units. It is
anticipated that in the year 2000, when the Phase II units participate
in the allowance program, Utilities may have an insufficient number of
allowances annually to offset its estimated emissions and may have to
purchase additional allowances, or make modifications to the plants or
limit operations to reduce emissions. Utilities is reviewing its
options to ensure that it will have sufficient allowances to offset its
emissions in the year 2000 and thereafter. Utilities believes that the
potential cost of ensuring sufficient allowances will not have a
material adverse effect on its financial position or results of
operations.
The Act also requires the United States Environmental Protection
Agency (EPA) to study and regulate, if necessary, additional issues that
potentially affect the electric utility industry, including emissions
relating to nitrogen oxides (NOx), ozone transport and mercury.
Currently, the impacts of these potential regulations are too
speculative to quantify.
In 1995, the EPA published the Sulfur Dioxide Network Design Review
for Cedar Rapids, Iowa, which, based on the EPA's assumptions and worst-
case modeling methods, suggests that the Cedar Rapids area could be
classified as "nonattainment" for the National Ambient Air Quality
Standard (NAAQS) established for sulfur dioxide. The worst-case
modeling study suggests that two of Utilities' generating facilities
contribute to the modeled exceedences and recommends that additional
monitors be located near Utilities' sources to assess actual ambient air
quality. In the event that Utilities' facilities contribute excessive
emissions, Utilities would be required to reduce emissions, which would
primarily entail capital expenditures for modifications to the
facilities. Utilities is currently reviewing EPA's assumptions and
modeling results and is proposing a strategy to voluntarily reduce the
excessive emissions through modification of its facilities at a
potential capital cost of up to $10 million over the next four years.
The National Energy Policy Act of 1992 requires owners of nuclear
power plants to pay a special assessment into a "Uranium Enrichment
Decontamination and Decommissioning Fund." The assessment is based upon
prior nuclear fuel purchases and, for the DAEC, averages $1.4 million
annually through 2007, of which Utilities' 70% share is $1.0 million.
Utilities is recovering the costs associated with this assessment
through its electric fuel adjustment clauses over the period the costs
are assessed. Utilities' 70% share of the future assessment,
$10.9 million payable through 2007, has been recorded as a liability in
the Consolidated Balance Sheets, including $0.8 million included in
"Current liabilities - Environmental liabilities," with a related
regulatory asset for the unrecovered amount.
The Nuclear Waste Policy Act of 1982 assigned responsibility to the
U.S. Department of Energy (DOE) to establish a facility for the ultimate
disposition of high level waste and spent nuclear fuel and authorized
the DOE to enter into contracts with parties for the disposal of such
material beginning in January 1998. Utilities entered into such a
contract and has made the agreed payments to DOE. The DOE, however, has
experienced significant delays in its efforts and material acceptance is
now expected to occur no earlier than 2010 with the possibility of
further delay being likely. Utilities has been storing spent nuclear
fuel on-site since plant operations began in 1974 and has current on-
site capability to store spent fuel until 2002. Utilities is
aggressively reviewing options for additional spent nuclear fuel storage
capability, including expanding on-site storage and supporting
legislation currently before the U.S. Congress, to resolve the lack of
progress by the DOE.
The Low-Level Radioactive Waste Policy Amendments Act of 1985
mandated that each state must take responsibility for the storage of low-
level radioactive waste produced within its borders. The State of Iowa
has joined the Midwest Interstate Low-Level Radioactive Waste Compact
Commission (Compact), which is planning a storage facility to be located
in Ohio to store waste generated by the Compact's six member states. At
December 31, 1995, Utilities has prepaid costs of approximately
$1.1 million to the Compact for the building of such a facility. A
Compact disposal facility is anticipated to be in operation in
approximately ten years after approval of new enabling legislation by
the member states. Such legislation is expected to be considered by the
member states in 1996. On-site storage capability currently exists for
low-level radioactive waste expected to be generated until the Compact
facility is able to accept waste materials. In addition, the Barnwell,
South Carolina disposal facility has reopened for an indefinite time
period and Utilities is in the process of shipping to Barnwell the
majority of the low-level radioactive waste it has accumulated on-site,
and intends to ship the waste it produces in the future as long as the
Barnwell site remains open, thereby minimizing the amount of waste
stored on-site.
The possibility that exposure to electric and magnetic fields (EMF)
emanating from power lines, household appliances and other electric
sources may result in adverse health effects has been the subject of
increased public, governmental, industry and media attention. A
considerable amount of scientific research has been conducted on this
topic without definitive results. Research is continuing in order to
resolve scientific uncertainties.
OTHER MATTERS
Competition As legislative, regulatory, economic and technological
changes occur, electric utilities are faced with increasing pressure to
become more competitive. Such competitive pressures could result in
loss of customers and an incurrence of stranded costs (i.e. the cost of
assets which could be rendered otherwise unrecoverable as the result of
competitive pricing). To the extent stranded costs cannot be recovered
from customers, they would be borne by security holders.
The National Energy Policy Act of 1992 addresses several matters
designed to promote competition in the electric wholesale power
generation market, including mandated open access to the electric
transmission system. In March 1995, the FERC issued a Notice of
Proposed Rulemaking pursuant to which FERC proposes to promote
competition in the electric utility industry by requiring that each
transmission owning utility must 1) implement non-discriminatory tariffs
allowing open access to that utility's transmission facilities by
wholesale buyers and sellers of electricity and 2) charge itself the
same price for transmission and ancillary services as it charges third
parties under the tariffs. Utilities filed conforming pro-forma open
access transmission tariffs with the FERC on July 24, 1995. The tariffs
were accepted by the FERC and became effective October 1, 1995. The
geographic position of Utilities' transmission system could provide
revenue opportunities in the open access environment. FERC's proposal
would allow for recovery of certain wholesale stranded costs in
connection with wholesale transmission. The Company cannot predict the
final regulations that may be adopted.
The IUB initiated a Notice of Inquiry (Docket No. NOI-95-1) in
early 1995 on the subject of "Emerging Competition in the Electric
Utility Industry." A one-day roundtable discussion was held to address
all forms of competition in the electric utility industry and to assist
the IUB in gathering information and perspectives on electric
competition from all persons or entities with an interest or stake in
the issues. Additional discussions were held in December 1995. The IUB
is expected to release a status report on the inquiry in the first
quarter of 1996.
Utilities is subject to the provisions of Statement of Financial
Accounting Standards No. 71, "Accounting for the Effects of Certain
Types of Regulation" (SFAS 71). If a portion of Utilities' operations
become no longer subject to the provisions of SFAS 71, a write-down of
related regulatory assets would be required, unless some form of
transition cost recovery is established by the appropriate regulatory
body. Utilities believes that it still meets the requirements of SFAS
71. Refer to Note 1(c) of the Notes to Consolidated Financial
Statements for a further discussion.
The Company cannot predict the long-term consequences of these
competitive issues on its results of operations or financial condition.
The Company's strategy for dealing with these emerging issues includes
seeking growth opportunities, continuing to offer quality customer
service, ongoing cost reductions and productivity enhancements. In
1995, the Company initiated a program called Process Redesign to examine
all of the major business processes of Utilities. The goals of Process
Redesign include improving customer service and commitment and
significantly reducing Utilities' cost structure. In 1995, Process
Redesign identified many of the changes that Utilities should pursue and
Utilities has begun implementing many of those actions. Implementation
will be substantially completed in 1996.
Accounting Pronouncements SFAS 121, issued in March 1995 by the
Financial Accounting Standards Board (FASB) and effective for 1996,
establishes accounting standards for the impairment of long-lived
assets. SFAS 121 also requires that regulatory assets that are no
longer probable of recovery through future revenues be charged to
earnings. SFAS 121 is not expected to have an impact on the financial
position or results of operations of the Company upon adoption.
Inflation Under the rate making principles prescribed by the regulatory
commissions to which Utilities is subject, only the historical cost of
plant is recoverable in revenues as depreciation. As a result,
Utilities has experienced economic losses equivalent to the current
year's impact of inflation on utility plant. In addition, the
regulatory process imposes a substantial time lag between the time when
operating and capital costs are incurred and when they are recovered.
Utilities does not expect the effects of inflation at current levels to
have a significant effect on its financial position or results of
operations.
Selected Consolidated Quarterly Financial Data (unaudited)
The following unaudited consolidated quarterly data, in the opinion
of the Company, includes adjustments, which are normal and recurring in
nature, necessary for the fair presentation of the results of operations
and financial position. The quarterly amounts were affected by the
Company's rate activities and seasonal weather conditions. The first
quarter net income in 1995 was significantly lower than 1994 as the
Company recorded an $8.0 million pre-tax reserve for electric rate
refund in the first quarter of 1995. Approximately $3.5 million of the
reserve related to revenues collected in the fourth quarter of 1994.
Milder weather in 1995 also contributed to the decrease. The Company's
rate activities are discussed in Note 3 of the Notes to Consolidated
Financial Statements. Refer to Management's Discussion and Analysis for
a discussion of the impacts of weather.
Quarter Ended
March June September December
31 30 30 31
(in thousands)
1995
Operating revenues $ 172,839 $ 157,671 $ 200,448 $ 178,868
Operating income 19,896 30,444 61,360 30,565
Net income 6,161 11,067 29,842 12,208
Net income available
for common stock 5,932 10,838 29,613 11,981
1994
Operating revenues $ 192,013 $ 148,019 $ 179,477 $ 165,857
Operating income 34,248 24,777 51,777 24,789
Net income 14,944 9,255 25,733 11,278
Net income available
for common stock 14,715 9,026 25,504 11,051
Item 8. Financial Statements and Supplementary Data
Information required by Item 8. begins on page 62.
REPORT OF MANAGEMENT
The Company's management has prepared and is responsible
for the presentation, integrity and objectivity of the
consolidated financial statements and related information
included in this report. The consolidated financial
statements have been prepared in conformity with generally
accepted accounting principles applied on a consistent basis
and, in some cases, include estimates that are based upon
management's judgment and the best available information,
giving due consideration to materiality. Financial information
contained elsewhere in this report is consistent with that in
the consolidated financial statements.
The Company maintains a system of internal accounting
controls which it believes is adequate to provide reasonable
assurance that assets are safeguarded, transactions are
executed in accordance with management authorization and the
financial records are reliable for preparing the consolidated
financial statements. The system of internal accounting
controls is supported by written policies and procedures, by a
staff of internal auditors and by the selection and training
of qualified personnel. The internal audit staff conducts
comprehensive audits of the Company's system of internal
accounting controls. Management strives to maintain an
adequate system of internal controls, recognizing that the
cost of such a system should not exceed the benefits derived.
In accordance with generally accepted auditing standards, the
independent public accountants (Arthur Andersen LLP) obtained
a sufficient understanding of the Company's internal controls
to plan their audit and determine the nature, timing and
extent of other tests to be performed. Management is not
aware of any material internal control weaknesses.
The Board of Directors, through its Audit Committee
comprised entirely of outside directors, meets periodically
with management, the internal auditor and Arthur Andersen LLP
to discuss financial reporting matters, internal control and
auditing. To ensure their independence, both the internal
auditor and Arthur Andersen LLP have full and free access to
the Audit Committee.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors of
IES Utilities Inc.:
We have audited the accompanying consolidated balance sheets and
statements of capitalization of IES Utilities Inc. (an Iowa corporation)
and subsidiary companies as of December 31, 1995 and 1994, and the
related consolidated statements of income, retained earnings and cash
flows for each of the three years in the period ended December 31, 1995.
These financial statements and the financial statement schedule referred
to below are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements
and schedule based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the
financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe
that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present
fairly, in all material respects, the financial position of IES
Utilities Inc. and subsidiary companies as of December 31, 1995 and
1994, and the results of their operations and their cash flows for each
of the three years in the period ended December 31, 1995, in conformity
with generally accepted accounting principles.
Our audits were made for the purpose of forming an opinion on the basic
financial statements taken as a whole. The financial statement schedule
listed in Item 14(a)2 is presented for purposes of complying with the
Securities and Exchange Commission's rules and is not part of the basic
financial statements. This schedule has been subjected to the auditing
procedures applied in the audits of the basic financial statements and,
in our opinion, fairly states in all material respects the financial
data required to be set forth therein in relation to the basic financial
statements taken as a whole.
As discussed in Note 7 to the consolidated financial statements,
effective January 1, 1993, IES Utilities Inc. and subsidiary companies
changed their method of accounting for postretirement benefits other
than pensions.
/s/ ARTHUR ANDERSEN LLP
ARTHUR ANDERSEN LLP
Chicago, Illinois,
February 2, 1996
CONSOLIDATED STATEMENTS OF INCOME
Year Ended December 31
1995 1994 1993
(in thousands)
Operating revenues:
Electric $ 560,471 $ 537,327 $ 550,521
Gas 137,292 139,033 154,318
Other 12,063 9,006 8,911
709,826 685,366 713,750
Operating expenses:
Fuel for production 96,256 85,952 87,702
Purchased power 66,874 68,794 93,449
Gas purchased for resale 91,198 95,340 109,122
Other operating expenses 145,250 132,281 123,210
Maintenance 43,586 49,542 46,219
Depreciation and amortization 79,384 75,316 69,407
Taxes other than income taxes 45,013 42,550 41,312
567,561 549,775 570,421
Operating income 142,265 135,591 143,329
Interest expense and other:
Interest expense 44,460 41,572 40,169
Allowance for funds used
during construction -3,424 -3,910 -1,972
Miscellaneous, net 856 -1,247 -801
41,892 36,415 37,396
Income before income taxes 100,373 99,176 105,933
Federal and state income taxes 41,095 37,966 37,963
Net income 59,278 61,210 67,970
Preferred dividend requirements 914 914 914
Net income available for common
stock $ 58,364 $ 60,296 $ 67,056
The accompanying Notes to Consolidated Financial Statements
are an integral part of these statements.
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
Year Ended December 31
1995 1994 1993
(in thousands)
Balance at beginning of year $ 197,158 $ 188,862 $ 153,106
Add:
Net income 59,278 61,210 67,970
Deduct:
Cash dividends declared -
Common stock 43,000 52,000 31,300
Preferred stock, at
stated rates 914 914 914
Balance at end of year $ 212,522 $ 197,158 $ 188,862
The accompanying Notes to Consolidated Financial Statements
are an integral part of these statements.
CONSOLIDATED BALANCE SHEETS
December 31
ASSETS 1995 1994
(in thousands)
Property, plant and equipment:
Utility -
Plant in service -
Electric $ 1,900,157 $ 1,798,059
Gas 165,825 158,115
Other 106,396 86,005
2,172,378 2,042,179
Less - Accumulated depreciation 950,324 880,888
1,222,054 1,161,291
Leased nuclear fuel, net of amortization 36,935 49,731
Construction work in progress 52,772 73,339
1,311,761 1,284,361
Other, net of accumulated depreciation and
amortization of $1,166,000 and $1,277,000,
respectively 5,477 2,686
1,317,238 1,287,047
Current assets:
Cash and temporary cash investments 2,734 2,135
Accounts receivable -
Customer, less reserve 18,619 12,051
Other 8,912 9,763
Income tax refunds receivable 846 3,450
Production fuel, at average cost 12,155 13,988
Materials and supplies, at average cost 27,229 26,699
Adjustment clause balances 0 1,433
Regulatory assets 22,791 20,145
Prepayments and other 18,556 19,630
111,842 109,294
Investments:
Nuclear decommissioning trust funds 47,028 33,779
Cash surrender value of life insurance policies 3,582 2,915
Other 475 223
51,085 36,917
Other assets:
Regulatory assets 207,202 192,955
Deferred charges and other 21,268 19,155
228,470 212,110
$ 1,708,635 $ 1,645,368
December 31
CAPITALIZATION AND LIABILITIES 1995 1994
(in thousands)
Capitalization (See Consolidated Statements of Capitalization):
Common stock $ 33,427 $ 33,427
Paid-in surplus 279,042 279,042
Retained earnings 212,522 197,158
Total common equity 524,991 509,627
Cumulative preferred stock 18,320 18,320
Long-term debt (excluding current portion) 465,463 380,404
1,008,774 908,351
Current liabilities:
Notes payble to associated companies 8,888 18,495
Short-term borrowings 101,000 37,000
Capital lease obligations 15,717 14,385
Maturities and sinking funds 15,140 100,140
Accounts payable 64,564 70,354
Accrued interest 8,038 9,438
Accrued taxes 50,369 47,188
Accumulated refueling outage provision 7,690 15,196
Adjustment clause balances 3,148 0
Environmental liabilities 5,521 5,428
Other 17,300 18,324
297,375 335,948
Long-term liabilities:
Pension and other benefit obiligations 41,866 36,826
Capital lease obligations 21,218 35,346
Environmental liabilities 40,905 37,853
Other 8,719 9,898
112,708 119,923
Deferred credits:
Accumulated deferred income taxes 252,663 241,345
Accumulated deferred investment tax credits 37,115 39,801
289,778 281,146
Commitments and contingencies (Note 11)
$ 1,708,635 $ 1,645,368
The accompanying Notes to Consolidated Financial Statements
are an integral part of these statements.
CONSOLIDATED STATEMENTS OF CAPITALIZATION
December 31
1995 1994
(in thousands)
Common equity:
Common stock - par value $2.50 per
share - authorized 24,000,000 shares;
outstanding 13,370,788 shares $ 33,427 $ 33,427
Paid-in surplus 279,042 279,042
Retained earnings 212,522 197,158
524,991 509,627
Cumulative preferred stock 18,320 18,320
Long-term debt:
Collateral Trust Bonds -
7.65% series, due 2000 50,000 0
6% series, due 2008 50,000 50,000
7% series, due 2023 50,000 50,000
5.5% series, due 2023 19,400 19,400
169,400 119,400
First Mortgage Bonds-
Series J, 6-1/4%, due 1996 15,000 15,000
Series L, 7-7/8%, due 2000 15,000 15,000
Series M, 7-5/8%, due 2002 30,000 30,000
Series W, 9-3/4%, retired in 1995 0 50,000
Series X, 9.42%, retired in 1995 0 50,000
Series Y, 8-5/8%, due 2001 60,000 60,000
Series Z, 7.60%, due 1999 50,000 50,000
6-1/8% series, due 1997 8,000 8,000
9-1/8% series, due 2001 21,000 21,000
7-3/8% series, due 2003 10,000 10,000
7-1/4% series, due 2007 30,000 30,000
239,000 339,000
Pollution control obligations-
5.75%, due serially 1996 to 2003 3,556 3,696
5.95%, due 2007, secured by First
Mortgage Bonds 10,000 10,000
Variable rate (5.10%-5.95% at
December 31, 1995), due 2000 to 2010 11,100 11,100
24,656 24,796
Subordinated Deferrable Interest
Debentures, 7-7/8%, due 2025 50,000 0
Unamortized debt premium and (discount), net -2,453 -2,652
480,603 480,544
Less-Amount due within one year 15,140 100,140
465,463 380,404
$ 1,008,774 $ 908,351
The accompanying Notes to Consolidated Financial Statements
are an integral part of these statements.
<TABLE>
CONSOLIDATED STATEMENTS OF CASH FLOWS
<CAPTION>
Year Ended December 31
1995 1994 1993
(in thousands)
<S> <C> <C> <C>
Cash flows from operating activities:
Net income $ 59,278 $ 61,210 $ 67,970
Adjustments to reconcile net income to net cash
flows from operating activities -
Depreciation and amortization 79,384 75,316 69,407
Amortization of principal under capital lease obligations 15,714 16,246 11,429
Deferred taxes and investment tax credits 7,628 -410 10,531
Refueling outage provision -7,506 12,536 -4,889
Amortization of other assets 7,391 2,228 2,083
Other 184 -1,232 -1,294
Other changes in assets and liabilities -
Accounts receivable -9,717 10,395 -8,553
Production fuel, materials and supplies 1,658 404 5,909
Accounts payable -4,395 20,444 5,620
Accrued taxes 5,785 7,057 -10,991
Provision for rate refunds 106 -8,670 -350
Adjustment clause balances 4,581 -6,582 6,366
Gas in storage 2,429 1,919 -2,309
Other -1,085 4,171 1,942
Net cash flows from operating activities 161,435 195,032 152,871
Cash flows from financing activities:
Dividends declared on common stock -43,000 -52,000 -31,300
Dividends declared on preferred stock -914 -914 -914
Equity infusion from parent company 0 0 50,000
Proceeds from issuance of long-term debt 100,000 0 119,400
Reductions in long-term debt -100,140 -224 -79,624
Net change in short-term borrowings 54,393 31,495 -68,560
Principal payments under capital lease obligations -14,463 -16,304 -11,276
Sale of utility accounts receivable 4,000 800 10,490
Other -1,831 -5,144 3,251
Net cash flows from financing activities -1,955 -42,291 -8,533
Cash flows from investing activities:
Construction and acquisition expenditures -
Utility -126,104 -146,240 -113,212
Other -3,340 -1,863 0
Deferred energy efficiency expenditures -18,029 -16,157 -9,747
Nuclear decommissioning trust funds -6,100 -5,532 -5,532
Other -5,308 873 723
Net cash flows from investing activities -158,881 -168,919 -127,768
Net increase (decrease) in cash and temporary cash investments 599 -16,178 16,570
Cash and temporary cash investments at beginning of year 2,135 18,313 1,743
Cash and temporary cash investments at end of year $ 2,734 $ 2,135 $ 18,313
Supplemental cash flow information:
Cash paid during the year for -
Interest $ 44,569 $ 40,005 $ 37,484
Income taxes $ 29,083 $ 34,479 $ 40,130
Noncash investing and financing activities -
Capital lease obligations incurred $ 2,918 $ 14,297 $ 14,605
The accompanying Notes to Consolidated Financial Statements
are an integral part of these statements.
</TABLE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
(a) Basis of Consolidation -
IES Utilities Inc. (Utilities) is a wholly-owned subsidiary of IES
Industries Inc. (Industries). The Consolidated Financial Statements
include the accounts of Utilities and its consolidated subsidiaries
(collectively the Company). Utilities is engaged principally in the
generation, transmission, distribution and sale of electric energy, the
purchase, distribution, transportation and sale of natural gas and to
provide steam for industrial and heating purposes. The Company's
markets are located in the state of Iowa.
All subsidiaries for which Utilities owns directly or indirectly
more than 50% of the voting stock are included as consolidated
subsidiaries. Utilities' only wholly-owned subsidiary at December 31,
1995 was IES Ventures Inc. (Ventures). Ventures' wholly-owned
subsidiary at December 31, 1995 was IES Midland Development Inc. All
significant intercompany balances and transactions have been eliminated
from the Consolidated Financial Statements.
Investments for which the Company has at least a 20% interest are
generally accounted for under the equity method of accounting. These
investments are stated at acquisition cost, increased or decreased for
the Company's equity in undistributed net income or loss, which is
included in "Miscellaneous, net" in the Consolidated Statements of
Income. Investments that do not meet the criteria for the consolidating
or equity methods of accounting are accounted for under the cost method.
The preparation of financial statements in conformity with
generally accepted accounting principles requires management to make
estimates and assumptions that affect: 1) the reported amounts of assets
and liabilities and the disclosure of contingent assets and liabilities
at the date of the financial statements, and 2) the reported amounts of
revenues and expenses during the reporting period. Actual results could
differ from those estimates.
Certain prior period amounts have been reclassified on a basis
consistent with the 1995 presentation.
(b) Regulation -
Utilities is subject to regulation by the Iowa Utilities Board
(IUB) and the Federal Energy Regulatory Commission (FERC). Utilities'
consolidated subsidiaries are not subject to regulation by the IUB or
the FERC.
Refer to Note 2 for a discussion of the proposed merger of
Industries.
(c) Regulatory Assets -
Utilities is subject to the provisions of Statement of Financial
Accounting Standards No. 71, "Accounting for the Effects of Certain
Types of Regulation" (SFAS 71). The regulatory assets represent
probable future revenue to Utilities associated with certain incurred
costs as these costs are recovered through the rate making process. At
December 31, regulatory assets as reflected in the Consolidated Balance
Sheets were comprised of the following items:
1995 1994
(in millions)
Deferred income taxes (Note 1(d)) $ 91.1 $ 90.1
Energy efficiency program costs (Note 3(c)) -
. Currently being recovered through rates 18.3 20.3
. Recovery has not yet been requested 31.4 14.4
Environmental liabilities (Note 11(f)) 46.9 43.8
Employee pension and benefit costs (Note 7) 27.5 25.0
Unamortized loss on reacquired debt 5.7 6.1
FERC Order No. 636 transition costs (Note 11(h)) 5.0 8.0
Other 4.1 5.4
230.0 213.1
Classified as "Current assets - regulatory assets" 22.8 20.1
Classified as "Other assets - regulatory assets" $ 207.2 $ 193.0
Refer to the individual footnotes referenced above for a further
discussion of certain items reflected in regulatory assets.
If a portion of Utilities' operations become no longer subject to
the provisions of SFAS 71, a write-off of related regulatory assets
would be required, unless some form of transition cost recovery is
established by the appropriate regulatory body.
SFAS 121, issued in March 1995 by the Financial Accounting
Standards Board (FASB) and effective for 1996, establishes accounting
standards for the impairment of long-lived assets. SFAS 121 also
requires that regulatory assets that are no longer probable of recovery
through future revenues be charged to earnings. SFAS 121 is not
expected to have an impact on the financial position or results of
operations of the Company upon adoption.
(d) Income Taxes -
The Company follows the liability method of accounting for deferred
income taxes, which requires the establishment of deferred tax
liabilities and assets, as appropriate, for all temporary differences
between the tax basis of assets and liabilities and the amounts reported
in the financial statements. Deferred taxes are recorded using
currently enacted tax rates.
Except as noted below, income tax expense includes provisions for
deferred taxes to reflect the tax effects of temporary differences
between the time when certain costs are recorded in the accounts and
when they are deducted for tax return purposes. As temporary
differences reverse, the related accumulated deferred income taxes are
reversed to income. Investment tax credits for Utilities have been
deferred and are subsequently credited to income over the average lives
of the related property.
Consistent with rate making practices for Utilities, deferred tax
expense is not recorded for certain temporary differences (primarily
related to utility property, plant and equipment). As the deferred
taxes become payable, over periods exceeding 30 years for some
generating plant differences, they are recovered through rates.
Accordingly, Utilities has recorded deferred tax liabilities and
regulatory assets, as identified in Note 1(c).
(e) Temporary Cash Investments -
Temporary cash investments are stated at cost, which approximates
market value, and are considered cash equivalents for the Consolidated
Statements of Cash Flows. These investments consist of short-term
liquid investments that have maturities of less than 90 days from the
date of acquisition.
(f) Depreciation of Utility Property, Plant and Equipment -
The depreciation life of Utilities' nuclear generating station, the
Duane Arnold Energy Center (DAEC), was increased from 36 years to 40
years based on an extension of the Nuclear Regulatory Commission (NRC)
license life to 2014, using the remaining life method, as part of
Utilities' most recent rate case as discussed in note 3(b). The average
rates of depreciation for electric and gas properties of Utilities,
consistent with current rate making practices, were as follows:
1995 1994 1993
Electric 3.4% 3.6% 3.5%
Gas 3.5% 3.8% 3.5%
The electric and gas depreciation rates declined in 1995 from 1994
because of revised depreciation rates approved in Utilities' most recent
electric and gas rate proceedings.
(g) Decommissioning of the DAEC -
Pursuant to the recent electric rate case order, the IUB allowed
Utilities to increase the recovery of anticipated costs to decommission
the DAEC from $5.5 million to $6.0 million annually. Decommissioning
expense is included in "Depreciation and amortization" in the
Consolidated Statements of Income and the cumulative amount is included
in "Accumulated depreciation" in the Consolidated Balance Sheets to the
extent recovered through rates. The current recovery figures are based
on the following assumptions: 1) cost to decommission the DAEC of $252.8
million in 1993 dollars, based on the NRC minimum formula (which exceeds
the amount in the current site-specific study completed in 1994); 2)
inflation of 4.91% annually through 1997; 3) the prompt dismantling and
removal method of decommissioning, which is assumed to begin in the year
2014; 4) monthly funding of all future collections into external trust
funds and funded on a tax-qualified basis to the extent possible; and 5)
an average after-tax return of 6.82% for all external investments. All
of these assumptions are subject to change in future regulatory
proceedings. At December 31, 1995, Utilities had $47.0 million invested
in external decommissioning trust funds as indicated in the Consolidated
Balance Sheets, and also had an internal decommissioning reserve of
$21.7 million recorded as accumulated depreciation. Earnings on the
external trust funds, which were $1.0 million in 1995, are recorded as
interest income and a corresponding interest expense payable to the
funds is recorded. The earnings accumulate in the external trust fund
balances and in accumulated depreciation on utility plant.
See "Management's Discussion and Analysis of the Results of
Operations and Financial Condition" for a discussion of the Exposure
Draft on Accounting for Liabilities Related to Closure and Removal of
Long-Lived Assets, issued by the FASB in the first quarter of 1996,
which deals with, among other issues, the accounting for decommissioning
costs.
(h) Property, Plant and Equipment -
Utility plant (excluding acquisition adjustments of $30.6 million,
net of accumulated amortization, recorded at cost) is recorded at
original cost. The allowance for funds used during construction (AFC),
which represents the cost during the construction period of funds used
for construction purposes, is capitalized by Utilities as a component of
the cost of utility plant. The amount of AFC applicable to debt funds
and to other (equity) funds, a non-cash item, is computed in accordance
with the prescribed FERC formula. The aggregate gross rates used by
Utilities for 1995-1993 were 6.5%, 9.3% and 5.7%, respectively. These
capitalized costs are recovered by Utilities in rates as the cost of the
utility plant is depreciated.
Other property, plant and equipment is recorded at cost. Upon
retirement or sale of other property and equipment, the cost and related
accumulated depreciation are removed from the accounts and any gain or
loss is included in "Miscellaneous, net" in the Consolidated Statements
of Income.
Normal repairs, maintenance and minor items of utility plant and
other property, plant and equipment are expensed. Ordinary retirements
of utility plant, including removal costs less salvage value, are
charged to accumulated depreciation upon removal from utility plant
accounts, and no gain or loss is recognized.
(i) Operating Revenues -
The Company accrues revenues for services rendered but unbilled at
month-end in order to more properly match revenues with expenses.
(j) Adjustment Clauses -
Utilities' tariffs provide for subsequent adjustments to its
electric and natural gas rates for changes in the cost of fuel and
purchased energy and in the cost of natural gas purchased for resale.
Changes in the under/over collection of these costs are reflected in
"Fuel for production" and "Gas purchased for resale" in the Consolidated
Statements of Income. The cumulative effects are reflected in the
Consolidated Balance Sheets as a current asset or current liability,
pending automatic reflection in future billings to customers.
(k) Accumulated Refueling Outage Provision -
The IUB allows Utilities to collect, as part of its base revenues,
funds to offset other operating and maintenance expenditures incurred
during refueling outages at the DAEC. As these revenues are collected,
an equivalent amount is charged to other operating and maintenance
expenses with a corresponding credit to a reserve. During a refueling
outage, the reserve is reversed to offset the refueling outage
expenditures.
(2) PROPOSED MERGER OF INDUSTRIES:
Industries, WPL Holdings, Inc. (WPLH) and Interstate Power Company
(IPC) have entered into an Agreement and Plan of Merger (Merger
Agreement), dated November 10, 1995, providing for: a) IPC becoming a
wholly-owned subsidiary of WPLH, and b) the merger of Industries with
and into WPLH, which merger will result in the combination of Industries
and WPLH as a single holding company (collectively, the Proposed
Merger). The new holding company will be named Interstate Energy
Corporation (Interstate Energy) and Industries will cease to exist. The
Proposed Merger, which will be accounted for as a pooling of interests,
has been approved by the respective Boards of Directors. It is still
subject to approval by the shareholders of each company as well as
several federal and state regulatory agencies. The companies expect to
receive the shareholder approvals in the second quarter of 1996 and the
regulatory approvals by the second quarter of 1997.
The operating revenues, net income from continuing operations and
total assets of the companies were as follows:
PRO FORMA
IES COMBINED
INDUSTRIES WPLH IPC (Unaudited)
(in thousands)
1995 operating revenues $ 851,010 $ 807,255 $ 318,542 $ 1,976,807
1995 net income from
continuing operations 64,176 71,618 25,198 160,992
Assets at December 31, 1995 1,985,591 1,872,414 634,316 4,492,321
Under the terms of the Merger Agreement, the outstanding shares of
WPLH's common stock will remain unchanged and outstanding as shares of
Interstate Energy. Each outstanding share of Industries' common stock
will be converted to .98 shares of Interstate Energy's common stock.
Each share of IPC's common stock will be converted to 1.11 shares of
Interstate Energy's common stock. It is anticipated that Interstate
Energy will retain WPLH's common share dividend payment level as of the
effective time of the merger. On January 24, 1996, the Board of
Directors of WPLH declared a quarterly dividend of 49.25 cents per
share. This represents an equivalent annual rate of $1.97 per share.
WPLH is a holding company headquartered in Madison, Wisconsin, and
is the parent company of Wisconsin Power and Light Company (WP&L) and
Heartland Development Corporation (HDC). WP&L supplies electric and gas
service to approximately 377,000 and 146,000 customers, respectively, in
south and central Wisconsin. HDC and its principal subsidiaries are
engaged in businesses in three major areas: environmental engineering
and consulting, affordable housing and energy services. IPC, an
operating public utility headquartered in Dubuque, Iowa, supplies
electric and gas service to approximately 163,000 and 49,000 customers,
respectively, in northeast Iowa, northwest Illinois and southern
Minnesota.
Interstate Energy will be the parent company of Utilities, WP&L and
IPC and will be registered under the Public Utility Holding Company Act
of 1935, as amended (1935 Act). The Merger Agreement provides that
these operating utility companies will continue to operate as separate
entities for a minimum of three years beyond the effective date of the
merger. In addition, the non-utility operations of Industries and WPLH
will be combined shortly after the effective date of the merger under
one entity to manage the diversified operations of Interstate Energy.
The corporate headquarters of Interstate Energy will be in Madison.
The SEC historically has interpreted the 1935 Act to preclude
registered holding companies, with limited exceptions, from owning both
electric and gas utility systems. Although the SEC has recently
recommended that registered holding companies be allowed to hold both
gas and electric utility operations if the affected states agree, it
remains possible that the SEC may require as a condition to its approval
of the Proposed Merger that Industries, WPLH and IPC divest their gas
utility properties, and possibly certain non-utility ventures of
Industries and WPLH, within a reasonable time after the effective date
of the Proposed Merger.
(3) RATE MATTERS:
(a) 1995 Gas Rate Case -
On August 4, 1995, Utilities applied to the IUB for an annual
increase in gas rates of $8.8 million, or 6.2%. An interim increase of
$8.6 million was requested and the IUB, subsequently, approved an
interim increase of $7.1 million annually, effective October 11, 1995,
subject to refund. Utilities, the Office of Consumer Advocate and all
three industrial intervenor groups have entered into a settlement
agreement, subject to IUB approval, which allows Utilities a $6.3
million annual increase. Utilities expects that the IUB will rule on
the settlement agreement no later than the second quarter of 1996.
(b) 1994 Electric Rate Case -
In 1994, Utilities applied to the IUB for an increase in retail
electric rates of approximately $26 million annually, or 5.2%. The IUB
issued its final order on June 30, 1995, which resulted in an annual
retail rate reduction of approximately $14.4 million. The Board ruled
against Utilities on issues of increased recovery levels of nuclear
depreciation expense and nuclear decommissioning expense, and recovery
of the full purchase price of Union Electric Company's (UE) Iowa service
territory.
On August 16, 1995, Utilities received approval from the IUB to
implement final prices. Northern and Southeastern zone price changes
became effective on that date. A price design change was implemented in
the Southern zone effective January 1, 1996. As a result of the IUB
order, Utilities refunded approximately $12.8 million, including
interest, in the fourth quarter of 1995.
(c) Energy Efficiency Cost Recovery -
The IUB has current rules that mandate Utilities to spend 2% of
electric and 1.5% of gas gross retail operating revenues for energy
efficiency programs. Under provisions of the IUB rules, Utilities
applied in 1994 to the IUB for recovery of costs incurred through 1993
for such programs. In April 1995, the IUB issued its Final Decision and
Order concerning Utilities' energy efficiency expenditures, which allows
Utilities to recover its direct expenditures, carrying costs, and a
return on its expenditures, as well as a reward of approximately
$4 million for a total allowed recovery of approximately $32 million.
Recovery of energy efficiency costs will be over a four-year period and
began on June 1, 1995. In 1996, under provisions of the IUB rules, the
Company will file for recovery of the costs incurred after December 31,
1993 ($31.4 million as of December 31, 1995).
(4) LEASES:
Utilities has a capital lease covering its 70% undivided interest
in nuclear fuel purchased for the DAEC. Future purchases of fuel may
also be added to the fuel lease. This lease provides for annual
one-year extensions and Utilities intends to exercise such extensions
through the DAEC's operating life. Interest costs under the lease are
based on commercial paper costs incurred by the lessor. Utilities is
responsible for the payment of taxes, maintenance, operating cost, risk
of loss and insurance relating to the leased fuel.
The lessor has a $65 million credit agreement with a bank
supporting the nuclear fuel lease. The agreement continues on a year-to-
year basis, unless either party provides at least a three-year notice of
termination; no such notice of termination has been provided by either
party.
Annual nuclear fuel lease expenses include the cost of fuel, based
on the quantity of heat produced for the generation of electric energy,
plus the lessor's interest costs related to fuel in the reactor and
administrative expenses. These expenses (included in "Fuel for
production" in the Consolidated Statements of Income) for 1995-1993 were
$18.0 million, $17.8 million and $12.4 million, respectively.
The Company's operating lease rental expenses for 1995-1993 were
$9.0 million, $9.8 million and $8.4 million, respectively.
The Company's future minimum lease payments by year are as follows:
Capital Operating
Year Lease Leases
(in thousands)
1996 $ 15,515 $ 6,824
1997 13,787 6,056
1998 6,389 5,788
1999 3,865 4,133
2000 824 1,562
2001 149 -
40,529 $ 24,363
Less: Amount representing
interest 3,594
Present value of net
minimum capital lease payments $ 36,935
(5) UTILITY ACCOUNTS RECEIVABLE:
Customer accounts receivable, including unbilled revenues, arise
primarily from the sale of electricity and natural gas. At December 31,
1995, Utilities was serving a diversified base of residential,
commercial and industrial customers consisting of approximately 333,000
electric and 174,000 gas customers.
Utilities has entered into an agreement, which expires in 1999,
with a financial institution to sell, with limited recourse, an
undivided fractional interest of up to $65 million in its pool of
utility accounts receivable. At December 31, 1995, $58 million was sold
under the agreement.
(6) INCOME TAXES:
The components of federal and state income taxes for the years
ended December 31, were as follows:
1995 1994 1993
(in millions)
Current tax expense $ 33.5 $ 38.4 $ 27.5
Deferred tax expense 10.3 2.2 15.4
Amortization and adjustment
of investment tax credits (2.7) (2.6) (4.9)
$ 41.1 $ 38.0 $ 38.0
The overall effective income tax rates shown below for the years
ended December 31, were computed by dividing total income tax expense by
income before income taxes.
1995 1994 1993
Statutory federal income tax rate 35.0% 35.0% 35.0%
Add (deduct):
State income taxes, net of federal
benefits 5.9 6.1 5.8
Effect of rate making on property
related differences 2.8 1.7 (0.2)
Amortization of investment
tax credits (2.7) (2.7) (2.5)
Adjustment of prior period taxes (0.1) (1.9) (2.0)
Other items, net - 0.1 (0.3)
Overall effective income tax rate 40.9% 38.3% 35.8%
The accumulated deferred income taxes as set forth below in the
Consolidated Balance Sheets at December 31, arise from the following
temporary differences:
1995 1994
(in millions)
Property related $ 282 $ 276
Investment tax credit related (26) (28)
Decommissioning related (14) (13)
Other 11 6
$ 253 $ 241
(7) BENEFIT PLANS:
(a) Pension Plans -
The Company has two non-contributory pension plans that,
collectively, cover substantially all of its employees. Plan benefits
are generally based on years of service and compensation during the
employees' latter years of employment. Payments made from the pension
funds to retired employees and beneficiaries during 1995 totaled
$9.0 million.
The Company's policy is to fund the pension cost at an amount that
is at least equal to the minimum funding requirements mandated by the
Employee Retirement Income Security Act (ERISA) and that does not exceed
the maximum tax deductible amount for the year. The Company has an
investment policy governing asset allocation guidelines for its pension
plans. The target ranges are as follows: 1) 37%-43% in large and mid-
sized domestic company equity securities, 2) 7%-13% in foreign equity
securities, 3) 7%-13% in small domestic company equity securities, 4) 0-
5% in real estate, and 5) the remainder in fixed income securities. As
of December 31, 1995, the plan's investment mix was consistent with the
policy guidelines.
Pursuant to the provisions of SFAS 71, certain adjustments to
Utilities' pension provision are necessary to reflect the accounting for
pension costs allowed in its most recent rate cases.
The components of the pension provision for the years ended
December 31, were as follows:
1995 1994 1993
(in thousands)
Service cost $ 4,721 $ 5,786 $ 4,275
Interest cost on projected benefit
obligation 11,577 11,265 11,131
Assumed return on plans' assets (12,340) (12,426) (12,177)
Amortization of unrecognized gain (741) (180) (763)
Amortization of prior service cost 1,328 1,335 1,195
Amortization of unrecognized plans'
assets as of January 1, 1987 (327) (329) (384)
Pension cost 4,218 5,451 3,277
Adjustment to funding level (4,218) (5,340) (2,867)
Total pension costs paid to the Trustee $ - $ 111 $ 410
Actual return on plans' assets $ 35,947 $ (101) $ 12,718
The reduction in the service cost for 1995 was primarily due to an
increase in the discount rate at December 31, 1994.
A reconciliation of the funded status of the plans to the amounts
recognized in the Consolidated Balance Sheets at December 31, is
presented below:
1995 1994
(in thousands)
Fair market value of plans' assets $ 191,782 $ 165,267
Actuarial present value of benefits
rendered to date -
Accumulated benefits based on
compensation to date, including vested
benefits of $117,624,000 and
$96,968,000, respectively 128,674 107,017
Additional benefits based on estimated
future salary levels 40,790 39,565
Projected benefit obligation 169,464 146,582
Plans' assets in excess of projected benefit
obligation 22,318 18,685
Remaining unrecognized net asset existing at
January 1, 1987, being amortized over 20 years (3,451) (3,792)
Unrecognized prior service cost 16,564 17,991
Unrecognized net gain (40,707) (33,942)
Accrued pension cost recognized in the
Consolidated Balance Sheets $ (5,276) $ (1,058)
Assumed rate of return, all plans 8.00% 8.00%
Weighted average discount rate of projected
benefit obligation, all plans 7.50% 8.25%
Range of assumed rates of increase in future
compensation levels for the plans 4.75% 4.00-5.75%
The increase in the projected benefit obligation was primarily due
to changes in the mortality rate assumptions and a reduction in the
discount rate at December 31, 1995.
(b) Other Postemployment Benefit Plans -
The Company provides certain benefits to retirees (primarily health
care benefits). Effective January 1, 1993, the Company adopted SFAS
106, which requires the accrual of the expected cost of postretirement
benefits other than pensions during the employees' years of service.
The IUB adopted rules stating that postretirement benefits other than
pensions will be included in Utilities' rates pursuant to the provisions
of SFAS 106. The rules permit Utilities to amortize the transition
obligation as of January 1, 1993, over 20 years and require that all
amounts collected are to be funded into an external trust to pay
benefits as they become due. The gas and electric portions of these
costs are being recovered through rates beginning in 1993 and 1995,
respectively, including amounts that were deferred by the Company
between when SFAS 106 was adopted and when recovery through rates began.
The amounts deferred are being amortized as they are collected through
rates over a three-year period. The unamortized balance of these
deferred costs was $3.4 million at December 31, 1995.
Pursuant to the provisions of SFAS 71, certain adjustments to
Utilities' other postretirement benefit provisions are necessary to
reflect the accounting for other postretirement benefit costs allowed in
its most recent rate cases.
The components of postretirement benefit costs for the years ended
December 31, were as follows:
1995 1994 1993
(in thousands)
Service cost $ 1,227 $ 1,785 $ 1,685
Interest cost on accumulated
postretirement benefit obligation 3,049 3,175 3,247
Assumed return on plans' assets (56) (60) -
Amortization of transition obligation
existing at January 1, 1993 2,024 2,024 2,024
Amortization of unrecognized gain (221) (4) -
Amortization of prior service cost 19 19 -
Postretirement benefit costs 6,042 6,939 6,956
Amortized/(deferred) postretirement
benefit costs 2,220 (2,732) (2,858)
Costs billed to affiliate (265) - -
Adjustment to funding level 1,162 - -
Net postretirement benefit costs $ 9,159 $ 4,207 $ 4,098
Actual return on plans' assets $ 273 $ 47 $ -
The reduction in the service cost for 1995 was primarily due to an
increase in the discount rate at December 31, 1994.
A reconciliation of the funded status of the plans to the amounts
recognized in the Consolidated Balance Sheets at December 31, is
presented below:
1995 1994
(in thousands)
Fair market value of plans' assets $ 6,515 $ 1,127
Accumulated postretirement benefit obligation -
Active employees not yet eligible 20,936 18,216
Active employees eligible 6,148 5,119
Retirees 21,846 18,161
Total accumulated postretirement benefit
obligation 48,930 41,496
Accumulated postretirement benefit obligation
in excess of plans' assets (42,415) (40,369)
Unrecognized transition obligation 34,415 36,439
Unrecognized net (gain)/loss 268 (5,358)
Unrecognized prior service cost 151 170
Accrued postretirement benefit cost in the
Consolidated Balance Sheets $ (7,581) $ (9,118)
Assumed rate of return 8.00% 8.00%
Weighted average discount rate of accumulated
postretirement benefit obligation 7.50% 8.25%
Medical trend on paid charges:
Initial trend rate 10.00% 11.00%
Ultimate trend rate 6.50% 6.50%
The increase in the accumulated postretirement benefit obligation
was primarily due to a reduction in the discount rate at December 31,
1995, as well as changes made for mortality, turnover and age
assumptions. The assumed medical trend rates are critical assumptions
in determining the service and interest cost and accumulated
postretirement benefit obligation related to postretirement benefit
costs. A 1% change in the medical trend rates, holding all other
assumptions constant, would have changed the 1995 service and interest
cost by $0.9 million (21%) and the accumulated postretirement benefit
obligation at December 31, 1995, by $8.3 million (17%).
(8) PREFERRED AND PREFERENCE STOCK:
Utilities has 466,406 shares of Cumulative Preferred Stock, $50 par
value, authorized for issuance at December 31, 1995, of which the 6.10%,
4.80% and 4.30% Series had 100,000, 146,406 and 120,000 shares,
respectively, outstanding at both December 31, 1995 and 1994. These
shares are redeemable at the option of Utilities upon 30 days notice at
$51.00, $50.25 and $51.00 per share, respectively, plus accrued
dividends. In addition, there are 700,000 shares of Utilities
Cumulative Preference Stock ($100 par value) authorized for issuance, of
which none were outstanding at December 31, 1995.
(9) DEBT:
(a) Long-Term Debt -
In December 1995, Utilities issued $50 million of Subordinated
Deferrable Interest Debentures, 7-7/8%, due 2025. The proceeds from the
issuance of the debentures were used to retire short-term borrowings which
were incurred in October 1995 to repay at maturity, $50 million of
Series X, 9.42% First Mortgage Bonds.
In March 1995, Utilities repaid at maturity $50 million of Series
W, 9.75% First Mortgage Bonds and, in a separate transaction, issued
$50 million of Collateral Trust Bonds, 7.65%, due 2000.
Utilities' Indentures and Deeds of Trust securing its First
Mortgage Bonds constitute direct first mortgage liens upon substantially
all tangible public utility property. Utilities' Indenture and Deed of
Trust securing its Collateral Trust Bonds constitutes a second lien on
substantially all tangible public utility property while First Mortgage
Bonds remain outstanding.
Total sinking fund requirements, which Utilities intends to meet by
pledging additional property under the terms of Utilities' Indentures
and Deeds of Trust, and debt maturities for 1996-2000 are as follows:
Debt Maturities
(in thousands)
Debt Issue 1996 1997 1998 1999 2000
Sinking fund
requirements $ 630 $ 550 $ 550 $ 550 $ 550
Pollution control 140 140 140 140 1,696
Series J 15,000 - - - -
6-1/8% Series - 8,000 - - -
Series Z - - - 50,000 -
Series L - - - - 15,000
7.65% Series - - - - 50,000
Total $ 15,770 $ 8,690 $ 690 $ 50,690 $ 67,246
The Company intends to refinance the majority of the debt
maturities with long-term securities.
(b) Short-Term Debt -
At December 31, 1995, the Company had bank lines of credit
aggregating $121.1 million, of which $101 million was being used to
support commercial paper (weighted average interest rate of 5.81%) and
$11.1 million was being used to support certain pollution control
obligations. Commitment fees are paid to maintain these lines and there
are no conditions which restrict the unused lines of credit. In
addition to the above, Utilities has an uncommitted credit facility with
a financial institution whereby it can borrow up to $40 million. Rates
are set at the time of borrowing and no fees are paid to maintain this
facility. At December 31, 1995, there were no borrowings outstanding
under this facility.
(10) ESTIMATED FAIR VALUE OF FINANCIAL INSTRUMENTS:
The estimated fair values of financial instruments at
December 31, 1995, and December 31, 1994, and the basis upon which they
were estimated are as follows:
(a) Current Assets and Current Liabilities -
The carrying amount approximates fair value because of the short
maturity of such financial instruments.
(b) Nuclear Decommissioning Trust Funds -
The carrying amount represents the fair value of these trust funds,
as reported by the trustee. The balance of the "Nuclear decommissioning
trust funds" as shown in the Consolidated Balance Sheets included $5.3
million of unrealized gains at December 31, 1995, and $0.8 million of
unrealized losses at December 31, 1994, on the investments held in the
trust funds. The accumulated reserve for decommissioning costs was
adjusted by a corresponding amount.
(c) Cumulative Preferred Stock of Utilities -
The estimated fair value of this stock of $11.3 million and $10.2
million at December 31, 1995, and December 31, 1994, respectively, is
based upon the market yield of similar securities and quoted market
prices.
(d) Long-Term Debt -
At December 31, 1995, and December 31, 1994, the carrying amount of
long-term debt was $483 million for both periods, compared to estimated
fair values of $507 million and $459 million, respectively. The
estimated fair value of long-term debt is based upon the market yield of
similar securities and quoted market prices.
Since Utilities is subject to regulation, any gains or losses
related to the difference between the carrying amount and the fair value
of financial instruments may not be realized by the Company's parent.
(11) COMMITMENTS AND CONTINGENCIES:
(a) Construction Program -
The Company's construction and acquisition program anticipates
expenditures of approximately $164 million for 1996, and additional
expenditures of approximately $13 million for mandated energy efficiency
programs. These energy efficiency expenditures will be deferred
pursuant to IUB rules as discussed in Note 3(c). Substantial
commitments have been made in connection with these expenditures.
(b) Purchase Power Contracts -
Utilities is purchasing power from UE under a firm capacity
contract with 1996 and 1997 requirements of 80 Mw and 60 Mw of delivered
capacity, respectively. Utilities will also purchase an additional
annual maximum interruptible capacity of up to 54 Mw of 25 Hz power,
which extends through 1998. The costs of capacity purchases for these
contracts are reflected in "Purchased power" in the Consolidated
Statements of Income.
Utilities has also entered into an agreement with Basin Electric
Power Cooperative to purchase capacity of 50 Mw, 75 Mw, 100 Mw and 100
Mw during the annual six-month summer season for the years 1996 through
1999, respectively.
Total capacity charges expected to be incurred under all existing
contracts will approximate $14.1 million, $11.1 million, $3.3 million,
$3.4 million and $0.4 million for the years 1996-2000, respectively.
(c) Coal Contract Commitments -
Utilities has entered into coal supply contracts which expire
between 1996 and 2001 for its fossil-fueled generating stations. At
December 31, 1995, the contracts cover approximately $158 million of
coal over the life of the contracts, which includes $55 million expected
to be incurred in 1996. Utilities expects to supplement these coal
contracts with spot market purchases to fulfill its future fossil fuel
needs.
(d) Information Technology Services -
The Company entered into an agreement, expiring in 2004, with
Electronic Data Systems Corporation (EDS) for information technology
services. The contract is subject to declining termination fees. The
Company's anticipated operating and capital expenditures under the
agreement for 1996 are estimated to total approximately $12.5 million.
Future costs under the agreement are variable and are dependent upon the
Company's level of usage of technological services from EDS.
(e) Nuclear Insurance Programs -
Public liability for nuclear accidents is governed by the Price
Anderson Act of 1988 which sets a statutory limit of $8.9 billion for
liability to the public for a single nuclear power plant incident and
requires nuclear power plant operators to provide financial protection
for this amount. As required, Utilities provides this financial
protection for a nuclear incident at the DAEC through a combination of
liability insurance ($200 million) and industry-wide retrospective
payment plans ($8.7 billion). Under the industry-wide plan, each
operating licensed nuclear reactor in the United States is subject to an
assessment in the event of a nuclear incident at any nuclear plant in
the United States. Based on its ownership of the DAEC, Utilities could
be assessed a maximum of $79.3 million per nuclear incident, with a
maximum of $10 million per incident per year (of which Utilities' 70%
ownership portion would be approximately $55 million and $7 million,
respectively) if losses relating to the incident exceeded $200 million.
These limits are subject to adjustments for changes in the number of
participants and inflation in future years.
Utilities is a member of Nuclear Mutual Limited (NML) and Nuclear
Electric Insurance Limited (NEIL). These companies provide $1.9 billion
of insurance coverage on certain property losses at DAEC for property
damage, decontamination and premature decommissioning. The proceeds
from such insurance, however, must first be used for reactor
stabilization and site decontamination before they can be used for plant
repair and premature decommissioning. NEIL also provides separate
coverage for the cost of replacement power during certain outages.
Owners of nuclear generating stations insured through NML and NEIL are
subject to retroactive premium adjustments if losses exceed accumulated
reserve funds. NML and NEIL's accumulated reserve funds are currently
sufficient to more than cover its exposure in the event of a single
incident under the primary and excess property damage or replacement
power coverages. However, Utilities could be assessed annually a
maximum of $3.1 million under NML, $9.8 million for NEIL property and
$0.7 million for NEIL replacement power if losses exceed the accumulated
reserves funds. Utilities is not aware of any losses that it believes
are likely to result in an assessment.
In the unlikely event of a catastrophic loss at DAEC, the amount of
insurance available may not be adequate to cover property damage,
decontamination and premature decommissioning. Uninsured losses, to the
extent not recovered through rates, would be borne by Utilities and
could have a material adverse effect on Utilities' financial position
and results of operations.
(f) Environmental Liabilities -
The Company has recorded environmental liabilities of approximately
$46.4 million in its Consolidated Balance Sheets at December 31, 1995.
The significant items are discussed below.
Former Manufactured Gas Plant (FMGP) Sites
Utilities has been named as a Potentially Responsible Party (PRP)
by various federal and state environmental agencies for 28 FMGP sites,
but believes it is not responsible for two of these sites. There are
also six other sites for which it may be designated as a PRP in the
future. Utilities is working pursuant to the requirements of the
various agencies to investigate, mitigate, prevent and remediate, where
necessary, damage to property, including damage to natural resources, at
and around the sites in order to protect public health and the
environment. Utilities believes it has completed the remediation of
five sites although it is in the process of obtaining final approval
from the applicable environmental agencies on this issue for each site.
Utilities is in various stages of the investigation and/or remediation
processes for 19 sites and expects to begin the investigation process in
1996 for the two other sites. Utilities estimates the range of costs to
be incurred for investigation and/or remediation of the sites to be
approximately $22 million to $55 million.
Utilities has recorded environmental liabilities related to the
FMGP sites of approximately $35 million (including $4.6 million as
current liabilities) at December 31, 1995. These amounts are based upon
Utilities' best current estimate of the amount to be incurred for
investigation and remediation costs for those sites where the
investigation process has been or is substantially completed, and the
minimum of the estimated cost range for those sites where the
investigation is in its earlier stages or has not started. It is
possible that future cost estimates will be greater than the current
estimates as the investigation process proceeds and as additional facts
become known. Utilities may be required to monitor these sites for a
number of years upon completion of remediation, as is the case with
several of the sites for which remediation has been completed.
Utilities has begun pursuing claims under its prior coverage for
investigation, mitigation, prevention, remediation, and monitoring costs
from its insurance carriers and is investigating the potential for third
party cost sharing for FMGP investigation and clean-up costs. The
amount of shared costs, if any, cannot be reasonably determined and,
accordingly, no potential sharing has been recorded at December
31, 1995. Regulatory assets of approximately $35 million, which reflect
the future recovery that is being provided through Utilities' rates,
have been recorded in the Consolidated Balance Sheets. Considering the
current rate treatment allowed by the IUB, management believes that the
clean-up costs incurred by Utilities for these FMGP sites will not have
a material adverse effect on its financial position or results of
operations.
National Energy Policy Act of 1992
The National Energy Policy Act of 1992 requires owners of nuclear
power plants to pay a special assessment into a "Uranium Enrichment
Decontamination and Decommissioning Fund." The assessment is based upon
prior nuclear fuel purchases and, for the DAEC, averages $1.4 million
annually through 2007, of which Utilities' 70% share is $1.0 million.
Utilities is recovering the costs associated with this assessment
through its electric fuel adjustment clauses over the period the costs
are assessed. Utilities' 70% share of the future assessment, $10.9
million payable through 2007, has been recorded as a liability in the
Consolidated Balance Sheets, including $0.8 million included in "Current
liabilities - Environmental liabilities," with a related regulatory
asset for the unrecovered amount.
(g) Air Quality Issues -
The Clean Air Act Amendments Act of 1990 (Act) requires emission
reductions of sulfur dioxide and nitrogen oxides (NOx) to achieve
reductions of atmospheric chemicals believed to cause acid rain. The
provisions of the Act are being implemented in two phases with Phase I
affecting two of Utilities' units beginning in 1995 and Phase II
affecting all units beginning in the year 2000. Utilities has completed
the modifications necessary to meet the Phase I requirements and has
installed continuous emission monitors on all affected units as required
by the Act. Utilities expects to meet the requirements of Phase II by
switching to lower sulfur fuels, capital expenditures primarily related
to fuel burning equipment and boiler modifications and the possible
purchase of sulfur dioxide allowances. Utilities estimates capital
expenditures at approximately $20 million, including $4 million in 1996,
in order to meet the acid rain requirements of the Act.
The acid rain program under the Act also creates sulfur dioxide
allowances. An allowance is defined as an authorization for an owner to
emit one ton of sulfur dioxide into the atmosphere. Currently,
Utilities receives a sufficient number of allowances annually to offset
its emissions of sulfur dioxide from its Phase I units. It is
anticipated that in the year 2000, when the Phase II units participate
in the allowance program, Utilities may have an insufficient number of
allowances annually to offset its estimated emissions and may have to
purchase additional allowances, or make modifications to the plants or
limit operations to reduce emissions. Utilities is reviewing its
options to ensure that it will have sufficient allowances to offset its
emissions in the year 2000 and thereafter. Utilities believes that the
potential cost of ensuring sufficient allowances will not have a
material adverse effect on its financial position or results of
operations.
The Act also requires the United States Environmental Protection
Agency (EPA) to study and regulate, if necessary, additional issues that
potentially affect the electric utility industry, including emissions
relating to nitrogen oxides (NOx), ozone transport and mercury.
Currently, the impacts of these potential regulations are too
speculative to quantify.
In 1995, the EPA published the Sulfur Dioxide Network Design Review
for Cedar Rapids, Iowa, which, based on the EPA's assumptions and worst-
case modeling methods, suggests that the Cedar Rapids area could be
classified as "nonattainment" for the National Ambient Air Quality
Standard (NAAQS) established for sulfur dioxide. The worst-case
modeling study suggests that two of Utilities' generating facilities
contribute to the modeled exceedences and recommends that additional
monitors be located near Utilities' sources to assess actual ambient air
quality. In the event that Utilities' facilities contribute excessive
emissions, Utilities would be required to reduce emissions, which would
primarily entail capital expenditures for modifications to the
facilities. Utilities is currently reviewing EPA's assumptions and
modeling results and is proposing a strategy to voluntarily reduce the
excessive emissions through modification of its facilities at a
potential capital cost of up to $10 million over the next four years.
(h) FERC Order No. 636 -
Pursuant to FERC Order No. 636 (Order 636), which transitions the
natural gas supply business to a less regulated environment, Utilities
has enhanced access to competitively priced gas supply and more flexible
transportation services. However, under Order 636, Utilities is
required to pay certain transition costs incurred and billed by its
pipeline suppliers.
Utilities began paying the transition costs in 1993 and at December
31, 1995, has recorded a liability of $5.0 million for those transition
costs that have been incurred, but not yet billed, by the pipelines to
date, including $1.9 million expected to be billed through 1996.
Utilities is currently recovering the transition costs from its
customers through its Purchased Gas Adjustment Clauses as such costs are
billed by the pipelines. Transition costs, in addition to the recorded
liability, that may ultimately be charged to Utilities could approximate
$7.0 million. The ultimate level of costs to be billed to Utilities
depends on the pipelines' future filings with the FERC and other future
events, including the market price of natural gas. However, Utilities
believes any transition costs that the FERC would allow the pipelines to
collect from Utilities would be recovered from its customers, based upon
regulatory treatment of these costs currently and similar past costs by
the IUB. Accordingly, regulatory assets, in amounts corresponding to
the recorded liabilities, have been recorded to reflect the anticipated
recovery.
(12) JOINTLY-OWNED ELECTRIC UTILITY PLANT:
Under joint ownership agreements with other Iowa utilities,
Utilities has undivided ownership interests in jointly-owned electric
generating stations and related transmission facilities. Each of the
respective owners is responsible for the financing of its portion of the
construction costs. Kilowatt-hour generation and operating expenses are
divided on the same basis as ownership with each owner reflecting its
respective costs in its Statements of Income. Information relative to
Utilities' ownership interest in these facilities at December 31, 1995
is as follows:
Ottumwa Neal
DAEC Unit 1 Unit 3
($ in millions)
Utility plant in service $ 498.0 $ 189.3 $ 56.2
Accumulated depreciation $ 201.2 $ 86.0 $ 27.1
Construction work in progress $ 2.7 $ 1.7 $ 0.7
Plant capacity - Mw 520 716 515
Percent ownership 70% 48% 28%
In-service date 1974 1981 1975
(13) SEGMENTS OF BUSINESS:
The principal business segments of the Company are the generation,
transmission, distribution and sale of electric energy and the purchase,
distribution, transportation and sale of natural gas. Certain financial
information relating to the Company's significant segments of business
is presented below:
Year Ended December 31
1995 1994 1993
(in thousands)
Operating results:
Revenues -
Electric $ 560,471 $ 537,327 $ 550,521
Gas 137,292 139,033 154,318
Operating income -
Electric 130,390 125,487 128,994
Gas 9,208 8,135 13,750
Other information:
Depreciation and amortization -
Electric 72,487 68,640 63,832
Gas 6,176 6,214 5,186
Construction and acquisition
expenditures -
Electric 108,902 120,180 96,736
Gas 9,368 10,066 15,428
Assets -
Identifiable assets -
Electric 1,395,666 1,347,024 1,288,505
Gas 192,045 186,911 164,773
1,587,711 1,533,935 1,453,278
Other corporate assets 120,924 111,433 93,700
Total consolidated $ 1,708,635 $ 1,645,368 $ 1,546,978
Item 9. Changes and Disagreements with Accountants on Accounting and
Financial Disclosure
None.
PART III
Item 10. Directors, Executive Officers, Promoters and Control Persons
of the Registrant
Information regarding the identification of directors is included
in Exhibit 99 and is incorporated herein by reference. Exhibit 99 is
primarily an excerpt from the IES Industries Inc. definitive proxy
statement prepared for the 1996 annual meeting of stockholders, which
will be filed within 120 days of December 31, 1995. The executive
officers of the registrant are as follows:
Executive Officers of the Registrant (Effective February 6, 1996)
Lee Liu, 62, Chairman of the Board & Chief Executive Officer.
First elected officer in 1975. (1)
Blake O. Fisher, Jr., 51, President, Chief Operating Officer &
Chief Financial Officer and Director. First elected officer in
1991. (2)
James E. Hoffman, 43, Executive Vice President, Customer Service &
Energy Delivery. First elected officer in 1995. (3)
Stephen W. Southwick, 49, Vice President, General Counsel &
Secretary. First elected officer in 1982.
John F. Franz, Jr., 56, Vice President, Nuclear. First elected
officer in 1992. (4)
Philip D. Ward, 55, Vice President, Engineering & Generation.
First elected officer in 1990.
Harold W. Rehrauer, 58, Vice President, Field Operations. First
elected officer in 1987.
Richard A. Gabbianelli, 39, Controller & Chief Accounting Officer.
First elected officer in 1994.
Dennis B. Vass, 46, Treasurer. First elected officer in 1995. (5)
Officers are elected annually by the Board of Directors and each of
the officers named above, except James E. Hoffman, John F. Franz, Jr.
and Dennis B. Vass, have been employed by the Company as an officer or
in other responsible positions at such companies for at least five
years. There are no family relationships among these officers. There
are no arrangements or understandings with respect to election of any
person as an officer.
(1) Lee Liu was elected Chairman of the Board, President & Chief
Executive Officer effective February 21, 1996.
(2) Blake O. Fisher, Jr. resigned as President, Chief
Operating Officer & Chief Financial Officer and Director of
IES Utilities Inc. effective February 21, 1996.
(3) Prior to the appointment of James E. Hoffman as Executive Vice
President, Customer Service & Energy Delivery in 1995, he was
employed by MCI Communications as Chief Information Officer
from 1990 to 1995 and by Telecom*USA as Vice President,
Information Services from 1988 to 1990.
(4) Prior to the appointment of John F. Franz, Jr. as Vice
President, Nuclear in 1992, he was employed by Philadelphia
Electric Company as Plant Manager, Peach Bottom Atomic Power
Station.
(5) Dennis B. Vass was elected as Treasurer & Principal Financial
Officer effective February 21, 1996. Prior to the appointment
of Mr. Vass as Treasurer of the Company in February 1995, he
was employed by Consumers Power Company as Financial Projects
Director and by the Company in April 1991, as Manager of
Finance.
Item 11. Executive Compensation
Information regarding executive compensation and transactions is
included in Exhibit 99 and is incorporated herein by reference.
Item 12. Security Ownership of Certain Beneficial Owners and Management
Information regarding security ownership of certain beneficial
owners and management is included in Exhibit 99 and is incorporated
herein by reference.
Item 13. Certain Relationships and Related Transactions
Information regarding certain relationships and related
transactions is included in Exhibit 99 and is incorporated herein by
reference.
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
Page No.
(a) 1. Financial Statements -
Included in Part II of this report -
Report of Management. 59 - 60
Report of Independent Public Accountants. 61
Consolidated Statements of Income for the
years ended December 31, 1995, 1994 and 1993. 62
Consolidated Statements of Retained Earnings
for the years ended December 31, 1995, 1994 and 1993. 63
Consolidated Balance Sheets at December 31, 1995
and 1994. 64 - 65
Consolidated Statements of Capitalization at
December 31, 1995 and 1994. 66
Consolidated Statements of Cash Flows for the
years ended December 31, 1995, 1994 and 1993. 67
Notes to Consolidated Financial Statements. 68 - 97
(a) 2. Financial Statement Schedules -
Included in Part IV of this report -
Schedule II - Valuation and Qualifying Accounts
and Reserves for the years ended
December 31, 1995, 1994 and 1993. 103
Other schedules are omitted as not required under
Rules of Regulation S-X.
(a) 3. Exhibits -
See Exhibit Index beginning on page 106.
(b) Reports on Form 8-K -
Items Reported Financial Statements Date of Report
5,7 None February 9, 1996 (1)
7 None December 8, 1995 (2)
5,7 None November 10, 1995 (3)
(1) The Form 8-K report was filed on February 20, 1996 with the
earliest event reported occurring on February 9, 1996.
(2) The Form 8-K report was filed on December 11, 1995 with the
earliest event reported occurring on December 8, 1995.
(3) The Form 8-K report was filed on November 21, 1995 with the
earliest event reported occurring on November 10, 1995.
IES UTILITIES INC.
SCHEDULE II--VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993
Column A Column B Column E
Balance Balance
Description January 1 December 31
(in thousands)
1995:
Accumulated provision for
uncollectible accounts $ 650 $ 676
Accumulated provision for rate refunds $ - $ 106
1994:
Accumulated provision for
uncollectible accounts $ 409 $ 650
Accumulated provision for rate refunds $ 8,670 $ -
1993:
Accumulated provision for
uncollectible accounts $ 567 $ 409
Accumulated provision for rate refunds $ 9,020 $ 8,670
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly caused this
report to be signed on its behalf by the undersigned, thereunto duly
authorized, on the 8th day of March 1996.
IES UTILITIES INC.
(Registrant)
By /s/ Lee Liu
Lee Liu
Chairman of the Board, President &
Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons on
behalf of the registrant and in the capacities indicated on
March 8, 1996:
/s/ Lee Liu Chairman of the Board, President &
Lee Liu Chief Executive Officer
(Principal Executive Officer)
/s/ Dennis B. Vass Treasurer and Principal Financial Officer
Dennis B. Vass (Principal Financial Officer)
/s/ Richard A. Gabbianelli Controller & Chief Accounting Officer
Richard A. Gabbianelli (Principal Accounting Officer)
/s/ C.R.S. Anderson Director
C.R.S. Anderson
/s/ J. Wayne Bevis Director
J. Wayne Bevis
Director
Dr. George Daly
/s/ G. Sharp Lannom, IV Director
G. Sharp Lannom, IV
/s/ Jack R. Newman Director
Jack R. Newman
/s/ Robert D. Ray Director
Robert D. Ray
/s/ David Q. Reed Director
David Q. Reed
/s/ Henry Royer Director
Henry Royer
/s/ Robert W. Schlutz Director
Robert W. Schlutz
/s/ Anthony R. Weiler Director
Anthony R. Weiler
EXHIBIT INDEX
The Exhibits designated by an asterisk are filed herewith and all other
Exhibits as stated to be filed are incorporated herein by reference.
Exhibit
3(a) Articles of Incorporation of the Registrant,
Amended and Restated as of January 6, 1994 (Filed as Exhibit 4(b)
to Company's Current Report on Form 8-K, dated January 7, 1994).
* 3(b) Bylaws of Registrant, as amended February 6, 1996.
4(a) Indenture of Mortgage and Deed of Trust, dated as
of September 1, 1993, between the Company (formerly Iowa Electric
Light and Power Company (IE)) and The First National Bank of
Chicago, as Trustee (Mortgage) (Filed as Exhibit 4(c) to IE's
Form 10-Q for the quarter ended September 30, 1993).
4(b) Supplemental Indentures to the Mortgage:
Number Dated as of IE File Reference Exhibit
First October 1, 1993 Form 10-Q, 11/12/93 4(d)
Second November 1, 1993 Form 10-Q, 11/12/93 4(e)
Third March 1, 1995 Form 10-Q, 5/12/95 4(b)
4(c) Indenture of Mortgage and Deed of Trust, dated as
of August 1, 1940, between the Company (formerly IE) and The
First National Bank of Chicago, Trustee (1940 Indenture) (Filed
as Exhibit 2(a) to IE's Registration Statement, File No. 2-
25347).
4(d) Supplemental Indentures to the 1940 Indenture:
Number Dated as of IE File Reference Exhibit
First March 1, 1941 2-25347 2(a)
Second July 15, 1942 2-25347 2(a)
Third August 2, 1943 2-25347 2(a)
Fourth August 10, 1944 2-25347 2(a)
Fifth November 10, 1944 2-25347 2(a)
Sixth August 8, 1945 2-25347 2(a)
Seventh July 1, 1946 2-25347 2(a)
Eighth July 1, 1947 2-25347 2(a)
Ninth December 15, 1948 2-25347 2(a)
Tenth November 1, 1949 2-25347 2(a)
Eleventh November 10, 1950 2-25347 2(a)
Twelfth October 1, 1951 2-25347 2(a)
Thirteenth March 1, 1952 2-25347 2(a)
Fourteenth November 5, 1952 2-25347 2(a)
Fifteenth February 1, 1953 2-25347 2(a)
Sixteenth May 1, 1953 2-25347 2(a)
Seventeenth November 3, 1953 2-25347 2(a)
Eighteenth November 8, 1954 2-25347 2(a)
Nineteenth January 1, 1955 2-25347 2(a)
Twentieth November 1, 1955 2-25347 2(a)
Twenty-first November 9, 1956 2-25347 2(a)
Twenty-second November 6, 1957 2-25347 2(a)
Twenty-third November 4, 1958 2-25347 2(a)
Twenty-fourth November 3, 1959 2-25347 2(a)
Twenty-fifth November 1, 1960 2-25347 2(a)
Twenty-sixth January 1, 1961 2-25347 2(a)
Twenty-seventh November 7, 1961 2-25347 2(a)
Twenty-eighth November 6, 1962 2-25347 2(a)
Twenty-ninth November 5, 1963 2-25347 2(a)
Thirtieth November 4, 1964 2-25347 2(a)
Thirty-first November 2, 1965 2-25347 2(a)
Thirty-second September 1, 1966 Form 10-K, 1966 4.10
Thirty-third November 30, 1966 Form 10-K, 1966 4.10
Thirty-fourth November 7, 1967 Form 10-K, 1967 4.10
Thirty-fifth November 5, 1968 Form 10-K, 1968 4.10
Thirty-sixth November 1, 1969 Form 10-K, 1969 4.10
Thirty-seventh December 1, 1970 Form 8-K, 12/70 1
Thirty-eighth November 2, 1971 2-43131 2(g)
Thirty-ninth May 1, 1972 Form 8-K, 5/72 1
Fortieth November 7, 1972 2-56078 2(i)
Forty-first November 7, 1973 2-56078 2(j)
Forty-second September 10, 1974 2-56078 2(k)
Forty-third November 5, 1975 2-56078 2(l)
Forty-fourth July 1, 1976 Form 8-K, 7/76 1
Forty-fifth November 1, 1976 Form 8-K, 12/76 1
Forty-sixth December 1, 1977 2-60040 2(o)
Forty-seventh November 1, 1978 Form 10-Q, 6/30/79 1
Forty-eighth December 1, 1979 Form S-16, 2-65996 2(q)
Forty-ninth November 1, 1981 Form 10-Q, 3/31/82 2
Fiftieth December 1, 1980 Form 10-K, 1981 4(s)
Fifty-first December 1, 1982 Form 10-K, 1982 4(t)
Fifty-second December 1, 1983 Form 10-K, 1983 4(u)
Fifty-third December 1, 1984 Form 10-K, 1984 4(v)
Fifty-fourth March 1, 1985 Form 10-K, 1984 4(w)
Fifty-fifth March 1, 1988 Form 10-Q, 5/12/88 4(b)
Fifty-sixth October 1, 1988 Form 10-Q, 11/10/88 4(c)
Fifty-seventh May 1, 1991 Form 10-Q, 8/13/91 4(d)
Fifty-eighth March 1, 1992 Form 10-K, 1991 4(c)
Fifty-ninth October 1, 1993 Form 10-Q, 11/12/93 4(a)
Sixtieth November 1, 1993 Form 10-Q, 11/12/93 4(b)
Sixty-first March 1, 1995 Form 10-Q, 5/12/95 4(a)
4(e) Indenture or Deed of Trust dated as of February 1,
1923, between the Company (successor to Iowa Southern Utilities
Company (IS) as result of merger of IS and IE) and The Northern
Trust Company (The First National Bank of Chicago, successor) and
Harold H. Rockwell (Richard D. Manella, successor), as Trustees
(1923 Indenture) (Filed as Exhibit B-1 to File No. 2-1719).
4(f) Supplemental Indentures to the 1923 Indenture:
Dated as of File Reference Exhibit
May 1, 1940 2-4921 B-1-k
May 2, 1940 2-4921 B-1-l
October 1, 1945 2-8053 7(m)
October 2, 1945 2-8053 7(n)
January 1, 1948 2-8053 7(o)
September 1, 1950 33-3995 4(e)
February 1, 1953 2-10543 4(b)
October 2, 1953 2-10543 4(q)
August 1, 1957 2-13496 2(b)
September 1, 1962 2-20667 2(b)
June 1, 1967 2-26478 2(b)
February 1, 1973 2-46530 2(b)
February 1, 1975 2-53860 2(aa)
July 1, 1975 2-54285 2(bb)
September 2, 1975 2-57510 2(bb)
March 10, 1976 2-57510 2(cc)
February 1, 1977 2-60276 2(ee)
January 1, 1978 0-849 2
March 1, 1979 0-849 2
March 1, 1980 0-849 2
May 31, 1986 33-3995 4(g)
July 1, 1991 0-849 4(h)
September 1, 1992 0-849 4(m)
December 1, 1994 0-4117-1 4(f)
4(g) Indenture (For Unsecured Subordinated Debt Securities),
dated as of December 1, 1995, between the Company and The First
National Bank of Chicago, as Trustee (Subordinated Indenture)
(Filed as Exhibit 4(i) to the Company's Amendment No. 1 to
Registration Statement, File No. 33-62259).
4(h) Officer's Certificate establishing the terms of new
Series of Subordinated Debentures (Filed as Exhibit 4 to
Utilities' Current Report on Form 8-K, dated December 8, 1995).
10(a) Operating and Transmission Agreement between Central Iowa
Power Cooperative and IE (Filed as Exhibit 10(q) to IE's Form 10-
K for the year 1990).
10(b) Duane Arnold Energy Center Ownership Participation
Agreement dated June 1, 1970 between Central Iowa Power
Cooperative, Corn Belt Power Cooperative and IE. (Filed as
Exhibit 5(kk) to IE's Registration Statement, File No. 2-38674).
10(c) Duane Arnold Energy Center Operating Agreement
dated June 1, 1970 between Central Iowa Power Cooperative, Corn
Belt Power Cooperative and IE. (Filed as Exhibit 5(ll) to IE's
Registration Statement, File No. 2-38674).
10(d) Duane Arnold Energy Center Agreement for
Transmission, Transformation, Switching and Related Facilities
dated June 1, 1970 between Central Iowa Power Cooperative, Corn
Belt Power Cooperative and IE. (Filed as Exhibit 5(mm) to IE's
Registration Statement, File No. 2-38674).
10(e) Basic Generating Agreement dated April 16, 1975
between Iowa Public Service Company, Iowa Power and Light
Company, Iowa-Illinois Gas and Electric Company and IS for the
joint ownership of Ottumwa Generating Station-Unit 1 (OGS-1).
(Filed as Exhibit 1 to IE's Form 10-K for the year 1977).
10(f) Addendum Agreement to the Basic Generating
Agreement for OGS-1 dated December 7, 1977 between Iowa Public
Service Company, Iowa-Illinois Gas and Electric Company, Iowa
Power and Light Company, IS and IE for the purchase of 15%
ownership in OGS-1. (Filed as Exhibit 3 to IE's Form 10-K for
the year 1977).
10(g) Second Amended and Restated Credit Agreement dated
as of September 17, 1987 between Arnold Fuel, Inc. and the First
National Bank of Chicago and the Amended and Restated Consent and
Agreement dated as of September 17, 1987 by IE. (Filed as
Exhibit 10(j) to IE's Form 10-K for the year 1987).
Management Contracts and/or Compensatory Plans (Exhibits 10(h) through 10(q))
10(h) Supplemental Retirement Plan. (Filed as Exhibit
10(l) to Industries' Form 10-K for the year 1987).
10(i) Management Incentive Compensation Plan. (Filed as
Exhibit 10(m) to Industries' Form 10-K for the year 1987).
10(j) Key Employee Deferred Compensation Plan. (Filed
as Exhibit 10(n) to Industries' Form 10-K for the year 1987).
10(k) Long-Term Incentive Plan. (Filed as Exhibit A to
Industries' Proxy Statement dated March 20, 1995).
10(l) Executive Guaranty Plan. (Filed as Exhibit 10(p)
to Industries' Form 10-K for the year 1987).
10(m) Executive Change of Control Severance Agreement.
(Filed as Exhibit 10(s) to Industries' Form 10-K for the year
1989).
10(n) Amendments to Key Employee Deferred Compensation
Agreement for Directors. (Filed as Exhibit 10(u) to Industries'
Form 10-Q for the quarter ended March 31, 1990).
10(o) Amendments to Key Employee Deferred Compensation
Agreement for Key Employees. (Filed as Exhibit 10(v) to
Industries' Form 10-Q for the quarter ended March 31, 1990).
10(p) Amendments to Management Incentive Compensation
Plan. (Filed as Exhibit 10(y) to Industries' Form 10-Q for the
quarter ended March 31, 1990).
10(q) Director Retirement Plan. (Filed as Exhibit 10(t)
to Industries' Form 10-K for the year 1993).
10(r) Agreement for Purchase and Sale of Certain Assets
and Real Estate and Assignment of Easements, Leases and Licenses
between Union Electric Company (Seller) and IE (Buyer). (Filed as
Exhibit 10(t) to IE's Form 10-K for the year 1991).
10(s) Receivables Purchase and Sale Agreement dated as of June 30,
1989, as Amended and Restated as of April 15, 1994, among IES
Utilities Inc. (as Seller) and CIESCO L.P. (as the Investor) and
Citicorp North America, Inc. (as Agent). (Filed as Exhibit 10(a)
to the Company's Form 10-Q for the quarter ended March 31, 1994).
10(t) Guaranty (IES Utilities Trust No. 1994-A) from IES Utilities
Inc., dated as of June 29, 1994. (Filed as Exhibit 10(b) to the
Company's Form 10-Q for the quarter ended June 30, 1994 (File No.
0-4117-1)).
10(u) Agreement and Plan of Merger between IE and IS dated as of
June 4, 1993 (Agreement and Plan of Merger) (Filed as Exhibit 2
to the Company's Current Report on Form 8-K, dated June 4, 1993
(File No. 0-4117-1)).
10(v) Amendment 1 dated June 16, 1993, to the Agreement and Plan
of Merger (Filed as Exhibit 2(b) to the IE Registration Statement
on Form S-3, dated September 14, 1993 (File No. 33-68796)).
10(w) Amendment 2 dated September 8, 1993, to the Agreement and
Plan of Merger (Filed as Exhibit 2(c) to the IE Registration
Statement on Form S-3, dated September 14, 1993 (File No.
33-68796)).
10(x) Amendment 3 dated September 27, 1993, to the Agreement and
Plan of Merger (Filed as Exhibit 2(d) to the IE Current Report on
Form 8-K, dated December 9, 1993 (File No. 0-4117-1)).
10(y) Copy of Coal Supply Agreement, dated July 27, 1977, between
IS and Sunoco Energy Development Co. (former parent of Cordero
Mining Co.), and letter memorandum thereto, dated October 29,
1984, relating to the purchase of coal supplies for the fuel
requirements at the Ottumwa Generating Station. (Filed as
Exhibit 10-A-4 to File No. 33-3995).
* 12 Ratio of Earnings to Fixed Charges.
* 23 Consent of Independent Public Accountants.
* 27 Financial Data Schedule.
* 99 Director and Officer Information.
Note: Pursuant to (b)(4)(iii)(A) of Item 601 of Regulation
S-K, the Company has not filed as an exhibit to this Form 10-K
certain instruments with respect to long-term debt that has not
been registered if the total amount of securities authorized
thereunder does not exceed 10% of total assets of the Company but
hereby agrees to furnish to the Commission on request any such
instruments.
BYLAWS AS AMENDED EXHIBIT 3(b)
OF
IES UTILITIES INC.
(Amended Through February 6, 1996)
ARTICLE I
OFFICES
SECTION 1.1. PRINCIPAL OFFICE. - The principal office
shall be established and maintained in the ie: Tower, 200
First Street, S.E., in the City of Cedar Rapids, in the County
of Linn, in the State of Iowa.
SECTION 1.2. OTHER OFFICES. - The Corporation may have
other offices, either within or without the State of Iowa, at
such place or places as the Board of Directors may from time
to time appoint or the business of the Corporation may re
quire. The registered office of the Corporation required by
the Iowa Business Corporation Act to be maintained in the
State of Iowa may be, but need not be identical with the
principal office in the State of Iowa, and the address of the
registered office may be changed from time to time by the
Board of Directors.
ARTICLE II
SHAREHOLDERS
SECTION 2.1. ANNUAL MEETING. - The annual meeting of
shareholders for the election of directors and the transaction
of other business shall be held, in each year, on the third
Tuesday in May at three o'clock in the afternoon unless such
day is a holiday, in which event the annual meeting will be
held at such time on the next succeeding business day.
SECTION 2.2. PLACE OF SHAREHOLDERS' MEETING. - The
annual meeting or any special meeting of shareholders shall be
held at the principal office of the Corporation or any place,
within the State of Iowa, as shall be designated by the Board
of Directors and stated in the notice of the meeting.
SECTION 2.3. SPECIAL MEETINGS. - Special meetings of the
shareholders may be called by the Chairman of the Board, the
President, the Board of Directors, or the holders of not less
than ten percent of all the shares entitled to vote at the
meeting.
SECTION 2.4. NOTICE OF MEETINGS. - WAIVER. - Written or
printed notice, stating the place, day and hour of the meeting
and, in case of a special meeting, the purpose or purposes for
which the meeting is called, shall be delivered not less than
ten nor more than sixty days before the date of the meeting,
either personally or by mail, by or at the direction of the
Board of Directors, to each shareholder of record entitled to
vote at such meeting. If mailed, such notice shall be deemed
to be delivered when deposited in the United States mail
addressed to the shareholder at the address appearing on the
stock transfer books of the Corporation, with postage thereon
prepaid.
SECTION 2.5. CLOSING OF TRANSFER BOOKS; FIXING OF RECORD
DATE. - For the purpose of determining shareholders entitled
to notice of, or to vote at, any special meeting of
shareholders, or at any adjournment thereof, or shareholders
entitled to receive payment of any dividend, or in order to
make a determination of shareholders for any other proper
purpose, the Board of Directors of the Corporation may provide
that the stock transfer books shall be closed for a stated
period but not to exceed, in any case, 60 days. If the stock
transfer books shall be closed for the purpose of determining
shareholders entitled to notice of or to vote at a meeting of
shareholders, such books shall be closed for at least 10 days
immediately preceding such meeting. In lieu of closing the
stock transfer books, the Board of Directors may fix in
advance a date as the record date for any such determination
of shareholders, such date in any case not to be more than 70
days, and in the case of a meeting of shareholders not less
than 10 days, prior to the date on which the particular
action, requiring such determination of shareholders, is to be
taken. If the stock transfer books are not closed and no
record date is fixed for the determination of shareholders,
the date on which notice of the meeting is mailed or the date
on which the resolution of the Board of Directors declaring
such dividend is adopted, as the case may be, shall be the
record date for such determination of shareholders. When a
determination of shareholders entitled to vote at any meeting
of shareholders has been made as provided in this section,
such determination shall apply to any adjournment thereof.
SECTION 2.6. VOTING RECORD. - The officer or agent
having charge of the stock transfer books for shares of the
Corporation shall make, at least 10 days prior to each meeting
of shareholders, a complete record of the shareholders en
titled to vote at such meeting, or any adjournment thereof,
arranged in alphabetical order with the address of and the
number of shares held by each, which record shall be kept on
file at the registered office of the Corporation and shall be
subject to inspection by any shareholder at any time during
usual business hours for a period of 10 days prior to such
meeting. Such record shall also be produced and kept open at
the time and place of the meeting and shall be subject to the
inspection of any shareholder during the whole time of the
meeting. The original stock transfer book shall be prima
facie evidence of the identity of the shareholders entitled to
examine such record or transfer books or to vote at any
meeting of shareholders.
SECTION 2.7. QUORUM. - A majority of the outstanding
shares of the Corporation entitled to vote, represented in
person or by proxy, shall constitute a quorum at a meeting of
shareholders. If less than a majority of the outstanding
shares are represented at a meeting, a majority of the shares
so represented may adjourn the meeting from time to time
without further notice. At such adjourned meeting at which a
quorum shall be present or represented, any business may be
transacted which might have been transacted at the meeting as
originally notified. The shareholders present at a duly
organized meeting may continue to transact business until
adjournment only if a quorum is represented throughout.
SECTION 2.8. CONDUCT OF MEETING. - Meetings of the
shareholders shall be presided over by one of the following
officers in the order of seniority if present and acting - the
Chairman of the Board, the President, the Secretary, or if
none of the foregoing is in office and present and acting, by
a chairperson to be chosen by the shareholders. The Secretary
of the Corporation, or if absent, an Assistant Secretary,
shall act as secretary of the meeting, but if neither the
Secretary nor an Assistant Secretary is present, or if the
Secretary is presiding over the meeting and the Assistant
Secretary is not present, the Chairman of the meeting shall
appoint a secretary of the meeting.
SECTION 2.9. PROXIES. - At all meetings of shareholders,
a shareholder may vote by proxy executed in writing by the
shareholder or by a duly authorized attorney-in-fact. Such
proxy shall be filed with the Secretary of the Corporation
before or at the time of the meeting. No proxy shall be valid
after eleven months from the date of its execution, unless
otherwise provided in the proxy.
SECTION 2.10. VOTING OF SHARES. - Each outstanding share
entitled to vote shall be entitled to one vote upon each
matter submitted to a vote at a meeting of shareholders.
SECTION 2.11. VOTING OF SHARES BY CERTAIN HOLDERS. -
Shares standing in the name of another corporation may be
voted by such officer, agent or proxy as the Bylaws of such
corporation may prescribe, or, in the absence of such provi
sion, as the Board of Directors of such corporation may
determine.
Shares held by an administrator, executor, guardian or
conservator may be voted by such person, either in person or
by proxy, without a transfer of such shares into that person's
name. Shares standing in the name of a trustee may be voted
by such trustee, either in person or by proxy, without a
transfer of such shares into the trustee's name. The
Corporation may request evidence of such fiduciary status with
respect to the vote, consent, waiver, or proxy appointment.
Shares standing in the name of a receiver or trustee in
bankruptcy may be voted by such receiver or trustee, and
shares held by or under the control of a receiver may be voted
by such receiver without the transfer of the shares into such
person's name if authority so to do be contained in an
appropriate order of the court by which such receiver was
appointed.
A pledgee, beneficial owner, or attorney-in-fact of the
shares held in the name of a shareholder shall be entitled to
vote such shares. The Corporation may request evidence of
such signatory's authority to sign for the shareholder with
respect to the vote, consent, waiver, or proxy appointment.
Neither treasury shares nor shares held by another
corporation, if a majority of the shares entitled to vote for
the election of Directors of such other corporation is held by
the Corporation, shall be voted at any meeting or counted in
determining the total number of outstanding shares at any
given time.
ARTICLE III
BOARD OF DIRECTORS
SECTION 3.1. GENERAL POWERS. - The business and affairs
of the Corporation shall be managed by its Board of Directors.
SECTION 3.2. NUMBER, TENURE, QUALIFICATIONS AND REMOVAL.
- - The number of Directors of the Corporation shall be
twelve. Each Director shall hold office until the next annual
meeting of shareholders and until the Director's successor
shall have been elected and qualified, unless removed at a
meeting called expressly for that purpose by a vote of a
majority of the shares then entitled to vote at an election of
Directors. A Director may only be removed upon a showing of
cause. Directors need not be residents of the State of Iowa
or shareholders of the Corporation. Not more than three
Directors shall be officers or employees of the Corporation or
its subsidiaries. No person who has reached the age of 70
years shall be eligible for election or reelection to the
Board of Directors.
SECTION 3.3. REGULAR MEETINGS. - An annual meeting of
the Board of Directors shall be held without other notice than
this Bylaw immediately after, and at the same place as, the
annual meeting of shareholders. Unless otherwise provided by
resolution of the Board of Directors, regular meetings of the
Board of Directors, additional to the annual meeting, shall be
held on the first Tuesday of February, May, and August, and on
the first Wednesday of November of each year, at the principal
office or any place within or without the State of Iowa as
shall be designated by the Board of Directors without notice
other than such resolution.
SECTION 3.4. SPECIAL MEETINGS. - Special meetings of the
Board of Directors may be called by or at the request of the
Chairman of the Board, President or any two Directors. The
person or persons authorized to call special meetings of the
Board of Directors may fix any place either within or without
the State of Iowa, whether in person or by telecommunications,
as the place for holding any special meeting of the Board of
Directors called by them.
SECTION 3.5. NOTICE. - Notice of any special meeting
shall be given at least three days prior to the meeting by
written notice delivered personally or mailed to each Director
at the Director's business address, by telegram, or orally by
telephone. If mailed, such notice shall be deemed to be
delivered when deposited in the United States mail, so ad
dressed, with postage prepaid. If notice be given by tele
gram, such notice shall be deemed to be delivered when the
telegram is delivered to the telegraph company. Any director
may waive notice of any meeting. The attendance of a Director
at a meeting shall constitute a waiver of notice of such
meeting, except where a Director attends a meeting for the
express purpose of objecting to the transaction of any busi
ness because the meeting is not lawfully called or convened.
Neither the business to be transacted at, nor the purpose of,
any regular or special meeting of the Board of Directors need
be specified in the notice or waiver of notice of such meet
ing.
SECTION 3.6. QUORUM. - A majority of the number of
Directors fixed by Section 3.2 of this Article III shall
constitute a quorum for the transaction of business at any
meeting of the Board of Directors, but if less than such
majority is present at a meeting, a majority of the Directors
present may adjourn the meeting from time to time without
further notice.
SECTION 3.7. MANNER OF ACTING. - The act of the majority
of the Directors present at a meeting at which a quorum is
present shall be the act of the Board of Directors. A Direc
tor shall be considered present at a meeting of the Board of
Directors or of a committee designated by the Board if the
Director participates in such meeting by conference telephone
or similar communications equipment by means of which all
persons participating in the meeting can hear each other.
SECTION 3.8. INFORMAL ACTION. Any action required or
permitted to be taken at any meeting of the Directors of the
Corporation or of any committee of the Board may be taken
without a meeting if a consent in writing setting forth the
action so taken shall be signed by all of the Directors or all
of the members of the committee of Directors, as the case may
be. Such consent shall have the same force and effect as a
unanimous vote at a meeting and shall be filed with the
Secretary of the Corporation to be included in the official
records of the Corporation.
SECTION 3.9. PRESUMPTION OF ASSENT. - A Director of the
Corporation who is present at a meeting of the Board of
Directors at which action on any corporate matter is taken
shall be presumed to have assented to the action taken unless
(a) the Director objects at the beginning of the meeting or
promptly upon arrival to the holding of or transacting
business at the meeting, (b) the Director's dissent shall be
entered in the minutes of the meeting, or (c) the Director
shall file a written dissent to such action with the person
acting as the secretary of the meeting before the adjournment
thereof or shall forward such dissent by registered or
certified mail to the Secretary of the Corporation immediately
after the adjournment of the meeting. Such right to dissent
shall not apply to a Director who voted in favor of such
action.
SECTION 3.10. VACANCIES. - Any vacancy occurring in the
board of Directors and any directorship to be filled by reason
of an increase in the number of Directors may be filled by the
affirmative vote of a majority of the Directors then in
office, even if less than a quorum of the Board of Directors.
Notwithstanding the foregoing, during the Five Year Period (as
such term is defined in the Agreement and Plan of Merger
between IE Industries Inc. and Iowa Southern Inc. dated
February 27, 1991), if any of the Company Directors (as such
term is defined in the Agreement and Plan of Merger between IE
Industries Inc. and Iowa Southern Inc. dated February 27,
1991) are removed, resign or cease to serve, unless a majority
of the remaining Company Directors elects not to fill such
vacancy or vacancies, then the vacancy or vacancies resulting
therefrom will be filled by a person selected by the Board of
Directors; provided that such person is acceptable to at least
three of the remaining Company Directors as evidenced by such
Company Directors' votes or written consents therefor. A
Director so elected shall be elected for the unexpired term of
the vacant directorship or the full term of such new
directorship. Failure to attend three consecutive regular
meetings of the Board of Directors shall disqualify a Director
from further service as a Director during the year in which
the third delinquency occurs and shall make such Director
ineligible for re-election, unless such failure to attend be
determined by the affirmative vote of two-thirds of the
remaining Directors holding office to be due to circumstances
beyond the control of such Director. A resignation may be
tendered by any Director at any meeting of the shareholders or
of the Board of Directors, who shall at such meeting accept
the same.
SECTION 3.11. COMPENSATION. - The Directors may be paid
their expenses, if any, of attendance at each meeting of the
Board of Directors and may be paid a fixed sum for attendance
at each meeting of the Board of Directors or may receive a
stated salary as Director. No such payment shall preclude any
Director from serving the Corporation in any other capacity
and receiving compensation therefor. Members of special or
standing committees may be allowed like compensation for
attending committee meetings.
SECTION 3.12. EXECUTIVE COMMITTEE. - The Board of
Directors shall, at each annual meeting thereof, appoint from
its number an Executive Committee of not less than three (3)
nor more than five (5) members, including the Chairman of the
Board and the Chief Executive Officer of the Corporation, to
serve, subject to the pleasure of the Board, for the year next
ensuing and until their successors are appointed by the Board.
The Board of Directors at such time shall also fix the compen
sation to be paid to the members of the Executive Committee.
No member of the Executive Committee shall continue to be a
member after ceasing to be a Director of the Corporation. The
Board of Directors shall have the power at any time to in
crease or decrease the number of members of the Executive
Committee, to fill vacancies, to change any member, and to
change the functions or terminate the Committee's existence.
SECTION 3.13. POWERS OF EXECUTIVE COMMITTEE. - The Execu
tive Committee appointed by the Board of Directors as above
provided shall possess all the power and authority of the
Board of Directors when said Board is not in session, but the
Executive Committee shall not have the power to: (1) declare
dividends or distributions, (2) approve or recommend directly
to the shareholders actions required by law to be approved by
shareholders, (3) fill vacancies on the Board of Directors or
designate directors for purposes of proxy solicitation,
(4) amend the Articles, (5) adopt, amend, or repeal Bylaws,
(6) approve a plan of merger not requiring shareholders
approval, (7) authorize reacquisition of shares unless
pursuant to a method specified by the Board, or (8) authorize
the sale or issuance of shares or designate the terms of a
series of a class of shares, except pursuant to a method
specified by the Board, to the extent permitted by law.
SECTION 3.14. PROCEDURE: MEETINGS: QUORUM. - Regular
meetings of the Executive Committee may be held at least once
in each month on such day as the Committee shall elect and
special meetings may be held at such other times as the
Chairman of the Board, the President, or any two members of
the Executive Committee may designate. Notice of special
meetings of the Executive Committee shall be given by letter,
telegram, or cable delivered for transmission not later than
during the second day immediately preceding the day for such
meeting or by word of mouth or telephone not later than the
day immediately preceding the date for such meeting. No such
notice need state the business to be transacted at the meet
ing. No notice need be given of an adjourned meeting. The
Executive Committee may fix its own rules of procedure. It
shall keep a record of its proceedings and shall report these
proceedings to the Board of Directors at the regular meeting
thereof held next after the meeting of the Executive Commit
tee. Attendance at any meeting of the Executive Committee at
a special meeting shall constitute a waiver of notice of such
special meeting.
At its last meeting preceding the annual meeting of the
Board of Directors, the Executive Committee shall make to the
Board its recommendation of officers of the Corporation to be
elected by the Board for the ensuing year.
The Chairman of the Board shall act as Chairman at all
meetings of the Executive Committee, and if the Chairman is
absent, the President shall act as such Chairman. The Secre
tary of the Corporation shall act as Secretary of the meeting.
In case of the absence from any meeting of the Executive
Committee of the Chairman of the Board and the President, or
the Secretary of the Corporation, the Executive Committee
shall appoint a chairman or secretary, as the case may be, of
the meeting. The Executive Committee may hold its meetings
within or without the State of Iowa, as it may from time to
time by resolution determine. A majority of the Executive
Committee shall be necessary to constitute a quorum for the
transaction of any business, and the act of a majority of the
members present at a meeting at which a quorum is present
shall be the act of the Executive Committee. The members of
the Executive Committee shall act only as a committee, and the
individual members shall have no power as such.
SECTION 3.15. OTHER COMMITTEES. - The Board of Directors
may appoint by resolution adopted by a majority of the full
Board of Directors from among its members, other committees,
temporary or permanent, and, to the extent permitted by law
and these Bylaws, may designate the duties, powers, and
authorities of such committees subject to the same restriction
of powers as provided in Section 3.13.
ARTICLE IV
OFFICERS
SECTION 4.1. OFFICERS. - The officers of the
Corporation shall be a Chairman of the Board, a President, a
Secretary and a Treasurer, each of whom shall be elected by
the Board of Directors. Such other officers, including vice
presidents, general counsel and assistant officers as may be
deemed necessary may be elected or appointed by the Board of
Directors. Any two or more of the offices may be held by the
same person if so decided by the Board of Directors.
SECTION 4.2. ELECTION AND TERM OF OFFICE. - The officers
of the Corporation to be elected by the Board of Directors
shall be elected annually by the Board at its annual meeting
held after each annual meeting of the shareholders. If the
election of officers shall not be held at such meeting, such
election shall be held as soon thereafter as may be conve
nient. A vacancy in any office for any reason may be filled
by the Board of Directors for the unexpired portion of the
term.
SECTION 4.3. REMOVAL OF OFFICERS. - Any officer may be
removed by the Board of Directors whenever in its judgment the
best interests of the Corporation will be served thereby, but
such removal shall be without prejudice to the contract
rights, if any, of the person so removed. Election or ap
pointment of an officer shall not of itself create contract
rights.
SECTION 4.4. CHAIRMAN OF THE BOARD. - The Chairman of
the Board shall be the Chief Executive Officer and Chief
Operating Officer of the Corporation, shall preside at all
meetings of the Board of Directors, and shall be a member of
the Executive Committee. The Chairman of the Board shall have
general supervision of and be accountable for the control of
the Corporation's business affairs, properties and management
subject, however, to the control of the Board of Directors and
the Executive Committee. The Chairman of the Board shall see
that all resolutions and orders of the Board of Directors or
Executive Committee are carried into effect and shall exercise
such other powers and perform such other duties as may be
delegated by the Board of Directors and the Executive
Committee.
SECTION 4.5. PRESIDENT. - The President shall have such
powers and perform such duties as the Chairman of the Board,
the Board of Directors or the Executive Committee may from
time to time prescribe or delegate.
SECTION 4.6. VICE-PRESIDENTS. - A Vice President (if one
or more be elected or appointed) shall have such powers and
perform such duties as the Board of Directors may from time to
time prescribe or as the Chairman of the Board or the Presi
dent may from time to time delegate.
SECTION 4.7. TREASURER. - The Treasurer shall have the
custody of the funds and securities of the Corporation.
Whenever necessary or proper, the Treasurer shall (1) endorse,
on behalf of the Corporation, checks, notes or other obliga
tions and deposit the same to the credit of the Corporation in
such bank or banks or depositories as the Board of Directors
may designate; (2) sign receipts or vouchers for payments made
to the Corporation which shall also be signed by such other
officer as may be designated by the Board of Directors;
(3) disburse the funds of the Corporation as may be ordered by
the Board, taking proper vouchers for such disbursements; and
(4) render to the Board of Directors, the Executive Committee,
the Chairman of the Board and the President at the regular
meetings of the Board or Executive Committee, or whenever any
of them may require it, an account of the financial condition
of the Corporation. If required by the Board of Directors,
the Treasurer shall give the Corporation a bond with one or
more sureties satisfactory to the board, for the faithful
performance of the duties of this office, and for the resto
ration to the Corporation, in case of death, resignation,
retirement or removal from office, of all books, papers,
vouchers, money and other property of whatever kind in posses
sion or under control of the Treasurer.
SECTION 4.8. SECRETARY. - The Secretary shall record the
votes and proceedings of the Shareholders, the Board of
Directors and the Executive Committee in a book or books kept
for that purpose, and shall serve notices of and attend all
meetings of the Directors, the Executive Committee and share
holders. In the absence of the Secretary or an Assistant
Secretary from any meeting of the Board of Directors, the
proceedings of such meeting shall be recorded by such other
person as may be appointed for that purpose.
The Secretary shall keep in safe custody the seal of the
Corporation, and duplicates, if any, and when requested by the
Board of Directors, or when any instrument shall have been
first signed by the Chairman of the Board, the President or a
Vice President duly authorized to sign the same, or when
necessary to attest any proceedings of the shareholders or
directors, shall affix it to any instrument requiring the
same, and shall attest the same. The Secretary shall, with
the Chairman of the Board or the President, sign certificates
of stock of the Corporation and affix a seal of the Corpora
tion or cause such seal to be imprinted or engraved thereon,
subject, however, to the provisions providing for the use of
facsimile signatures on stock certificates under certain
conditions. The Secretary shall have charge of such books and
papers as properly belong to such office, or as may be commit
ted to the Secretary's care by the Board of Directors or by
the Executive Committee, and shall perform such other duties
as pertain to such office, or as may be required by the Board
of Directors, the Executive Committee or the Chairman of the
Board.
SECTION 4.9. ASSISTANT TREASURERS. - Each Assistant
Treasurer (if one or more Assistant Treasurers be elected or
appointed) shall assist the Treasurer and shall perform such
other duties as the Board of Directors may from time to time
prescribe or the Chairman of the Board or the President may
from time to time delegate. At the request of the Treasurer,
any Assistant Treasurer may perform temporarily the duties of
Treasurer in the case of the Treasurer's absence or inability
to act. In the case of the death of the Treasurer, or in the
case of absence or inability to act without having designated
an Assistant Treasurer to perform temporarily the duties of
Treasurer, an Assistant Treasurer shall be designated by the
Chairman of the Board or the President to perform the duties
of the Treasurer. Each Assistant Treasurer shall, if required
by the Board of Directors, give the Corporation a bond with
such surety or sureties as may be ordered by the Board of
Directors, for the faithful performance of the duties of such
office and for the restoration to the Corporation, in case of
death, resignation, retirement or removal from office, of all
books, papers, vouchers, money and other property of whatever
kind belonging to the Corporation in the possession or under
control of such Assistant Treasurer.
SECTION 4.10. ASSISTANT SECRETARIES. - Each Assistant
Secretary (if one or more Assistant secretaries be elected or
appointed) shall assist the Secretary and shall perform such
other duties as the Board of Directors may from time to time
prescribe or the Chairman of the Board or the President may
from time to time delegate. At the request of the Secretary,
any Assistant Secretary may perform temporarily the duties of
Secretary in the case of the Secretary's absence or inability
to act. In the case of the death of the Secretary, or in the
case of absence or inability to act without having designated
an Assistant Secretary to perform temporarily the duties of
Secretary, the Assistant Secretary to perform the duties of
the Secretary shall be designated by the Chairman of the Board
or the President.
SECTION 4.11. GENERAL COUNSEL. - The General Counsel
shall be responsible for the management of the Legal
Department in its support of all other operations of the
Corporation including management guidance to assure
responsible decisions, information for all employees
concerning the legal and judicial environment and recommended
changes of law as deemed advisable. In addition, the General
Counsel shall be responsible for the coordination of outside
counsel activities in all instances as well as the prosecution
of charges against the Corporation or other judicial or
regulatory activities. This shall include full information
for the management and employees of judicial, regulatory or
other administrative body rulings and their impact on the
Corporation. The duties shall include approval of all legal
and contractual documents of the Corporation, prior to their
authorization, and full support to various departments to
assist in the development of these documents. The General
Counsel shall perform such other duties as may be assigned
from time to time by the Board of Directors, the Executive
Committee, the Chairman of the Board or the President.
ARTICLE V
CERTIFICATES FOR SHARES AND THEIR TRANSFER
SECTION 5.1. CERTIFICATES FOR SHARES. - Each certificate
representing shares of the Corporation shall state upon the
face (a) that the Corporation is organized under the laws of
the State of Iowa, (b) the name of the person to whom issued,
(c) the number and class of shares, and the designation of the
series, if any, which such certificate represents, and (d) the
par value of each share, if any, and each such certificate
shall otherwise be in such form as shall be determined by the
Board of Directors. Such certificates shall be signed by the
Chairman of the Board or the President and by the Secretary or
an Assistant Secretary and shall be sealed with the corporate
seal or a facsimile thereof. The signatures of such officers
upon a certificate may be facsimiles. If a certificate is
countersigned by a transfer agent, or registered by a
registrar, the signatures of the persons signing for such
transfer agent or registrar also may be facsimiles. In case
any officer or other authorized person who has signed or whose
facsimile signature has been placed upon such certificate for
the Corporation shall have ceased to be such officer or
employee or agent before such certificate is issued, it may be
issued by the Corporation with the same effect as if such
person were an officer or employee or agent at the date of its
issue. Each certificate for shares shall be consecutively
numbered or otherwise identified.
All certificates surrendered to the Corporation for
transfer shall be cancelled and no new certificate shall be
issued until the former certificate for a like number of
shares shall have been surrendered and cancelled, except that
in case of a lost, destroyed or mutilated certificate a new
one may be issued therefor upon such terms and indemnity to
the Corporation as the Board of Directors may prescribe.
SECTION 5.2. TRANSFER OF SHARES. - Transfer of shares of
the Corporation shall be made only on the stock transfer books
of the Corporation by the holder of record thereof or by such
person's legal representative, who shall furnish proper
evidence of authority to transfer, or authorized attorney, by
power of attorney duly executed and filed with the Secretary
of the Corporation, and on surrender for cancellation of the
certificate for such shares.
Subject to the provisions of Section 2.11 of Article II
of these Bylaws, the person in whose name shares stand on the
books of the Corporation shall be treated by the Corporation
as the owner thereof for all purposes, including all rights
deriving from such shares, and the Corporation shall not be
bound to recognize any equitable or other claim to, or inter
est in, such shares or rights deriving from such shares, on
the part of any other person, including (without limitation) a
purchaser, assignee or transferee of such shares, or rights
deriving from such shares, unless and until such purchaser,
assignee, transferee or other person becomes the record holder
of such shares, whether or not the Corporation shall have
either actual or constructive notice of the interest of such
purchaser, assignee, transferee or other person. Except as
provided in said Section 2.11 hereof, no such purchaser,
assignee, transferee or other person shall be entitled to
receive notice of the meetings of shareholders, to vote at
such meetings, to examine the complete record of the share
holders entitled to vote at meetings, or to own, enjoy or
exercise any other property or rights deriving from such
shares against the Corporation, until such purchaser, assign
ee, transferee or other person has become the record holder of
such shares.
ARTICLE VI
MISCELLANEOUS PROVISIONS
SECTION 6.1. INDEMNIFICATION. - The Corporation shall
indemnify its directors, officers, employees and agents to the
full extent permitted by the Iowa Business Corporation Act, as
amended from time to time. The Corporation shall purchase and
maintain insurance on behalf of any person who is or was a
director, officer, employee or agent of the Corporation, or is
or was serving at the request of the Corporation as a direc
tor, officer, employee, or agent of another corporation,
partnership, joint venture, trust, or other enterprise against
any liability asserted against and incurred by such person in
any such capacity or arising out of such person's status as
such, whether or not the Corporation would have the power to
indemnify such person against such liability under the provi
sions of this section.
SECTION 6.2. FISCAL YEAR. - The fiscal year of the
Corporation shall be the calendar year.
SECTION 6.3. SEAL. - The corporate seal shall be circu
lar in form and shall have inscribed thereon the name of the
Corporation and the words "CORPORATE SEAL IOWA". Said seal
may be used by causing it or a facsimile thereof to be im
pressed or affixed or reproduced or otherwise.
SECTION 6.4. CONTRACTS, CHECKS, DRAFTS, LOANS AND
DEPOSITS. - All contracts, checks, drafts or other orders for
the payment of money, notes or other evidences of indebtedness
issued in the name of the Corporation, shall be signed by such
officer or officers, agent or agents of the Corporation and in
such manner as shall from time to time be determined by
resolution of the Board of Directors. The Board may authorize
by resolution any officer or officers to enter into and
execute any contract or instrument of indebtedness in the name
of the Corporation; and such authority may be general or
confined to specific instances. All funds of the Corporation
not otherwise employed shall be deposited from time to time to
the credit of the Corporation in such banks or other deposito
ries as the Board of Directors may authorize.
SECTION 6.5. DIVIDENDS. - Subject to the provisions of
the Articles of Incorporation, the Board of Directors may, at
any regular or special meeting, declare dividends upon the
capital stock of the Corporation payable out of surplus
(whether earned or paid-in) or profits as and when they deem
expedient. Before declaring any dividend there may be set
apart out of surplus or profits such sum or sums as the
directors from time to time in their discretion deem proper
for working capital or as a reserve fund to meet contingencies
or for such other purposes as the directors shall deem condu
cive to the interests of the Corporation.
SECTION 6.6. WAIVER OF NOTICE. - Whenever any notice is
required to be given to any shareholder or Director of the
Corporation under the provisions of these Bylaws or under the
provisions of the Articles of Incorporation or under the
provisions of the Iowa Business Corporation Act, a waiver
thereof in writing signed by the person or persons entitled to
such notice, whether before or after the time stated therein,
shall be deemed equivalent to the giving of such notice.
SECTION 6.7. VOTING OF SHARES OWNED BY THE CORPORATION. -
Subject always to the specific directions of the Board of
Directors, any share or shares of stock issued by any other
corporation and owned or controlled by the Corporation may be
voted at any shareholders' meeting of such other corporation
by the President of the Corporation if present, or if absent
by any other officer of the Corporation who may be present.
Whenever, in the judgment of the President, or if absent, of
any officer, it is desirable for the Corporation to execute a
proxy or give a shareholders' consent in respect to any share
or shares of stock issued by any other corporation and owned
by the Corporation, such proxy or consent shall be executed in
the name of the Corporation by the President or one of the
officers of the Corporation and shall be attested by the
Secretary or an Assistant Secretary of the Corporation without
necessity of any authorization by the Board of Directors. Any
person or persons designated in the manner above stated as the
proxy or proxies of the Corporation shall have full right,
power and authority to vote the share or shares of stock
issued by such other corporation and owned by the Corporation
in the same manner as such share or shares might be voted by
the Corporation.
SECTION 6.8. AMENDMENTS. - These Bylaws may be altered,
amended or repealed and new Bylaws may be adopted by the Board
of Directors at any regular or special meeting of the Board of
Directors.
EXHIBIT 12
IES UTILITIES INC.
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
Year Ended December 31,
1991 1992 1993 1994 1995
(in thousands, except ratio of earnings to fixed charges)
Net income $ 47,563 $ 45,291 $ 67,970 $ 61,210 $ 59,278
Federal and state
income taxes 23,494 20,723 37,963 37,966 41,095
Net income before
income taxes 71,057 66,014 105,933 99,176 100,373
Interest on long-term
debt 31,171 35,689 34,926 37,942 36,375
Other interest 5,595 3,939 5,243 3,630 8,085
Estimated interest
component of rents 6,594 4,567 3,729 3,970 4,637
Fixed charges as defined 43,360 44,195 43,898 45,542 49,097
Earnings as defined $ 114,417 $ 110,209 $ 149,831 $ 144,718 $ 149,470
Ratio of earnings to
fixed charges
(unaudited) 2.64 2.49 3.41 3.18 3.04
For the purposes of computation of these ratios (a) earnings have been
calculated by adding fixed charges and Federal and state income taxes
to net income; (b) fixed charges consist of interest (including amortization
of debt expense, premium and discount) on long-term and other debt and the
estimated interest component of rents.
EXHIBIT 23
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the
incorporation of our report included in the Form 10-K into IES Utilities
Inc.'s previously filed Form S-3 Registration Statement (File No. 33-
62259).
/s/ ARTHUR ANDERSEN LLP
ARTHUR ANDERSEN LLP
Chicago, Illinois
March 7, 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> 56,562
<TOTAL-CURRENT-ASSETS> 111,842
<TOTAL-DEFERRED-CHARGES> 21,268
<OTHER-ASSETS> 207,202
<TOTAL-ASSETS> 1,708,635
<COMMON> 33,427
<CAPITAL-SURPLUS-PAID-IN> 279,042
<RETAINED-EARNINGS> 212,522
<TOTAL-COMMON-STOCKHOLDERS-EQ> 524,991
0
18,320
<LONG-TERM-DEBT-NET> 465,463
<SHORT-TERM-NOTES> 8,888
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 101,000
<LONG-TERM-DEBT-CURRENT-PORT> 15,140
0
<CAPITAL-LEASE-OBLIGATIONS> 21,218
<LEASES-CURRENT> 15,717
<OTHER-ITEMS-CAPITAL-AND-LIAB> 537,898
<TOT-CAPITALIZATION-AND-LIAB> 1,708,635
<GROSS-OPERATING-REVENUE> 709,826
<INCOME-TAX-EXPENSE> 41,095<F1>
<OTHER-OPERATING-EXPENSES> 567,561
<TOTAL-OPERATING-EXPENSES> 567,561<F1>
<OPERATING-INCOME-LOSS> 142,265
<OTHER-INCOME-NET> 2,568
<INCOME-BEFORE-INTEREST-EXPEN> 144,833
<TOTAL-INTEREST-EXPENSE> 44,460
<NET-INCOME> 59,278
914
<EARNINGS-AVAILABLE-FOR-COMM> 58,364
<COMMON-STOCK-DIVIDENDS> 43,000
<TOTAL-INTEREST-ON-BONDS> 35,424
<CASH-FLOW-OPERATIONS> 161,435
<EPS-PRIMARY> 0
<EPS-DILUTED> 0
<FN>
<F1>Income tax expense is not included in Operating Expense in the Consolidated
Statements of Income for IES Utilities Inc.
</FN>
</TABLE>
EXHIBIT 99
IES Utilities Inc. (Utilities) is a wholly-owned subsidiary
of IES Industries Inc. (IES). Substantially all of the
information required for Utilities with respect to Form 10-K
Items 11, 12 and 13 is included in IES' definitive proxy
statement prepared for the 1996 annual meeting of the
shareholders, which will be filed within 120 days of December 31,
1995. Included hereto are drafts of the applicable sections from
the IES' definitive proxy statement.
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 of
(1) 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 current 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 of
(1) 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. 12,775 .04%
James E. Hoffman 0 (2)
G. Sharp Lannom, IV 480 (2)
Lee Liu 38,262 .13%
Rene H. Males 8,980 .03%
Jack R. Newman 0 (2)
Robert D. Ray 1,500 (2)
David Q. Reed 4,002 .01%
Larry D. Root 17,287 .06%
Henry Royer 1,825 (2)
Robert W. Schlutz 1,385 (2)
Anthony R. Weiler 2,251 (2)
All listed Executive 127,412 .43%
Officers and directors
of IES and Utilities as
a group (16 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.
FUNCTIONING OF THE IES BOARD AND COMMITTEES
IES's Board has an Executive Committee, an Audit Committee, a
Nominating Committee and a Compensation Committee.
Current members of the Executive Committee are Lee Liu,
Chairman, C.R.S. Anderson, David Q. Reed and Henry Royer. The
current members served on this Committee during 1995. The
Committee met three times during 1995. It is empowered with all
of the authority vested in the IES Board, subject to certain
limitations, and may act when the IES Board is not in session.
Current members of the Audit Committee are C.R.S. Anderson,
Chairman, J. Wayne Bevis, Robert D. Ray and Robert W. Schlutz.
The current members served on this Committee during 1995. The
Committee met twice during 1995. The principal functions of the
Committee are to review IES's internal audit activities,
including reviews of the internal control procedures; to oversee
the corporate compliance process; to recommend to the IES Board
an independent public accounting firm to be IES's auditors; and
to approve the audit arrangements and audit results. Both the
internal and independent auditors have direct and independent
access to the Audit Committee.
Current members of the Nominating Committee are David Q. Reed,
Chairman, Lee Liu, Robert D. Ray and Anthony R. Weiler. The
current members served on this Committee during 1995. The
Committee met twice during 1995. Its principal function is to
review and recommend to the IES Board nominees to serve on the
IES Board and its committees. While there are no formal
procedures, the Committee considers nominees brought to its
attention by other members of the IES Board, members of
management and shareholders.
Current members of the Compensation Committee are Henry Royer,
Chairman, Dr. George Daly, G. Sharp Lannom, IV and Jack R.
Newman. The current members served on this Committee during 1995.
The Committee met five times during 1995. The principal
functions of the Committee are to review and make recommendations
to the IES Board on the salaries and other compensation and
benefits of the elected officers of IES and its subsidiaries, and
to review and administer incentive compensation or similar plans
for officers and other key employees of IES and its subsidiaries.
The report of the Compensation Committee is included later in
this Joint Proxy Statement/Prospectus.
IES's Board met ten times in 1995. The various committees of
the Board met an aggregate of twelve times. All of the directors
attended 75% or more of these meetings.
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:
SUMMARY COMPENSATION TABLE
Annual Compensation Long-Term
Compensation
Name and Year Salary Bonus Other Restricted All Other
Principal (3) (4) Stock Compensation
Position(1) Awards(5) (6)
Lee Liu 1995 $340,000 $142,800 $1,588 * $ 13,507
Chairman of the 1994 324,375 161,798 1,114 298,127 13,604
Board, 1993 307,450(2) 157,500 1,625 237,341 10,571
President &
Chief Executive
Officer
Blake O. 1995 241,861 76,440 160 - 6,945
Fisher, Jr. 1994 210,060 88,800 160 88,894 7,138
Executive Vice 1993 212,475(2) 81,974 720 74,049 4,392
President &
Chief Financial
Officer
James E. 1995 89,583 206,500 51,523 * 324
Hoffman
Executive Vice
President
Larry D. Root 1995 220,822(2) 62,606 566 - 208,038
Executive Vice 1994 197,765 70,935 483 83,690 7,820
President 1993 200,694(2) 77,176 2,168 69,724 5,948
John F. Franz, 1995 144,050 25,213 418 * 4,893
Jr. 1994 127,379 30,062 57 257,473 1,863
Vice President 1993 114,425 32,577 171 28,634 1,035
Rene H. Males 1995 141,624(2) 38,084 780 - 358,244
Executive Vice 1994 162,750 57,534 1,761 - 4,910
President 1993 179,024(2) 65,100 404 - 25,817
____________________
* 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 nor 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 Estimated Maximum Annual Retirement Benefits Based
Annual Salary on Service Years
(Remuneration)
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 Service Years
Annual
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 supplemental
retirement agreements 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 Service Years
Annual
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 Service Years
Annual
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 90
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.
