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, 1994
OR
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
For the transition period from to
Commission file number 1-9187
IES INDUSTRIES INC.
(Exact name of registrant as specified in its charter)
Iowa 42-1271452
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
IES Tower, Cedar Rapids, Iowa 52401
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code 319-398-4411
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange on
Title of each class which registered
Common Stock, no par value New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark 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.
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
The aggregate market value of the registrant's voting stock
held by non-affiliates, as of February 28, 1995 was
approximately $788,404,517 based upon the Composite Tape
closing price as reported in The Wall Street Journal. (For
this purpose only, the individuals listed under "Security
Ownership of Management" in the Definitive Proxy Statement
incorporated herein by reference are considered to be
affiliates.)
Indicate the number of shares outstanding of each of the
registrant's classes of Common Stock, as of February 28, 1995.
Common Stock, no par value - 28,904,606 shares
Documents Incorporated by Reference
Part of this Form 10-K into
Document Which Document is Incorporated
Definitive proxy statement
as filed on March 20, 1995 III
PART I
Item l. Business
IES Industries Inc.
IES Industries Inc. (Industries) is a holding company
which is incorporated under the laws of Iowa. Industries'
wholly-owned subsidiaries are IES Utilities Inc. (Utilities)
and IES Diversified Inc. (Diversified). Utilities is primarily
an electric and natural gas utility company operating in the
State of Iowa which serves approximately 330,000 electric and
173,000 natural gas retail customers as well as 32 resale
customers in more than 550 Iowa communities. Diversified is a
holding company for subsidiaries engaged in non-utility
operations, including oil and natural gas production and
marketing, independent power generation, railroad and other
transportation businesses in the Midwest and local real estate
development.
Industries' consolidated assets and earnings are
predominantly those of Utilities.
Utilities
Utilities is primarily a public utility operating company
engaged in providing electric energy, natural gas and, to a
limited extent, steam used for heating and industrial
purposes, in the State of Iowa.
Utilities' only wholly-owned subsidiary as of December
31, 1994, was IES Ventures Inc. (Ventures), which is a holding
company for unregulated investments. Ventures' wholly-owned
subsidiary at December 31, 1994, was IES Midland Development
Inc. (Midland), which owns and operates a landfill in Ottumwa,
Iowa. Both Ventures and Midland were formed in December 1994
and neither had any operations in 1994. Ventures also has a
35% equity investment in Aqua Ventures L.C., which is an
aquaculture facility formed to raise fish for human
consumption.
Utilities' sales of electricity (in Kwh), excluding off-
system sales, increased (decreased) 4.3%, 24.9% and (1.5%),
during the years 1994-1992, respectively. The 1994 Kwh sales
were adversely affected by milder than normal weather,
particularly during the summer months. The 1993 increase is
attributable to the acquisition of the Iowa retail service
territory from Union Electric Company (UE) (See Note 2 of the
Notes to Consolidated Financial Statements) and a return to
more normal weather conditions. The 1992 results were
adversely affected by extremely mild weather conditions in
Utilities' service territory. Total gas delivered by
Utilities, including transported volumes, increased
(decreased) (2.7%), 5.3% and (0.3%) during the years
1994-1992, respectively.
The approximate percentages of Utilities' revenue and
operating income before income taxes and interest derived from
the sale of electricity and gas during the years 1994-1992 are
as follows:
1994 1993 1992
Revenues:
Electric 78% 77% 76%
Gas 20 22 23
Operating income before
income taxes and interest:
Electric 93% 90% 91%
Gas 6 10 8
The relationships between the electric and gas
percentages presented above are influenced by changes in
energy sales, timing of rate proceedings and changes in the
costs of fuel or purchased gas billed to customers through
related adjustment clauses.
There are seasonal variations in Utilities' electric and
gas businesses, which are principally related to the use of
energy for air conditioning and heating. In 1994, 40.2% of
Utilities' electric revenues were reported in June through
September, reflecting the use of electricity for cooling, and
60.1% of Utilities' gas revenues were reported in the months
of January, February, March and December, reflecting the use
of gas for heating.
For additional information concerning electric and gas
operations, see Item 1. "Other Information Relating to
Utilities Only", Item 7. "Management's Discussion and Analysis
of the Results of Operations and Financial Condition" and the
Electric and Gas Operating Comparisons.
Terra Comfort Corporation
Terra Comfort Corporation (Terra Comfort), which was a
wholly-owned subsidiary of Diversified and owned combustion
turbines with 114 Mw of capacity, had a contract through 1994
to provide generating capacity to Utilities. Effective
December 31, 1994, all of the assets of Terra Comfort were
sold to Utilities.
Diversified
Other than Utilities' unregulated investments, the non-
utility operations of the Company are organized under
Diversified. Diversified is a holding company whose wholly-
owned subsidiaries include IES Transportation Inc. (IES
Transportation), IES Energy Inc. (IES Energy) and IES
Investments Inc. (IES Investments).
IES Transportation is a holding company whose wholly-
owned subsidiaries at December 31, 1994, included the Cedar
Rapids and Iowa City Railway Company (CRANDIC), IES Railcar
Service Center Inc. (Railcar) and IES Transfer Services Inc.
(Transfer), which was formerly named Port of Cedar Rapids Inc.
CRANDIC is a short-line railway which renders freight service
between Cedar Rapids and Iowa City. Railcar's operations
consist of washing, repairing and painting railcars.
Transfer's operations include transloading and storage
services. IES Transportation has a 75% equity investment in
IEI Barge Services, Inc. (Barge) which provides barge terminal
and hauling service on the Mississippi River. IES
Transportation also has several other equity investments in
transportation related businesses. IES Transportation's 1994
operating revenues and assets at December 31, 1994 were as
follows:
Operating
Revenues Assets
(in 000's)
CRANDIC $ 15,341 $ 26,668
Railcar 4,373 7,301
Barge 1,897 7,996
Transfer 28 873
Other - 1,294
$ 21,639 $ 44,132
IES Energy is a holding company whose wholly-owned
subsidiaries at December 31, 1994, included Industrial Energy
Applications, Inc. (IEA) and Whiting Petroleum Corporation
(Whiting). IEA is involved in developing stand-by production
facilities for large users of electricity and markets natural
gas and steam to end-users. Whiting is organized to purchase,
explore for, develop and produce crude oil and natural gas, in
part through the formation and operation of limited
partnerships. IES Energy's 1994 operating revenues and assets
at December 31, 1994 were as follows:
Operating
Revenues Assets
(in 000's)
IEA $ 32,796 $ 23,709
Whiting 24,573 72,858
Other - 156
$ 57,369 $ 96,723
IES Investments is a holding company whose primary wholly-
owned subsidiaries at December 31, 1994, included Iowa Land
and Building Company (Iowa Land), IES Investco Inc.
(Investco), Southern Iowa Manufacturing Company (SIMCO) and
Village Lakeshares, Inc. (Lakeshares). Iowa Land is organized
to pursue real estate and economic development activities in
Utilities' service territory. Investco is a holding company
for certain equity investments. SIMCO manufactures hydraulic
rotary drill rigs. IES Investments purchased an additional
32.9% equity interest in Lakeshares during 1994, making it a
wholly-owned subsidiary. Lakeshares is a holding company for
resort properties in Iowa.
IES Investments has an equity investment of less than 20%
voting interest in McLeod, Inc., a holding company for various
telecommunications businesses. IES Investments also has
direct and indirect equity interests in various real estate
ventures, primarily concentrated in Cedar Rapids, and holds
other passive investments. IES Investments' 1994 operating
revenues and assets at December 31, 1994 were as follows:
Operating
Revenues Assets
(in 000's)
Iowa Land $ 2,504 $ 10,530
Investco - 3,507
SIMCO 2,650 1,227
Lakeshares 5,641 13,283
Real estate ventures 3,306 23,987
Other 5,085 8,541
$ 19,186 $ 61,075
Other Information Relating to the Company
CONSTRUCTION AND ACQUISITION PROGRAM AND FINANCING. The
capital requirements, including $3.1 million of sinking funds
that may be met by pledging additional utility property, for
the period 1995-1999 are estimated at $1.4 billion and are
summarized as follows:
Capital Requirements
1995 1996 1997 1998 1999
(in thousands)
Construction and
acquisition expenditures -
Electric:
Generation $ 52,687 $ 48,369 $ 47,992 $ 62,484 $ 72,965
Transmission 14,578 30,538 24,393 32,698 30,065
Distribution 37,504 42,910 40,250 40,820 42,525
Other 11,836 13,146 9,810 10,784 10,873
Gas and other 46,559 32,323 23,262 22,971 25,861
Total utility
expenditures 163,164 167,286 145,707 169,757 182,289
Non-utility
expenditures 38,642 62,299 63,707 64,899 44,680
Total construction
and acquisition
expenditures 201,806 229,585 209,414 234,656 226,969
Energy efficiency
expenditures 12,986 13,406 14,474 15,379 14,605
Long-term debt
maturities and
sinking funds:
Utilities 100,920 15,770 8,690 690 50,690
Diversified 80,500 - - - -
Other subsidiaries 282 305 331 357 10,393
181,702 16,075 9,021 1,047 61,083
Total capital
requirements $ 396,494 $ 259,066 $ 232,909 $ 251,082 $ 302,657
The Company intends to refinance the majority of the
debt maturities with long-term securities.
Approximately 34% of Utilities' construction expenditures
are related to generation. Of this amount, approximately 64%
represents capacity expansions and other improvements at
fossil generating stations and 36% represents modifications
and improvements at Utilities' nuclear generating station, the
Duane Arnold Energy Center (DAEC).
Included in non-utility construction and acquisition
expenditures for the five year period 1995-1999 are oil and
gas acquisition expenditures at Whiting of $128 million and
anticipated expenditures for energy-related business
expansions of $120 million.
For a discussion regarding the Company's assumptions in
financing future capital requirements, see the "Liquidity and
Capital Resources" section of Item 7. "Management's Discussion
and Analysis of the Results of Operations and Financial
Condition."
REGULATION. Because of its ownership of Utilities,
Industries is a "holding company" as defined by the Public
Utility Holding Company Act of 1935 (PUHCA). However,
Industries claims exemption from regulation under the PUHCA
(except for Section 9(a)2 thereof, which requires that any
acquisition of securities of a utility company by Industries
be approved by the Securities and Exchange Commission) on the
basis that Industries and Utilities are both organized in the
same state and Utilities conducts its business in that state.
Utilities operates pursuant to the laws of the State of
Iowa and is thereby subject to the jurisdiction of the Iowa
Utilities Board (IUB). The IUB has authority to regulate
rates and standards of service, to prescribe accounting
requirements and to approve the location and construction of
electric generating facilities having a capacity in excess of
25,000 Kw. The IUB is comprised of three Commissioners
appointed by the Governor and ratified by the State Senate.
Requests for rate relief are based on historical test periods,
adjusted for certain known and measurable changes. The IUB
must decide on requests for rate relief within 10 months of
the date of the application for which relief is filed or the
interim rates granted become permanent. Interim rates, if
allowed, are permitted to become effective, subject to refund,
no later than 90 days after the rate increase application is
filed.
In Iowa, non-exclusive franchises, which cover the use of
streets and alleys for public utility facilities in
incorporated communities, are granted for a maximum of
twenty-five years by a majority vote of local qualified
residents. In addition, the IUB defines the boundaries of
mutually exclusive service territories for all electric
utilities. The IUB has jurisdiction and grants franchises for
the use of public highway rights-of-way for electric and gas
facilities outside corporate limits.
Utilities is subject to the jurisdiction of the Federal
Energy Regulatory Commission (FERC) with respect to wholesale
electric sales and the issuance of securities. Revenues
derived from Utilities' wholesale and off-system sales
amounted to 6.9%, 9.0% and 10.1% of electric revenues for 1994-
1992, respectively. The 1994 decrease is primarily the result
of lower off-system sales to other utilities. Utilities'
consolidated subsidiaries are not subject to regulation by the
IUB or the FERC.
EMPLOYEES. At December 31, 1994, the Company had a total
of 2,763 (2,248 at Utilities) regular full-time employees. At
December 31, 1994, Utilities had 1,124 employees subject to
six collective bargaining arrangements, CRANDIC had 59
employees subject to four collective bargaining arrangements,
Railcar had 63 employees subject to one collective bargaining
arrangement and Barge had nine employees subject to one
collective bargaining arrangement.
ENVIRONMENTAL MATTERS. The Company is regulated in
environmental protection matters by a number of Federal, state
and local agencies. Such regulations are the result of a
number of environmental protection laws passed by the U. S.
Congress, state legislature and local governments and enforced
by Federal, state and county agencies. The laws impacting the
Company's operations include the Clean Water Act; Clean Air
Act, as amended by the Clean Air Act Amendments of 1990;
National Environmental Policy Act; Resource Conservation and
Recovery Act; Comprehensive Environmental Response,
Compensation and Liability Act of 1980 (CERCLA), as amended by
the Superfund Amendments and Reauthorization Act of 1986;
Occupational Safety and Health Act; National Energy Policy Act
of 1992 and a number of others.
The Company regularly secures and renews Federal, state
and local permits to comply with the environmental protection
laws and regulations. Costs associated with such compliances
have increased in recent years and are expected to increase
moderately in the future. The Clean Air Act Amendments of
1990 calls for significant reductions in sulfur dioxide and
nitrogen oxide air emissions. The majority of such reductions
will be required from utilities. It is anticipated that any
costs incurred by Utilities will be recovered from its
ratepayers under current regulatory principles. Refer to
Notes 12(a) and 12(g) of the Notes to Consolidated Financial
Statements for additional information regarding Utilities'
expected capital expenditures.
In January 1995, Utilities received an Administrative
Compliance Order (ACO) from the United States Environmental
Protection Agency (EPA) alleging noncompliance and requiring
Utilities to satisfy certain monitoring, reporting, and
recordkeeping requirements of the Acid Rain Program at its
Phase II units. Utilities has since notified EPA that it is
currently in compliance with the specified requirements. EPA
has indicated that it is considering issuing an Administrative
Penalty Order to address the alleged noncompliance.
Management believes that any penalties incurred by Utilities
would not have a material adverse effect on its financial
position or results of operations.
At December 31, 1994, the Company had recorded
$44 million of environmental liabilities ($43 million at
Utilities), which, pursuant to generally accepted accounting
principles, represents either the best current estimate or the
minimum amount of the estimated range of such costs which the
Company expects to incur, depending on the information known
for each site. These estimates are subject to continuing
review and could ultimately exceed the recorded amounts.
Utilities has been named as a Potentially Responsible
Party (PRP) for certain former manufactured gas plant (FMGP)
sites by either the Iowa Department of Natural Resources
(IDNR), the Minnesota Pollution Control Agency (MPCA) or the
EPA. Utilities is working with the IDNR, MPCA and EPA to
investigate its sites and to determine the appropriate
remediation activities that may be needed to mitigate health
and environmental concerns.
Utilities is investigating the possibility of insurance
and third party cost sharing for FMGP clean-up costs. The
amount of shared costs, if any, cannot be reasonably
determined and, accordingly, no potential sharing has been
recorded at December 31, 1994. Considering the rate treatment
allowed by the IUB, management believes that the clean-up
costs incurred by Utilities for these FMGP sites will not have
a material adverse effect on its financial position or results
of operations. Refer to Note 12(f) of the Notes to
Consolidated Financial Statements for more information.
The Nuclear Waste Policy Act of 1982 assigned
responsibility to the U.S. Department of Energy (DOE) to
establish a facility for the ultimate disposition of high
level waste and spent nuclear fuel and authorized the DOE to
enter into contracts with parties for the disposal of such
material beginning in January 1998. Utilities entered into
such a contract and has made the agreed payments to DOE. The
DOE, however, has experienced significant delays in its
efforts and material acceptance is now expected to occur no
earlier than 2010. 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, pursuing other off-site storage and supporting
legislation 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, 1994, Utilities has prepaid costs of
approximately $1 million to the Compact for the building of
such a facility. Currently, Utilities is storing its low-
level radioactive waste generated at the DAEC on-site until
new disposal arrangements are finalized among the Compact
members. A Compact disposal facility is anticipated to be in
operation in approximately ten years. 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.
Utilities was notified in 1986 by the EPA of its
investigation and potential corrective action for the control
of releases and threatened releases of hazardous substances at
the Maxey Flats Nuclear Disposal site at Morehead, Kentucky.
The EPA action is being taken pursuant to CERCLA, and under
such act Utilities has been designated as a PRP (there are 832
in total) as defined under CERCLA. The EPA notice encouraged
all PRP's to undertake voluntary clean-up activities at the
site. A Steering Committee has been organized and Utilities
is participating in its activities. Low-level radioactive
wastes were the only materials contributed to the site by
Utilities. Such contributions comprise only 0.28% of the
total volumes deposited by all contributors. The Steering
Committee is nearing settlement of the issues with the EPA,
the State of Kentucky and deminimis parties. Proposed Consent
Decrees are currently being reviewed and, once executed, will
be submitted to the court for approval.
The environmental concern is that a release of hazardous
substances has occurred at the Maxey Flats site and that such
release may pose an environmental threat to local surface
waters, ground waters, wells and landowners. Utilities'
portion of the costs of the remedial activities, including the
ultimate clean-up, are currently estimated at $275,000 which
is included in the $44 million of environmental liabilities
the Company has recorded at December 31, 1994. Utilities has
notified its nuclear insurance carriers of the proceedings.
The possibility that exposure to electric and magnetic
fields emanating from power lines, household appliances and
other electric sources may result in adverse health effects
has been the subject of increased public, governmental and
media attention. A considerable amount of scientific research
has been conducted on this topic without definitive results.
Research is continuing in order to resolve scientific
uncertainties.
Whiting is responsible for certain dismantlement and
abandonment costs related to various off-shore oil and gas
properties, the most significant of which is located off the
coast of California. Whiting accrues these costs as reserves
are extracted and such costs are included in "Depreciation and
amortization" in the Consolidated Statements of Income. A
corresponding environmental liability, $0.1 million at
December 31, 1994, has been recognized in the Consolidated
Balance Sheets for the cumulative amount expensed.
Refer to Note 12 of the Notes to Consolidated Financial
Statements and Item 7. "Management's Discussion and Analysis
of the Results of Operations and Financial Condition" for
further discussion of environmental matters.
Other Information Relating to Utilities Only
RATE MATTERS. Refer to Note 3 of the Notes to
Consolidated Financial Statements for a discussion of
Utilities' rate matters.
ELECTRIC OPERATIONS. Utilities' net peak load (60
minutes integrated) of 1,779,627 kilowatts occurred on June
17, 1994. At the time of the peak load, no interruptible
customers were interrupted, however, 7,210 residential air
conditioning cycling customers were interrupted. The total
kilowatts interrupted was 5,840 of a possible 318,102
kilowatts available for interruption. Utilities' additional
reserve obligation at that time was 226,744 kilowatts. The
net capability of Utilities' generating stations at the time
of this peak load was 1,741,100 kilowatts, with an additional
280,000 kilowatts being available under purchase contracts,
thereby providing an aggregate capability of 2,021,100
kilowatts.
Utilities projects an electric sales growth rate of 2.0
to 2.5 percent per year over the next decade, which will be
met by a mix of its existing generation, capacity purchases
and new construction. The construction activities will be
undertaken in a fashion that best meets the needs of
individual customers and the system as a whole. See Note
12(b) of the Notes to Consolidated Financial Statements for a
discussion of Utilities' firm contracts for the purchase of
capacity.
Utilities is interconnected with other utilities in Iowa
and neighboring states and is a member of the Mid-Continent
Area Power Pool (MAPP). MAPP's purpose is to coordinate the
planning, construction and operation of generation and
transmission facilities, and the purchase and sale of power
and energy among its members.
In addition, Utilities, Midwest Power Systems Inc.
(Midwest) and Iowa-Illinois Gas and Electric Company (Iowa-
Illinois) are partners in ENEREX, a general partnership formed
to operate a common control system for dispatching
electricity. Through ENEREX, the most efficient electric
generating plants are used to meet the combined electric needs
of the customers of all of the partners. The ENEREX control
center recommends the specific generating units to be operated
each day in order to provide the most economical and efficient
use of such units at any particular time. The partnership is
being dissolved on June 30, 1995, due to the pending merger of
Midwest and Iowa-Illinois. After that time, there would only
be two members in the partnership, thus the diversity and
savings available would no longer justify the existence of the
partnership.
Utilities is a party to the Twin Cities-Iowa-St. Louis
345 Kv Interconnection Coordinating Agreement (the
Coordinating Agreement) with five other midwestern utilities,
three of which operate in the State of Iowa. The Coordinating
Agreement provides for the interconnection of the respective
systems of the companies through a 345 Kv transmission line
and for the interchange of power on various bases. The rates
under the Coordinating Agreement are primarily determined by
agreement between the delivering and receiving companies.
Utilities maintains and operates transmission and
substation facilities connecting with its high voltage
transmission systems pursuant to a non-cancellable operating
agreement (the Operating Agreement) with Central Iowa Power
Cooperative (CIPCO). The Operating Agreement, which will
terminate on December 31, 2035, provides for the joint use of
certain transmission facilities of Utilities and CIPCO.
For comments relating to agreements between Utilities and
its partners for the joint ownership of the DAEC, the Ottumwa
Generating Station (OGS), and Neal Unit No. 3, see Item 2.
"Properties" and Note 13 of the Notes to Consolidated
Financial Statements.
FUEL SUPPLY. The following table details the sources of
the electricity sold by Utilities during 1994 and expected
sources for the following three years:
Actual /-------- Expected --------/
1994 1995 1996 1997
Fossil, primarily coal 50% 61% 60% 60%
Nuclear 26 23 22 26
Purchases 24 16 18 14
100% 100% 100% 100%
The above percentages assume nuclear refueling outages
will occur during both 1995 and 1996. There was no refueling
outage in 1994. The 1994 purchases include purchases by
Utilities from Terra Comfort. The increase in the expected
fossil percentages from the 1994 actual is a function of lower
projected fuel costs for 1995-1997 as well as the timing of
the nuclear refueling outages. In addition, Utilities
anticipates the availability and efficiency of its fossil
generating stations to be greater in 1995-1997 due to capacity
improvements made at certain stations in recent years.
Utilities' primary fuel source is coal and the generation
mix is influenced directly by refueling outages at the DAEC.
The average cost of fuel used for generation by Utilities for
the years 1994-1992 is presented below:
1994 1993 1992
Average cost of fuel:
Nuclear, per million Btu's $ .67 $ .60 $ .55
Coal, per million Btu's .97 .97 1.08
Average for all fuels,
per million Btu's .89 .90 .93
The following table summarizes Utilities' minimum coal
contract commitments:
Average
Annual Maximum estimated base price
Quantity Termination Sulfur per ton of coal delivered
(Tons) Date Content 1995 1996 1997
Cordero Mining Co.
(OGS) (1) 780,571 12/31/01 0.6% $ 17.24 $ 17.76 $ 18.29
Koch Carbon Inc.
(Sutherland) 100,000 12/31/99 6.2% $ 19.23 $ 19.51 $ 19.77
Caballo Coal Co.
(OGS or
BGS) (2) 1,200,000 12/31/97 0.4% $ 12.41 $ 12.80 $ 13.19
Thunder Basin
(Sutherland) 320,000 12/31/96 0.3% $ 13.63 $ 13.95 $ N/A
Caballo Rojo
(BGS) 200,000 12/31/96 0.3% $ 14.83 $ 15.18 $ N/A
Caballo Rojo (3) 640,000 12/31/96 0.3% $ 16.17 $ 16.56 $ N/A
Short-term
contracts
(BGS) 27,000 04/30/95 1.0% $ 22.50 $ N/A $ N/A
(1) Cost under the contracts 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 to 1,550,000
annual tons delivered to either OGS or Burlington
Generating Station (BGS). The prices listed in the
table are for OGS; the BGS delivered price would be
slightly higher.
(3) Coal may be delivered to either Prairie Creek
Station or Sixth Street Station. The prices listed
in the table are for Prairie Creek; the Sixth Street
delivered price would be slightly higher.
During 1994, Utilities purchased a total of 3,761,000
tons of coal for its generating plants. At December 31, 1994,
Utilities had coal inventory at its principal generating
stations ranging from 58 to 119 days' usage during high demand
periods or a weighted average of 70 days' usage.
Utilities estimates that its existing coal fired
generating units will require approximately 13,292,000 tons of
coal to operate during the period 1995-1997. Utilities
believes that an ample supply of coal is available in the spot
market and intends to purchase such coal as necessary to
supplement its coal supply contracts and meet its generation
requirements.
Some of Utilities' contracted coal supply is provided by
surface mining operations which are regulated by the Federal
Strip Mine Act. Most of the surface mining coal contracts
contain clauses which pass reclamation and royalty costs
through to the respective utility; such costs billed to
Utilities are recoverable through its Energy Adjustment
Clauses (EAC). See Note 1(k) of the Notes to Consolidated
Financial Statements for discussion of the EAC.
Utilities has purchased a supply of UF6 pursuant to a
contract with Eldorado, Ltd. of Canada which, along with
previously purchased and contracted amounts, will provide
Utilities with sufficient UF6 to cover its needs through the
1995 refueling. Such uranium is being held without charge by
the United States Department of Energy (DOE) under a usage
agreement between the DOE and Utilities, which allows
Utilities to retrieve the material as needed. Bids are
currently being evaluated for purchase of additional uranium.
Enrichment services are being provided by the United States
Enrichment Corporation (USEC) under a contract which extends
to the year 2014 or the retirement of the plant, whichever
occurs first. Under provisions of that contract, Utilities is
exploring possibilities of obtaining lower cost enrichment
from non-USEC sources. Fabrication of the nuclear fuel is
being performed by General Electric Company for fuel through
the 2008 refueling of the DAEC. See Note 12(f) of the Notes
to Consolidated Financial Statements for a discussion of
Utilities' assessment under the National Energy Policy Act of
1992 for the "Uranium Enrichment Decontamination and
Decommissioning Fund," which is based upon prior nuclear fuel
purchases.
Refer to Item 1. "Environmental Matters" for a discussion
of nuclear waste disposal issues.
GAS OPERATIONS. With the advent of FERC Order 636 (Order
636), issued in 1992, the nature of Utilities' gas supply
portfolio has changed. Traditionally, Utilities' natural gas
was supplied by the following interstate pipelines - Northern
Natural Gas Company (Northern), Natural Gas Pipeline Company
of America (Natural) and ANR Pipeline Company (ANR). These
pipelines were obligated to supply natural gas to Utilities
under peak day conditions up to pre-determined contract
levels. Order 636, among other things, eliminated the
interstate pipelines obligation to serve and now requires
Utilities to purchase virtually 100% of its gas supply
requirements from non-pipeline suppliers.
Order 636, as modified on rehearing: 1) requires
Utilities' pipeline suppliers to unbundle their services so
that gas supplies are obtained separately from transportation
service, and transportation and storage services are operated
and billed as separate and distinct services; 2) requires the
pipeline suppliers to offer "no notice" transportation service
under which firm transporters (such as Utilities) can receive
delivery of gas up to their contractual capacity level on any
day without prior scheduling; 3) allows pipelines to abandon
long-term (one year or more) transportation service provided
to a customer under an expiring contract whenever the customer
fails to match the highest rate and longest term (up to 20
years) offered to the pipeline by other customers for the
particular capacity; and 4) provides for a mechanism under
which pipelines can recover prudently incurred transition
costs associated with the restructuring process. Utilities
has enhanced access to competitively priced gas supply and
more flexible transportation services as a result of Order
636. However, under Order 636, Utilities is required to pay
certain transition costs incurred and billed by its pipeline
suppliers.
Utilities' three pipeline suppliers have made filings
with the FERC to begin collecting their respective transition
costs, and additional filings are expected. Utilities began
paying the transition costs in 1993, and, at December 31,
1994, has recorded a liability of $8.0 million for those
transition costs that have been incurred by the pipelines to
date, including $3.0 million expected to be billed through
1995. 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 $10
million. The ultimate level of costs to be billed to
Utilities depends on the pipelines' filings with the FERC and
other future events, including the market price of natural
gas. However, Utilities believes any transition costs that the
FERC would allow the pipelines to collect from Utilities would
be recovered from its customers, based upon regulatory
treatment of these costs currently and similar past costs by
the IUB. Accordingly, regulatory assets, in amounts
corresponding to the recorded liabilities, have been recorded
to reflect the anticipated recovery.
Contracts with the pipelines subsequent to Order 636 are
comprised primarily of firm transportation, firm storage and
no-notice service. Firm transportation contracts grant
Utilities access to firm pipeline capacity which is used to
transport gas supplies from non-pipeline suppliers on peak
day. Firm storage service allows Utilities to purchase gas
during off-peak periods and place this gas in an account with
the pipelines. When the gas is needed for peak day
deliveries, Utilities requests and the pipelines deliver the
gas back on a firm basis. No-notice service is a new service
offered as a result of Order 636. No-notice service grants
Utilities the right to take more or less gas than is actually
nominated up to the level of no-notice service. No-notice
service takes the form of transportation balancing or storage
service depending on the pipeline.
Utilities' portfolio of firm transportation, firm storage
and no-notice service from pipelines is as follows:
Firm Firm
Transportation Storage No-Notice
Northern:
Volume (Dth/day) 140,996 48,218 10,000
Expiration date 10/31/97 10/31/97 10/31/97
Natural:
Volume (Dth/day) 28,605 37,467 10,000
Expiration date 11/30/2000 11/30/95 11/30/95
ANR:
Volume (Dth/day) 60,737 19,180 5,000
Expiration date 10/31/2003 10/31/2003 10/31/2003
In addition to firm storage with pipelines, Utilities
also contracts for firm storage from Llano, Inc. This
contract calls for peak day deliveries of 18,667 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 1994, Utilities' maximum daily load
occurred on January 17, 1995, with total system flow of
approximately 289,000 dekatherms, including transported
volumes, and total contract availability of approximately
276,000 dekatherms.
As a result of Order 636, Utilities accepted assignment
of certain gas supply contracts previously held by Northern.
Accepting assignment of these contracts resulted in lower
costs to Utilities than would have been incurred had Northern
bought out the agreements and billed Utilities for its share
of such costs.
Contracts assigned to Utilities from Northern have
maximum delivery requirements of 23,147 Dth, and minimum take
requirements of 5,851 Dth, under contracts with remaining
lengths of up to six years.
Additional firm gas supply agreements were independently
negotiated by Utilities. These gas supply agreements have
maximum and minimum obligations as follows:
Maximum Minimum
Daily Quantity Daily Quantity
(Dth/day) (Dth/day)
Northern 55,410 29,983
Natural 21,575 18,812
ANR 25,000 18,500
These gas supply contracts have expiration dates ranging
from five months to five years.
Rates charged by Utilities' pipeline suppliers are
subject to regulation by the FERC. A purchased gas adjustment
clause (PGA) allows Utilities to adjust customer rates as a
result of changes in the cost of gas purchased. See Note 1(k)
of the Notes to Consolidated Financial Statements for
discussion of the PGA.
NUCLEAR REGULATORY COMMISSION (NRC) AND OTHER NUCLEAR
MATTERS. As an owner and the operator of a nuclear generating
unit at the DAEC, Utilities is subject to the jurisdiction of
the NRC. The NRC has broad supervisory and regulatory
jurisdiction over the construction and operation of nuclear
reactors, particularly with regard to public health, safety
and environmental considerations.
The operation and design of nuclear power plants is under
constant review by the NRC. Utilities has complied with and
is currently complying with all NRC requests for data relating
to these reviews. As a result of such reviews, further
changes in operations or modifications of equipment may be
required, the cost of which cannot currently be estimated.
Utilities will be conducting an inspection during the
1995 refueling outage of the DAEC reactor core internals.
This is in response to cracking identified in similar
reactors. If cracking is identified, repairs will be
completed either at the time discovered or during the 1996
refueling outage depending upon the type of repair required.
It is estimated that such repairs, if necessary, would cost
approximately $3.0 million.
The large amount of change in regulations, designs and
procedures that occur for a nuclear power plant over a period
of time presents a difficult task to ensure that all affected
design information documents, procedures and specifications
are continually updated. Utilities has developed a
Configuration Management Plan and a Design Basis Program which
are designed to coordinate control of the updating and
maintenance of plant documents to ensure regulatory
requirements are met. The first phase of this effort has been
completed and work is now under way on the second phase.
Through 1994, $4.3 million had been spent on the second phase.
It is expected that an additional $1.1 million will be
expended through 1996.
The NRC has expressed concern to licensees over use of
thermolag fire proofing material in nuclear power plants.
Utilities has spent $0.7 million through 1994 and anticipates
spending an additional $1.0 million through 1997 to identify
and resolve deficiencies.
Under the Price-Anderson Amendments Act of 1988 (1988
Act), Utilities currently has the benefit of $8.9 billion of
public liability coverage which would compensate the public in
the event of an accident at a commercial nuclear power plant.
The 1988 Act permits such coverage to rise with increased
availability of nuclear insurance and the changing number of
operating nuclear plants subject to retroactive premium
assessments. The 1988 Act provides for inflation indexing
(Consumer Price Index every fifth year) of the retroactive
premium assessments.
As an outgrowth of the Three Mile Island Nuclear Power
Plant (TMI) experience, nuclear plant owners have initiated a
cooperative insurance program designed to help cover
replacement power expenses for participating utilities arising
from a possible nuclear plant accident. Utilities is a
participant in this program. This type of insurance is an
industry response intended to lessen the cost burden on
customers in the event of a lengthy plant shutdown.
To provide this coverage, a nuclear utility mutual
insurance company known as Nuclear Electric Insurance Limited
(NEIL) was formed. Under Utilities' policy, following a 21
week waiting period from the time of an accident, coverage of
up to 100% of estimated replacement power costs for an ensuing
one year period is provided and up to 80% of that amount will
be provided for a second and third year. The annual premium
cost to Utilities is estimated to be less than the cost of
replacement power for one week.
Utilities currently carries primary property insurance
coverage on the DAEC facility of $500 million with the Nuclear
Insurance Pools (American Nuclear Insurers and Mutual Atomic
Energy Liability Underwriters). Following the TMI incident,
it became apparent to nuclear plant owners that the
commercially available property insurance was inadequate
considering the cost of decontamination. Consequently,
Utilities obtained excess property insurance through the
Nuclear Insurance Pools and NEIL as it became available. The
Nuclear Insurance Pools excess insurance now provides
$850 million of coverage after losses exceed $500 million.
The NEIL excess insurance provides an additional $1.4 billion
of coverage after losses exceed $1.35 billion. These policies
bring the total property coverage to $2.75 billion. The NEIL
policy limits include $250 million for premature
decommissioning.
For information concerning the potential assessment of
retroactive premiums relating to the above described public
liability, replacement power and excess property insurance
coverages, refer to Note 12(e) of the Notes to Consolidated
Financial Statements. The NRC established requirements with
respect to guaranteeing the ability of owners to make such
retroactive payments on the public liability policy. Of the
various alternatives available, Utilities elected to submit
certified financial statements showing that sufficient cash
flow could be generated and would be available for payment of
the required assessments within a three month period. The
maximum of the annual retroactive premiums was approximately
$7 million at December 31, 1994.
The NRC has a backlog of generic and unresolved safety
issues which it is currently studying. Resolution of such
issues may require additional modifications to the DAEC.
Refer to Item 1. "Environmental Matters" for a discussion
of nuclear waste disposal issues.
NATIONAL ENERGY POLICY ACT. In 1992, the National Energy
Policy Act of 1992 (Energy Act) was enacted. In addition to
the assessments for the Uranium Enrichment Decontamination and
Decommissioning Fund discussed in Note 12(f) of the Notes to
Consolidated Financial Statements, the Energy Act addresses a
wide range of energy issues. Title VII of the Energy Act
creates exemptions from regulation under PUHCA and creates a
class of exempt wholesale generators consisting of utility
affiliates and nonutilities that are owners and operators of
facilities for the generation and transmission of power for
wholesale sales. In addition, PUHCA has been amended to allow
utilities to compete on a global scale with foreign entities
to own and operate generation, transmission and distribution
facilities. The Energy Act also gives FERC the authority to
order investor owned utilities to transmit power and energy to
or for wholesale purchasers and sellers. FERC may also
require electric utilities to increase their transmission
capacity to provide these services. The new law creates the
potential for electric utilities and other power producers to
gain increased access to the transmission systems of other
entities to facilitate wholesale sales.
The IUB has initiated a Notice of Inquiry (Docket No. NOI-
95-1) on the subject of "Emerging Competition in the Electric
Utility Industry." The purpose is to address all forms of
competition in the electric utility industry and to gather
information and perspectives on electric competition from all
persons and entities with an interest or stake in the issues.
Informal discussions among the parties will be held. Such
discussions are not expected to produce any specific actions
by the IUB at this time. The Company is unable to predict the
ultimate impact the Energy Act or the IUB's Notice of Inquiry
will have on its operations.
See Item 7. "Management's Discussion and Analysis of the
Results of Operations and Financial Condition" for more
information.
ELECTRIC OPERATING COMPARISON
FIVE-YEAR
COMPOUND
RATE OF
1994 1993 1992 1991 1990 1989 GROWTH (1)
Operating revenue (000's):
Residential and Rural $ 200,629 $ 206,561 $ 177,625 $ 189,194 $ 185,302 $ 175,899
Commercial 146,086 145,898 124,829 124,320 119,908 112,662
Industrial 143,944 137,595 103,886 100,733 97,788 94,222
Street lighting and public
authorities 6,504 6,098 5,410 6,332 6,478 6,282
Total from ultimate
consumers 497,163 496,152 411,750 420,579 409,476 389,065
Sales for resale 19,195 20,254 18,602 19,745 19,582 18,214
Off-system 18,077 29,400 28,304 36,596 31,144 28,281
Other 2,892 4,715 4,343 5,658 3,047 2,973
$ 537,327 $ 550,521 $ 462,999 $ 482,578 $ 463,249 $ 438,533
Energy sales (000's Kwh):
Residential and Rural 2,493,702 2,528,220 2,158,768 2,367,979 2,254,913 2,222,152 2.3%
Commercial 2,148,302 2,078,635 1,771,357 1,764,495 1,686,132 1,626,046 5.7%
Industrial 4,014,821 3,674,217 2,612,803 2,467,533 2,312,109 2,236,388 12.4%
Street lighting and public
authorities 67,029 63,174 60,991 87,022 88,305 86,635 -5.0%
Total to ultimate consumers 8,723,854 8,344,246 6,603,919 6,687,029 6,341,459 6,171,221 7.2%
Sales for resale 567,721 561,276 528,752 557,180 538,677 500,253 2.6%
Sales of electricity to
customers 9,291,575 8,905,522 7,132,671 7,244,209 6,880,136 6,671,474 6.8%
Off-system 1,137,219 2,068,015 2,275,616 2,738,159 2,282,204 1,959,828 -10.3%
10,428,794 10,973,537 9,408,287 9,982,368 9,162,340 8,631,302 3.9%
Sources of electric energy (000's Kwh):
Generation:
Fossil, primarily coal 5,522,966 5,356,930 4,317,154 4,758,720 4,354,697 4,063,974
Nuclear (2) 2,875,867 2,264,507 2,402,501 2,902,768 2,108,100 2,228,068
Hydro 8,205 7,201 7,579 6,547 4,195 1,902
8,407,038 7,628,638 6,727,234 7,668,035 6,466,992 6,293,944
Purchases 2,646,673 3,949,296 3,322,182 2,994,216 3,282,886 2,891,808
11,053,711 11,577,934 10,049,416 10,662,251 9,749,878 9,185,752
Net capability at time of peak load (Kw):
Generating capability 1,741,100 1,733,700 1,718,600 1,719,150 1,684,700 1,633,000
Purchase capability 280,000 248,000 207,000 227,000 179,000 170,000
Capacity credits (3) 0 0 0 0 18,960 20,650
2,021,100 1,981,700 1,925,600 1,946,150 1,882,660 1,823,650 2.1%
Net peak load (Kw) (4) 1,779,627 1,716,380 1,425,441 1,607,606 1,547,826 1,486,243 3.7%
Number of customers at year-end 330,405 327,265 325,172 305,663 304,265 302,632 1.8%
Revenue per Kwh (excluding
off-system) in cents 5.59 5.85 6.09 6.16 6.28 6.15 -1.9%
(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.
GAS OPERATING COMPARISON
FIVE-YEAR
COMPOUND
RATE OF
1994 1993 1992 1991 1990 1989 GROWTH
Operating revenue (000's):
IES Utilities Inc.:
Residential $ 82,795 $ 90,462 $ 78,685 $ 74,114 $ 66,513 $ 68,751
Commercial 40,912 45,528 39,780 37,613 35,378 38,035
Industrial 12,515 15,593 18,649 17,383 21,500 25,172
136,222 151,583 137,114 129,110 123,391 131,958
Other 2,811 2,735 2,341 1,908 1,884 1,923
Total revenues 139,033 154,318 139,455 131,018 125,275 133,881
Industrial Energy
Applications, Inc. 26,536 27,605 27,627 15,219 6,808 1,049
$ 165,569 $ 181,923 $ 167,082 $ 146,237 $ 132,083 $ 134,930
Energy sales (000's dekatherms):
IES Utilities Inc.:
Residential 15,766 16,971 15,098 15,571 14,315 15,878 -0.1%
Commercial 9,298 10,133 8,479 9,389 8,798 9,854 -1.2%
Industrial 4,010 4,618 6,175 5,980 6,640 7,409 -11.6%
29,074 31,722 29,752 30,940 29,753 33,141 -2.6%
Industrial - transported
volumes 8,901 7,284 7,283 6,189 6,733 6,909 5.2%
Total volumes delivered 37,975 39,006 37,035 37,129 36,486 40,050 -1.1%
Industrial Energy
Applications, Inc. 14,443 12,493 14,830 7,666 4,465 624 87.5%
52,418 51,499 51,865 44,795 40,951 40,674 5.2%
Operating statistics for IES Utilities Inc.:
Cost per dekatherm of gas
purchased for resale $ 3.31 $ 3.49 $ 3.36 $ 3.10 $ 3.23 $ 2.95
Peak daily sendout in dekatherms 288,352 268,419 254,989 266,344 272,089 311,600 -1.5%
Number of customers at year-end 172,829 170,719 167,813 164,078 161,794 160,792 1.5%
Revenue per dekatherm sold
for IES Utilities Inc.
(excluding transported volumes) $ 4.69 $ 4.78 $ 4.61 $ 4.17 $ 4.15 $ 3.98 3.3%
Item 2. Properties
Industries has no significant properties other than
common stock of affiliates, temporary cash investments and
cash surrender value of corporate life insurance policies.
Utilities' principal electric generating stations at
December 31, 1994, are as follows:
Name and Location Major Fuel Net Kilowatts Accredited
of Station Type Generating Capability
Duane Arnold Energy Center,
Palo, Iowa Nuclear 360,500 (1)
Ottumwa Generating Station,
Ottumwa, Iowa Coal 343,440 (2)
Prairie Creek Station,
Cedar Rapids, Iowa Coal 234,000
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 1,147,440
Peaking Turbines,
Marshalltown, Iowa Oil 156,000
Centerville Combustion Turbines,
Centerville, Iowa Oil 49,000 (4)
Diesel Stations, all in Iowa Oil 12,200
Total Oil 217,200
Grinnell Station, Grinnell, Iowa Gas 47,200
Agency Street Combustion Turbines,
West Burlington, Iowa Gas 65,000 (4)
Burlington Combustion Turbines,
Burlington, Iowa Gas 16,600
Total Gas 128,800
Total generating capability 1,853,940
(1) Represents Utilities' 70% ownership interest in this
515,000 Kw generating station. The plant is
operated by Utilities.
(2) Represents Utilities' 48% ownership interest in this
715,500 Kw generating station. The plant is
operated by Utilities.
(3) Represents Utilities' 28% ownership interest in this
515,000 Kw generating station which is operated by
an unaffiliated utility.
(4) Effective December 31, 1994, all of the assets of
Terra Comfort were sold to Utilities, including the
Centerville and Agency Street Combustion Turbines.
At December 31, 1994, the transmission lines of
Utilities, operating from 34,000 to 345,000 volts,
approximated 4,390 circuit miles (all located in Iowa).
Utilities owned 108 transmission substations (all located in
Iowa) with a total installed capacity of 8,415.7 MVa and 466
distribution substations (all located in Iowa) with a total
installed capacity of 2,545.8 MVa.
Subsidiaries other than Utilities also own property which
primarily represents investments in transportation, oil and
gas and real estate properties.
The Company's principal properties are suitable for their
intended use. Utilities' principal properties are held
subject to liens of indentures relating to its First Mortgage
Bonds.
Item 3. Legal Proceedings
Industries, IES Energy, MicroFuel Corporation (the
Corporation) now known as Ely, Inc. in which IES Energy has a
69.40% equity ownership, and other parties have been sued in
Linn County District Court in Cedar Rapids, Iowa, by Allen C.
Wiley. Mr. Wiley claims money damages on various tort and
contract theories arising out of the 1992 sale of the assets
of the Corporation, of which Mr. Wiley was a director and
shareholder. All of the defendants in Mr. Wiley's suit have
answered the complaint and denied liability. All of the
defendants believe that the claims are without merit and are
vigorously contesting them. The trial has been continued to
an unspecified date, pending a decision in the appeal related
to a separate suit discussed below.
The Corporation commenced a separate suit to determine
the fair value of Mr. Wiley's shares under Iowa Code section
490. A decision was issued on August 31, 1994, by the Linn
County District Court ruling that the value of Mr. Wiley's
shares was $377,600 based on a 40 cent per share valuation.
The Corporation contended that the value of Mr. Wiley's shares
was 2.5 cents per share. The Decision has been appealed to
the Iowa Supreme Court by the Corporation on a number of
issues, including the Corporation's position that the trial
court erred as a matter of law in discounting the testimony of
the Corporation's expert witness. A decision on the appeal is
not expected before the fourth quarter of 1995.
Reference is made to Notes 3 and 12 of the Notes to
Consolidated Financial Statements for a discussion of
Utilities' rate proceedings and environmental matters. Also
see Item 1. "Business - Environmental Matters" and Item 7.
"Management's Discussion and Analysis of the Results of
Operations and Financial Condition."
Item 4. Submission of Matters to a Vote of Security Holders
None.
PART II
Item 5. Market for the Registrant's Common Stock and Related
Stockholder Matters
(a) Price Range of Common Stock and Dividends
Declared
IES Industries Common Stock is listed on the New York
Stock Exchange (NYSE) under the symbol "IES." The table below
sets forth, for the calendar quarters indicated, the reported
high and low sales prices of IES Industries Common Stock as
reported on the NYSE Composite Tape based on published
financial sources, and the dividends declared per share on IES
Industries Common Stock.
IES Industries Common Stock
High Sale Low Sale Dividend (i)
1994
First Quarter $ 31 3/8 $ 27 $ .525
Second Quarter 29 25 1/2 .525
Third Quarter 28 3/8 24 7/8 .525
Fourth Quarter 26 5/8 24 3/4 .525
1993
First Quarter 31 1/8 28 3/8 .525
Second Quarter 32 5/8 28 5/8 .525
Third Quarter 34 1/4 31 1/4 .525
Fourth Quarter 34 29 1/8 .525
(i) The Company has paid regular quarterly
dividends on its common stock since April 1, 1950.
Although the Company's practice has been to pay
dividends quarterly, the time of payment and amount
of future dividends are necessarily dependent upon
earnings, financial requirements and other factors.
(b) Approximate Number of Equity Security Holders
Approximate Number of Record
Title of Class Holders (as of December 31, 1994)
Common Stock, no par value 32,567
(c) Restriction on Payment of Dividends
Under terms of the Fifty-fifth and Fifty-sixth
Supplemental Indentures relating to Utilities' Series W and
Series X First Mortgage Bonds, Utilities agreed that no cash
dividends shall be paid or declared, nor shall any
distribution be made on any capital stock, nor shall any
shares of such stock be purchased, redeemed or otherwise
acquired for any consideration by Utilities or any subsidiary
of Utilities, if after immediately giving effect to such
payment, distribution or retirements, (A) the principal amount
of all outstanding defined Unsecured Indebtedness of Utilities
exceeds 20% of defined Total Capitalization, or (B) the
aggregate amount of all such payments, distributions and
retirements made since December 31, 1987, exceeds net income
of Utilities since December 31, 1987, plus $50,000,000.
Pursuant to these terms, at December 31, 1994, $18,209,000 of
Utilities' retained earnings was restricted as to the payment
of cash dividends. Utilities may periodically pay cash
dividends on any shares of its preferred or preference stock
at any time issued and outstanding, provided that all such
payments shall be included in the above payments as determined
since December 31, 1987.
The Series W and Series X First Mortgage Bonds both
mature in 1995. Once such maturities are completed, there
will no longer be any restrictions on Utilities' retained
earnings.
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 1994-1992.
The 1993 results were affected by the acquisition of the
Iowa service territory from Union Electric Company, as
discussed in Note 2 of the Notes to Consolidated Financial
Statements. The 1990 results were affected by a pre-tax gain
of $66 million on the sale of Telecom*USA stock. The 1989
results were affected by a $5.0 million pre-tax estimated
liability to pipeline suppliers recorded in 1988 and
eliminated in 1989 when the issue was favorably resolved.
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.
SELECTED CONSOLIDATED FINANCIAL DATA
1994 1993 1992 1991 1990 1989
Income statement data (000's):
Operating revenue $ 785,864 $ 801,266 $ 678,296 $ 661,538 $ 624,214 $ 599,838
Operating income 147,933 151,269 109,024 103,357 98,043 106,592
Net income 66,818 67,938 48,711 44,657 80,330* 53,565
Common stock data (per share
except percentages):
Earnings $ 2.34 $ 2.45 $ 1.92 $ 1.85 $ 3.37* $ 2.27
Dividends declared 2.10 2.10 2.10 2.03 1.82 1.77
Return on average common equity 11.5% 12.4% 10.3% 9.7% 18.4% 13.2%
Market price at year-end $ 25.25 $ 31.25 $ 29.50 $ 27.25 $ 27.75 $ 27.63
Book value at year-end 20.56 20.21 18.89 19.07 19.15 17.52
Ratio of market price to book value
at year-end 123% 155% 156% 143% 145% 158%
Capitalization:
Common equity 50% 51% 48% 50% 53% 49%
Preferred and preference stock 2 2 2 3 3 4
Long-term debt 48 47 50 47 44 47
100% 100% 100% 100% 100% 100%
Other selected financial data:
Total assets (000's) $ 1,843,989 $ 1,699,819 $ 1,594,382 $ 1,448,492 $ 1,400,802 $ 1,342,615
Non-utility assets (000's) 198,621 152,841 155,144 145,283 141,739 127,684
Long-term obligations (000's) 626,011 577,611 553,257 507,921 462,798 472,760
Construction and acquisition
expenditures (000's) 201,552 163,644 191,834** 119,821 103,154 87,381
Times interest earned before
income taxes 3.38 3.38 2.63 2.69 4.45 3.10
Selected financial data for
IES Utilities Inc.:
Utility plant in service (000's) $ 2,042,179 $ 1,932,558 $ 1,852,733 $ 1,680,108 $ 1,587,886 $ 1,475,550
Accumulated depreciation (000's) 880,888 813,312 759,754 691,015 639,211 579,160
Construction and acquisition
expenditures (000's) 148,062*** 113,212 171,013** 105,009 95,075 79,919
Times interest earned before
income taxes 3.39 3.64 2.67 2.93 3.04 3.36
Electric Kwh sales
(excluding off-system) (000's) 9,291,575 8,905,522 7,132,671 7,244,209 6,880,136 6,671,474
Gas Dth sales (including
transported volumes) (000's) 37,975 39,006 37,035 37,129 36,486 40,050
* Includes the effects of a $66 million pre-tax gain on sale of Telecom*USA
stock.
** Includes $61 million for the acquisition of the Iowa service territory
from Union Electric Company.
*** Includes $9.2 million of acquisitions from affiliated companies.
Item 7.
MANAGEMENT'S DISCUSSION AND ANALYSIS
OF THE RESULTS OF OPERATIONS AND FINANCIAL CONDITION
The following discussion analyzes significant changes in
the components of net income and financial condition from the
prior periods for IES Industries Inc. (Industries) and its
consolidated subsidiaries (the Company).
RESULTS OF OPERATIONS
Industries' wholly-owned subsidiaries are IES Utilities
Inc. (Utilities) and IES Diversified Inc. (Diversified). The
Company's net income decreased $1.1 million during 1994 and
increased $19.2 million during 1993. Earnings per average
common share declined from $2.45 in 1993 to $2.34 in 1994
because of the lower net income and the effect of increased
average common shares outstanding. The 1994 results were
affected by milder than normal weather, particularly during
the summer months. The 1993 results reflect Utilities'
acquisition of the Iowa service territory of Union Electric
Company (UE) (as discussed in Note 2 of the Notes to
Consolidated Financial Statements) and a return to more normal
weather conditions in Utilities' service territory from that
experienced in 1992. The 1993 results also reflect the
recording of certain property write-downs at Diversified and a
$2.5 million contribution to the IES Industries Charitable
Foundation. The 1992 results were adversely affected by
extremely cool summer weather and a mild winter in Utilities'
service territory.
The Company's operating income decreased $3.3 million
during 1994 and increased $42.2 million during 1993. Reasons
for the changes in the results of operations are explained in
the following discussion.
ELECTRIC REVENUES
Electric revenues and Kwh sales for Utilities increased
or (decreased) as compared with the prior year as follows:
1994 1993
($ in millions)
Electric revenues $ (13.2) $ 87.5
Electric sales (excluding off-system sales):
Residential and Rural (1.4%) 17.1%
Commercial 3.4% 17.4%
Industrial 9.3% 40.6%
Total 4.3% 24.9%
The 1994 Kwh sales were adversely affected by milder than
normal weather, particularly during the summer months. The
largest effect of weather was on sales to residential and
rural customers. Under normal weather conditions, 1994 sales
would have been flat and total sales (excluding off-system
sales) would have increased 4.8%, compared to 1993 actual
sales. The growth in commercial and industrial sales
continues to reflect the underlying strength of the economy as
several major industrial expansions in Utilities' service
territory were announced in 1994.
The 1993 sales increases are attributable to the
acquisition of the UE territory and a return to more normal
weather conditions. After adjusting for these items,
underlying total electric sales (excluding off-system sales)
increased 6% in 1993, which reflects the economic growth in
the industrial and commercial customer base.
Utilities' electric tariffs include energy adjustment
clauses (EAC) that are designed to currently recover the costs
of fuel and the energy portion of purchased power billings to
customers. See Note 1(k) of the Notes to Consolidated
Financial Statements for discussion of the EAC.
The decrease in the 1994 electric revenues is
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 sales (excluding off-system sales) partially offset the
effects of the above items. The increase in electric revenues
for 1993 is primarily because of the higher sales and
increased recovery of fuel costs through the EAC.
See Note 3(a) of the Notes to Consolidated Financial
Statements for a discussion of Utilities' 1994 electric rate
case.
GAS REVENUES
Gas revenues increased or (decreased) as compared with
the prior year as follows:
1994 1993
(in millions)
Gas revenues:
Utilities $ (15.3) $ 14.9
Industrial Energy Applications, Inc. (IEA) (1.1) (0.1)
$ (16.4) $ 14.8
Utilities' gas sales in therms (including transported
volumes), which also reflect the effects of weather, decreased
2.7% in 1994 and increased 5.3% in 1993. Adjusting for the
effects of weather, Utilities' gas sales decreased 1.8% and
1.5% in 1994 and 1993, respectively.
Utilities' gas tariffs include purchased gas adjustment
clauses (PGA) that are designed to currently recover the cost
of gas sold. See Note 1(k) of the Notes to Consolidated
Financial Statements for discussion of the PGA.
Utilities' gas revenues decreased in 1994 primarily
because of lower gas costs recovered through the PGA and, to a
lesser extent, the effect of the lower sales. Gas revenues
increased in 1993 substantially because of increased costs of
gas recovered through the PGA, the effect of gas rate
increases that became effective in September 1992 and the
sales increase.
The decrease in IEA's gas revenues in 1994 also reflects
the lower price of natural gas. Despite an increase of 16% in
gas volumes, revenues decreased by $1.1 million.
OTHER REVENUES
Other revenues increased $14.1 million and $20.6 million
during 1994 and 1993, respectively, largely because of
increased revenues at Whiting Petroleum Company (Whiting) and
Diversified's other subsidiaries, primarily in the energy and
transportation industries. In addition, approximately $10
million of the 1993 increase related to the acquisition of
certain resort properties in March 1993; Diversified
previously held an equity interest in a company that owned the
properties. Utilities' steam revenues also contributed to the
1993 increase.
OPERATING EXPENSES
Despite an increase in the amount of Kwh generation from
a year ago, 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, which are included
in fuel for production. Generation at Utilities' generating
stations increased because of the increase in electric Kwh
sales and because of increased availability of Utilities'
nuclear generating station, the Duane Arnold Energy Center
(DAEC), which was down for part of 1993 because of a scheduled
refueling outage. There were refueling outages in 1993 and
1992, but no such outage in 1994. Fuel for production
increased $14.3 million in 1993 because of increased
availability of Utilities' fossil-fueled generating stations,
which experienced extended maintenance outages in 1992, and
because of increased sales.
Purchased power decreased $24.7 million in 1994 because
of 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. Purchased power increased $18.7
million in 1993, of which approximately $14.7 million
represents increased energy purchases and approximately
$4.0 million is a net increase in capacity charges. The
increase in energy purchases is because of the increased Kwh
sales. The increased capacity costs reflect the contracts
associated with the acquisition of the UE service territory,
partially offset by the expiration of the purchase power
agreement with the City of Muscatine. (See Note 12(b) of the
Notes to Consolidated Financial Statements).
Gas purchased for resale decreased $15.0 million in 1994
because of lower gas costs and lower gas sales at Utilities.
Gas purchased for resale increased $7.6 million during 1993
primarily because of increased per unit gas costs at Utilities
and the increased sales.
Other operating expenses increased $14.2 million and
$20.3 million in 1994 and 1993, respectively. The 1994
increase is primarily attributable to increases in labor and
benefits costs, nuclear operating costs, former manufactured
gas plant (FMGP) clean-up costs and information technology
costs at Utilities, and increased operating activities at
Whiting. The 1993 increase is primarily because of increased
labor and benefits costs at Utilities and increased operating
activities at several of Diversified's subsidiaries, including
IEA and Whiting. In addition, $9 million of the 1993 increase
is attributable to the resort properties acquired in March
1993.
Maintenance expenses increased $3.9 million and $7.5
million during 1994 and 1993, respectively. The 1994 increase
is primarily because of increased labor costs and maintenance
at the DAEC, partially offset by lower maintenance at
Utilities' fossil-fueled generating stations. The 1993
increase is primarily because of increased maintenance at
Utilities' fossil-fueled generating stations and the DAEC.
Depreciation and amortization increased during both years
because of increases in utility plant in service, increased
amortization and depreciation of oil and gas properties and,
in 1993, the acquisition of the UE territory on
December 31, 1992. An increase in the average gas utility
property depreciation rate, resulting from an updated
depreciation study, also contributed to the 1993 increase.
Depreciation and amortization expenses for all years include
$5.5 million for the DAEC decommissioning provision, which is
collected through rates.
The staff of the Securities and Exchange Commission (SEC)
has questioned certain of the current accounting practices of
the electric utility industry regarding the recognition,
measurement and classification of decommissioning costs for
nuclear generating stations in the financial statements of
electric utilities. In response to these questions, the
Financial Accounting Standards Board has agreed to review the
accounting for removal costs, including decommissioning. If
current electric utility industry accounting practices for
such decommissioning are changed: (1) annual provisions for
decommissioning could increase, (2) the estimated cost for
decommissioning could be recorded as a liability rather than
as accumulated depreciation, and (3) trust fund income from
the external decommissioning trusts could be reported as
investment income rather than as a reduction to
decommissioning expense. 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
Utilities' proposal for collection of decommissioning costs
included in its current rate filing).
Taxes other than income taxes increased $1.9 million and
$4.8 million during 1994 and 1993, respectively, largely
because of increased property taxes. The 1993 increase is
related, in part, to the acquisition of the UE service
territory.
INTEREST EXPENSE AND OTHER
Interest expense increased $1.6 million during 1994
primarily because of an increase in the average amount of debt
outstanding. Interest expense decreased $1.0 million in 1993
because of a lower average interest rate, partially offset by
an increase in the average amount of debt outstanding. The
lower average interest rate reflects the refinancing of
certain long-term debt issues at lower rates and lower cost
short-term borrowings outstanding for interim periods between
the redemption of certain long-term debt series and the
issuance of their long-term replacements.
Miscellaneous, net reflects income of $3.5 million and
$7.5 million in 1994 and 1992, respectively, and expense of
$2.9 million in 1993. The comparability of the years was
significantly affected by the following 1993 transactions:
(1) certain property write-downs at Diversified, (2) a
contribution to the IES Industries Charitable Foundation, (3)
a loss on the defeasance of Industries' debentures, and (4)
gains on the sale of assets at Whiting and IEA aggregating
$2.6 million. In 1994, a gain on the sale of an investment by
one of Diversified's subsidiaries, net of lower interest
income, also contributed to the increase in income over 1993.
Federal and state income taxes increased $4.5 million and
$13.2 million in 1994 and 1993, respectively. The increase in
1994 is largely because of the effect of property related
temporary differences for which deferred taxes had not been
provided that are now becoming payable. The 1993 increase
results from an increase in taxable income and an increase of
1% in the Federal statutory income tax rate. Adjustments of
$1.5 million, recorded in the second quarter of 1992, to
previously recorded tax reserves also affected the
comparability of 1993 with the prior period.
OTHER MATTERS
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 and greater
encouragement of independent power production and
cogeneration. Although various states throughout the country
are currently exploring the possibility of expanded
competition in the retail electric energy market, there is no
significant activity underway in Iowa.
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, on-going cost
reductions and productivity enhancements. The Company
recently initiated a major project to review and redesign its
business processes with the primary goals being reduced
operating costs, increased efficiency and enhanced customer
service.
LIQUIDITY AND CAPITAL RESOURCES
The Company's capital requirements are primarily
attributable to Utilities' construction programs, its debt
maturities and sinking fund requirements and the level of
Diversified's business opportunities. The Company's pre-tax
ratio of earnings to fixed charges was 3.38, 3.38 and 2.63 in
1994-1992, respectively. In 1994, cash flows from operating
activities were $216 million. These funds were primarily used
for construction and acquisition expenditures and for energy
efficiency program costs mandated by the Iowa Utilities Board
(IUB).
The Company anticipates that future capital requirements
will be met by cash generated from operations and external
financing. The level of cash generated from operations is
partially dependent upon economic conditions, legislative
activities, environmental matters and timely rate relief for
Utilities. (See Notes 3 and 12 of the Notes to Consolidated
Financial Statements).
Access to the long-term and short-term capital and credit
markets is necessary for obtaining funds externally. The
Company's debt ratings are as follows:
Moody's Standard & Poor's
Utilities - Long-term debt A1 A
- Short-term debt P1 A1
Diversified - Short-term debt P2 A2
Utilities' liquidity and capital resources will be
affected by environmental and legislative issues, including
the ultimate disposition of remediation issues surrounding the
FMGP issue, the Clean Air Act as amended, the National Energy
Policy Act of 1992 and Federal Energy Regulatory Commission
(FERC) Order 636, as discussed in Note 12 of the Notes to
Consolidated Financial Statements. 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.
The IUB has adopted 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, 1994, Utilities had
$35 million of such costs recorded as regulatory assets.
Under provisions of the IUB rules, Utilities made its initial
filing for recovery of the costs in August 1994. See Note
3(b) of the Notes to Consolidated Financial Statements for a
discussion of the filing.
CONSTRUCTION AND ACQUISITION PROGRAM
The Company's construction and acquisition program
anticipates expenditures of approximately $202 million for
1995, of which approximately $163 million represents
expenditures at Utilities and approximately $39 million
represents expenditures at Diversified. Of the $163 million
of Utilities' expenditures, 32% represents expenditures for
electric transmission and distribution facilities, 23%
represents fossil-fueled generation expenditures, 15%
represents expenditures for steam distribution plant and 9%
represents nuclear generation expenditures. The remaining 21%
represents miscellaneous electric, gas and general
expenditures. Diversified's anticipated expenditures include
approximately $26 million at Whiting. In addition to the
$163 million, Utilities anticipates expenditures of
$13 million in connection with mandated energy efficiency
programs. Substantial commitments have been made in connection
with all such expenditures.
The Company's levels of construction and acquisition
expenditures are projected to be $230 million in 1996,
$209 million in 1997, $235 million in 1998 and $227 million in
1999. It is estimated that approximately 70% of construction
expenditures will be provided by cash from operating
activities (after payment of dividends) for the five-year
period 1995-1999.
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.
LONG-TERM FINANCING
Other than Utilities' periodic sinking fund requirements,
which Utilities intends to meet by pledging additional
property, the following long-term debt will mature prior to
December 31, 1999:
(in millions)
Issue:
Utilities $ 173.7
Diversified's variable rate credit facility 80.5
Other subsidiaries' debt 11.7
$ 265.9
The Company intends to refinance the majority of the debt
maturities with long-term securities.
In order to provide an up-to-date instrument for the
issuance of bonds, notes or other evidence of indebtedness,
Utilities has entered into an Indenture of Mortgage and Deed
of Trust dated September 1, 1993 (New Mortgage). 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. 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. 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, 1994, such restrictions would
have allowed Utilities to issue $320 million of additional
First Mortgage Bonds. Utilities has received authority from
the FERC to issue $250 million of long-term debt and is
currently authorized by the SEC to issue $50 million of
long-term debt under an existing registration statement.
Utilities expects to replace two series of First Mortgage
Bonds that mature in 1995 with other long-term securities.
Diversified has a variable rate credit facility that
extends through November 9, 1997, with two one-year extensions
available to Diversified. The facility also serves as a stand-
by agreement for Diversified's commercial paper program. The
agreement provides for a combined maximum of $150 million of
borrowings under the agreement and commercial paper to be
outstanding at any one time. Interest rates and maturities
are set at the time of borrowing for direct borrowings under
the agreement and for issuances of commercial paper. The
interest rate options are based upon quoted market rates and
the maturities are less than one year. At December 31, 1994,
$12 million was borrowed under this facility, bearing an
interest rate of 6.44%, maturing in January 1995. Diversified
also had $68.5 million of commercial paper outstanding at
December 31, 1994, with interest rates ranging from 6.27% to
6.38% and maturity dates in the first quarter of 1995, which
was also supported by the facility. Diversified intends to
continue borrowing under the renewal options of the facility
and no conditions exist at December 31, 1994, that would
prevent such borrowings. Accordingly, this debt is classified
as long-term in the Consolidated Balance Sheets.
The Articles of Incorporation of Utilities authorize and
limit the aggregate amount of additional shares of Cumulative
Preferred Stock and Cumulative Preference Stock which may be
issued. At December 31, 1994, Utilities could have issued an
additional 700,000 shares of Cumulative Preference Stock and
100,000 additional shares of Cumulative Preferred Stock. In
addition, Industries had 5,000,000 shares of Cumulative
Preferred Stock, no par value, authorized for issuance, none
of which were outstanding at December 31, 1994.
The Company's capitalization ratios at year-end were as
follows:
1994 1993
Long-term debt 48% 47%
Preferred stock 2 2
Common equity 50 51
100% 100%
The 1994 ratios include $100 million of
Utilities' First Mortgage Bonds maturing in 1995
that are classified as a current liability in
the Consolidated Balance Sheets, but which are
expected to be refinanced with long-term
securities.
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, 1994, Utilities had outstanding short-term
borrowings of $55.5 million, including $18.5 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, 1994,
Utilities had sold $54 million under the agreement.
At December 31, 1994, the Company had bank lines of
credit aggregating $77.7 million (Industries - $1.5 million,
Utilities - $67.7 million, Diversified - $7.5 million and
Whiting - $1.0 million). Utilities was using $37 million of
its lines to support commercial paper (weighted average
interest rate of 6.13%) and $7.7 million to support certain
pollution control obligations. Commitment fees are paid to
maintain these lines and there are no conditions which
restrict the unused lines of credit. In addition to the
above, Utilities has an uncommitted credit facility with a
financial institution whereby it can borrow up to $40 million.
Rates are set at the time of borrowing and no fees are paid to
maintain this facility. At December 31, 1994, there were no
borrowings under this facility. Utilities also has a letter
of credit in the amount of $3.4 million supporting two of its
variable rate pollution control obligations.
ENVIRONMENTAL MATTERS
Utilities has been named as a Potentially Responsible
Party (PRP) by either the Iowa Department of Natural Resources
(IDNR), the Minnesota Pollution Control Agency (MPCA) or the
United States Environmental Protection Agency (EPA) for 28
FMGP sites. Utilities believes that it is not responsible for
two of the sites for which it has been designated a PRP.
Utilities has another FMGP site for which it has not yet been
formally designated as a PRP. Utilities is working pursuant
to the requirements of the IDNR, MPCA and EPA to investigate,
mitigate, prevent and remediate, where necessary, damage to
property, including damage to natural resources, at and around
the remaining 27 sites in order to protect public health and
the environment. In addition, Utilities has recently become
aware that two additional sites may exist, but it has not yet
been able to determine if any liability may exist.
Utilities has completed the remediation of three sites
and is in various stages of the investigation and/or
remediation processes for 22 sites. The investigation process
is scheduled to begin in 1995 or 1996 for the two other sites.
In 1994, Utilities received updated investigation reports on a
number of sites, which, at some sites, indicated a greater
volume of contaminated soil, surface and ground water needing
treatment, and a greater volume of substances requiring higher
cost incineration, than was anticipated in prior estimates.
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 has recorded environmental liabilities related
to the FMGP sites of $31 million (including $4.3 million as
current liabilities) at December 31, 1994. 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. For those sites where the
investigation is in its earlier stages or has not started, the
liability represents the minimum of the estimated cost range.
All investigations are expected to be completed by 1999 and
site-specific remediations, based on recommendations from the
IDNR, MPCA and EPA, are anticipated to be completed within
three years after the completion of the investigations of each
site. Utilities may be required to monitor these sites for a
number of years upon completion of remediation, as is the case
with the three sites for which remediation has been completed.
Utilities has begun pursuing 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, 1994. Regulatory assets of
$31.0 million have been recorded in the Consolidated Balance
Sheets, which reflect the future recovery that is being
provided through Utilities' rates. Considering the rate
treatment allowed by the IUB, management believes that the
clean-up costs incurred by Utilities for these FMGP sites will
not have a material adverse effect on its financial position
or results of operations.
The Clean Air Act Amendments Act of 1990 (Act) requires
emission reductions of sulfur dioxide and nitrogen oxides to
achieve reductions of atmospheric chemicals believed to cause
acid rain. The provisions of the Act will be 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 is in the process of completing
the modifications necessary to meet the Phase I requirements.
Utilities expects to meet the requirements of Phase II by
switching to lower sulfur fuels and through capital
expenditures primarily related to fuel burning equipment and
boiler modifications. Utilities estimates capital
expenditures at approximately $22.5 million, including $4.4
million in 1995, in order to meet the requirements of the Act.
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,
$12.0 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. 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, pursuing other off-site storage and supporting
legislation 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, 1994, Utilities has prepaid costs of
approximately $1 million to the Compact for the building of
such a facility. Currently, Utilities is storing its low-
level radioactive waste generated at the DAEC on-site until
new disposal arrangements are finalized among the Compact
members. A Compact disposal facility is anticipated to be in
operation in approximately ten years. 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.
The possibility that exposure to electric and magnetic
fields emanating from power lines, household appliances and
other electric sources may result in adverse health effects
has been the subject of increased public, governmental and
media attention. A considerable amount of scientific research
has been conducted on this topic without definitive results.
Research is continuing in order to resolve scientific
uncertainties.
Whiting is responsible for certain dismantlement and
abandonment costs related to various off-shore oil and gas
properties, the most significant of which is located off the
coast of California. Whiting accrues these costs as reserves
are extracted and such costs are included in "Depreciation and
amortization" in the Consolidated Statements of Income. A
corresponding environmental liability, $0.1 million at
December 31, 1994, has been recognized in the Consolidated
Balance Sheets for the cumulative amount expensed.
EFFECTS OF 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 results of operations.
Selected Consolidated Quarterly Financial Data (unaudited)
The following unaudited consolidated quarterly data, in
the opinion of the Company, includes adjustments, which are
normal and recurring in nature, necessary for the fair
presentation of the results of operations and financial
position. Utilities' results of operations are a significant
portion of the consolidated results. The quarterly amounts
were affected by seasonal weather conditions. The
comparability of earnings per average common share is affected
by the sale of 2.3 million shares to the public in the first
quarter of 1993 as discussed in Note 8 of the Notes to
Consolidated Financial Statements.
Quarter Ended
March June September December
31 30 30 31
(in thousands, except per share amounts)
1994
Operating revenues $ 211,621 $ 171,117 $ 207,345 $ 195,781
Operating income 35,694 28,436 56,700 27,103
Net income 15,144 10,858 28,009 12,807
Earnings per average
common share 0.53 0.38 0.98 0.45
1993
Operating revenues $ 213,077 $ 170,470 $ 212,052 $ 205,667
Operating income 34,514 27,455 57,767 31,533
Net income 13,935 11,740 27,957 14,306
Earnings per average
common share 0.53 0.42 0.99 0.51
Item 8. Financial Statements and Supplementary Data
Information required by Item 8. begins on page 59.
REPORT OF MANAGEMENT
The Company's management has prepared and is responsible
for the presentation, integrity and objectivity of the
consolidated financial statements and related information
included in this report. The consolidated financial
statements have been prepared in conformity with generally
accepted accounting principles applied on a consistent basis
and, in some cases, include estimates that are based upon
management's judgment and the best available information,
giving due consideration to materiality. Financial information
contained elsewhere in this report is consistent with that in
the consolidated financial statements.
The Company maintains a system of internal accounting
controls which it believes is adequate to provide reasonable
assurance that assets are safeguarded, transactions are
executed in accordance with management authorization and the
financial records are reliable for preparing the consolidated
financial statements. The system of internal accounting
controls is supported by written policies and procedures, by a
staff of internal auditors and by the selection and training
of qualified personnel. The internal audit staff conducts
comprehensive audits of the Company's system of internal
accounting controls. Management strives to maintain an
adequate system of internal controls, recognizing that the
cost of such a system should not exceed the benefits derived.
In accordance with generally accepted auditing standards, the
independent public accountants (Arthur Andersen LLP) obtained
a sufficient understanding of the Company's internal controls
to plan their audit and determine the nature, timing and
extent of other tests to be performed. Management is not
aware of any material internal control weaknesses.
The Board of Directors, through its Audit Committee
comprised entirely of outside directors, meets periodically
with management, the internal auditor and Arthur Andersen LLP
to discuss financial reporting matters, internal control and
auditing. To ensure their independence, both the internal
auditor and Arthur Andersen LLP have full and free access to
the Audit Committee.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors of
IES Industries Inc.:
We have audited the accompanying consolidated balance sheets
and statements of capitalization of IES INDUSTRIES INC. (an
Iowa corporation) AND SUBSIDIARY COMPANIES as of
December 31, 1994 and 1993, and the related consolidated
statements of income, retained earnings and cash flows for
each of the three years in the period ended December 31, 1994.
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 financial statement
schedule based on our audits.
We conducted our audits in accordance with generally accepted
auditing standards. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether
the financial statements are free of material misstatement.
An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting
principles used and significant estimates made by management,
as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable
basis for our opinion.
In our opinion, the financial statements referred to above
present fairly, in all material respects, the financial
position of IES Industries Inc. and Subsidiary Companies as of
December 31, 1994 and 1993, and the results of their
operations and their cash flows for each of the three years in
the period ended December 31, 1994, 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 Industries Inc. and
subsidiary companies changed their method of accounting for
postretirement benefits other than pensions.
ARTHUR ANDERSEN LLP
Chicago, Illinois,
February 3, 1995
CONSOLIDATED STATEMENTS OF INCOME
Year Ended December 31
1994 1993 1992
(in thousands, except per share amounts)
Operating revenues:
Electric $ 537,327 $ 550,521 $ 462,999
Gas 165,569 181,923 167,082
Other 82,968 68,822 48,215
785,864 801,266 678,296
Operating expenses:
Fuel for production 85,952 87,702 73,368
Purchased power 68,794 93,449 74,794
Gas purchased for resale 120,795 135,830 128,259
Other operating expenses 176,863 162,642 142,348
Maintenance 52,841 48,913 41,415
Depreciation and amortization 86,378 77,012 69,392
Taxes other than income taxes 46,308 44,449 39,696
637,931 649,997 569,272
Operating income 147,933 151,269 109,024
Interest expense and other:
Interest expense 46,010 44,440 45,426
Allowance for funds used during
construction -3,910 -1,972 -3,177
Preferred dividend requirements of
IES Utilities Inc. 914 914 1,729
Miscellaneous, net -3,472 2,908 -7,495
39,542 46,290 36,483
Income before income taxes 108,391 104,979 72,541
Federal and state income taxes 41,573 37,041 23,830
Net income $ 66,818 $ 67,938 $ 48,711
Average number of common shares
outstanding 28,560 27,764 25,389
Earnings per average common share $ 2.34 $ 2.45 $ 1.92
The accompanying Notes to Consolidated Financial Statements are an integral
part of these statements.
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
Year Ended December 31
1994 1993 1992
(in thousands)
Balance at beginning of year $211,750 $ 202,919 $ 202,882
Add:
Net income 66,818 67,938 48,711
Acquisition of Whiting Petroleum
Corporation 0 0 5,233
Deduct:
Cash dividends declared on common
stock, at a per share rate of
$2.10 for all years 60,065 59,107 53,350
Other 210 0 557
Balance at end of year
($18,209,000 restricted as to
payment of cash dividends) $218,293 $ 211,750 $ 202,919
The accompanying Notes to Consolidated Financial Statements are an integral
part of these statements.
CONSOLIDATED BALANCE SHEETS
December 31
ASSETS 1994 1993
(in thousands)
Property, plant and equipment, at original cost:
Utility -
Plant in service -
Electric $ 1,798,059 $ 1,708,757
Gas 158,115 147,956
Other 86,005 75,845
2,042,179 1,932,558
Less - Accumulated depreciation 880,888 813,312
1,161,291 1,119,246
Leased nuclear fuel, net of amortization 49,731 51,681
Construction work in progress 73,339 45,566
1,284,361 1,216,493
Other, net of accumulated depreciation
and amortization of $34,490,000
and $35,007,000, respectively 153,795 124,275
1,438,156 1,340,768
Current assets:
Cash and temporary cash investments 4,993 7,465
Accounts receivable -
Customer, less reserve 26,098 33,642
Other 10,388 10,421
Income tax refunds receivable 1,330 3,376
Production fuel, at average cost 13,988 14,338
Materials and supplies, at average cost 30,216 29,046
Adjustment clause balances 1,433 0
Regulatory assets 20,145 14,225
Prepayments and other 34,607 34,265
143,198 146,778
Investments:
Nuclear decommissioning trust funds 33,779 28,059
Cash surrender value of life insurance policies 8,867 7,562
Investment in McLeod, Inc. 7,500 4,500
Other 5,609 4,349
55,755 44,470
Other assets:
Regulatory assets 192,955 148,592
Deferred charges and other 13,925 19,211
206,880 167,803
$ 1,843,989 $ 1,699,819
December 31
CAPITALIZATION AND LIABILITIES 1994 1993
(in thousands)
Capitalization (See Consolidated Statements of
Capitalization):
Common stock $ 373,490 $ 360,301
Retained earnings 218,293 211,750
Total common equity 591,783 572,051
Cumulative preferred stock of IES Utilities Inc. 18,320 18,320
Long-term debt 473,206 522,343
1,083,309 1,112,714
Current liabilities:
Short-term borrowings 37,000 24,000
Capital lease obligations 14,385 15,345
Maturities and sinking funds 100,422 464
Accounts payable 78,582 53,980
Accrued interest 9,494 9,471
Accrued taxes 44,897 42,368
Accumulated refueling outage provision 15,196 2,660
Dividends payable 15,839 15,519
Adjustment clause balances 0 5,149
Provision for rate refund liability 0 8,670
Environmental liabilities 5,428 4,871
Other 21,844 23,127
343,087 205,624
Long-term liabilities:
Capital lease obligations 35,346 36,336
Environmental liabilities 38,288 21,324
Other 58,793 45,231
132,427 102,891
Deferred credits:
Accumulated deferred income taxes 245,365 236,131
Accumulated deferred investment tax credits 39,801 42,459
285,166 278,590
Commitments and contingencies (Note 12)
$ 1,843,989 $ 1,699,819
The accompanying Notes to Consolidated Financial Statements are an integral
part of these statements.
CONSOLIDATED STATEMENTS OF CAPITALIZATION
December 31
1994 1993
(in thousands)
Common equity:
Common stock - no par value - authorized
48,000,000 shares; outstanding 28,777,046
and 28,304,188 shares, respectively $ 373,490 $ 360,301
Retained earnings 218,293 211,750
591,783 572,051
Cumulative preferred stock of IES Utilities Inc. 18,320 18,320
Long-term debt:
IES Utilities Inc. -
Collateral Trust Bonds -
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
119,400 119,400
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%, due 1995 50,000 50,000
Series X, 9.42%, due 1995 50,000 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
339,000 339,000
Pollution control obligations -
5.75%, due serially 1995 to 2003 3,696 3,920
5.95%, due 2007, secured by
First Mortgage Bonds 10,000 10,000
Variable rate (5.45% - 5.60% at
December 31, 1994), due 2000 to 2010 11,100 11,100
24,796 25,020
Total IES Utilities Inc. 483,196 483,420
IES Diversified Inc. -
Variable rate credit facility 80,500 32,000
Other subsidiaries' debt maturing
through 2013 12,584 10,510
576,280 525,930
Unamortized debt premium and (discount), net -2,652 -3,123
573,628 522,807
Less - Amount due within one year 100,422 464
473,206 522,343
$ 1,083,309 $ 1,112,714
The accompanying Notes to Consolidated Financial Statements are an integral
part of these statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31
1994 1993 1992
(in thousands)
Cash flows from operating activities:
Net income $ 66,818 $ 67,938 $ 48,711
Adjustments to reconcile net income to net cash flows
from operating activities -
Depreciation and amortization 86,378 77,012 69,392
Principal payments under capital lease obligations 16,246 11,429 11,725
Deferred taxes and investment tax credits 4,050 9,254 -1,374
Refueling outage provision 12,536 -4,889 -5,503
Allowance for equity funds used during construction -2,299 -824 -1,831
Other 4,859 8,764 1,761
Other changes in assets and liabilities -
Accounts receivable 6,777 -8,861 -4,000
Production fuel, materials and supplies -1,184 5,836 83
Accounts payable 21,871 7,984 -3,894
Accrued taxes 4,575 7,549 7,111
Provision for rate refunds -8,670 -350 7,528
Adjustment clause balances -6,582 6,366 -4,122
Gas in storage 1,135 -2,300 -7,908
Other 9,206 -7,669 7,136
Net cash flows from operating activities 215,716 177,239 124,815
Cash flows from financing activities:
Dividends declared on common stock -60,065 -59,107 -53,350
Dividends payable 320 1,727 13,679
Proceeds from issuance of common stock 16,426 79,746 10,726
Purchase of treasury stock -6,233 0 0
Proceeds from issuance of long-term debt 60,140 146,734 114,400
Reductions in long-term debt and preferred stock -9,790 -126,803 -70,158
Net change in short-term borrowings 13,000 -68,000 51,100
Principal payments under capital lease obligations -16,304 -11,276 -12,337
Sale of utility accounts receivable 800 10,490 7,710
Other -177 1,247 -29
Net cash flows from financing activities -1,883 -25,242 61,741
Cash flows from investing activities:
Construction and acquisition expenditures -
Utility -138,829 -113,212 -171,013
Other -62,723 -50,432 -20,821
Nuclear decommissioning trust funds -5,532 -5,532 -5,532
Deferred energy efficiency costs -16,157 -9,747 -6,877
Investments in unconsolidated affiliates -4,956 -5,373 -686
Proceeds from disposition of assets 8,803 28,790 1,106
Other 3,089 3,633 642
Net cash flows from investing activities -216,305 -151,873 -203,181
Net increase (decrease) in cash and temporary cash investments -2,472 124 -16,625
Cash and temporary cash investments at beginning of year 7,465 7,341 23,966
Cash and temporary cash investments at end of year $ 4,993 $ 7,465 $ 7,341
Supplemental cash flow information:
Cash paid during the year for -
Interest $ 47,094 $ 44,697 $ 41,747
Income taxes $ 36,097 $ 22,179 $ 23,539
Noncash investing and financing activities -
Capital lease obligations incurred $ 14,297 $ 14,605 $ 1,973
The accompanying Notes to Consolidated Financial Statements are an integral
part of these statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
(a) Basis of Consolidation -
The Consolidated Financial Statements include the
accounts of IES Industries Inc. (Industries) and its
consolidated subsidiaries (collectively the Company). All
subsidiaries for which Industries owns directly or indirectly
more than 50% of the voting stock are included as consolidated
subsidiaries. Industries' wholly-owned subsidiaries are IES
Utilities Inc. (Utilities) and IES Diversified Inc.
(Diversified). All significant intercompany balances and
transactions, other than energy related transactions affecting
Utilities, have been eliminated from the Consolidated
Financial Statements. Such energy related transactions are
made at prices that approximate market value and the
associated costs are recoverable from Utilities' customers
through the rate making process.
Investments for which the Company has at least a 20%
interest are generally accounted for under the equity method
of accounting. These investments are stated at acquisition
cost, increased or decreased for the Company's equity in
undistributed net income or loss, which is included in
"Interest expense and other - Miscellaneous, net" in the
Consolidated Statements of Income.
Certain prior period amounts have been reclassified on a
basis consistent with the 1994 presentation.
(b) Regulation -
Because of its ownership of Utilities, Industries is a
holding company under the Public Utility Holding Company Act of
1935, but claims an exemption from all provisions thereof except
Section 9(a)(2), which applies to the purchase of stock of other
utility companies. Utilities is subject to regulation by the
Iowa Utilities Board (IUB) and the Federal Energy Regulatory
Commission (FERC).
(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:
1994 1993
(in millions)
Deferred income taxes (Note 1(d)) $ 90.1 $ 88.6
Environmental liabilities (Note 12(f)) 43.8 25.4
Energy efficiency programs (Note 3(b)) 34.7 18.5
Employee pension and benefit costs (Note 7) 25.0 14.1
FERC Order No. 636 transition costs (Note 12(h)) 8.0 5.0
Unamortized loss on reacquired debt 6.1 6.4
Cancelled plant costs 2.4 3.3
Other 3.0 1.5
213.1 162.8
Classified as "Current assets - regulatory assets" 20.1 14.2
Classified as "Other assets - regulatory assets" $ 193.0 $ 148.6
Refer to the individual footnotes referenced above for a
further discussion of certain items reflected in regulatory
assets.
(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). 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 which have maturities of
less than 90 days from the date of acquisition.
(f) Depreciation of Utility Property, Plant and Equipment -
The average rates of depreciation for electric and gas
properties of Utilities, including Utilities' nuclear generating
station, the Duane Arnold Energy Center (DAEC), which is being
depreciated over a 36-year life using a remaining life method,
consistent with current rate making practices, were as follows:
1994 1993 1992
Electric 3.6% 3.5% 3.5%
Gas 3.8% 3.5% 3.0%
(g) Decommissioning of the DAEC -
Included in Utilities' proposed electric rate increase
discussed in Note 3(a) is a proposal to increase the annual
recovery of anticipated costs to decommission the DAEC to
approximately $9 million annually from the current level of $5.5
million. 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 proposal is based on the following
assumptions: 1) cost to decommission the DAEC of $252.7 million
in 1993 dollars, based on the Nuclear Regulatory Commission (NRC)
minimum formula (which exceeds the amount in the current
site-specific study completed in 1994); 2) inflation of 4.91%
annually to the year 2014, when decommissioning is expected to
begin; 3) the prompt dismantling and removal method of
decommissioning; 4) monthly funding of all future collections
into external trust funds and funded on a tax-qualified basis to
the extent possible; 5) an average after-tax return of 6.82% for
all external investments; and 6) collection of the costs on a
straight-line basis, in real terms, through 2014. Current
levels of rate recovery: 1) do not recognize estimated future
inflation for the entire period prior to commencement of the
decommissioning process; 2) assume that decommissioning begins in
2010; and 3) provide recovery on a straight-line basis without
considering the effects of inflation. At December 31, 1994,
Utilities had $33.8 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 1994, 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 industry
issues raised by the staff of the SEC and a Financial Accounting
Standards Board review regarding the electric utility industry
method of accounting for decommissioning costs.
(h) Allowance for Funds Used During Construction -
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 1994-1992 were
9.3%, 5.7% and 9.2%, respectively.
(i) Oil and Gas Properties -
Whiting Petroleum Company (Whiting), a wholly-owned
subsidiary of Diversified, uses the full
cost method of accounting for its oil and gas properties.
Accordingly, all costs of acquisition, exploration and
development of properties are capitalized. Amortization of
proved oil and gas properties is calculated using the units of
production method. At December 31, 1994, capitalized costs less
related accumulated amortization do not exceed the sum of (1) the
present value of future net revenue from estimated production of
proved oil and gas reserves (calculated using current prices);
plus (2) the cost of properties not being amortized, if any; plus
(3) the lower of cost or estimated fair value of unproved
properties included in the costs being amortized, if any; less
(4) income tax effects related to differences in the book and tax
basis of oil and gas properties. See Note 12(f) for a discussion
of dismantlement and abandonment costs associated with certain
oil and gas properties.
(j) Operating Revenues -
The Company accrues revenues for services rendered but
unbilled at month-end in order to more properly match revenues
with expenses.
(k) Adjustment Clauses -
Utilities' tariffs provide for subsequent adjustments to its
electric and natural gas rates for changes in the cost of fuel
and purchased energy and in the cost of natural gas purchased for
resale. Changes in the under/over collection of these costs are
reflected in "Fuel for production" and "Gas purchased for resale"
in the Consolidated Statements of Income. The cumulative effects
are reflected in the Consolidated Balance Sheets as a current
asset or current liability, pending automatic reflection in
future billings to customers.
(l) Accumulated Refueling Outage Provision -
The IUB allows Utilities to collect, as part of its base
revenues, funds to offset other operating and maintenance
expenditures incurred during refueling outages at the DAEC. As
these revenues are collected, an equivalent amount is charged to
other operating and maintenance expenses with a corresponding
credit to a reserve. During a refueling outage, the reserve is
reversed to offset the refueling outage expenditures.
(2) ACQUISITION OF IOWA SERVICE TERRITORY OF UNION ELECTRIC
COMPANY:
Effective December 31, 1992, Utilities purchased the Iowa
distribution system and a portion of the Iowa transmission
facilities of Union Electric Company (UE) for approximately $65
million in cash. The net book value of the acquired assets was
approximately $35 million and the amount of the purchase price in
excess of the book value (approximately $30 million) has been
recorded as an acquisition adjustment. The acquisition adjustment
is being amortized over the life of the property and the
amortization is included in "Interest expense and
other - Miscellaneous, net" in the Consolidated Statements of
Income. Recovery of the acquisition adjustment through rates has
been requested in Utilities' current electric rate filing, which
is discussed in Note 3(a). See Note 12(b) for a discussion of
the purchase power contracts between Utilities and UE associated
with this acquisition.
(3) RATE MATTERS:
(a) 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%. Utilities' proposal includes approximately $12 million in
annual revenue requirement related to increased recovery levels
of depreciation expense and nuclear decommissioning expense. To
the extent these proposals are approved by the IUB, corresponding
increases in expense would be recorded and there would be no
effect on net income. No interim increase was requested.
The Office of Consumer Advocate (OCA) filed a petition in
connection with this proceeding to reduce the rates for retail
electric service by approximately $27 million or 5.5%. The
primary differences between the amount of the increase requested
by Utilities and the decrease proposed by the OCA are: 1) a 13.9%
return on common equity requested by Utilities compared to 11.1%
proposed by the OCA; 2) OCA's rejection of Utilities' proposal to
increase collections for decommissioning the DAEC; 3) OCA's
rejection of Utilities' proposal to increase depreciation rates;
4) OCA's proposal to reject most of Utilities' request to recover
an acquisition adjustment associated with its acquisition of the
Iowa service territory of UE; and 5) an adjustment to test year
sales levels proposed by the OCA. If a rate reduction is
ultimately ordered by the IUB, the reduction would be effective
from October 22, 1994, and revenues collected beyond that date
would be subject to refund to the extent of the reduction
approved by the IUB, if any. As of December 31, 1994, Utilities'
revenues collected subject to refund were approximately
$5 million.
Intervenors in the proceeding also submitted filings in
October 1994. These parties, which primarily represent
individual or groups of customers, generally object to particular
elements of the price increase and Utilities' price design
proposals. Those intervenors that quantified their positions
have generally argued for a price decrease, but none as large as
that proposed by the OCA.
Utilities expects to receive an order from the IUB in May
1995.
(b) 1994 Energy Efficiency Cost Recovery Filing -
The IUB has adopted 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,
in August 1994, Utilities applied to the IUB for recovery of
approximately $23 million and $13 million for the electric and
gas programs, respectively, related to costs incurred through
1993 for such programs. The $36 million total for the electric
and gas programs is comprised of $21 million of direct
expenditures and carrying costs (recorded as a "Regulatory asset"
in the Consolidated Balance Sheets, including $3.6 million as
current), $7 million for a return on the expenditures over the
recovery period and $8 million for a reward based on a sharing of
the benefits of such programs.
In October 1994, the OCA and an intervenor in the proceeding
filed their direct testimony. The principal difference between
Utilities and the other parties is approximately $7 million in
the reward calculation. Hearings in the proceeding were held in
January 1995. Any increase approved by the IUB is not expected
to be effective before April 1995, and recovery will be over a
four-year period with a return allowed on the unrecovered portion
over the recovery period.
(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 an $80 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 1994-1992 were $17.8 million, $12.4 million and
$12.9 million, respectively.
The Company's operating lease rental expenses for 1994-1992
were $11.1 million, $9.1 million and $7.7 million, respectively.
The Company's future minimum lease payments by year are as
follows:
Capital Operating
Year Lease Leases
(in thousands)
1995 $ 15,634 $ 8,549
1996 15,653 8,479
1997 12,942 5,674
1998 6,394 4,245
1999 4,176 3,109
2000 - 2002 1,267 601
56,066 $ 30,657
Less: Amount representing interest 6,335
Present value of net minimum
capital lease payments $ 49,731
(5) UTILITY ACCOUNTS RECEIVABLE:
Customer accounts receivable, including unbilled revenues,
arise primarily from the sale of electricity and natural gas. At
December 31, 1994, Utilities was serving a diversified base of
residential, commercial and industrial customers consisting of
approximately 330,000 electric and 173,000 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, 1994, $54 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:
1994 1993 1992
(in millions)
Current tax expense $ 37.5 $ 27.8 $ 25.2
Deferred tax expense 6.7 14.1 1.4
Amortization and adjustment
of investment tax credits (2.6) (4.9) (2.8)
$ 41.6 $ 37.0 $ 23.8
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.
1994 1993 1992
Statutory Federal income tax rate 35.0% 35.0% 34.0%
Add (deduct):
State income taxes, net of
Federal benefits 5.9 5.5 5.8
Effect of property related
temporary differences for which
deferred taxes are not provided
under rate making principles 3.0 1.5 0.4
Amortization of investment tax credits (2.5) (2.6) (3.9)
Reversal through tariffs of
deferred taxes provided at rates in
excess of the current statutory
Federal income tax rate (1.4) (1.7) (2.4)
Adjustment of prior period taxes (1.6) (2.3) (1.6)
Other items, net - (0.1) 0.6
Overall effective income tax rate 38.4% 35.3% 32.9%
The accumulated deferred income taxes as set forth below in
the Consolidated Balance Sheets at December 31, arise from the
following temporary differences:
1994 1993
(in millions)
Property related $ 288 $ 280
Investment tax credit related (28) (30)
Decommissioning related (13) (12)
Other (2) (2)
$ 245 $ 236
(7) BENEFIT PLANS:
(a) Pension Plans -
The Company has one contributory and two non-contributory
retirement 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 1994 totaled $9.9 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.
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:
1994 1993 1992
(in thousands)
Service cost $ 5,863 $ 4,342 $ 4,529
Interest cost on projected
benefit obligation 11,431 11,314 10,219
Assumed return on plans' assets (12,593) (12,363) (11,872)
Amortization of unrecognized gain (180) (767) (135)
Amortization of prior service cost 1,354 1,213 956
Amortization of unrecognized plans'
assets as of January 1, 1987 (333) (389) (389)
Pension cost 5,542 3,350 3,308
Adjustment to funding level (5,431) (2,940) 294
Total pension costs paid to
the Trustees $ 111 $ 410 $ 3,602
Actual return on plans'assets $ (97) $ 12,880 $ 8,949
A reconciliation of the funded status of the plans to the
amounts recognized in the Consolidated Balance Sheets at December
31, is presented below:
1994 1993
(in thousands)
Fair market value of plans' assets $ 167,535 $ 176,935
Actuarial present value of benefits
rendered to date -
Accumulated benefits based on
compensation to date,
including vested benefits of
$98,384,000 and $102,621,000, respectively 108,585 112,561
Additional benefits based on
estimated future salary levels 40,146 43,673
Projected benefit obligation 148,731 156,234
Plans' assets in excess of projected
benefit obligation 18,804 20,701
Remaining unrecognized net asset
existing at January 1, 1987, being amortized
over 20 years (3,844) (4,177)
Unrecognized prior service cost 18,260 16,985
Unrecognized net gain (34,420) (29,278)
Prepaid (accrued) pension cost recognized in
the Consolidated Balance Sheets $ (1,200) $ 4,231
Assumed rate of return, all plans 8.00% 8.00%
Weighted average discount rate of
projected benefit obligation, all plans 8.25% 7.50%
Range of assumed rates of increase in
future compensation levels for the plans 4.00-5.75% 4.00-5.75%
(b) Other Postemployment Benefit Plans -
The Company provides certain benefits to retirees (primarily
health care benefits). Through 1992, the Company expensed such
costs as benefits were paid ($2.2 million for 1992), which was
consistent with rate making practices at that time.
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 has 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. Beginning in 1993, the gas portion of these
costs is being recovered in Utilities' gas rates, and is funded
in external trust funds. The IUB has adopted a rule that permits
a deferral of the incremental electric SFAS 106 costs until the
earlier of: 1) an order in an electric rate case, or 2)
December 31, 1995. Accordingly, pursuant to the provisions of
SFAS 71, Utilities had deferred $5.6 million of such costs at
December 31, 1994. Utilities has requested recovery of these
costs in the electric rate case discussed in Note 3(a).
The transition obligation for the non-regulated operations
was expensed in 1993 and is reflected in other operating
expenses.
The components of postretirement benefit costs for the years
ended December 31, were as follows:
1994 1993
(in thousands)
Service cost $ 1,838 $ 1,744
Interest cost on accumulated
postretirement benefit obligation 3,275 3,363
Actual return on plan assets (47) -
Amortization of transition obligation
existing at January 1, 1993, for
regulated operations 2,024 2,024
Amortization of unrecognized asset loss (13) -
Amortization of unrecognized gain (6) -
Amortization of prior service cost 19 -
Write-off of transition obligation
existing at January 1, 1993,
for non-regulated operations - 1,434
Postretirement benefit costs 7,090 8,565
Less: Deferred postretirement
benefit costs 2,732 2,858
Net postretirement benefit costs $ 4,358 $ 5,707
A reconciliation of the funded status of the plans to the
amounts recognized in the Consolidated Balance Sheets at December
31, is presented below:
1994 1993
(in thousands)
Fair market value of plans' assets $ 1,127 $ 1,171
Accumulated postretirement
benefit obligation -
Active employees not yet eligible 18,896 19,092
Active employees eligible 5,306 4,294
Retirees 18,602 20,739
Total accumulated postretirement
benefit obligation 42,804 44,125
Accumulated postretirement
benefit obligation in
excess of plans' assets (41,677) (42,954)
Unrecognized transition obligation 36,439 38,463
Unrecognized net gain (5,703) (1,175)
Unrecognized prior service cost 170 -
Accrued postretirement benefit cost in
in the Consolidated Balance Sheets $ (10,771) $ (5,666)
Assumed rate of return 8.00% 8.00%
Weighted average discount rate
of accumulated postretirement
benefit obligation 8.25% 7.50%
Medical trend on paid charges:
Initial trend rate 11.00% 12.00%
Ultimate trend rate 6.50% 6.50%
The assumed medical trend rates are critical assumptions in
determining the service 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 1994 service cost by
$1.0 million (20%) and the accumulated postretirement benefit
obligation at December 31, 1994, by $6.8 million (16%).
On January 1, 1994, the Company adopted the provisions of
SFAS 112, "Employers' Accounting for Postemployment Benefits,"
and its adoption did not have a material effect on the Company's
financial position or results of operations.
(8) COMMON STOCK:
The following table presents information relating to the
issuance of common stock.
Common Stock
Number of Shares
Outstanding Amount
(in thousands)
Balance, December 31, 1991 24,298,807 $ 260,414
Stock plan issuances* 404,324 11,473
Shares issued in connection
with the Whiting merger 853,832 7,923
Balance, December 31, 1992 25,556,963 279,810
Public offering 2,300,000 66,555
Stock plan issuances* 447,225 13,936
Balance, December 31, 1993 28,304,188 360,301
Shares issued in connection with
acquisition of Okie Companies 139,102 4,027
Purchases of treasury stock (213,300) (6,233)
Stock plan issuances* 547,056 15,395
Balance, December 31, 1994 28,777,046 $ 373,490
Shares reserved for issuance
pursuant to the Company's stock
plans at December 31, 1994* 2,457,397
* Dividend Reinvestment and Stock Purchase
Plan, Employee Stock Purchase Plan, Employee
Savings Plan, Long-Term Incentive Plan of
1987, IES Bonus Stock Ownership Plan and
Whiting Stock Option Plans
In 1994, Industries issued 139,102 shares of its common
stock for the purchase of certain companies, collectively
referred to as the Okie Companies, in a transaction that was
accounted for as a purchase. The Okie Companies hold oil and gas
properties in the United States and are now wholly-owned
subsidiaries of Whiting.
During 1994, Industries reacquired 213,300 shares of its
common stock on the open market, at an average price of $29.22
per share, which were subsequently issued to the Dividend
Reinvestment Plan and certain of its benefit plans. At
December 31, 1994, no shares remained held as treasury stock.
In the first quarter of 1993, Industries sold 2.3 million
shares of its common stock in a public offering. The shares were
priced at $30 per share. Net proceeds to Industries from this
sale were approximately $67 million.
(9) PREFERRED AND PREFERENCE STOCK:
Utilities has 466,406 shares of Cumulative Preferred Stock,
$50 par value, authorized for issuance at December 31, 1994, 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,
1994 and 1993. These shares are redeemable at the option of
Utilities upon 30 days notice at $51.00, $50.25 and $51.00 per
share, respectively, plus accrued dividends.
There are 5,000,000 shares of Industries Cumulative
Preferred Stock (no par value) and 700,000 shares of Utilities
Cumulative Preference Stock ($100 par value) authorized for
issuance, of which none were outstanding at December 31, 1994.
(10) DEBT:
(a) Long-Term Debt -
Utilities' Indentures and Deeds of Trust securing its First
Mortgage Bonds constitute direct first mortgage liens upon
substantially all tangible public utility property. Utilities'
Indenture and Deed of Trust securing its Collateral Trust Bonds
constitutes a second lien on substantially all tangible public
utility property while First Mortgage Bonds remain outstanding.
Diversified has a variable rate credit facility that extends
through November 9, 1997, with two one-year extensions available
to Diversified. The facility also serves as a stand-by agreement
for Diversified's commercial paper program. The agreement
provides for a combined maximum of $150 million of borrowings
under the agreement and commercial paper to be outstanding at any
one time. Interest rates and maturities are set at the time of
borrowing for direct borrowings under the agreement and for
issuances of commercial paper. The interest rate options are
based upon quoted market rates and the maturities are less than
one year. At December 31, 1994, $12 million was borrowed under
this facility, bearing an interest rate of 6.44%, maturing in
January 1995. Diversified also had $68.5 million of commercial
paper outstanding at December 31, 1994, with interest rates
ranging from 6.27% to 6.38% and maturity dates in the first
quarter of 1995, which was also supported by the facility.
Diversified intends to continue borrowing under the renewal
options of the facility and no conditions exist at December 31,
1994, that would prevent such borrowings. Accordingly, this debt
is classified as long-term in the Consolidated Balance Sheets.
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
1995-1999 are as follows:
Debt Maturities
(in thousands)
Debt Issue 1995 1996 1997 1998 1999
Utilities -
Sinking fund
requirements $ 780 $ 630 $ 550 $ 550 $ 550
Pollution control 140 140 140 140 140
Series W 50,000 - - - -
Series X 50,000 - - - -
Series J - 15,000 - - -
6-1/8% Series - - 8,000 - -
Series Z - - - - 50,000
Diversified -
Variable rate
credit facility 80,500 - - - -
Other subsidiaries'
debt 282 305 331 357 10,393
Total $ 181,702 $ 16,075 $ 9,021 $ 1,047 $ 61,083
The Company intends to refinance the majority of the debt
maturities with long-term securities.
(b) Long-Term Debt of McLeod, Inc. -
Diversified has a $7.5 million investment in Class B Common
Stock of McLeod, Inc. (McLeod), which represents a voting
interest of less than 20%. McLeod provides local and
long-distance telecommunication services to business customers
and other services related to fiber optics. In 1994, Diversified
entered into an agreement whereby it will guarantee $6 million
under a credit facility between McLeod and its bankers.
Diversified is paid an annual commitment fee and receives options
to purchase additional shares of Class B Common Stock for as long
as the guarantee remains outstanding. At December 31, 1994,
McLeod had $3.5 million outstanding under its facility.
(c) Short-Term Debt -
At December 31, 1994, the Company had bank lines of credit
aggregating $77.7 million (Industries - $1.5 million, Utilities -
$67.7 million, Diversified - $7.5 million and
Whiting - $1.0 million). Utilities was using $37 million to
support commercial paper (weighted average interest rate of
6.13%) and $7.7 million to support certain pollution control
obligations. Commitment fees are paid to maintain these lines
and there are no conditions which restrict the unused lines of
credit. In addition to the above, Utilities has an uncommitted
credit facility with a financial institution whereby it can
borrow up to $40 million. Rates are set at the time of borrowing
and no fees are paid to maintain this facility. At
December 31, 1994, there were no borrowings under this facility.
Utilities also has a letter of credit in the amount of
$3.4 million supporting two of its variable rate pollution
control obligations.
(11) ESTIMATED FAIR VALUE OF FINANCIAL INSTRUMENTS:
The estimated fair values of financial instruments at
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. On January 1, 1994, the
Company adopted SFAS 115, "Accounting for Certain Investments in
Debt and Equity Securities." This standard, which applies to
Utilities' nuclear decommissioning trust funds, requires that
unrealized gains and losses on such investments be included in
the reported balance of such investments. At December 31, 1994,
the balance of the "Nuclear decommissioning trust funds" as shown
in the Consolidated Balance Sheets included $0.8 million of
unrealized losses on the investments held in the trust funds.
The accumulated reserve for decommissioning costs was adjusted by
a corresponding amount and there was no effect on net income or
earnings per average common share from adopting this standard.
(c) Cumulative Preferred Stock of Utilities -
The estimated fair value of this stock of $10.2 million is
based upon the market yield of similar securities.
(d) Long-Term Debt -
The carrying amount of long-term debt was $576 million
compared to estimated fair value of $551 million. The estimated
fair value of long-term debt is based upon quoted market prices.
Since Utilities is subject to regulation, any gains or
losses related to the difference between the carrying amount and
the fair value of financial instruments may not be realized by
the Company's shareholders.
(12) COMMITMENTS AND CONTINGENCIES:
(a) Construction Program -
The Company's construction and acquisition program
anticipates expenditures of approximately $202 million for 1995,
which includes $163 million at Utilities and $39 million at
Diversified. In addition to the $163 million, Utilities
anticipates expenditures of approximately $13 million for
mandated energy efficiency programs. These expenditures will be
deferred pursuant to IUB rules as discussed in Note 3(b).
Substantial commitments have been made in connection with all
such expenditures.
(b) Purchase Power Contracts -
In connection with the acquisition of the UE properties
discussed in Note 2, Utilities is purchasing power from UE under
a firm capacity contract with a 1995 requirement of 100 Mw of
delivered capacity declining to 60 Mw in 1997. Utilities will
also purchase an additional annual maximum interruptible capacity
of up to 54 Mw of 25 Hz power, which extends through 1998 and
will continue thereafter unless either party gives a three-year
notice of cancellation. The costs of capacity purchases for
these contracts are reflected in "Purchased power" in the
Consolidated Statements of Income.
Utilities has a contract to purchase capacity of 50 Mw from
the City of Muscatine for the period May 1, 1995, through
October 31, 1995. 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 under all existing contracts will
approximate $16.3 million, $14.3 million, $12.3 million,
$4.7 million and $3.4 million for the years 1995-1999,
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, 1994, the contracts cover
approximately $199 million of coal over the life of the
contracts, which includes $50 million expected to be incurred
in 1995. 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 expenditures under
the agreement for 1995 are estimated to be approximately
$9.5 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 -
The Price-Anderson Amendments Act of 1988 (1988 Act)
provides Utilities with the benefit of $8.9 billion of public
liability coverage consisting of $200 million of insurance and
$8.7 billion of potential retroactive assessments from the owners
of nuclear power plants. Based upon its ownership of the DAEC,
under the 1988 Act, Utilities could be assessed a maximum of
$79.3 million per nuclear incident, with a maximum of $10 million
per year (of which Utilities' 70% ownership portion would be
approximately $55 million and $7 million, respectively) if losses
relating to the incidents exceeded $200 million. These limits
are subject to adjustments for inflation in future years.
Utilities is a member of Nuclear Electric Insurance Limited
(NEIL), which provides insurance coverage for the cost of certain
property losses at nuclear generating stations and for the cost
of replacement power during certain outages. Companies insured
through NEIL are subject to retroactive premium adjustments if
losses exceed accumulated reserve funds. NEIL's accumulated
reserve funds are currently sufficient to more than cover its
exposure in the event of a single incident under the property
damage or replacement power coverages. However, Utilities could
be assessed annually a maximum of $8.5 million for certain
property losses and $0.7 million for replacement power if NEIL's
losses relating to accidents exceeded its accumulated reserve
funds. Utilities is not aware of any losses that it believes are
likely to result in an assessment.
(f) Environmental Liabilities -
The Company has recorded environmental liabilities of
approximately $44 million, including $5.4 million as current
liabilities, in its Consolidated Balance Sheets at December 31,
1994. The significant items are discussed below.
Former Manufactured Gas Plant (FMGP) Sites
Utilities has been named as a Potentially Responsible Party
(PRP) by either the Iowa Department of Natural Resources (IDNR),
the Minnesota Pollution Control Agency (MPCA) or the United
States Environmental Protection Agency (EPA) for 28 FMGP sites.
Utilities believes that it is not responsible for two of the
sites for which it has been designated a PRP. Utilities has
another FMGP site for which it has not yet been formally
designated as a PRP. Utilities is working pursuant to the
requirements of the IDNR, MPCA and EPA to investigate, mitigate,
prevent and remediate, where necessary, damage to property,
including damage to natural resources, at and around the
remaining 27 sites in order to protect public health and the
environment. In addition, Utilities has recently become aware
that two additional sites may exist, but it has not yet been able
to determine if any liability may exist.
Utilities has completed the remediation of three sites and
is in various stages of the investigation and/or remediation
processes for 22 sites. The investigation process is scheduled
to begin in 1995 or 1996 for the two other sites. In 1994,
Utilities received updated investigation reports on a number of
sites, which, at some sites, indicated a greater volume of
contaminated soil, surface and ground water needing treatment,
and a greater volume of substances requiring higher cost
incineration, than was anticipated in prior estimates. 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 has recorded environmental liabilities related to
the FMGP sites of $31 million (including $4.3 million as current
liabilities) at December 31, 1994. 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.
For those sites where the investigation is in its earlier stages
or has not started, the liability represents the minimum of the
estimated cost range. All investigations are expected to be
completed by 1999 and site-specific remediations, based on
recommendations from the IDNR, MPCA and EPA, are anticipated to
be completed within three years after the completion of the
investigations of each site. Utilities may be required to monitor
these sites for a number of years upon completion of remediation,
as is the case with the three sites for which remediation has
been completed.
Utilities has begun pursuing 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, 1994. Regulatory assets of
$31.0 million have been recorded in the Consolidated Balance
Sheets, which reflect the future recovery that is being provided
through Utilities' rates. Considering the rate treatment allowed
by the IUB, management believes that the clean-up costs incurred
by Utilities for these FMGP sites will not have a material
adverse effect on its financial position or results of
operations.
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, $12.0 million
payable through 2007, has been recorded as a liability in the
Consolidated Balance Sheets, including $0.8 million included in
"Current liabilities - Environmental liabilities," with a related
regulatory asset for the unrecovered amount.
Oil and Gas Properties Dismantlement and Abandonment
Costs
Whiting is responsible for certain dismantlement and
abandonment costs related to various off-shore oil and gas
properties, the most significant of which is located off the
coast of California. Whiting accrues these costs as reserves are
extracted and such costs are included in "Depreciation and
amortization" in the Consolidated Statements of Income. A
corresponding environmental liability, $0.1 million at December
31, 1994, has been recognized in the Consolidated Balance Sheets
for the cumulative amount expensed.
(g) Clean Air Act -
The Clean Air Act Amendments Act of 1990 (Act) requires
emission reductions of sulfur dioxide and nitrogen oxides to
achieve reductions of atmospheric chemicals believed to cause
acid rain. The provisions of the Act will be 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 is in the process of completing the
modifications necessary to meet the Phase I requirements.
Utilities expects to meet the requirements of Phase II by
switching to lower sulfur fuels and through capital expenditures
primarily related to fuel burning equipment and boiler
modifications. Utilities estimates capital expenditures at
approximately $22.5 million, including $4.4 million in 1995, in
order to meet the requirements of the Act.
(h) FERC Order No. 636 -
The FERC issued Order No. 636 (Order 636) in 1992. Order
636, as modified on rehearing: 1) requires Utilities' pipeline
suppliers to unbundle their services so that gas supplies are
obtained separately from transportation service, and
transportation and storage services are operated and billed as
separate and distinct services; 2) requires the pipeline
suppliers to offer "no notice" transportation service under which
firm transporters (such as Utilities) can receive delivery of gas
up to their contractual capacity level on any day without prior
scheduling; 3) allows pipelines to abandon long-term (one year or
more) transportation service provided to a customer under an
expiring contract whenever the customer fails to match the
highest rate and longest term (up to 20 years) offered to the
pipeline by other customers for the particular capacity; and 4)
provides for a mechanism under which pipelines can recover
prudently incurred transition costs associated with the
restructuring process. Utilities has enhanced access to
competitively priced gas supply and more flexible transportation
services as a result of Order 636. However, under Order 636,
Utilities is required to pay certain transition costs incurred
and billed by its pipeline suppliers.
Utilities' three pipeline suppliers have made filings with
the FERC to begin collecting their respective transition costs,
and additional filings are expected. Utilities began paying the
transition costs in 1993, and, at December 31, 1994, has recorded
a liability of $8.0 million for those transition costs that have
been incurred by the pipelines to date, including $3.0 million
expected to be billed through 1995. 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 $10 million. The ultimate level of costs to be
billed to Utilities depends on the pipelines' filings with the
FERC and other future events, including the market price of
natural gas. However, Utilities believes any transition costs
that the FERC would allow the pipelines to collect from Utilities
would be recovered from its customers, based upon regulatory
treatment of these costs currently and similar past costs by the
IUB. Accordingly, regulatory assets, in amounts corresponding to
the recorded liabilities, have been recorded to reflect the
anticipated recovery.
(13) JOINTLY-OWNED ELECTRIC UTILITY PLANT:
Under joint ownership agreements with other Iowa utilities,
Utilities has undivided ownership interests in jointly-owned
electric generating stations and related transmission facilities.
Each of the respective owners is responsible for the financing of
its portion of the construction costs. Kilowatt-hour generation
and operating expenses are divided on the same basis as ownership
with each owner reflecting its respective costs in its Statements
of Income. Information relative to Utilities' ownership interest
in these facilities at December 31, 1994 is as follows:
Ottumwa Neal
DAEC Unit 1 Unit 3
($ in millions)
Utility plant in service $ 490.8 $ 187.9 $ 55.5
Accumulated depreciation $ 242.4 $ 80.6 $ 25.7
Construction work in progress $ 5.3 $ - $ 1.3
Plant capacity - Mw 515 716 515
Percent ownership 70% 48% 28%
In-service date 1974 1981 1975
(14) SEGMENTS OF BUSINESS:
The principal business segments of Industries are the
generation, transmission, distribution and sale of electric
energy by Utilities and the purchase, distribution and sale of
natural gas by Utilities and Industrial Energy Applications,
Inc., a wholly-owned subsidiary of Diversified. Certain
financial information relating to Industries' significant
segments of business is presented below:
Year Ended December 31
1994 1993 1992
(in thousands)
Operating results:
Revenues -
Electric $ 537,327 $ 550,521 $ 462,999
Gas 165,569 181,923 167,082
Operating income -
Electric 125,487 128,994 90,891
Gas 8,762 13,673 9,164
Other information:
Depreciation and amortization -
Electric 68,640 63,832 59,707
Gas 6,214 5,186 4,024
Construction and acquisition
expenditures -
Electric 99,543 84,720 154,902
Gas 12,719 12,582 17,323
Assets -
Identifiable assets -
Electric 1,347,024 1,288,505 1,226,614
Gas 192,397 168,800 147,395
1,539,421 1,457,305 1,374,009
Other corporate assets 304,568 242,514 220,373
Total consolidated assets $ 1,843,989 $ 1,699,819 $ 1,594,382
Item 9. Changes and Disagreements with Accountants on Accounting
and Financial Disclosure
None.
PART III
Item 10. Directors, Executive Officers, Promoters and Control
Persons of the Registrant
Information regarding the identification of directors of
Industries and compliance with Section 16(a) reporting
requirements of the Securities and Exchange Commission is
included in Industries' definitive proxy statement prepared
for the 1995 annual meeting of stockholders, which was filed
on March 20, 1995, (Proxy Statement under the captions
"Proposal Number 1 - Nomination and Election of Directors" and
"Certain SEC Filings") and is incorporated herein by
reference. The executive officers of the registrant are as
follows:
Executive Officers of the Registrant (Effective February 7, 1995)
Lee Liu, 61, Chairman of the Board, President & Chief
Executive Officer. First elected officer in 1975.
Blake O. Fisher, Jr., 50, Executive Vice President &
Chief Financial Officer and Director. First elected
officer in 1991. (i)
Larry D. Root, 58, Executive Vice President. First
elected officer in 1979.
Dr. Robert J. Latham, 52, Senior Vice President, Finance.
First elected officer in 1985.
Stephen W. Southwick, 48, Vice President, General Counsel
& Secretary. First elected officer in 1982.
Thomas R. Seldon, 56, Vice President, Human Resources.
First elected officer in 1987.
Dean E. Ekstrom, 47, Vice President, Management Systems.
First elected officer in 1991.
Peter W. Dietrich, 55, Vice President, Corporate
Development. First elected officer in 1988.
Richard A. Gabbianelli, 38, Controller & Chief Accounting
Officer. First elected officer in 1994.
Dennis B. Vass, 45, Treasurer. First elected officer in
1995. (ii)
Officers are elected annually by the Board of Directors
and each of the officers named above, except Blake O. Fisher,
Jr. and Dennis B. Vass, have been employed by Industries or
one of its significant subsidiaries as an officer or in other
responsible positions at such companies for at least five
years. There are no family relationships among these
officers. There are no arrangements or understandings with
respect to election of any person as an officer.
(i) Prior to the appointment of Blake O. Fisher,
Jr. as Executive Vice President & Chief Financial
Officer of the Company in January 1991, he was
employed by Consumers Power Company as Vice
President Finance and Treasurer.
(ii) Prior to the appointment of Dennis B. 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 the Proxy Statement under the
captions "Compensation of Directors", "Summary Compensation
Table", "Compensation Committee Interlocks and Insider
Participation" and "IES Industries Plans" and is incorporated
herein by reference, except for the "Report of the
Compensation Committee on Executive Compensation," the
"Performance Graph" and "Proposal Number 2 - To Amend the IE
Industries Inc. Long-Term Incentive Plan of 1987" included
therein, which are not incorporated herein by reference.
Item 12. Security Ownership of Certain Beneficial Owners and
Management
Information regarding security ownership of certain
beneficial owners and management is included in the Proxy
Statement under the captions "Security Ownership of Beneficial
Owners" and "Security Ownership of Management" and is
incorporated herein by reference.
Item 13. Certain Relationships and Related Transactions
Information regarding certain relationships and related
transactions is included in the Proxy Statement under the
captions "Other Transactions" and "Compensation of Directors"
and is incorporated herein by reference.
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports
on Form 8-K
Page No.
(a) 1. Financial Statements -
Included in Part II of this report -
Report of Management. 56 - 57
Report of Independent Public Accountants. 58
Consolidated Statements of Income for the
years ended December 31, 1994, 1993 and 1992. 59
Consolidated Statements of Retained Earnings
for the years ended December 31, 1994, 1993 and 1992. 60
Consolidated Balance Sheets at December 31, 1994 and
1993. 61 - 62
Consolidated Statements of Capitalization at
December 31, 1994 and 1993. 63
Consolidated Statements of Cash Flows for the
years ended December 31, 1994, 1993 and 1992. 64
Notes to Consolidated Financial Statements. 65 - 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, 1994,
1993 and 1992. 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 -
None.
IES INDUSTRIES INC.
SCHEDULE II--VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE YEARS ENDED DECEMBER 31, 1994, 1993 AND 1992
Column A Column B Column E
Balance Balance
Description January 1 December 31
(in thousands)
IES Industries Inc. and Non-utility Subsidiaries:
1994:
Reserve for economic development loans $ 49 $ 49
Accumulated provision for uncollectible
accounts and other $ 457 $ 323
1993:
Reserve for economic development loans $ 247 $ 49
Accumulated provision for uncollectible
accounts and other $ - $ 457
1992:
Reserve for economic development loans $ 1,388 $ 247
Accumulated provision for uncollectible
accounts and other $ 3,757 $ -
IES Utilities Inc.:
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
1992:
Accumulated provision for
uncollectible accounts $ 804 $ 567
Accumulated provision for rate refunds $ 1,492 $ 9,020
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of
the Securities Exchange Act of 1934, the registrant has duly
caused this report to be signed on its behalf by the
undersigned, thereunto duly authorized, on the 29th day of
March 1995.
IES INDUSTRIES INC.
(Registrant)
By /s/ Blake O. Fisher, Jr.
Blake O. Fisher, Jr.
Executive Vice President &
Chief Financial Officer and Director
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 29, 1995:
/s/ Lee Liu Chairman of the Board, President &
Lee Liu Chief Executive Officer
(Principal Executive Officer)
/s/ Blake O. Fisher, Jr. Executive Vice President & Chief
Blake O. Fisher, Jr. Financial Officer and Director
(Principal Financial Officer)
/s/ Richard A. Gabbianelli Controller & Chief Accounting Officer
Richard A. Gabbianelli (Principal Accounting Officer)
/s/ C.R.S. Anderson Director
C.R.S. Anderson
/s/ J. Wayne Bevis Director
J. Wayne Bevis
/s/ Dr. George Daly Director
Dr. George Daly
/s/ G. Sharp Lannom, IV Director
G. Sharp Lannom, IV
/s/ Jack R. Newman Director
Jack R. Newman
/s/ Robert D. Ray Director
Robert D. Ray
/s/ David Q. Reed Director
David Q. Reed
/s/ Henry Royer Director
Henry Royer
/s/ Robert W. Schlutz Director
Robert W. Schlutz
/s/ Anthony R. Weiler Director
Anthony R. Weiler
EXHIBIT INDEX
The Exhibits designated by an asterisk are filed herewith and
all other Exhibits as stated to be filed are incorporated
herein by reference.
Exhibit
3(a) Articles of Incorporation of Registrant, Amended
and Restated as of May 4, 1993 (Filed as Exhibit 3(a)
to Company's Form 10-K for the year 1993).
3(b) Bylaws of Registrant, as amended
November 2, 1994 (Filed as Exhibit 3 to Company's
Registration Statement, File No. 33-56981).
4(a) Indenture of Mortgage and Deed of Trust,
dated as of September 1, 1993, between Utilities
(formerly Iowa Electric Light and Power Company (IE))
and the First National Bank of Chicago, as Trustee
(Mortgage) (Filed as Exhibit 4(c) to IE's Form 10-Q for
the quarter ended September 30, 1993).
4(b) Supplemental Indentures to the Mortgage:
Number Dated as of IE File Reference Exhibit
First October 1, 1993 Form 10-Q, 11/12/93 4(d)
Second November 1, 1993 Form 10-Q, 11/12/93 4(e)
4(c) Indenture of Mortgage and Deed of Trust,
dated as of August 1, 1940, between Utilities (formerly
IE) and the First National Bank of Chicago, Trustee
(1940 Indenture) (Filed as Exhibit 2(a) to IE's
Registration Statement, File No. 2-25347).
4(d) Supplemental Indentures to the 1940 Indenture:
Number Dated as of IE File Reference Exhibit
First March 1, 1941 2-25347 2(a)
Second July 15, 1942 2-25347 2(a)
Third August 2, 1943 2-25347 2(a)
Fourth August 10, 1944 2-25347 2(a)
Fifth November 10, 1944 2-25347 2(a)
Sixth August 8, 1945 2-25347 2(a)
Seventh July 1, 1946 2-25347 2(a)
Eighth July 1, 1947 2-25347 2(a)
Ninth December 15, 1948 2-25347 2(a)
Tenth November 1, 1949 2-25347 2(a)
Eleventh November 10, 1950 2-25347 2(a)
Twelfth October 1, 1951 2-25347 2(a)
Thirteenth March 1, 1952 2-25347 2(a)
Fourteenth November 5, 1952 2-25347 2(a)
Fifteenth February 1, 1953 2-25347 2(a)
Sixteenth May 1, 1953 2-25347 2(a)
Seventeenth November 3, 1953 2-25347 2(a)
Eighteenth November 8, 1954 2-25347 2(a)
Nineteenth January 1, 1955 2-25347 2(a)
Twentieth November 1, 1955 2-25347 2(a)
Twenty-first November 9, 1956 2-25347 2(a)
Twenty-second November 6, 1957 2-25347 2(a)
Twenty-third November 4, 1958 2-25347 2(a)
Twenty-fourth November 3, 1959 2-25347 2(a)
Twenty-fifth November 1, 1960 2-25347 2(a)
Twenty-sixth January 1, 1961 2-25347 2(a)
Twenty-seventh November 7, 1961 2-25347 2(a)
Twenty-eighth November 6, 1962 2-25347 2(a)
Twenty-ninth November 5, 1963 2-25347 2(a)
Thirtieth November 4, 1964 2-25347 2(a)
Thirty-first November 2, 1965 2-25347 2(a)
Thirty-second September 1, 1966 Form 10-K, 1966 4.10
Thirty-third November 30, 1966 Form 10-K, 1966 4.10
Thirty-fourth November 7, 1967 Form 10-K, 1967 4.10
Thirty-fifth November 5, 1968 Form 10-K, 1968 4.10
Thirty-sixth November 1, 1969 Form 10-K, 1969 4.10
Thirty-seventh December 1, 1970 Form 8-K, 12/70 1
Thirty-eighth November 2, 1971 2-43131 2(g)
Thirty-ninth May 1, 1972 Form 8-K, 5/72 1
Fortieth November 7, 1972 2-56078 2(i)
Forty-first November 7, 1973 2-56078 2(j)
Forty-second September 10,1974 2-56078 2(k)
Forty-third November 5, 1975 2-56078 2(l)
Forty-fourth July 1, 1976 Form 8-K, 7/76 1
Forty-fifth November 1, 1976 Form 8-K, 12/76 1
Forty-sixth December 1, 1977 2-60040 2(o)
Forty-seventh November 1, 1978 Form 10-Q, 6/30/79 1
Forty-eighth December 1, 1979 Form S-16, 2-65996 2(q)
Forty-ninth November 1, 1981 Form 10-Q, 3/31/82 2
Fiftieth December 1, 1980 Form 10-K, 1981 4(s)
Fifty-first December 1, 1982 Form 10-K, 1982 4(t)
Fifty-second December 1, 1983 Form 10-K, 1983 4(u)
Fifty-third December 1, 1984 Form 10-K, 1984 4(v)
Fifty-fourth March 1, 1985 Form 10-K, 1984 4(w)
Fifty-fifth March 1, 1988 Form 10-Q, 5/12/88 4(b)
Fifty-sixth October 1, 1988 Form 10-Q, 11/10/88 4(c)
Fifty-seventh May 1, 1991 Form 10-Q, 8/13/91 4(d)
Fifty-eighth March 1, 1992 Form 10-K, 1991 4(c)
Fifty-ninth October 1, 1993 Form 10-Q, 11/12/93 4(a)
Sixtieth November 1, 1993 Form 10-Q, 11/12/93 4(b)
4(e) Indenture or Deed of Trust dated as of
February 1, 1923, between Utilities (successor to Iowa
Southern Utilities Company (IS) as result of merger of
IS and IE) and The Northern Trust Company (The First
National Bank of Chicago, successor) and Harold H.
Rockwell (Richard D. Manella, successor), as Trustees
(1923 Indenture) (Filed as Exhibit B-1 to File No. 2-
1719).
4(f) Supplemental Indentures to the 1923 Indenture:
Dated as of File Reference Exhibit
May 1, 1940 2-4921 B-1-k
May 2, 1940 2-4921 B-1-l
October 1, 1945 2-8053 7(m)
October 2, 1945 2-8053 7(n)
January 1, 1948 2-8053 7(o)
September 1, 1950 33-3995 4(e)
February 1, 1953 2-10543 4(b)
October 2, 1953 2-10543 4(q)
August 1, 1957 2-13496 2(b)
September 1, 1962 2-20667 2(b)
June 1, 1967 2-26478 2(b)
February 1, 1973 2-46530 2(b)
February 1, 1975 2-53860 2(aa)
July 1, 1975 2-54285 2(bb)
September 2, 1975 2-57510 2(bb)
March 10, 1976 2-57510 2(cc)
February 1, 1977 2-60276 2(ee)
January 1, 1978 0-849 2
March 1, 1979 0-849 2
March 1, 1980 0-849 2
May 31, 1986 33-3995 4(g)
July 1, 1991 0-849 4(h)
September 1, 1992 0-849 4(m)
December 1, 1994 0-4117-1 4(f)
4(g) Credit Agreement dated as of March 5,
1992 among IES Diversified Inc. as Borrower, certain
banks and Citibank, N.A., as Agent. (Filed as Exhibit
4(p) to Company's Form 10-K for the year 1991).
4(h) Amended and Restated Credit Agreement
dated as of January 7, 1993 among IES Diversified Inc.
as Borrower, certain banks and Citibank, N.A., as
Agent. (Filed as Exhibit 4(v) to the Company's Form 10-
K for the year 1992).
* 4(i) Second Amended and Restated Credit
Agreement dated as of November 9, 1994 among IES
Diversified Inc. as Borrower, certain banks and
Citibank, N.A., as Agent.
10(a) Agreement dated December 15, 1971
between Central Iowa Power Cooperative and IE. (Filed
as Exhibit 5(a) to IE's Registration Statement, File
No. 2-43131).
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) Fuel Lease dated August 21, 1973, as
amended by Amendment No. 1 dated August 29, 1973, and
by Amendment dated September 17, 1987, between Arnold
Fuel, Inc. and IE for the procurement and financing of
nuclear fuel. (Filed as Exhibit 10(l) to IE's Form
10-K for the year 1984).
10(h) Amendment dated as of September 17, 1987
to the Fuel Lease dated as of August 21, 1973 between
Arnold Fuel, Inc. and IE. (Filed as Exhibit 10(i) to
IE's Form 10-K for the year 1987).
10(i) 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(j)
through 10(t))
10(j) Service Contract between S. Levy,
Incorporated and IE. (Filed as Exhibit 10(m) to IE's
Form 10-K for the year 1985).
10(k) Supplemental Retirement Plan. (Filed as
Exhibit 10(l) to the Company's Form 10-K for the year
1987).
10(l) Management Incentive Compensation Plan.
(Filed as Exhibit 10(m) to the Company's Form 10-K for
the year 1987).
10(m) Key Employee Deferred Compensation Plan.
(Filed as Exhibit 10(n) to the Company's Form 10-K for
the year 1987).
10(n) Long-Term Incentive Plan. (Filed as
Exhibit 10(o) to the Company's Form 10-K for the
year 1987).
10(o) Executive Guaranty Plan. (Filed as
Exhibit 10(p) to the Company's Form 10-K for the
year 1987).
10(p) Executive Change of Control Severance
Agreement. (Filed as Exhibit 10(s) to the Company's
Form 10-K for the year 1989).
10(q) Amendments to Key Employee Deferred
Compensation Agreement for Directors. (Filed as
Exhibit 10(u) to the Company's Form 10-Q for the
quarter ended March 31, 1990).
10(r) Amendments to Key Employee Deferred
Compensation Agreement for Key Employees. (Filed as
Exhibit 10(v) to the Company's Form 10-Q for the
quarter ended March 31, 1990).
10(s) Amendments to Management Incentive
Compensation Plan. (Filed as Exhibit 10(y) to the
Company's Form 10-Q for the quarter ended March 31,
1990).
10(t) Director Retirement Plan. (Filed as
Exhibit 10(t) to the Company's Form 10-K for the year
1993).
10(u) Agreement and Plan of Merger, dated as
of February 27, 1991, by and between IE Industries Inc.
and Iowa Southern Inc. (Filed as Exhibit 2 to the
Company's Form 8-K dated February 27, 1991).
10(v) IES Industries Inc. Shareholders' Rights
Plan. (Filed as Exhibit I-2 to the Company's
Registration Statement on Form 8-A filed November 13,
1991).
10(w) Restated Agreement and Plan of Merger
among IES Industries Inc., WPC Acquisition Corp. and
Whiting Petroleum Corporation dated November 15, 1991.
(Filed as Annex A to the Company's Form S-4
Registration Statement No. 33-44495).
10(x) 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(y) Lease and Security Agreement, dated
October 1, 1993, between IES Diversified Inc., as
lessee, and Sumitomo Bank Leasing and Finance, Inc., as
lessor. (Filed as Exhibit 10(z) to the Company's Form
10-K for the year 1993).
10(z) Receivables Purchase and Sale Agreement dated as
of June 30, 1989, as Amended and Restated as of April
15, 1994, among IES Utilities Inc. (as Seller) and
CIESCO L.P. (as the Investor) and Citicorp North
America, Inc. (as Agent). (Filed as Exhibit 10(a) to
Utilities' Form 10-Q for the quarter ended March 31,
1994 (File No. 0-4117-1)).
10(aa) Agreement and Plan of Merger among IES Industries
Inc., WOC Acquisition Company, Okie Crude Company, Elba
Gas Company, Kimble Gas Gathering Company, Thomas M.
Atkinson and Joan B. Atkinson, dated as of March 25,
1994. (Filed as Exhibit 10(b) to Company's Form 10-Q
for the quarter ended March 31, 1994).
10(ab) IES Diversified Inc. Guaranty with McLeod, Inc.,
dated May 16, 1994 (Filed as Exhibit 10(c) to Company's
Form 10-Q for the quarter ended June 30, 1994).
10(ac) Agreement Regarding Guarantee Between McLeod, Inc.
and IES Diversified Inc., dated May 16, 1994 (Filed as
Exhibit 10(d) to Company's Form 10-Q for the quarter
ended June 30, 1994).
10(ad) Guaranty (IES Utilities Trust No. 1994-A) from IES
Utilities Inc., dated as of June 29, 1994. (Filed as
Exhibit 10(b) to Utilities' Form 10-Q for the quarter
ended June 30, 1994 (File No. 0-4117-1)).
10(ae) Agreement and Plan of Merger between IE and IS
dated as of June 4, 1993 (Agreement and Plan of Merger)
(Filed as Exhibit 2 to the Company's Current Report on
Form 8-K, dated June 4, 1993).
10(af) 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(ag) 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(ah) Amendment 3 dated September 27, 1993, to the
Agreement and Plan of Merger (Filed as Exhibit 2(d) to
the Company's Current Report on Form 8-K, dated
December 9, 1993).
* 21 Subsidiaries of the Registrant.
* 23 Consent of Independent Public Accountants.
* 27 Financial Data Schedule
Note: Pursuant to (b)(4)(iii)(A) of Item 601 of
Regulation S-K, the Company has not filed as an exhibit
to this Form 10-K certain instruments with respect to
long-term debt that has not been registered if the
total amount of securities authorized thereunder does
not exceed 10% of total assets of the Company but
hereby agrees to furnish to the Commission on request
any such instruments.