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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, 1993
OR
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
For the transition period from to
Commission file number 0-4117-1
IES UTILITIES INC.
(Exact name of registrant as specified in its charter)
Iowa 42-0331370
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
IE 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: None
Securities registered pursuant to Section 12(g) of the Act:
Cumulative Preferred Stock Par Value $50 per share 4.80%
(Title of class)
Indicate by check mark 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 (l) 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, 1994 was $0.
Indicate the number of shares outstanding of each of the registrant's classes
of Common Stock, as of February 28, 1994.
Common Stock, $2.50 par value - 13,370,788 shares
PART I
Item l. Business
IES Utilities Inc. (the Company) is a wholly-owned subsidiary of IES
Industries Inc. (Industries). On June 4, 1993, Industries announced that its
wholly-owned utility subsidiaries, Iowa Electric Light and Power Company (IE)
and Iowa Southern Utilities Company (IS), filed applications for regulatory
authority to merge. The merger became effective December 31, 1993, following
receipt of all necessary Boards of Directors, shareholder and regulatory
approvals. IE is the surviving corporation and has been renamed IES Utilities
Inc. The separate existence of IS has ceased.
The Company is 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. The Company provided service
to approximately 325,000 electric and 170,000 natural gas retail customers as
well as 32 resale customers in more than 550 Iowa communities at
December 31, 1993. See Note 3 of the Notes to Financial Statements for a
discussion of the Company's acquisition on December 31, 1992, of the Iowa
retail service territory from Union Electric Company (UE).
The Company's sales of electricity (in Kwh), excluding off-system sales,
increased (decreased) 25%, (1.5%) and 5.3%, during the years 1993-1991,
respectively. The 1993 increase is attributable to the acquisition of the UE
service territory and a return to more normal weather conditions. The 1992
results were adversely affected by extremely mild weather conditions in the
Company's service territory. Total gas delivered by the Company, including
transported volumes, increased (decreased) 5.3%, (0.3%) and 1.8% during the
years 1993-1991, respectively.
The approximate percentages of the Company's revenue and operating
income before income taxes and interest derived from the sale of electricity
and gas during the years 1993-1991 are as follows:
1993 1992 1991
Revenues:
Electric 77% 76% 78%
Gas 22 23 21
Operating income before
income taxes and interest:
Electric 90% 91% 99%
Gas 10 8 0
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 billed to customers through fuel adjustment
clauses. The 1991 gas operating income was affected by a $3.9 million pre-tax
write-off of previously deferred Former Manufactured Gas Plant (FMGP) clean-up
costs pursuant to disallowance of recovery in an Iowa Utilities Board (IUB)
order.
For additional information concerning electric and gas operations, see
Item 7. "Management's Discussion and Analysis of the Results of Operations and
Financial Condition" and the Electric and Gas Operating Comparisons.
Other Information Relating to the Company
CONSTRUCTION AND ACQUISITION PROGRAM AND FINANCING. The capital
requirements, including $3.3 million of sinking funds that may be met by
pledging additional utility property, for the period 1994-1998 are estimated
at $882 million and are summarized as follows:
Capital Requirements
1994 1995 1996 1997 1998
(in thousands)
Construction expenditures
(excluding allowance
for equity funds used
during construction)-
Electric:
Generation $ 42,157 $ 57,032 $ 55,799 $ 51,512 $ 64,892
Transmission 26,225 28,136 22,465 26,318 21,110
Distribution 35,385 25,868 23,134 33,028 39,724
Other 9,493 7,079 7,314 7,581 7,831
Gas and other 35,972 31,762 35,760 31,871 27,179
Total construction
expenditures 149,232 149,877 144,472 150,310 160,736
Long-term debt
sinking funds and
maturities 1,004 100,920 15,770 8,690 690
Total capital
requirements $ 150,236 $ 250,797 $ 160,242 $ 159,000 $ 161,426
The Company intends to refinance the majority of the debt maturities
with long-term debt.
Approximately 36% of the Company's construction expenditures are related
to generation. Of this amount, approximately 53% represents capacity
expansions and other improvements at generating stations, 37% represents
modifications and improvements at the Duane Arnold Energy Center (DAEC) and
10% represents expenditures related to compliance with the Clean Air Act
Amendments Act of 1990.
For a discussion regarding the Company's assumptions in financing future
capital requirements, see the "Liquidity and Capital Resources" section of
Item 7. "Management's Discussion and Analysis of the Results of Operations and
Financial Condition."
REGULATION. The Company operates pursuant to the laws of the State of
Iowa and is thereby subject to the jurisdiction of the 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, all electric utilities are required by law to define
the boundaries of mutually exclusive service territories. The IUB has
jurisdiction and grants franchises for the use of public highway rights-of-way
for electric and gas facilities outside corporate limits.
The Company is subject to the jurisdiction of the Federal Energy
Regulatory Commission (FERC) with respect to wholesale electric sales and the
issuance of securities. Revenues derived from the Company's wholesale and
off-system sales amounted to 9.0%, 10.1% and 11.7% of electric revenues for
1993-1991, respectively.
EMPLOYEES. At December 31, 1993, the Company had a total of 2,255
regular full-time employees, of which an aggregate of 1,134 employees were
subject to six collective bargaining arrangements.
RATE MATTERS. Refer to Note 4 of the Notes to Financial Statements for
a discussion of the Company's rate matters.
ELECTRIC OPERATIONS. The Company's net peak load (60 minutes
integrated) of 1,716,380 kilowatts occurred on August 26, 1993. At the time
of the peak load five customers were interrupted representing 53,294 kilowatts
of a possible 231,594 kilowatts available for interruption. The Company's
additional reserve obligation at that time was 214,861 kilowatts. The net
capability of the Company's generating stations at the time of this peak load
was 1,733,700 kilowatts, with an additional 248,000 kilowatts being available
under purchase contracts, thereby providing an aggregate capability of
1,981,700 kilowatts.
In order to meet its electric demand, the Company has firm contracts for
the purchase of capacity. See Note 12(b) of the Notes to Financial Statements
for a discussion of these contracts.
The Company is interconnected with other utilities in Iowa and
neighboring states and is a member of the Mid-Continent Area Power Pool
(MAPP). MAPP's purpose is to coordinate the planning, construction and
operation of generation and transmission facilities, and the purchase and sale
of power and energy among its members.
In addition, the Company, Midwest Power Systems Inc. and Iowa-Illinois
Gas & Electric Company 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 Company is a party to the Twin Cities-Iowa-St. Louis 345 Kv
Interconnection Coordinating Agreement (the Coordinating Agreement) with five
other midwestern utilities, three of which operate in the State of Iowa. The
Coordinating Agreement provides for the interconnection of the respective
systems of the companies through a 345 Kv transmission line and for the
interchange of power on various bases. The rates under the Coordinating
Agreement are primarily determined by agreement between the delivering and
receiving companies.
The Company maintains and operates transmission and substation
facilities connecting with its high voltage transmission systems pursuant to a
noncancellable operating agreement (the Operating Agreement) with Central Iowa
Power Cooperative (CIPCO). The Operating Agreement, which will terminate on
December 31, 2035, provides for the joint use of certain transmission
facilities of the Company and CIPCO.
For comments relating to agreements between the Company and its partners
for the joint ownership of the DAEC, the Ottumwa Generating Station (OGS), and
Neal Unit No. 3, see "Item 2. Properties."
FUEL SUPPLY. The following table details the sources of the electricity
sold by the Company during 1993 and expected sources for the following three
years:
Actual /-------- Expected --------\
1993 1994 1995 1996
Fossil, primarily coal 46% 61% 64% 64%
Nuclear 20 29 24 24
Purchases 34 10 12 12
100% 100% 100% 100%
The above percentages assume nuclear refueling outages will occur during
both 1995 and 1996. There also was a refueling outage in 1993. The 1993 and
1994 purchases include purchases by the Company from Terra Comfort Corporation
(a wholly-owned subsidiary of Industries). The increase in the expected
fossil percentages from the 1993 actual is a function of lower projected fuel
costs for 1994-1996. In addition, the Company anticipates the availability
and efficiency of its fossil generating stations to be greater in 1994-1996
due to improvements made to the stations in recent years.
The Company's primary fuel source is coal and the generation mix is
influenced directly by refueling outages at the DAEC. The average cost of
fuel used for generation by the Company for the years 1993-1991 is presented
below:
1993 1992 1991
Average cost of fuel:
Nuclear, per million Btu's $ .60 $ .55 $ .65
Coal, per million Btu's .97 1.08 1.18
Average for all fuels, per
million Btu's .90 .93 .98
The following table summarizes the Company's minimum coal contract
commitments:
Average Maximum estimated base price
Annual per ton of coal delivered
Quantity Termination Sulfur
(Tons) Date Content 1994 1995 1996
Cordero
Mining
Co. (OGS) (1) 787,000 12/31/01 0.6% $ 18.94 $ 19.22 $ 19.51
Koch Carbon Inc. 100,000 12/31/99 6.2 18.98 19.23 19.48
Exxon Coal USA
Inc. (Neal
No. 3) (1) 214,000 12/31/94 0.6% 13.21 N/A N/A
Short-term
contracts (2) 12/31/94 (2) 14.07 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) Tonnage may range from 1,600,000 to 2,200,000 annual tons with
sulfur contents from 0.35% to 1.0%. Certain contracts contain
options for adjusting the shipments plus or minus 25%.
During 1993, the Company purchased a total of 3,342,898 tons of coal for
its generating plants.
At December 31, 1993, the Company had coal inventory at its principal
generating stations ranging from 43 to 93 days' usage during high demand
periods or a weighted average of 65 days' usage.
The Company estimates that its existing coal fired generating units will
require approximately 12,390,000 tons of coal to operate during the period
1994-1996. The Company 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 the Company's contracted coal supply is provided by surface
mining operations which are regulated by the Federal Strip Mine Act. Most of
the surface mining coal contracts contain clauses which pass reclamation and
royalty costs through to the respective utility; such costs billed to the
Company are recoverable through its Energy Adjustment Clauses (EAC). See Note
2(g) of the Notes to Financial Statements for discussion of the EAC.
The Company 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 the Company with sufficient UF6 to cover its needs
through the 1995 refueling. Plans are currently being developed for purchase
of additional uranium. Such uranium is being held without charge by the
United States Department of Energy (DOE) under a usage agreement between the
DOE and the Company, which allows the Company to retrieve the material as
needed. 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. Fabrication of the
nuclear fuel is being performed by General Electric Company for fuel through
the 2008 refueling of the DAEC. See Note 12(h) of the Notes to Financial
Statements for a discussion of the Company's assessment under the National
Energy Policy Act of 1992 for the "Uranium Enrichment Decontamination and
Decommissioning Fund," which is based upon prior nuclear fuel purchases.
The Company will be required to store its spent fuel until such time as
it can be shipped off site for storage or disposal. Additional in-plant
storage capability at the DAEC was installed in order to provide an interim
solution through approximately the year 1998. The Company has also signed a
contract with the DOE in which the DOE agrees to assume the responsibility for
the ultimate disposal of spent nuclear fuel beginning in 1998. The DOE has
proposed delaying the start-up date of the final repository until 2010. The
Company is taking additional measures regarding spent nuclear fuel storage and
anticipates spending approximately $1.9 million during 1994 to increase
in-plant storage capacity. This increase in capacity is currently projected
to provide storage capability through 2002, however, this may vary depending
on actual fuel usage during this time.
GAS OPERATIONS. With the advent of FERC Order 636 (Order 636),
effective in 1993, the nature of the Company's gas supply portfolio has
changed. Traditionally, the interstate pipelines serving the Company
(Northern Natural Gas Company (Northern) serving 51%, Natural Gas Pipeline
Company of America (Natural) serving 27% and ANR Pipeline Company (ANR)
serving 22%) were obligated to supply natural gas to the Company under peak
day conditions up to pre-determined contract levels. Order 636, among other
things, eliminated the interstate pipelines' obligation to serve as gas
suppliers and now requires the Company to purchase virtually 100% of gas
supply requirements from non-pipeline suppliers.
Order 636, as modified on rehearing, (1) requires the Company's 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 the Company) 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.
The Company may benefit from enhanced access to competitively priced gas
supply and more flexible transportation services as a result of Order 636.
However, the Company will be required to pay certain transition costs passed
on from its pipeline suppliers as they implement Order 636.
The Company's three pipeline suppliers have filed new tariffs with the
FERC implementing Order 636 and the pipelines have also made filings with the
FERC to begin collecting their respective transition costs. The Company began
paying the transition costs in November 1993, and has recorded a liability of
$5.0 million for such transition costs that have been incurred by the
pipelines to date, including $1.7 million expected to be billed in 1994.
While the magnitude of the total transition costs to be charged to the Company
cannot yet be determined, the Company believes any transition costs the FERC
would allow the pipelines to collect would be recovered from its customers,
based upon past regulatory treatment of similar costs by the IUB.
Accordingly, regulatory assets, in amounts corresponding to the liabilities,
have been recorded to reflect the anticipated recovery.
As a result of each pipeline's Order 636 compliance filing, which became
effective November 1, 1993, for Northern and ANR and December 1, 1993, for
Natural, the Company restructured its gas supply portfolio to reflect
elimination of the pipelines' merchant service.
Contracts with the pipelines subsequent to Order 636 are comprised
primarily of firm transportation, firm storage and no-notice service. Firm
transportation contracts grant the Company access to firm pipeline capacity
which is used to transport gas supplies from non-pipeline suppliers on peak
day. Firm storage service allows the Company to purchase gas during off-peak
periods, and place this gas in an account with the pipelines. When the gas is
needed for peak day deliveries, the Company requests and the pipelines
deliver the gas back on a firm basis. No-notice service is a new service
offered as a result of Order 636. No-notice service grants the Company 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.
The Company's portfolio of firm transportation, firm storage and no-
notice service from pipelines is as follows:
Firm Firm
Transportation Storage No-Notice
Northern:
Volume (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, the Company 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 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 1993, the Company's maximum daily
load occurred on February 17, 1993, with total system flow of 268,419
dekatherms and total contract availability of 274,570 dekatherms.
As a result of Order 636, the Company accepted assignment of certain gas
supply contracts previously held by Northern. Accepting assignment of these
contracts is expected to result in lower costs to the Company than would have
been incurred had Northern bought out the agreements and billed the Company
for its share of such costs.
Contracts assigned to the Company from Northern have maximum delivery
requirements of 29,941 Dth, and minimum take requirements of 5,077 Dth, under
contracts ranging in length from one to fifteen years.
Additional firm gas supply agreements were independently negotiated by
the Company. These gas supply agreements have maximum and minimum obligations
as follows:
Maximum Minimum
Daily Daily
Quantity Quantity
(Dth/day) (Dth/day)
Northern 61,029 29,071
Natural 24,075 19,575
ANR 30,155 20,578
Terms on these gas supply contracts range from five months to five
years.
Rates charged by the Company's pipeline suppliers are subject to
regulation by the FERC. A purchased gas adjustment clause (PGA) allows the
Company to adjust customer rates as a result of changes in the cost of gas
purchased. See Note 2(g) of the Notes to 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, the Company
is subject to the jurisdiction of the NRC. The NRC has broad supervisory and
regulatory jurisdiction over the construction and operation of nuclear
reactors, particularly with regard to public health, safety and environmental
considerations.
The operation and design of nuclear power plants is under constant
review by the NRC. The Company has complied with and is currently complying
with all NRC requests for data relating to these reviews. As a result of such
reviews, further changes in operations or modifications of equipment may be
required, the cost of which cannot currently be estimated.
The NRC issued Generic Letter 88-20 which has required all licensees to
perform an evaluation of their plant's vulnerability to accidents that lead to
the melting of the nuclear core. The initial phase of this effort has been
completed, with the conclusion that an adequate level of safety exists. The
NRC has required an additional evaluation for accidents related to external
events; expenditures have been $0.3 million through 1993 and are estimated to
be an additional $0.4 million through 1995. The results of this evaluation
could indicate that additional safety improvements may be necessary.
Past performance of the Main Steam Isolation Valves (MSIVs) and the High
Pressure Coolant Injection System (HPCI) at the DAEC has required costly
repairs and has generated regulatory concern. The Company has worked with
General Electric to improve the performance of these systems. Through 1993,
$11.0 million has been spent on improvements to these systems. Performance
improvements have been realized and future related expenditures are expected
to be significantly lower. The amount of future expenditures continues to be
dependent on the performance of these systems.
Through 1993, $14.5 million has been expended for various security
system component and equipment upgrades at the DAEC. These upgrades are now
complete. The NRC has also issued new requirements for land vehicle intrusion
detection. The Company expects to spend approximately $2.2 million through
1995 to meet these requirements.
The large amount of change in regulations, designs and procedures that
occur for a nuclear power plant over a period of time presents a difficult
task to ensure that all affected design information documents, procedures and
specifications are continually updated. The Company has 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. Through 1993, $5.3 million had been
spent on these programs. It is expected that an additional $1.9 million will
be expended through 1996 for the implementation of these programs.
The NRC has significantly revised federal regulations that deal with
radiation exposure to workers. These changes will require the Company to make
substantial changes in its computer tracking programs, monitoring devices and
training programs for radiation protection. Also, in response to an industry
initiative to further lower radiation exposure to workers, the Company is
undertaking a program to reduce the amount of a particular metal which
develops high radiation characteristics as the reactor is operated. The
Company has spent $4.5 million through 1993 and considers these programs to be
virtually completed.
The NRC has expressed concern to licensees over use of thermolag fire
proofing material in nuclear power plants. The Company anticipates spending
approximately $1.5 million through 1995 to determine if any deficiencies
exist.
A high level radioactive waste depository to be built under the
direction of the Department of Energy will not be ready for use before the
DAEC loses full core discharge capability in 1998. The Company has elected
to increase its spent fuel storage capability to allow for continued full
core discharge through 2002. The Company has expended $3.9 million through
1993 and anticipates expending an additional $1.9 million to complete this
portion of the project by the end of 1994.
Under the Price-Anderson Amendments Act of 1988 (1988 Act), the Company
currently has the benefit of $9.4 billion of public liability coverage which
would compensate the public in the event of an accident at a commercial
nuclear power plant. See Note 12(e) of the Notes to Financial Statements for
a discussion of the Company's exposure to retroactive premium assessments.
The 1988 Act permits such coverage to rise with increased availability of
nuclear insurance and the changing number of operating nuclear plants subject
to retroactive premium assessments. The 1988 Act provides for inflation
indexing (Consumer Price Index every fifth year) of the retroactive premium
assessments.
As an outgrowth of the Three Mile Island Nuclear Power Plant (TMI)
experience, nuclear plant owners have initiated a cooperative insurance
program designed to help cover replacement power expenses for participating
utilities arising from a possible nuclear plant accident. The Company is a
participant in this program. This type of insurance is an industry response
intended to lessen the cost burden on customers in the event of a lengthy
plant shutdown.
To provide this coverage, a nuclear utility mutual insurance company
known as Nuclear Electric Insurance Limited (NEIL) was formed. Under the
Company's policy, following a 21 week waiting period from the time of an
accident, coverage of up to 100% of estimated replacement power costs for an
ensuing one year period is provided and up to 67% of that amount will be
provided for a second and third year. The annual premium cost to the Company
is estimated to be less than the cost of replacement power for one week.
The Company currently carries primary property insurance coverage on the
DAEC facility of $500 million with the Nuclear Insurance Pools (American
Nuclear Insurers & 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, the Company 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 also 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
Financial Statements. The NRC established requirements with respect to
guaranteeing the ability of owners to make such retroactive payments on the
public liability policy. Of the various alternatives available, the Company
elected to submit certified financial statements showing that sufficient cash
flow could be generated and would be available for payment of the required
assessments within a three month period. The maximum of the annual
retroactive premiums was approximately $7 million at December 31, 1993.
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.
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(h) of
the Notes to 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 Company is unable to predict the ultimate impact of the
Energy Act on its operations.
ENVIRONMENTAL MATTERS. In addition to the regulations imposed by the
NRC, 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 Act 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
Act 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 the Company will be
recovered from its ratepayers under current regulatory principles. Refer to
Notes 12(a) and 12(g) of the Notes to Financial Statements for additional
information regarding the Company's expected capital expenditures.
The Company has been named as a Potentially Responsible Party (PRP) for
certain FMGP sites by either the Iowa Department of Natural Resources (IDNR)
or the United States Environmental Protection Agency (EPA). The Company is
working with the IDNR and EPA to investigate its 27 sites and to determine the
appropriate remediation activities that may be needed to mitigate health and
environmental concerns.
At December 31, 1993, the Company had recorded $13.1 million of
environmental liabilities, which, pursuant to generally accepted accounting
principles, represents the minimum amount of the estimated range of such costs
which the Company expects to incur. These estimates are subject to continuing
review and could ultimately exceed the recorded amounts.
The Company is investigating the possibility of insurance and third
party cost sharing for FMGP clean-up costs. The amount of shared costs, if
any, cannot be reasonably determined and, accordingly, no potential sharing
has been recorded. Consistent with past rate treatment, management
believes that the clean-up costs incurred by the Company for these FMGP
sites will not have a material adverse effect on the financial position
or results of operations of the Company. Refer to Note 12(f) of the
Notes to Financial Statements for more information.
The Company 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 the Company 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 the Company is participating in its activities. Low-level
radioactive wastes were the only materials contributed to the site by the
Company. Such contributions comprise only 0.28% of the total volumes
deposited by all contributors.
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. The Company's portion of the costs of the remedial activities,
including the ultimate clean-up, are currently estimated at $275,000 which is
included in the $13.1 million of environmental liabilities the Company has
recorded at December 31, 1993. The Company has notified its nuclear insurance
carriers of the proceedings.
The Low-Level Radioactive Waste Policy Amendments Act of 1985 (Act),
which mandates that by January 1, 1993, each state must take responsibility
for the storage of low-level radioactive waste produced within its borders,
will have an impact on disposal practices for low-level radioactive waste over
the next several years. The State of Iowa has joined the Midwest Interstate
Low-Level Radioactive Waste Compact Commission (Midwest Compact Commission),
which is planning a storage facility to be located in Ohio to store waste
generated by the six states in the Midwest Compact Commission. At December
31, 1993, the Company has prepaid costs of $1.1 million (included in "Current
assets - Prepayments and other" in the Balance Sheets) to the Midwest Compact
Commission for the building of such a facility. Due to the legal and
political concerns, the Company cannot estimate the future payments, if any,
that will be made to the Midwest Compact Commission.
Prior to January 1, 1993, the Company and the other members of the
Midwest Compact Commission shipped their low-level wastes to waste management
facilities in Barnwell, South Carolina, Hanford, Washington and Beatty,
Nevada. The Southeast Interstate Low-Level Radioactive Waste Management
Compact Commission permits access to the Barnwell, South Carolina disposal
facility for disposal of low-level radioactive waste at the normal disposal
fee plus an access surcharge of $220 per cubic foot and pursuant to certain
additional contract provisions. Currently, the Company will be required to
store its low-level radioactive waste on site after June 30, 1994, until new
disposal arrangements are finalized among the Midwest Compact Commission
members. On-site storage capability currently exists for low-level
radioactive waste expected to be generated through 1998 and work is in
progress to increase the capability to allow for continued full core discharge
through 2002.
In February 1993, the NRC proposed a rule which would not permit on-site
storage of low-level radioactive waste after January 1, 1996, unless the
generator of such waste can document that it has exhausted other reasonable
waste management options. The Company is currently investigating its options
for the disposal of its low-level radioactive waste.
Refer to Note 12 of the Notes to Financial Statements and Item 3. "Legal
Proceedings" for further discussion of environmental matters.
IES UTILITIES INC.
ELECTRIC OPERATING COMPARISON
Five year
rate of
1993 1992 1991 1990 1989 1988 growth (1)
Operating revenue (000's):
Residential and Rural $206,561 $177,625 $189,194 $185,302 $175,899 $180,520
Commercial 145,898 124,829 124,320 119,908 112,662 110,587
Industrial 137,595 103,886 100,733 97,788 94,222 97,723
Street lighting and public
authorities 6,098 5,410 6,332 6,478 6,282 6,378
Total from ultimate
consumers 496,152 411,750 420,579 409,476 389,065 395,208
Sales for resale 20,254 18,602 19,745 19,582 18,214 17,104
Off-system 29,400 28,304 36,596 31,144 28,281 30,332
Other 4,715 4,343 5,658 3,047 2,973 3,015
$550,521 $462,999 $482,578 $463,249 $438,533 $445,659
Energy sales (000's Kwh):
Residential and Rural 2,528,220 2,158,768 2,367,979 2,254,913 2,222,152 2,269,001 2.2%
Commercial 2,078,635 1,771,357 1,764,495 1,686,132 1,626,046 1,579,086 5.7%
Industrial 3,674,217 2,612,803 2,467,533 2,312,109 2,236,388 2,359,596 9.3%
Street lighting and public
authorities 63,174 60,991 87,022 88,305 86,635 88,870 (6.6%)
Total to ultimate
consumers 8,344,246 6,603,919 6,687,029 6,341,459 6,171,221 6,296,553 5.8%
Sales for resale 561,276 528,752 557,180 538,677 500,253 463,172 3.9%
Sales of electricity to
customers 8,905,522 7,132,671 7,244,209 6,880,136 6,671,474 6,759,725 5.7%
Off-system 2,068,015 2,275,616 2,738,159 2,282,204 1,959,828 2,075,037 (0.1%)
10,973,537 9,408,287 9,982,368 9,162,340 8,631,302 8,834,762 4.4%
Sources of electric energy (000's Kwh):
Generation -
Fossil, primarily coal 5,356,930 4,317,154 4,758,720 4,354,697 4,063,974 4,403,738
Nuclear (2) 2,264,507 2,402,501 2,902,768 2,108,100 2,228,068 2,214,243
Hydro 7,201 7,579 6,547 4,195 1,902 3,300
7,628,638 6,727,234 7,668,035 6,466,992 6,293,944 6,621,281
Purchases 3,949,296 3,322,182 2,994,216 3,282,886 2,891,808 2,810,225
11,577,934 10,049,416 10,662,251 9,749,878 9,185,752 9,431,506
Net capability at time of peak load (Kw) -
Generating capability 1,733,700 1,718,600 1,719,150 1,684,700 1,633,000 1,632,500
Purchase capability 248,000 207,000 227,000 179,000 170,000 90,000
Capacity credits (3) 0 0 0 18,960 20,650 0
1,981,700 1,925,600 1,946,150 1,882,660 1,823,650 1,722,500 2.8%
Net peak load (Kw) (4) 1,716,380 1,425,441 1,607,606 1,547,826 1,486,243 1,543,864 2.1%
Number of customers at year-end 327,265 325,172 305,663 304,265 302,632 300,701 1.7%
Revenue per Kwh (excluding
off-system) in cents 5.85 6.09 6.16 6.28 6.15 6.14
(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.
(3) Represents capacity credits from municipals served by IES Utilities.
(4) 60 minutes integrated.
IES UTILITIES INC.
GAS OPERATING COMPARISON
Five year
compound
rate of
1993 1992 1991 1990 1989 1988 growth
Operating revenue (000's):
Residential $90,462 $78,685 $74,114 $66,513 $68,751 $71,484
Commercial 45,528 39,780 37,614 35,378 38,035 38,918
Industrial 15,593 18,649 17,383 21,500 25,172 24,693
151,583 137,114 129,111 123,391 131,958 135,095
Other 2,735 2,341 1,908 1,884 1,923 1,514
$154,318 $139,455 $131,019 $125,275 $133,881 $136,609
Energy sales (000's dekatherms):
Residential 16,971 15,098 15,571 14,315 15,878 15,573 1.7%
Commercial 10,133 8,479 9,389 8,798 9,854 9,523 1.2%
Industrial 4,618 6,175 5,980 6,640 7,409 7,780 (9.9%)
31,722 29,752 30,940 29,753 33,141 32,876 (0.7%)
Industrial - transported
volumes 7,284 7,283 6,189 6,733 6,909 6,498 2.3%
Total volumes delivered 39,006 37,035 37,129 36,486 40,050 39,374 (0.2%)
Operating Statistics:
Cost per dekatherm of gas
purchased for resale $3.49 $3.36 $3.10 $3.23 $2.95 $3.42
Sendout capability at time of
peak demand
(in dekatherms) 274,570 273,270 266,563 267,443 271,140 300,231 (1.8%)
Peak daily sendout
(in dekatherms) 268,419 254,989 266,344 272,089 311,600 286,196 (1.3%)
Number of customers at year-end 170,719 167,813 164,078 161,794 160,792 159,931 1.3%
Revenue per dekatherm sold
(excluding transported volumes) $4.78 $4.61 $4.17 $4.15 $3.98 $4.11
Item 2. Properties
The Company's principal electric generating stations at December 31,
1993, are as follows:
Net
Kilowatts
Accredited
Major Generating
Name and Location of Station Fuel Type Capability
Duane Arnold Energy Center, Palo, Iowa Nuclear 371,000 (1)
Ottumwa Generating Station, Ottumwa, Iowa Coal 339,840 (2)
Prairie Creek Station, Cedar Rapids, Iowa Coal 234,000
Sutherland Station, Marshalltown, Iowa Coal 145,500
Sixth Street Station, Cedar Rapids, Iowa Coal 66,000
Peaking Turbines, Marshalltown, Iowa Oil 210,000
Diesel Stations, all in Iowa Oil 12,200
Burlington Generating Station, Burlington, Iowa Coal 211,800
Grinnell Station, Grinnell, Iowa Gas 47,200
George Neal Unit 3, Sioux City, Iowa Coal 144,200 (3)
Total generating capability 1,781,740
(1) The capability represents the Company's 70% ownership interest in
the 530,000 Kw generating station. The other owners are Central
Iowa Power Cooperative (20%) and Corn Belt Power Cooperative
(10%). The plant is operated by the Company.
(2) The Company owns 48% of this 708,000 Kw generating station. The
plant is operated by the Company.
(3) This represents the Company's 28% ownership interest in this
515,000 Kw generating station which is operated by an unaffiliated
utility.
At December 31, 1993, the transmission lines of the Company, operating
from 34,000 to 345,000 volts, approximated 4,259 circuit miles (all located in
Iowa). The Company owned 107 transmission substations (all located in Iowa)
with a total installed capacity of 8,426.4 MVa and 464 distribution
substations (all located in Iowa) with a total installed capacity of 2,445.3
MVa.
The Company's principal properties are suitable for their intended use
and are held subject to liens of indentures relating to its First Mortgage
Bonds.
Item 3. Legal Proceedings
On December 24, 1990, IS filed in the United States Federal District
Court (Court) for the Southern District of Iowa, a Complaint for Declaratory
and Other Relief against the Iowa Department of Transportation (IDOT) for
declaratory relief and contribution under CERCLA to recover costs that have
been and will be incurred by IS (subsequently the Company) in connection with
FMGP clean-up costs related to certain real property located in the City of
Burlington, Iowa, and nearby areas, including the Mississippi River. On
February 11, 1991, IDOT filed an Answer and Counterclaim against IS pursuant
to CERCLA, alleging that it had incurred costs and expenses in excess of $1.3
million responding to the release of contamination and requesting judgment
against IS for such costs and for all such future costs. Subsequently, in
correspondence to IS's counsel, IDOT alleged that it had incurred in excess of
$4.7 million in response costs.
On June 3, 1993, the Court approved a Settlement Agreement and Order
Confirming Settlement between IS (subsequently the Company) and IDOT. Under
the terms of the agreement, the Company and IDOT agreed to dismiss the suit
and countersuit discussed above. Additionally, the Company and IDOT have
agreed to a cost-sharing arrangement for future investigation and clean-up
costs at the Burlington site, whereby the Company will absorb the next $15
million of such costs and 75% of additional costs thereafter, to the extent
any such costs are incurred pursuant to clean-up plans acceptable to
regulatory agencies. The Company will also supervise the investigation and
clean-up activities.
Reference is made to Notes 4 and 12 of the Notes to Financial Statements
for a discussion of the Company's rate proceedings and environmental matters.
Also see Item 1. "Business - Environmental Matters."
Item 4. Submission of Matters to a Vote of Security Holders
At a special meeting of the IE preferred shareholders held on
October 22, 1993, the proposed merger of IE and IS was voted upon and
approved. A summary of the results of the vote is as follows:
Shares
Eligible
Shareholder Class to Vote For Against Abstain
4.30% preferred 120,000 110,917 - 308
4.80% preferred 146,406 91,625 267 2,535
6.10% preferred 100,000 63,174 - 2,853
The Company's sole common shareholder, Industries, approved the merger
on May 4, 1993.
PART II
Item 5. Market for the Registrant's Common Stock and Related Stockholder
Matters
All outstanding common stock of the Company is held by its parent
(Industries) and is not publicly traded.
The amounts of dividends declared for the last two years are as follows:
Quarter Dividends Declared
(000's)
1993
First Quarter $ 10,000
Second Quarter 5,700
Third Quarter 3,800
Fourth Quarter 11,800
$ 31,300
1992
First Quarter $ 13,231
Second Quarter 3,000
Third Quarter 4,462
Fourth Quarter 4,028
$ 24,721
Under terms of the Fifty-fifth and Fifty-sixth Supplemental Indentures
relating to Series W and Series X First Mortgage Bonds, the Company has 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 the Company or any
subsidiary of the Company, if after immediately giving effect to such payment,
distribution or retirement, (A) the principal amount of all outstanding
defined Unsecured Indebtedness 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 since December 31, 1987 plus
$50,000,000. Pursuant to these terms, at December 31, 1993, $18,209,000 of
retained earnings was restricted as to the payment of cash dividends. The
Company 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.
Item 6. Selected Financial Data
The following selected 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 1993-1991.
The 1993 results were affected by the acquisition of the Iowa service
territory from Union Electric Company, as discussed in Note 3 of the Notes to
Financial Statements. The 1989 results were affected by a $5.0 million pre-
tax estimated liability to pipeline suppliers recorded in 1988 and eliminated
in 1989 when the issue was favorably resolved. The Selected Financial Data
should be read in conjunction with the Financial Statements, the Notes to
Financial Statements and Management's Discussion and Analysis of the Results
of Operations and Financial Condition contained elsewhere in this report.
Year Ended December 31
1993 1992 1991 1990 1989
($ in thousands, except times interest earned)
Operating revenues $ 713,750 $ 610,262 $ 621,993 $ 595,477 $ 579,834
Operating income 103,919 78,939 78,293 72,446 80,029
Net income 67,970 45,291 47,563 45,969 53,454
Net income available
for common stock 67,056 43,562 45,393 43,569 50,849
Cash dividends declared
on common stock 31,300 24,721 45,321 49,516 45,323
Total assets 1,546,978 1,440,891 1,304,110 1,256,211 1,214,931
Times interest earned
before income taxes 3.64 2.67 2.93 3.04 3.36
Capitalization Ratios:
Common equity 50% 48% 49% 50% 49%
Preferred and
preference stock 2 2 4 4 5
Long-term debt 48 50 47 46 46
100% 100% 100% 100% 100%
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 during the years 1993 and 1992. See
Note 1 of the Notes to Financial Statements for a discussion of the merger
of Iowa Electric Light and Power Company (IE) and Iowa Southern Utilities
Company (IS), effective December 31, 1993, that formed the Company.
RESULTS OF OPERATIONS
The Company's net income increased $23.5 million during 1993 and
decreased $1.8 million during 1992. The 1993 results reflect the acquisition
of the Iowa service territory of Union Electric Company (UE) (as discussed in
Note 3 of the Notes to Financial Statements) and a return to more normal
weather conditions in the Company's service territory. The floods in Iowa
in 1993 did not significantly affect the Company's results of operations.
The 1992 results were adversely affected by extremely cool summer weather and
a mild winter in the Company's service territory.
The Company's operating income increased $25.0 million and $0.6 million
during 1993 and 1992, respectively, as compared to prior years. Reasons for
the changes in the results of operations are explained in the following
discussion.
ELECTRIC REVENUES
Electric revenues and Kwh sales (excluding off-system sales) increased
$87.5 million and 25%, respectively, during 1993. In 1992, electric revenues
and Kwh sales decreased $19.6 million and 1.5%, respectively. The 1993 sales
increase is attributable to the acquisition of the UE territory and a return
to more normal weather conditions. After adjusting for these items,
underlying electric sales increased 6% in 1993, which reflects the economic
growth in the industrial and commercial customer base.
The 1992 Kwh sales decrease reflects unusually mild weather conditions in
the Company's service territory. Residential sales, which are the most
weather sensitive, decreased 9.5%. However, industrial sales, which are less
sensitive to weather, increased approximately 5.5%. Adjusting for the
effects of weather, Kwh sales increased 2.7%, reflecting economic growth in
the Company's service territory.
The Company's 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 2(g) of the Notes
to Financial Statements for discussion of the EAC. The increase in electric
revenues for 1993 is primarily because of the sales increase and increased
recovery of fuel costs through the EAC.
The revenue decrease in 1992 was primarily related to the lower Kwh sales
discussed above and lower off-system sales to other utilities. A rate decrease
in the former IS service territory that became effective in September 1991
contributed to the revenue decrease to a lesser extent. These items were
partially offset by the effect of the rate increase in the former IE service
territory that became effective in December 1991. See Note 4(b) of the
Notes to Financial Statements for a discussion of the electric rate case
in the former IE service territory.
GAS REVENUES
Gas revenues increased $14.9 million and $8.4 million during 1993 and
1992, respectively. Gas sales in therms (including transported volumes)
increased 5.3% in 1993 and were flat in 1992. Gas sales also reflect the
effects of weather. Adjusting for the effects of weather, gas sales decreased
1.5% in 1993 and increased 1.5% in 1992.
The Company's tariffs include purchased gas adjustment clauses (PGA) that
are designed to currently recover the cost of gas sold. See Note 2(g) of the
Notes to Financial Statements for discussion of the PGA.
Gas revenues increased in 1993 and 1992 substantially because of
increased costs of gas recovered through the PGA and the effect of gas rate
increases in the former service territory of both IE and IS, that became
effective in September 1992. The 1993 sales increase also contributed
to the revenue increase for that year. See Note 4(a) of the Notes to
Financial Statements for a discussion of the gas rate increases.
STEAM REVENUES
Steam revenues increased $1.1 million during 1993 and decreased $0.6
million during 1992, primarily related to fluctuations in sales volumes among
large industrial customers.
OPERATING EXPENSES
Fuel for production increased $14.3 million in 1993 because of increased
availability of the Company's fossil-fueled generating stations, which
experienced extended maintenance outages in 1992, and because of increased
sales. Fuel for production decreased $17.8 million during 1992 primarily
because of a nuclear refueling outage at the Duane Arnold Energy Center
(DAEC), maintenance outages at the fossil-fueled generating stations and
the lower electric sales. There were refueling outages in 1993 and 1992, but
no such outage in 1991. The decrease in Kwh generation during the refueling
and maintenance outages was substantially replaced by purchased power.
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, in April 1993, of the purchase
power agreement with the City of Muscatine. (See Note 12(b) of the Notes
to Financial Statements). Purchased power increased $4.5 million in 1992
because of increased purchases during the refueling and maintenance outages,
partially offset by lower purchases related to lower off-system sales.
Gas purchased for resale increased $7.5 million and $5.1 million during
1993 and 1992, respectively. The increases are primarily because of increased
per unit gas costs, and in 1993, increased sales.
Other operating expenses increased $3.6 million in 1993 and decreased
$5.2 million during 1992. The 1993 increase is primarily because of
increased labor and benefit costs and higher electric and gas transmission
and distribution costs, partially offset by lower non-labor costs at the
DAEC. The 1992 decrease was substantially related to a regulatory
disallowance of $3.9 million recorded in April 1991, after the Iowa Utilities
Board (IUB) denied recovery of previously deferred former manufactured gas
plant (FMGP) clean-up costs. Lower non-labor costs at the DAEC and lower
Nuclear Regulatory Commission fees, partially offset by increased labor and
benefit costs, also affected 1992.
Maintenance expenses increased $6.6 million during 1993 and were flat in
1992. The 1993 increase is primarily because of increased maintenance at the
Company's fossil-fueled generating stations and the DAEC. The 1992 maintenance
expenses reflect increased maintenance at fossil-fueled generating stations,
substantially offset by lower maintenance costs at the DAEC.
Depreciation and amortization increased during both years primarily
because of increases in utility plant in service, including 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 both years include $5.5 million for the DAEC
decommissioning provision, which is collected through rates.
Property taxes increased $4.8 million during 1993, primarily because of
the acquisition of the UE service territory and increases assessed values.
Federal and state income taxes included in operating expenses increased
$18.0 million in 1993 primarily because of increases in taxable income and an
increase of 1% in the Federal statutory income tax rate. Such income taxes
decreased $1.9 million in 1992 primarily because of adjustments of
$1.5 million recorded in the second quarter of 1992 to previously recorded
tax reserves and a reduction in taxable income.
INTEREST EXPENSE
Interest expense (long-term debt and other combined) increased in 1993
and 1992 primarily because of an increase in the average amount of debt
outstanding. A reduction in the average interest rate in 1993 substantially
offset the effect of the higher average outstanding debt. 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. Interest expense related to the
Company's reserves for rate refunds also contributed to the increase in 1992.
LIQUIDITY AND CAPITAL RESOURCES
The Company's capital requirements are primarily attributable to its
construction programs and debt maturities. Cash and temporary cash investments
increased $16.6 million during 1993. In 1993, cash flows from operating
activities were $149 million. These funds were primarily used for construction
and acquisition expenditures and to pay dividends.
It is anticipated that the Company's 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. (See
Notes 4 and 12 of the Notes to Financial Statements). Access to the long-term
and short-term capital and credit markets is necessary for obtaining funds
externally.
The Company's 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
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 the Company 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. At December 31, 1993, the Company had $18.5 million of such costs
recorded as regulatory assets. The Company will make its initial filing for
recovery of the costs in 1994.
CONSTRUCTION AND ACQUISITION PROGRAM
The Company's construction and acquisition program anticipates
expenditures of $150 million for 1994, of which approximately 44% represents
expenditures for electric transmission and distribution facilities, 18%
represents fossil-fueled generation expenditures and 10% represents
nuclear generation expenditures. Substantial commitments have been made in
connection with such expenditures.
The Company's levels of construction and acquisition expenditures are
projected to be $149 million in 1995, $144 million in 1996, $149 million in
1997 and $160 million in 1998. It is estimated that approximately 80% of
construction expenditures will be provided by cash from operating activities
(after payment of dividends) for the five year period 1994-1998.
Capital expenditure and investment and financing plans are subject to
continual review and change. The capital expenditure and investment program
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 periodic sinking fund requirements which the Company intends to
meet by pledging additional property, $124 million of long-term debt, including
four series of First Mortgage Bonds aggregating $123 million, will mature prior
to December 31, 1998. The Company intends to refinance the majority of the
debt maturities with long-term debt.
In order to provide an up-to-date instrument for the issuance of bonds,
notes or other evidence of indebtedness, the Company 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 the Company's 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. Accordingly, to the extent that the
Company 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 the Company's first mortgages. Under the terms of the New
Mortgage, the Company 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.
In November 1993, the Company entered into arrangements with various
cities in the State of Iowa (Cities), whereby the Cities issued an aggregate
of $19.4 million of pollution control revenue refunding bonds (PCRRBs),
all at 5.5%, due 2023. Each series of the PCRRBs is secured, in part, by
payments on a corresponding principal amount of Collateral Trust Bonds, at
5.5%, due 2023. The proceeds received by the Company in the transaction were
used to redeem $10.2 million of Pollution Control Obligations, 5.75%, due
serially 1995-2003 and an aggregate of $9.2 million of First Mortgage Bonds,
Series P & Q, 6.7%, due 2006.
In October 1993, the Company sold $100 million aggregate principal amount
of Collateral Trust Bonds, 6% Series, due 2008, and 7% Series, due 2023. A
portion of the proceeds from the Collateral Trust Bonds was used to retire
short-term debt, with the balance used for general corporate purposes,
including support of the Company's construction program.
In May 1993, the Company redeemed First Mortgage Bonds Series K, 8-5/8%,
principal amount of $20 million, and Series R, 8-1/4%, principal amount of
$25 million and First Mortgage Bonds Series 8-3/4%, principal amount of $15
million. The redemptions were completed with proceeds from short-term
borrowings and, as discussed above, long-term debt was ultimately issued to
replace the short-term borrowings.
The Indentures pursuant to which the Company 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, 1993, such restrictions would have
allowed the Company to issue $258 million of additional First Mortgage Bonds.
The Company intends to file in the first quarter of 1994 with the FERC for
authority to issue $250 million of long-term debt. The Company is currently
authorized by the SEC to issue $50 million of long-term debt under an existing
registration statement. The Company expects to issue up to $150 million in
1994. The proceeds are expected to be used for the early redemption of three
series of First Mortgage Bonds aggregating $55 million, which have not yet
been called, and for general corporate purposes, including support of its
construction program.
The Articles of Incorporation of the Company authorize and limit the
aggregate amount of additional shares of Cumulative Preferred Stock and
Cumulative Preference Stock which may be issued. At December 31, 1993, the
Company could have issued an additional 700,000 shares of Cumulative Preference
Stock and 100,000 additional shares of Cumulative Preferred Stock.
The Company's capitalization ratios at year-end were as follows:
1993 1992
Long-term debt 48% 50%
Preferred stock 2 2
Common equity 50 48
100% 100%
SHORT-TERM FINANCING
For interim financing, the Company is authorized by the FERC to issue,
through 1994, up to $125 million of short-term notes. This availability of
short-term financing provides the Company flexibility in the issuance of
long-term securities. At December 31, 1993, the Company had outstanding
short-term borrowings of $24 million.
The Company has two agreements, both of which expire in 1994, with
separate financial institutions to sell up to $65 million of its utility
accounts receivable. The Company intends to consolidate the agreements
into one new agreement in 1994. At December 31, 1993, the Company had sold
$53.2 million under the agreements.
At December 31, 1993, the Company had bank lines of credit aggregating
$67.7 million and was using $19.0 million of its lines to support commercial
paper 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, the
Company has an uncommitted credit facility with a financial institution
whereby it can borrow up to $50 million. Rates are set at the time of
borrowing and no fees are paid to maintain this facility. At December 31,
1993, $5.0 million was borrowed at 3.4% under this facility. The Company
also has a letter of credit in the amount of $3.4 million supporting two
of its variable rate pollution control obligations.
EFFECTS OF INFLATION
Under the rate making principles prescribed by the regulatory commissions
to which the Company is subject, only the historical cost of plant is
recoverable in revenues as depreciation. As a result, the Company 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. The Company does not expect the effects of inflation at current
levels to have a significant effect on its results of operations.
Selected Quarterly Financial Data (unaudited)
The following unaudited 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.
Quarter Ended
March June September December
31 30 30 31
(in thousands)
1993
Operating revenues $193,784 $148,919 $187,392 $183,655
Operating income 24,100 18,095 36,095 25,629
Net income 14,422 10,491 26,213 16,844
Net income available
for common stock 14,193 10,262 25,985 16,616
1992
Operating revenues $166,494 $132,843 $145,003 $165,922
Operating income 17,721 15,755 26,034 19,429
Net income 9,522 7,501 17,561 10,707
Net income available
for common stock 9,022 7,002 17,059 10,479
The above amounts were affected by seasonal weather conditions and the
timing of utility rate changes. Rate activities are discussed in Note 4 of
the Notes to Financial Statements.
The 1993 results were affected by the acquisition of the Iowa service
territory from Union Electric Company, as discussed in Note 3 of the Notes
to Financial Statements. Refer to Management's Discussion and Analysis for
discussion of the adverse effect of weather upon 1992 results, primarily
in the third quarter.
Item 8. Financial Statements and Supplementary Data
Information required by Item 8. begins on page 48.
MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL STATEMENTS
The Company's management has prepared and is responsible for
the presentation, integrity and objectivity of the financial
statements and related information included in this report. The
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
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 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 & Co.), 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. No material internal control
weaknesses have been reported to management, nor is management
aware of any such weaknesses.
The Board of Directors, through its Audit Committee comprised
entirely of outside directors, meets periodically with
management, the internal auditor and Arthur Andersen & Co. to
discuss financial reporting matters, internal control and
auditing. To ensure their independence, both the internal
auditor and Arthur Andersen & Co. have full and free access to
the Audit Committee.
/s/ Lee Liu
(Signature)
Lee Liu
Chairman of the Board,
President & Chief
Executive Officer
/s/ Blake O. Fisher, Jr.
(Signature)
Blake O. Fisher, Jr.
Executive Vice President &
Chief Financial Officer
/s/ Richard A. Gabbianelli
(Signature)
Richard A. Gabbianelli
Controller & Chief
Accounting Officer
ARTHUR ANDERSEN & CO.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors of
IES Utilities Inc.:
We have audited the accompanying balance sheets and statements of
capitalization of IES UTILITIES INC. (an Iowa corporation) as of
December 31, 1993 and 1992, and the related statements of income,
retained earnings and cash flows for each of the three years in
the period ended December 31, 1993. These financial statements
and the financial statement schedules
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 schedules
based on our audits.
We conducted our audits in accordance with generally accepted
auditing standards. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether
the financial statements are free of material misstatement. An
audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating
the overall financial statement presentation. We believe that
our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above
present fairly, in all material respects, the financial position
of IES Utilities Inc. as of December 31, 1993 and 1992, and the
results of its operations and its cash flows for each of the
three years in the period ended December 31, 1993, 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
schedules listed in Item 14(a)2 are presented for purposes of complying
with the Securities and Exchange Commission's rules and are not part
of the basic financial statements. These schedules have been subjected
to the auditing procedures applied in the audits of the basic financial
statements and, in our opinion, fairly state in all material respects
the financial data required to be set forth therein in relation to the
basic financial statements taken as a whole.
As discussed in Note 8 to the financial statements, effective
January 1, 1993, IES Utilities Inc. changed its method of
accounting for postretirement benefits other than pensions.
/s/ Arthur Andersen & Co.
(Signature)
ARTHUR ANDERSEN & CO.
Chicago, Illinois,
January 28, 1994
IES UTILITIES INC.
STATEMENTS OF INCOME
Year Ended December 31
1993 1992 1991
(in thousands)
Operating revenues:
Electric $550,521 $462,999 $482,578
Gas 154,318 139,455 131,019
Steam 8,911 7,808 8,396
713,750 610,262 621,993
Operating expenses:
Fuel for production 87,702 73,368 91,182
Purchased power 93,449 74,794 70,245
Gas purchased for resale 109,122 101,605 96,504
Other operating expenses 123,210 119,607 124,855
Maintenance 46,219 39,573 39,571
Depreciation and amortization 69,407 64,107 61,466
Property taxes 36,426 31,586 31,770
Federal and state income taxes 39,411 21,422 23,307
Miscellaneous taxes 4,885 5,261 4,800
609,831 531,323 543,700
Operating income 103,919 78,939 78,293
Other income and deductions:
Allowance for equity funds used
during construction 824 1,831 820
Miscellaneous, net 2,248 2,803 3,950
3,072 4,634 4,770
Interest:
Long-term debt 34,926 35,689 31,171
Other 5,243 3,939 5,595
Allowance for debt funds used
during construction (1,148) (1,346) (1,266)
39,021 38,282 35,500
Net income 67,970 45,291 47,563
Preferred and preference dividend
requirements 914 1,729 2,170
Net income available for
common stock $ 67,056 $ 43,562 $ 45,393
The accompanying Notes to Financial Statements are an integral part of these
statements.
IES UTILITIES INC.
STATEMENTS OF RETAINED EARNINGS
Year Ended December 31
1993 1992 1991
(in thousands)
Balance at beginning of year $153,106 $134,822 $134,750
Add:
Net income 67,970 45,291 47,563
221,076 180,113 182,313
Deduct:
Cash dividends declared -
Common stock 31,300 24,721 45,321
Preferred stock, at stated rates 914 1,665 1,956
Preference stock, at stated rates - 64 214
Preferred stock redemption premiums - 557 -
32,214 27,007 47,491
Balance at end of year
($18,209,000 restricted as to payment
of cash dividends) $188,862 $153,106 $134,822
The accompanying Notes to Financial Statements are an integral part of these
statements.
IES UTILITIES INC.
BALANCE SHEETS
December 31
1993 1992
(in thousands)
ASSETS
Utility plant, at original cost:
Plant in service -
Electric $1,707,278 $1,641,536
Gas 147,956 137,227
Other 75,845 73,970
1,931,079 1,852,733
Less - Accumulated depreciation 813,312 759,754
1,117,767 1,092,979
Leased nuclear fuel, net of amortization 51,681 48,505
Construction work in progress 41,937 30,324
1,211,385 1,171,808
Current assets:
Cash and temporary cash investments 18,313 1,743
Accounts receivable -
Customer, less reserve 22,679 24,517
Other 10,330 10,429
Income tax refunds receivable 8,767 -
Production fuel, at average cost 14,338 19,418
Materials and supplies, at average cost 26,861 28,765
Adjustment clause balances - 1,217
Regulatory assets 6,421 3,636
Prepayments and other 31,502 26,085
139,211 115,810
Other assets:
Regulatory assets 149,978 118,215
Nuclear decommissioning trust funds 28,059 21,327
Deferred charges and other 18,345 13,731
196,382 153,273
$1,546,978 $1,440,891
CAPITALIZATION AND LIABILITIES
Capitalization (See Statements of Capitalization):
Common stock $ 33,427 $ 33,427
Paid-in surplus 279,042 229,042
Retained earnings 188,862 153,106
Total common equity 501,331 415,575
Cumulative preferred stock 18,320 18,320
Long-term debt 480,074 441,522
999,725 875,417
Current liabilities:
Short-term borrowings 24,000 92,000
Notes payable - associated companies - 560
Capital lease obligations 15,345 13,211
Sinking funds and maturities 224 224
Accounts payable 47,179 45,384
Dividends payable 5,229 229
Accrued interest 9,438 9,247
Accrued taxes 39,763 41,987
Accumulated refueling outage provision 2,660 7,549
Adjustment clause balances 5,149 -
Provision for rate refund liability 8,670 9,020
Other 27,038 17,848
184,695 237,259
Long-term liabilities:
Capital lease obligations 36,336 35,294
Liability under National Energy Policy Act of 1992 11,984 12,054
Environmental liabilities 9,130 9,815
Other 25,197 17,645
82,647 74,808
Deferred credits:
Accumulated deferred income taxes 237,464 206,099
Accumulated deferred investment tax credits 42,447 47,308
279,911 253,407
Commitments and contingencies (Note 12)
$1,546,978 $1,440,891
The accompanying Notes to Financial Statements are an integral part of these
statements.
IES UTILITIES INC.
STATEMENTS OF CAPITALIZATION
December 31
1993 1992
(in thousands)
Common equity:
Common stock - par value $2.50 per share -
authorized 24,000,000 shares; outstanding
13,370,788 shares $ 33,427 $ 33,427
Paid-in surplus 279,042 229,042
Retained earnings 188,862 153,106
501,331 415,575
Cumulative preferred stock - par value $50 per
share - authorized 466,406 shares; outstanding
366,406 shares -
6.10% - Outstanding 100,000 shares 5,000 5,000
4.80% - Outstanding 146,406 shares 7,320 7,320
4.30% - Outstanding 120,000 shares 6,000 6,000
18,320 18,320
Long-term debt:
Collateral trust bonds -
6% series, due 2008 50,000 -
7% series, due 2023 50,000 -
5.5% series, due 2023 19,400 -
119,400 -
First mortgage bonds -
Series J, 6-1/4%, due 1996 15,000 15,000
Series K, 8-5/8%, retired in 1993 - 20,000
Series L, 7-7/8%, due 2000 15,000 15,000
Series M, 7-5/8%, due 2002 30,000 30,000
Series P & Q, 6.70%, retired in 1993 - 9,200
Series R, 8-1/4%, retired in 1993 - 25,000
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
8-3/4% series, retired in 1993 - 15,000
339,000 408,200
Pollution control obligations -
5.75%, retired in 1993 - 10,200
4.90% to 5.75%, due serially 1994 to 2003 3,920 4,144
5.95%, due 2007, secured by First mortgage bonds 10,000 10,000
Variable rate (3.15% at December 31, 1993),
due 2000 to 2010 11,100 11,100
25,020 35,444
Unamortized debt premium and (discount), net (3,122) (1,898)
480,298 441,746
Less - Amount due within one year 224 224
480,074 441,522
$ 999,725 $ 875,417
The accompanying Notes to Financial Statements are an integral part of these
statements.
IES UTILITIES INC.
STATEMENTS OF CASH FLOWS
Year Ended December 31
1993 1992 1991
(in thousands)
Cash flows from operating activities:
Net income $67,970 $45,291 $47,563
Adjustments to reconcile net income to
net cash flows from operating activities -
Depreciation and amortization 69,407 64,107 61,466
Principal payments under capital
lease obligations 11,429 11,725 15,471
Deferred taxes and investment tax credits 10,531 (2,406) (13,068)
Amortization of deferred charges 860 961 7,778
Refueling outage provision (4,889) (5,503) 11,553
Allowance for equity funds used during
construction (824) (1,831) (820)
(Gain) loss on disposition of assets, net (655) - 30
Other (1,321) (4,742) (4,026)
Other changes in assets and liabilities -
Accounts receivable (8,553) (571) (3)
Sale of utility accounts receivable 10,490 7,710 (5,000)
Accounts payable 5,620 345 569
Accrued taxes (10,991) 6,118 3,375
Production fuel 5,080 2,579 1,234
Adjustment clause balances 6,366 (4,122) 184
Deferred energy efficiency costs (9,747) (6,877) (1,905)
Provision for rate refunds (350) 7,528 (197)
Other (1,281) (4,519) 2,307
Net cash flows from operating activities 149,142 115,793 126,511
Cash flows from financing activities:
Dividends declared on common stock (31,300) (24,721) (45,321)
Dividends on preferred and preference stock (914) (1,729) (2,170)
Proceeds from issuance of long-term debt 119,400 83,400 88,700
Equity infusion from parent company 50,000 - 40,000
Net change in short-term borrowings (68,560) 51,660 (55,750)
Sinking fund requirements and reductions in
long-term debt and preferred and
preference stock (79,624) (39,429) (31,589)
Principal payments under capital lease
obligations (11,276) (12,337) (14,738)
Dividends payable 5,000 - -
Other (1,295) 476 (500)
Net cash flows from financing activities (18,569) 57,320 (21,368)
Cash flows from investing activities:
Construction and acquisition expenditures (113,212) (171,013) (105,009)
Nuclear decommissioning trust funds (5,532) (5,532) (5,505)
Proceeds from disposition of assets 837 - 203
Other 3,904 (246) (620)
Net cash flows from investing activities (114,003) (176,791) (110,931)
Net increase (decrease) in cash and
temporary cash investments 16,570 (3,678) (5,788)
Cash and temporary cash investments
at beginning of year 1,743 5,421 11,209
Cash and temporary cash investments
at end of year $ 18,313 $ 1,743 $ 5,421
Supplemental cash flow information:
Cash paid during the year for -
Interest $ 39,747 $ 36,503 $ 36,932
Income taxes $ 40,130 $ 23,640 $ 32,925
Noncash investing and financing activities -
Capital lease obligations incurred $ 14,605 $ 1,973 $ 11,874
The accompanying Notes to Financial Statements are an integral part of these
statements.
NOTES TO FINANCIAL STATEMENTS
(1) GENERAL:
IES Utilities Inc. (the Company) is a wholly-owned subsidiary of IES
Industries Inc. (Industries) and is subject to regulation by the Iowa
Utilities Board (IUB) and the Federal Energy Regulatory Commission (FERC).
On June 4, 1993, Industries announced that its wholly-owned utility
subsidiaries, Iowa Electric Light and Power Company (IE) and Iowa Southern
Utilities Company (IS), filed applications for regulatory authority to merge.
The merger became effective December 31, 1993, following receipt of all
necessary Boards of Directors, shareholder and regulatory approvals.
IE is the surviving corporation and has been renamed IES Utilities Inc.
The separate existence of IS has ceased. The Company serves a total of
325,000 electric and 170,000 natural gas retail customers as well as 32 resale
customers in more than 550 Iowa communities.
The merger was accounted for under a method of accounting similar to
pooling of interests, which combined the ownership interests of IE and IS.
The assets and liabilities of IE and IS were combined at their recorded
amounts as of the merger date.
(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
(a) Regulatory Assets -
The Company is subject to the provisions of Statement of Financial
Accounting Standards No. 71 "Accounting for the Effects of Certain Types of
Regulation" (SFAS 71). The regulatory assets represent probable future
revenue associated with certain incurred costs as these costs are recovered
through the ratemaking process. At December 31, 1993, regulatory assets
were comprised of the following items, and were reflected in the Balance
Sheets as follows:
Regulatory Assets
(in millions)
Deferred income taxes (Note 2(b)) $ 88.6
Energy efficiency programs 18.5
Employee pension and benefit costs (Note 8) 14.1
Environmental liabilities (Note 12(f)) 12.9
National Energy Policy Act of 1992 (Note 12(h)) 12.5
FERC Order No. 636 transition costs (Note 12(i)) 5.0
Cancelled plant costs 3.3
Regulatory study costs 1.5
156.4
Less current amounts 6.4
$150.0
Refer to the individual footnotes referenced above for a discussion of
the specific items reflected in regulatory assets. The amounts reflected
for energy efficiency programs are a result of an IUB mandate whereby 2% of
electric and 1.5% of gas gross retail operating revenues are to be expended
annually for energy efficiency programs. Under this mandate, the Company will
make its initial filing for recovery of the costs in 1994.
(b) 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 have been deferred and are subsequently credited to income over
the average lives of the related property.
Consistent with ratemaking practices, deferred tax expense is not
recorded for certain temporary differences (primarily related to utility
property, plant and equipment). Accordingly, the Company has recorded
deferred tax liabilities and regulatory assets, as discussed in Note 2(a).
(c) Temporary Cash Investments -
Temporary cash investments are stated at cost which approximates market
value and are considered cash equivalents for the 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 and at
December 31, 1993, include $15 million invested with affiliated companies.
(d) Depreciation of Utility Property, Plant and Equipment -
The average rates of depreciation for electric and gas properties,
including the Company's nuclear generating station, the Duane Arnold Energy
Center (DAEC), which is being depreciated over a 36 year life using a
remaining life method, were as follows:
1993 1992 1991
Electric 3.5% 3.5% 3.5%
Gas 3.5% 3.0% 3.0%
Based on the most recent site specific study, completed in 1992, the
Company's 70% share of the estimated cost to decommission the DAEC and return
the underlying property to its original state approximated $223 million
in 1992 dollars. The study is based on the prompt removal and dismantling
decommissioning alternative and is assumed to begin at the end of the DAEC's
operating license in 2014. The level of annual recovery through rates of
decommissioning costs is $5.5 million, which is deposited in external trust
funds, and is based on a remaining life recovery method. The annual recovery
level is reviewed and, if necessary, adjusted in each rate case.
Decommissioning costs, at the level collected through rates, are included in
"Depreciation and amortization" expense in the Statements of Income.
In addition to the $28.1 million invested in the external trust funds
as indicated in the Balance Sheets, the Company has an internal
decommissioning reserve of $21.7 million recorded as accumulated depreciation.
Earnings on the external funds are recognized as income and a corresponding
amount of interest expense is recorded for the reinvestment of the earnings.
(e) 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 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 for 1993-1991 were 5.7%, 9.2% and 8.5%,
respectively.
(f) Operating Revenues -
The Company accrues revenues for services rendered but unbilled at
month-end in order to more properly match revenues with expenses.
(g) Adjustment Clauses -
The Company's 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 Statements of Income. The cumulative effects
are reflected in the Balance Sheets as a current asset or current
liability, pending automatic reflection in future billings to customers.
(h) Accumulated Refueling Outage Provision -
The IUB allows the Company 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.
(i) Reclassifications -
Certain prior period amounts have been reclassified on a basis consistent
with the 1993 presentation.
(3) ACQUISITION OF IOWA SERVICE TERRITORY OF UNION ELECTRIC COMPANY:
Effective December 31, 1992, the Company acquired the Iowa distribution
system and a portion of the Iowa transmission facilities of Union Electric
Company (UE) for $65.0 million in cash. The acquisition was accounted for as
a purchase. The net book value of the acquired assets was approximately
$34.4 million and the amount of the purchase price in excess of the
book value ($30.6 million) has been recorded as an acquisition adjustment.
The acquisition adjustment is being amortized over the life of the property
and is included in "Other income and deductions - Miscellaneous, net" in the
Statements of Income. Recovery of the acquisition adjustment through rates
will be addressed in future rate proceedings. See Note 12(b) for a
discussion of the purchase power contracts with UE associated with this
acquisition.
(4) RATE MATTERS:
(a) Gas Rate Cases -
Former IE Service Territory
In July 1992, IE applied to the IUB for an increase in gas rates of
$6.3 million annually, or 5.9%. Effective September 30, 1992, the
IUB authorized an interim increase of $5.4 million, subject to refund. On
April 30, 1993, the IUB issued its "Final Decision and Order," which
approved stipulations between IE and certain intervenors providing for an
annual increase in revenues of $5.5 million. IE did not have any refund
liability as a result of the Order.
Former IS Service Territory
In July 1992, IS applied to the IUB for an increase in gas rates of
$2.3 million annually, or 6.2%. Effective September 30, 1992, the IUB
authorized an interim increase of $1.9 million, subject to refund. In
February 1993, the IUB approved stipulations between IS and certain
intervenors in the proceeding that provided for an annual increase in revenues
of $1.6 million. As a result of the Order, IS refunded approximately
$0.2 million, including interest, in the second quarter of 1993.
(b) 1991 Electric Rate Case -
In October 1991, IE applied to the IUB for an increase in interim and
final retail electric rates of $18.9 million annually, or 6.0%. The IUB
approved an interim rate increase of $15.6 million, annually, which became
effective in December 1991, subject to refund.
In July 1992, the IUB issued its "Final Decision and Order" approving an
annual electric rate increase of $7.9 million. The application of double
leverage ratemaking theory to IE's capital structure accounted for
approximately $4 million of the difference between the interim rate level
and the amount allowed in the Order. After a limited rehearing of
the double leverage issue, the IUB issued its "Order On Rehearing" in
December 1992, which affirmed the original decision.
IE appealed the IUB's Order to the Iowa District Court (Court). In
December 1993, the Court issued its decision, which upholds the IUB's Order.
The Company did not appeal the Court's decision to the Iowa Supreme Court.
In the second quarter of 1993, IE refunded approximately $4.1 million,
including interest, which represented a refund down to the level of revenues
that would have resulted had it won the appeal. An additional refund,
including interest, of $8.7 million is required at December 31, 1993, as a
result of the Court's decision. The refund is expected to be completed in
the second quarter of 1994. There will be no effect on electric revenues
and net income when the additional refund is made because the Company has
been reserving for the effect of the additional refund.
(5) LEASES:
The Company 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 the Company 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. The Company 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 Statements
of Income) for 1993-1991 were $12.4 million, $12.9 million and $17.5 million,
respectively.
The Company's operating lease rental expenses for 1993-1991 were
$8.4 million, $6.8 million and $7.0 million, respectively.
The Company's future minimum lease payments by year are as follows:
Capital Operating
Year Lease Leases
(in thousands)
1994 $ 16,994 $ 6,511
1995 11,970 6,353
1996 10,784 4,865
1997 9,940 3,420
1998 4,145 3,549
1999-2003 4,111 12,130
57,944 $ 36,828
Less: Amount
representing interest 6,263
Present value of net
minimum capital
lease payments $ 51,681
(6) UTILITY ACCOUNTS RECEIVABLE:
Customer accounts receivable, including unbilled revenues, arise
primarily from the sale of electricity and natural gas. At
December 31, 1993, the Company was serving a diversified base of residential,
commercial and industrial customers consisting of approximately
325,000 electric and 170,000 gas customers.
The Company has entered into two agreements, one with limited recourse, to
sell undivided fractional interests of an aggregate of $65 million in its pool
of utility accounts receivable. At December 31, 1993, $53.2 million was sold
under the agreements. The agreements expire in June and December 1994. The
Company intends to consolidate the agreements into one new agreement in 1994.
(7) INCOME TAXES:
The components of federal and state income taxes for the years ended
December 31, were as follows:
1993 1992 1991
(in millions)
Classified as Federal and
State Income Taxes:
Current tax expense $ 28.4 $ 24.0 $ 36.3
Deferred tax expense 15.9 0.2 (10.1)
Amortization and adjustment
of investment tax credits (4.9) (2.8) (2.9)
39.4 21.4 23.3
Included in Miscellaneous, net:
Current tax expense (0.9) (0.8) 0.4
Deferred tax expense (0.5) 0.1 (0.2)
(1.4) (0.7) 0.2
Total income tax expense $ 38.0 $ 20.7 $ 23.5
The overall effective income tax rates shown below were computed by
dividing total income tax expense by income before income taxes.
Year Ended December 31
1993 1992 1991
Statutory Federal income tax rate 35.0% 34.0% 34.0%
Add (deduct):
Amortization of investment tax credits (2.5) (4.2) (4.0)
State income taxes, net of Federal
benefits 5.8 5.6 6.4
Property basis and other temporary
differences for which deferred taxes are
not provided under ratemaking principles 1.5 0.5 2.1
Reversal through tariffs of deferred
taxes provided at rates in excess
of the current statutory Federal
income tax rate (1.7) (2.7) (3.7)
Adjustment of prior period taxes (2.0) (2.0) (1.3)
Other items, net (0.3) 0.2 (0.4)
Overall effective income tax rate 35.8% 31.4% 33.1%
The accumulated deferred income taxes as set forth below and in the
Balance Sheets arise from the following temporary differences:
December 31
1993 1992
(in millions)
Property related $ 272 $ 256
Decommissioning related (12) (11)
Investment tax credit related (30) (32)
Other 7 (7)
$ 237 $ 206
(8) BENEFIT PLANS:
The Company has one contributory and two non-contributory retirement plans
which, 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 1993 totaled $10.4 million. In
addition to these payments, the Company purchased annuities totaling
$6.3 million for all previous employees who had retired as of January 1993,
under one of the plans. The cost of the annuities and the reduction
in the projected benefit obligation were substantially equivalent.
The Company's policy is to fund the pension cost at an amount which is at
least equal to the minimum funding requirements mandated by the Employee
Retirement Income Security Act (ERISA) and which does not exceed the maximum
tax deductible amount for the year.
Pursuant to the provisions of SFAS 71, certain adjustments to the Company's
pension provision are necessary to reflect the accounting for pension costs
allowed in the most recent rate cases.
The components of the pension provision are as follows:
Year Ended December 31
1993 1992 1991
(in thousands)
Service cost $ 4,275 $ 4,439 $ 4,517
Interest cost on projected
benefit obligation 11,131 9,999 8,959
Assumed return on plans' assets (12,177) (11,640) (10,026)
Amortization of unrecognized gain (763) (135) (19)
Amortization of prior service cost 1,195 938 775
Amortization of unrecognized plans'
assets as of January 1, 1987 (384) (382) (392)
Pension cost 3,277 3,219 3,814
Adjustment to funding level (2,867) 301 (228)
Total pension costs paid to the
Trustees $ 410 $ 3,520 $ 3,586
Actual return on plans' assets $ 12,718 $ 8,861 $ 37,085
A reconciliation of the funded status of the plans to the amounts
recognized in the Balance Sheets is presented below:
December 31
1993 1992
(in thousands)
Fair market value of plans' assets $ 174,133 $ 177,514
Actuarial present value of benefits
rendered to date -
Accumulated benefits based on
compensation to date, including
vested benefits of $100,905,000
and $91,303,000, respectively 110,676 100,288
Additional benefits based on estimated
future salary levels 42,938 31,324
Projected benefit obligation 153,614 131,612
Plans' assets in excess of projected
benefit obligation 20,519 45,902
Remaining unrecognized net asset existing
at January 1, 1987, being amortized over
20 years (4,109) (5,256)
Unrecognized prior service cost 16,708 14,961
Unrecognized net gain (28,830) (52,709)
Prepaid pension cost recognized in the
Balance Sheets $ 4,288 $ 2,898
Assumed rate of return, all plans 8.00% 8.00%
Weighted average discount rate of
projected benefit obligation, all plans 7.50% 8.25%
Range of assumed rates of increase in
future compensation levels for
the plans 4.00-5.75% 4.00-5.75%
The decrease in the discount rate used to compute the projected benefit
obligation, from 8.25% at December 31, 1992 to 7.50% at December 31, 1993,
accounted for a significant portion of the reduction in the unrecognized net
gain between periods and, similarly, contributed to the increase in the
projected benefit obligation at December 31, 1993.
The Company provides certain benefits to retirees (primarily health care
benefits). Through 1992, the Company expensed such costs as benefits were
paid, which was consistent with ratemaking practices. Such costs totaled
$2.2 million for 1992 and $1.9 million for 1991.
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
rates pursuant to the provisions of SFAS 106. The rules permit the Company
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 the Company's gas rates, and are
funded in external trust funds; recovery of the electric portion will be
addressed in future electric proceedings. 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, the Company had deferred
$2.9 million of such costs at December 31, 1993, and it expects to file
electric rate cases seeking recovery of the deferred costs before
December 31, 1995.
The components of postretirement benefit costs for the year ended
December 31, 1993, are as follows:
1993
(in thousands)
Service cost $ 1,685
Interest cost on accumulated postretirement
benefit obligation 3,247
Amortization of transition obligation existing
at January 1, 1993 2,024
Postretirement benefit costs 6,956
Less: Deferred postretirement benefit costs 2,858
Net postretirement benefit costs $ 4,098
A reconciliation of the funded status of the plans to the amounts
recognized in the Balance Sheets is presented below:
December 31, January 1,
1993 1993
(in thousands)
Fair market value of plans' assets $ 1,171 $ -
Accumulated postretirement benefit obligation -
Active employees not yet eligible 18,325 18,232
Active employees eligible 4,130 3,698
Retirees 20,140 18,558
Total accumulated postretirement benefit obligation 42,595 40,488
Accumulated postretirement benefit obligation
in excess of plans' assets (41,424) (40,488)
Unrecognized transition obligation 38,463 40,488
Unrecognized net gain (1,167) -
Accrued postretirement benefit cost in the
Balance Sheets $ (4,128) $ -
Assumed rate of return 8.0% -
Weighted average discount rate of
accumulated postretirement benefit obligation 7.5% 8.25%
Medical trend on paid charges:
Initial trend rate 12.0% 13.0%
Ultimate trend rate 6.5% 8.0%
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 1993 service cost by
$1.1 million (22%) and the accumulated postretirement benefit obligation at
December 31, 1993 by $6.7 million (16%).
The Company will adopt the provisions of SFAS 112 "Employers' Accounting
for Postemployment Benefits" as of January 1, 1994 and its adoption will not
have a material effect on the Company's financial position or results of
operations. This statement requires that benefits offered to former or
inactive employees after termination of employment, but before retirement, be
accrued over the service lives of the employees if all of the following
conditions are met: 1) the obligation relates to services already performed,
2) the employees' rights vest, 3) the payments are probable, and 4) the
amounts are reasonably determinable. Otherwise, such obligations are to be
recognized at the time they become probable and reasonably determinable.
The Company has generally accounted for these obligations as they were paid.
(9) PREFERRED AND PREFERENCE STOCK:
The Company has 466,406 shares of Cumulative Preferred Stock, $50 par
value, authorized for issuance at December 31, 1993, 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, 1993 and 1992. These shares are redeemable
at the Company's option upon 30 days notice at $51.00, $50.25 and $51.00 per
share, respectively, plus accrued dividends.
The Company also has 700,000 shares of Cumulative Preference Stock
($100 par value) authorized for issuance, of which none were outstanding at
December 31, 1993.
(10) DEBT:
(a) Long-Term Debt -
In November 1993, the Company entered into arrangements with various
cities in the State of Iowa (Cities), whereby the Cities issued an aggregate
of $19.4 million of pollution control revenue refunding bonds (PCRRBs), all
at 5.5%, due 2023. Each series of the PCRRBs is secured, in part, by
payments on a corresponding principal amount of Collateral Trust Bonds,
at 5.5%, due 2023. The proceeds received by the Company in the transaction
were used to redeem $10.2 million of Pollution Control Obligations, 5.75%, due
serially 1995-2003 and an aggregate of $9.2 million of First Mortgage Bonds,
Series P & Q, 6.7%, due 2006.
In October 1993, the Company sold $100 million aggregate principal amount
of Collateral Trust Bonds, 6% Series, due 2008, and 7% Series, due 2023. A
portion of the proceeds from the Collateral Trust Bonds was used to retire
short-term debt, with the balance used for general corporate purposes,
including support of its construction program.
In May 1993, the Company redeemed First Mortgage Bonds Series K, 8-5/8%,
principal amount of $20 million, and Series R, 8-1/4%, principal amount of
$25 million and First Mortgage Bonds Series 8-3/4%, principal amount of
$15 million. The redemptions were completed with proceeds from short-term
borrowings and, as discussed above, long-term debt was ultimately issued to
replace the short-term borrowings.
The Company's Indentures and Deeds of Trust securing its First Mortgage
Bonds constitute direct first mortgage liens upon substantially all tangible
public utility property. The Company's Indenture and Deed of Trust securing
its Collateral Trust Bonds constitutes a second lien on substantially all
tangible public utility property while First Mortgage Bonds remain
outstanding.
Total sinking fund requirements, which the Company intends to meet by
pledging additional property under the terms of the Company's Indentures and
Deeds of Trust, and debt maturities for 1994-1998 are as follows:
Debt maturities
(in thousands)
Debt Issue 1994 1995 1996 1997 1998
Sinking Fund
Requirements $ 780 $ 780 $ 630 $ 550 $ 550
Pollution
Control 224 140 140 140 140
Series W - 50,000 - - -
Series X - 50,000 - - -
Series J - - 15,000 - -
6 1/8% Series - - - 8,000 -
$1,004 $100,920 $ 15,770 $ 8,690 $ 690
The Company intends to refinance the majority of the debt maturities with
long-term debt.
(b) Short-Term Debt -
At December 31, 1993, the Company had bank lines of credit aggregating
$67.7 million and was using $19.0 million to support commercial paper 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, the Company
has an uncommitted credit facility with a financial institution whereby it
can borrow up to $50 million. Rates are set at the time of borrowing and no
fees are paid to maintain this facility. At December 31, 1993, $5.0 million
was borrowed at 3.4% under this facility. The Company 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, 1993,
and the basis upon which they were estimated are as follows:
Current assets and current liabilities -
The carrying amount approximates fair value because of the short
maturity of such financial instruments.
Nuclear decommissioning trust funds -
The estimated fair value of these trust funds, as reported by the
trustee based upon current market values, is $29.5 million.
Cumulative preferred stock -
The estimated fair value of this stock of $12.8 million is based
upon quoted market prices.
Long-term debt -
The carrying amount of long-term debt was $480 million compared to
estimated fair value of $507 million. The estimated fair value of
long-term debt is based upon quoted market prices.
Since the Company is subject to regulation, any gains or losses related
to the difference between the carrying amount and the fair value of financial
instruments may not be realized by the Company's parent.
(12) COMMITMENTS AND CONTINGENCIES:
(a) Construction Program -
The Company's construction and acquisition program anticipates
expenditures of approximately $150 million, for which substantial commitments
have been made.
(b) Purchase Power Contracts -
The Company has a purchase power contract with Terra Comfort Company
(Terra Comfort), a wholly-owned subsidiary of Industries, for annual capacity
purchases of 114 Mw that expires on December 31, 1994.
In connection with the acquisition of the UE properties discussed in
Note 3, the Company is purchasing power from UE under a five-year firm
capacity contract with a 1994 requirement of 120 Mw of delivered capacity
declining to 60 Mw in 1997. The Company will also purchase an additional
maximum interruptible capacity of up to 54 Mw of 25 Hz power. This 25 Hz
power purchase will extend 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 Statements of Income.
Total capacity charges under all existing contracts will approximate
$21.0 million, $14.7 million, $11.4 million, $8.7 million and $0.3 million
for the years 1994-1998, respectively.
(c) Coal Contract Commitments -
The Company has entered into coal supply contracts which expire between
1994 and 2001 for its fossil-fueled generating stations. At December 31,
1993, the contracts cover approximately $147 million of coal over the life
of the contracts, which includes $34 million expected to be incurred in
1994. The Company expects to supplement these coal contracts with spot
market purchases to fulfill its future fossil fuel needs.
(d) Information Technology Services -
In 1992, the Company entered into an agreement with Electronic Data
Systems Corporation (EDS) for information technology services. The term of
the contract is twelve years and the contract is subject to declining
termination fees. The Company's anticipated expenditures under the agreement
for 1994 are estimated to be approximately $8.9 million. Future costs under
the agreement are variable and are dependent upon the Company's level of
usage of technological services from EDS, as well as inflation.
(e) Nuclear Insurance Programs -
The Price-Anderson Amendments Act of 1988 (1988 Act) provides the Company
with the benefit of $9.4 billion of public liability coverage consisting of
$200 million of insurance and $9.2 billion of potential retroactive
assessments from the owners of nuclear power plants. Under the 1988 Act,
the Company could be assessed a maximum of $79 million per nuclear incident,
with a maximum of $10 million per year (of which the Company's 70% ownership
portion would be $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.
Pursuant to provisions in various nuclear insurance policies, the Company
could be assessed retroactive premiums in connection with future accidents at
a nuclear facility owned by a utility participating in the particular
insurance plan. With respect to excess property damage and replacement
power coverages, the Company could be assessed annually a maximum of
$8.5 million and $1 million, respectively, if the insurer's losses relating
to accidents exceeded its reserves. While assessments may also be made for
losses in certain prior years, the Company is not aware of any losses in such
years that it believes are likely to result in an assessment.
(f) Environmental Liabilities -
At December 31, 1993, the Company's Balance Sheet reflects $13.1 million
(including $4.0 million as current) of environmental liabilities, which,
pursuant to generally accepted accounting principles, represents the minimum
amount of the estimated range of such costs that the Company expects to
incur. The minimum amount of the range is used because no amount within
the range represents a better estimate. These estimates are subject to
continuing review.
The Company has been named as a Potentially Responsible Party (PRP) for
certain former manufactured gas plant (FMGP) sites by either the Iowa
Department of Natural Resources (IDNR) or the Environmental Protection
Agency (EPA). The Company is working with the IDNR and EPA to investigate
its 27 sites and to determine the appropriate remediation activities that may
be needed to mitigate health and environmental concerns. Such investigations
are expected to be completed by 1999 and site-specific remediations are
anticipated to be completed within 3 years after the completion of the
investigations of each site. The Company may be required to monitor these
sites for a number of years upon completion of remediation.
The Company is investigating the possibility of insurance and third party
cost sharing for FMGP clean-up costs. The amount of shared costs, if any, can
not be reasonably determined and, accordingly, no potential sharing has been
recorded. Regulatory assets of $12.9 million have been recorded in the
Balance Sheets, which reflects the future recovery that is being provided
through the Company's rates (See Note 2(a)). Considering the recorded
reserves for environmental liabilities and the past rate treatment
allowed by the IUB, management believes that the clean-up costs incurred
by the Company for these FMGP sites will not have a material adverse effect on
its financial position or results of operations.
(g) Clean Air Act -
The Clean Air Act Amendments 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 the Company's units
beginning in 1995 and Phase II affecting all units beginning in the
year 2000.
The Company expects to meet the requirements of the Act by switching to
lower sulfur fuels and through capital expenditures primarily related to fuel
burning equipment and boiler modifications. The Company estimates capital
expenditures at approximately $28 million, including $4 million in 1994, in
order to meet these requirements of the Act.
(h) 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 $1.3 million annually through 2007,
of which the Company's 70% share is $0.9 million. The Company is recovering
the costs associated with this assessment through its electric fuel adjustment
clauses over the period the costs are assessed. The Company's 70% share of
the future assessment, $12.7 million payable through 2007, has been recorded
as a liability in the Balance Sheets, including $0.7 million included
in "Current liabilities - other," with a related regulatory asset for the
unrecovered amount (See Note 2(a)).
(i) FERC Order No. 636 -
The FERC issued Order No. 636 (Order 636) in 1992. Order 636 as modified
on rehearing, (1) requires the Company's 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 the
Company) 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 to a customer 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. The Company may
benefit from enhanced access to competitively priced gas supply and more
flexible transportation services as a result of Order 636. However, the
Company will be required to pay certain transition costs passed on from its
pipeline suppliers as they implement Order 636.
The Company's three pipeline suppliers have filed new tariffs with the
FERC implementing Order 636 and the pipelines have also made filings with the
FERC to begin collecting their respective transition costs. The Company
began paying the transition costs in November 1993, and has recorded a
liability of $5.0 million for such transition costs that have been
incurred by the pipelines to date, including $1.7 million expected to be
billed in 1994. While the magnitude of the total transition costs to be
charged to the Company cannot yet be determined, the Company believes any
transition costs the FERC would allow the pipelines to collect would be
recovered from its customers, based upon past regulatory treatment of
similar costs by the IUB. Accordingly, regulatory assets, in amounts
corresponding to the liabilities, have been recorded to reflect the
anticipated recovery.
(13) JOINTLY-OWNED ELECTRIC UTILITY PLANT:
Under joint ownership agreements with other Iowa utilities, the Company
has undivided ownership interests in jointly-owned electric generating
stations and related transmission facilities. Each of the respective owners
is responsible for the financing of its portion of the construction
costs. Kilowatt-hour generation and operating expenses are divided on the
same basis as ownership with each owner reflecting its respective
costs in its Statements of Income. Information relative to the Company's
ownership interest in these facilities at December 31, 1993 is as follows:
Ottumwa Neal
DAEC Unit 1 Unit 3
($ in millions)
Utility plant in service $ 484 $ 179 $ 43
Accumulated depreciation $ 221 $ 69 $ 22
Construction work in progress $ 7 $ - $ -
Plant capacity - Mw 530 708 515
Percent ownership 70% 48% 28%
In-service date 1974 1981 1975
(14) SEGMENTS OF BUSINESS:
The principal business segments of the Company are the generation,
transmission, distribution and sale of electric energy and the purchase,
distribution and sale of natural gas. Certain financial information relating to
the Company's significant segments of business is presented below:
Year Ended December 31
1993 1992 1991
(in thousands)
Operating results:
Revenues -
Electric $ 550,521 $ 462,999 $ 482,578
Gas 154,318 139,455 131,019
Operating income (pre-tax) -
Electric 128,994 90,891 100,402
Gas 13,750 8,367 (360)*
Other information:
Depreciation and amortization -
Electric 63,832 59,707 57,612
Gas 5,186 4,024 3,480
Construction and acquisition
expenditures -
Electric 84,720 154,902 77,646
Gas 12,582 17,308 21,100
Assets -
Identifiable assets -
Electric 1,288,505 1,226,614 1,115,310
Gas 164,773 141,801 108,851
1,453,278 1,368,415 1,224,161
Other corporate assets 93,700 72,476 79,949
Total assets $1,546,978 $1,440,891 $1,304,110
* Includes a $3.9 million pre-tax write-off of previously deferred
FMGP clean-up costs pursuant to disallowance of recovery in an
IUB order.
Item 9. Changes and Disagreements with Accountants on Accounting and
Financial Disclosure.
None.
PART III
Item 10. Directors, Executive Officers, Promoters and Control Persons of the
Registrant
Information regarding the identification of directors is included in
Exhibit 99 and is incorporated herein by reference. Exhibit 99 is primarily
an excerpt from IES Industries Inc. definitive proxy statement prepared for
the 1994 annual meeting of stockholders, which will be filed on or about
April 4, 1994. The executive officers of the registrant are as follows:
Executive Officers of the Registrant (Effective February 1, 1994)
Lee Liu, 60, Chairman of the Board, President & Chief Executive Officer.
First elected officer in 1975.
Larry D. Root, 57, President and Group Executive, Energy Delivery and
Nuclear Group and Director. First elected officer in 1979.
Rene H. Males, 61, President and Group Executive, Generation and
Engineering Group and Director. First elected officer in 1991. (i)
Blake O. Fisher, Jr., 49, Executive Vice President & Chief Financial
Officer and Director. First elected officer in 1991. (ii)
Dr. Robert J. Latham, 51, Senior Vice President, Finance and Corporate
Affairs, & Treasurer. First elected officer in 1985.
Stephen W. Southwick, 47, Vice President & General Counsel. First
elected officer in 1982.
John F. Franz, Jr., 54, Vice President, Nuclear. First elected officer
in 1992. (iii)
Phillip D. Ward, 53, Vice President, Engineering. First elected officer
in 1990.
Harold W. Rehrauer, 56, Vice President, Field Operations. First elected
officer in 1987.
Thomas R. Seldon, 55, Vice President, Human Resources. First elected
officer in 1987.
Robert J. Kucharski, 61, Vice President, Administration & Secretary.
First elected officer in 1976.
Richard A. Gabbianelli, 37, Controller & Chief Accounting Officer.
First elected officer in 1994.
Officers are elected annually by the Board of Directors and each of the
officers named above, except Rene H. Males, Blake O. Fisher, Jr. and John F.
Franz, Jr., have been employed by the Company (or IS) 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 Rene H. Males as an officer of IS in
1990, he was President of Joy Environment Equipment Company of
Monrovia, California. He was Senior Vice President for Wisconsin
Electric Power Company from 1987 to 1989.
(ii) 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.
(iii) Prior to the appointment of John F. Franz, Jr. as Vice President,
Nuclear in 1992, he was employed by Philadelphia Electric Company
as Plant Manager, Peach Bottom Atomic Power Station.
Item 11. Executive Compensation
Information regarding executive compensation is included in Exhibit 99
and is incorporated herein by reference.
Item 12. Security Ownership of Certain Beneficial Owners and Management
Information regarding security ownership of certain beneficial owners
and management is included in Exhibit 99 and is incorporated herein by
reference.
Item 13. Certain Relationships and Related Transactions
Information regarding certain relationships and related transactions is
included in Exhibit 99 and is incorporated herein by reference.
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
Page No.
(a) 1. Financial Statements -
Included in Part II of this report -
Management's Responsibility for Financial
Statements. 45 - 46
Report of Independent Public Accountants. 47
Statements of Income for the years ended
December 31, 1993, 1992 and 1991. 48
Statements of Retained Earnings for the years
ended December 31, 1993, 1992 and 1991. 49
Balance Sheets at December 31, 1993 and 1992. 50 - 51
Statements of Capitalization at
December 31, 1993 and 1992. 52
Statements of Cash Flows for the years ended
December 31, 1993, 1992 and 1991. 53
Notes to Financial Statements. 54 - 81
(a) 2. Financial Statement Schedules -
Included in Part IV of this report -
Schedule II - Amounts Receivable from Related
Parties and Underwriters, Promoters
and Employees Other Than
Related Parties for the years ended
December 31, 1993, 1992 and 1991. 87
Schedule V - Utility Plant for the years ended
December 31, 1993, 1992 and 1991. 88 - 90
Schedule VI - Accumulated Depreciation for the years
ended December 31, 1993, 1992 and 1991. 91
Schedule VII - Guarantees of Securities of Other
Issuers as of December 31, 1993. 92
Schedule VIII - Valuation and Qualifying Accounts
and Reserves for the years ended
December 31, 1993, 1992 and 1991. 93
Schedule IX - Short-term Borrowings for the years
ended December 31, 1993, 1992 and 1991. 94
Other schedules are omitted as not required under Rules of
Regulation S-X.
(a) 3. Exhibits -
See Exhibit Index beginning on page 97.
(b) Reports on Form 8-K and Form 8-K/A -
Items Financial
Reported Statements Date of Report File No.
5,7 None December 9, 1993 0-4117-1 (1)
5,7 None December 9, 1993 0-849 (2)
2,5,7 None January 7, 1994 0-4117-1 (3)
2,7 None January 7, 1994 0-849 (3)
7 (4) March 2, 1994 0-4117-1 (4)
Notes:
(1) Form 8-K filed by Iowa Electric Light and Power Company.
(2) Form 8-K filed by Iowa Southern Utilities Company.
(3) Form 8-K filed by IES Utilities Inc. subsequent to the merger
of Iowa Electric Light and Power Company and Iowa Southern
Utilities Company effective December 31, 1993.
(4) Form 8-K/A filed by IES Utilities Inc. amending Form 8-K filed on
January 7, 1994, File No. 0-4117-1, providing the audited
financial statements of the Company for the year ended
December 31, 1993.
IES UTILITIES INC.
SCHEDULE II - AMOUNTS RECEIVABLE FROM RELATED PARTIES
AND UNDERWRITERS, PROMOTERS AND
EMPLOYEES OTHER THAN RELATED PARTIES
BALANCE AT DECEMBER 31
(in thousands)
Affiliated Company 1991 1992 1993
Cedar Rapids and Iowa City
Railway Company $ 54 $ 46 $ 19
IES Industries Inc. 842 613 985
IES Diversified Inc. - - 48
Industrial Energy
Applications, Inc. 41 130 21
Total $ 937 $ 789 $1,073
NOTE: All receivables are collected from the affiliated companies
within one month, thus all amounts are current and are recorded
in the Balance Sheets as Current Assets - Accounts
Receivable - Other.
IES UTILITIES INC.
SCHEDULE V -- UTILITY PLANT
FOR THE YEAR ENDED DECEMBER 31, 1993
(in thousands)
Column A Column B Column C Column D Column E Column F
Balance Additions Retirements Reclassification Balance
Classification Jan. 1, 1993 at Cost At Cost and Transfers Dec. 31, 1993
- --------------------------------- ------------- ------------- ------------- ------------- -------------
ELECTRIC:
Electric plant in service -
Intangibles $6,536 $693 $14 $186 $7,401
Production 875,881 33,214 3,684 (2,190) 903,221
Transmission 226,521 15,139 257 (453) 240,950
Distribution 467,540 26,036 3,584 (3,956) 486,036
General 30,060 3,374 1,407 3,589 35,616
Leased Nuclear Fuel 48,505 14,606 0 (11,429) 51,682
Construction Work in Progress 28,135 7,987 0 0 36,122
Plant Held For Future 1,858 0 0 (656) 1,202
Acquisition Adjustment 33,140 0 0 (292) 32,848
------------- ------------- ------------- ------------- -------------
1,718,176 101,049 8,946 (15,201) 1,795,078
------------- ------------- ------------- ------------- -------------
GAS:
Gas plant in service -
Intangibles 472 196 4 0 664
Production 602 4 0 0 606
Transmission 15,282 538 14 848 16,654
Distribution 115,345 10,458 855 (784) 124,164
General 5,345 673 265 (64) 5,689
Construction Work in Progress 471 2,789 0 0 3,260
Acquisition Adjustment 181 0 0 0 181
------------- ------------- ------------- ------------- -------------
137,698 14,658 1,138 0 151,218
------------- ------------- ------------- ------------- -------------
STEAM:
Steam plant in service 13,766 429 43 0 14,152
Construction Work in Progress 0 546 0 0 546
------------- ------------- ------------- ------------- -------------
13,766 975 43 0 14,698
------------- ------------- ------------- ------------- -------------
COMMON:
Common plant in service 60,204 9,009 7,519 0 61,694
Construction Work in Progress 1,718 291 0 0 2,009
------------- ------------- ------------- ------------- -------------
61,922 9,300 7,519 0 63,703
------------- ------------- ------------- ------------- -------------
TOTAL UTILITY PLANT $1,931,562 $125,982 (1) $17,646 ($15,201) (2) $2,024,697
============= ============= ============= ============= =============
BALANCE SHEET CAPTION:
Utility plant in service -
Electric $1,641,536 $1,707,278
Gas 137,227 147,956
Other 73,970 75,845
------------- -------------
1,852,733 1,931,079
Leased Nuclear Fuel 48,505 51,681
Construction work in progress 30,324 41,937
------------- -------------
TOTAL UTILITY PLANT $1,931,562 $2,024,697
============= =============
(1) Construction and acquisition expenditures $113,212
Additions to leased nuclear fuel 14,606
Other (1,836)
-------------
$125,982
=============
(2) Amortization of leased nuclear fuel ($11,429)
Other (3,772)
-------------
($15,201)
=============
IES UTILITIES INC.
SCHEDULE V -- UTILITY PLANT
FOR THE YEAR ENDED DECEMBER 31, 1992
(in thousands)
Column A Column B Column C Column D Column E Column F
Balance Additions Retirements Reclassification Balance
Classification Jan. 1, 1992 at Cost At Cost and Transfers Dec. 31, 1992
- --------------------------------- ------------- ------------- ------------- ------------- -------------
ELECTRIC:
Electric plant in service -
Intangibles $5,400 $333 $18 $821 $6,536
Production 850,720 30,155 3,398 (1,596) 875,881
Transmission 207,154 21,020 3,690 2,037 226,521
Distribution 396,441 76,605 3,139 (2,367) 467,540
General 27,598 3,137 747 72 30,060
Leased Nuclear Fuel 58,256 1,974 0 (11,725) 48,505
Construction Work in Progress 23,005 5,130 0 0 28,135
Plant Held For Future 1,038 820 0 0 1,858
Acquisition Adjustment 2,570 30,570 0 0 33,140
------------- ------------- ------------- ------------- -------------
1,572,182 169,744 10,992 (12,758) 1,718,176
------------- ------------- ------------- ------------- -------------
GAS:
Gas plant in service -
Intangibles 411 7 6 60 472
Production 602 0 0 0 602
Transmission 12,437 2,915 2 (68) 15,282
Distribution 101,953 14,268 884 8 115,345
General 5,014 600 292 23 5,345
Construction Work in Progress 1,988 (1,517) 0 0 471
Acquisition Adjustment 181 0 0 0 181
------------- ------------- ------------- ------------- -------------
122,586 16,273 1,184 23 137,698
------------- ------------- ------------- ------------- -------------
STEAM:
Steam plant in service 13,615 169 18 0 13,766
Construction Work in Progress 18 (18) 0 0 0
------------- ------------- ------------- ------------- -------------
13,633 151 18 0 13,766
------------- ------------- ------------- ------------- -------------
COMMON:
Common plant in service 54,974 6,694 1,530 66 60,204
Construction Work in Progress 1,359 359 0 0 1,718
------------- ------------- ------------- ------------- -------------
56,333 7,053 1,530 66 61,922
------------- ------------- ------------- ------------- -------------
TOTAL UTILITY PLANT $1,764,734 $193,221 (1) $13,724 ($12,669) (2) $1,931,562
============= ============= ============= ============= =============
BALANCE SHEET CAPTION:
Utility plant in service -
Electric $1,490,921 $1,641,536
Gas 120,598 137,227
Other 68,589 73,970
------------- -------------
1,680,108 1,852,733
Leased Nuclear Fuel 58,256 48,505
Construction work in progress 26,370 30,324
------------- -------------
TOTAL UTILITY PLANT $1,764,734 $1,931,562
============= =============
(1) Construction and acquisition expenditures $171,013
Additions to leased nuclear fuel 1,974
Union Electric (3) 18,967
Other 1,267
-------------
$193,221
=============
(2) Amortization of leased nuclear fuel ($11,725)
Other (944)
-------------
($12,669)
=============
(3) Utility construction and acquisition expenditures include $61 million for
the acquisition of Iowa Service territory from Union Electric Company.
The above amount represents the difference between the gross basis of
plant and cash paid.
IES UTILITIES INC.
SCHEDULE V-UTILITY PLANT
FOR THE YEAR ENDED DECEMBER 31, 1991
(in thousands)
Column A Column B Column C Column D Column E Column F
Balance Additions Retirements Reclassification Balance
Classification Jan. 1, 1991 at Cost At Cost and Transfers Dec. 31, 1991
- --------------------------------- ------------- ------------- ------------- ------------- -------------
ELECTRIC:
Electric plant in service -
Intangibles $5,400 $2 $4 $2 $5,400
Production 828,191 24,681 2,143 (9) 850,720
Transmission 194,389 14,498 529 (1,204) 207,154
Distribution 362,697 35,990 3,440 1,194 396,441
General 24,961 3,419 832 50 27,598
Leased Nuclear Fuel 61,853 11,874 0 (15,471) 58,256
Construction Work in Progress 24,222 (1,217) 0 0 23,005
Plant Held For Future 836 202 0 0 1,038
Acquisition Adjustment 2,570 0 0 0 2,570
------------- ------------- ------------- ------------- -------------
1,505,119 89,449 6,948 (15,438) 1,572,182
------------- ------------- ------------- ------------- -------------
GAS:
Gas plant in service -
Intangibles 388 26 5 2 411
Production 602 0 0 0 602
Transmission 5,835 6,591 0 11 12,437
Distribution 91,278 11,443 773 5 101,953
General 4,599 603 218 30 5,014
Construction Work in Progress 85 1,903 0 0 1,988
Acquisition Adjustment 181 0 0 0 181
------------- ------------- ------------- ------------- -------------
102,968 20,566 996 48 122,586
------------- ------------- ------------- ------------- -------------
STEAM:
Steam plant in service 13,334 285 4 0 13,615
Construction Work in Progress 0 18 0 0 18
------------- ------------- ------------- ------------- -------------
13,334 303 4 0 13,633
------------- ------------- ------------- ------------- -------------
COMMON:
Common plant in service 52,624 5,792 3,358 (84) 54,974
Construction Work in Progress 586 773 0 0 1,359
------------- ------------- ------------- ------------- -------------
53,210 6,565 3,358 (84) 56,333
------------- ------------- ------------- ------------- -------------
TOTAL UTILITY PLANT $1,674,631 $116,883 (1) $11,306 ($15,474) (2) $1,764,734
============= ============= ============= ============= =============
BALANCE SHEET CAPTION:
Utility plant in service -
Electric $1,419,044 $1,490,921
Gas 102,883 120,598
Other 65,958 68,589
------------- -------------
1,587,885 1,680,108
Leased Nuclear Fuel 61,853 58,256
Construction work in progress 24,893 26,370
------------- -------------
TOTAL UTILITY PLANT $1,674,631 $1,764,734
============= =============
(1) Construction and acquisition expenditures $105,009
Additions to leased nuclear fuel 11,874
-------------
$116,883
=============
(2) Amortization of leased nuclear fuel ($15,471)
Other (3)
-------------
($15,474)
=============
IES UTILITIES INC.
SCHEDULE VI-ACCUMULATED DEPRECIATION
FOR THE YEARS ENDED 1993, 1992 AND 1991
(in thousands)
Additions Removal
Charged to Cost and
Balance Costs and Property Salvage (net) Balance
Classification January 1 Expenses Retired and Other December 31
- -------------- --------------- ------------ ------------ --------------- --------------
1993
Department
Electric 681,282 60,552 8,726 (262) 732,846
Gas 43,048 4,896 1,138 (14) 46,792
Steam 3,965 360 43 (56) 4,226
Common 31,459 3,674 7,517 1,832 29,448
--------------- ------------ ------------ --------------- --------------
Total 759,754 69,482 17,424 1,500 813,312
=============== ============ ============ =============== ==============
1992
Department
Electric 618,491 56,759 10,991 17,023 681,282
Gas 40,499 3,573 1,185 161 43,048
Steam 3,639 355 18 (11) 3,965
Common 28,386 3,206 1,528 1,395 31,459
--------------- ------------ ------------ --------------- --------------
Total 691,015 63,893 13,722 18,568 759,754
=============== ============ ============ =============== ==============
1991
Department
Electric 571,090 54,573 6,925 (247) 618,491
Gas 38,292 3,068 997 136 40,499
Steam 3,297 350 4 (4) 3,639
Common 26,532 3,880 3,358 1,332 28,386
--------------- ------------ ------------ --------------- --------------
Total 639,211 61,871 11,284 1,217 691,015
=============== ============ ============ =============== ==============
1993 1992 1991
------------ --------------- ---------------
Reconciliation of additions per this
schedule and the statement
of income:
Additions per above schedule 69,482 63,893 61,871
Amortization of unrecovered plant costs 1,125 1,125 1,125
Earnings on Nuclear decommissioning trust
funds (1,200) (911) (773)
Other 0 0 (757)
---------------------------- --------------
Depreciation and amortization per the
statements of income 69,407 64,107 61,466
============ =============== ==============
Reconciliation of retirements per this
schedule to Schedule V:
Retirements per above 17,424 13,722 11,284
Other 222 2 22
------------ --------------- --------------
Retirements per Schedule V 17,646 13,724 11,306
============ =============== ==============
Note: Included in Removal Cost and Salvage (net) and other for 1992 is
$18,967,000, of accumulated depreciation recorded for the Union
Electric purchase.
IES UTILITIES INC.
SCHEDULE VII--GUARANTEES OF SECURITIES OF OTHER ISSUERS
AS OF DECEMBER 31, 1993
Nature of any
Default by Issuer of
Securities Guaranteed
in Principal, Interest,
Total Amount Sinding Fund or
Name of Issuer of Title of Guaranteed Redemption Provisions,
Securities Guaranteed Issue of Each Class of and Nature of or Payment of
by Registrant Securities Guaranteed Outstanding Guarantee Dividends
Kwik-Way Industries, Second Mortgage Note and $ 618,295 Principal and Kwik-Way filed to
Inc. Second Mortgage, 12% interest reorganize under
dated May 29, 1987 protection of the
Federal Bankruptcy
Law on 9-20-91
IES UTILITIES INC.
SCHEDULE VIII--VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991
Column A Column B Column E
Balance Balance
Description January 1 December 31
(in thousands)
1993:
Accumulated provision for
uncollectible accounts $ 567 $ 268
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
1991:
Accumulated provision for
uncollectible accounts $ 727 $ 804
Accumulated provision for
rate refunds $ 2,022 $ 1,492
IES UTILITIES INC.
SCHEDULE IX--SHORT-TERM BORROWINGS
FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991
Column A Column B Column C Column D Column E Column F
Average Weighted
Category of Weighted Maximum Daily Daily
Aggregate Average Amount Amount Average
Short-term Balance Interest Outstanding Outstanding Interst Rate
Borrowings December 31 Rate During During During
the Period the Period the Period
1993:
Commercial
paper $19,000,000 3.50% $92,000,000 $39,182,000 3.33%
Uncommitted
Credit
Facility $ 5,000,000 3.40% $ 5,000,000 $ 1,027,000 3.30%
1992:
Commercial
paper $92,000,000 3.71% $92,000,000 $ 9,160,000 4.14%
1991:
Commercial
paper $40,900,000 5.02% $51,000,000 $30,298,000 6.43%
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 1994.
IES UTILITIES INC.
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 in the capacities
indicated on March 29, 1994:
/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/ Robert F. Brewer Director
Robert F. Brewer
/s/ Dr. George Daly Director
Dr. George Daly
/s/ G. Sharp Lannom, IV Director
G. Sharp Lannom, IV
/s/ Salomon Levy Director
Dr. Salomon Levy
/s/ Rene H. Males Director
Rene H. Males
/s/ Robert D. Ray Director
Robert D. Ray
/s/ David Q. Reed Director
David Q. Reed
/s/ Larry D. Root Director
Larry D. Root
/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
2(a) Agreement and Plan of Merger between IE and IS dated as of June 4,
1993 (Agreement and Plan of Merger) (Filed as Exhibit 2 to the
Company's Current Report on Form 8-K, dated June 4, 1993 (File No.
0-4117-1).
2(b) 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)).
2(c) 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)).
2(d) Amendment 3 dated September 27, 1993, to the Agreement and Plan of
Merger (Filed as Exhibit 2(d) to the IE Current Report on Form
8-K, dated December 9, 1993 (File No. 0-4117-1)).
3(a) Articles of Incorporation of the Registrant, Amended and Restated
as of January 6, 1994. (Filed as Exhibit 4(b) to the Company's
Current Report on Form 8-K, dated January 7, 1994 (File No.
0-4117-1)).
* 3(b) Bylaws of Registrant, Amended as of February 1, 1994.
4(a) Indenture of Mortgage and Deed of Trust, dated as of
September 1, 1993, between the Company (formerly 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:
IE File
Number Dated as of 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 the Company (formerly IE) and the First National
Bank of Chicago, Trustee (1940 Indenture) (Filed as Exhibit 2(a)
to IE's Registration Statement File No. 2-25347).
4(d) Supplemental Indentures to the 1940 Indenture:
Number Dated as of IE File Reference Exhibit
First March 1, 1941 2-25347 2(a)
Second July 15, 1942 2-25347 2(a)
Third August 2, 1943 2-25347 2(a)
Fourth August 10, 1944 2-25347 2(a)
Fifth November 10, 1944 2-25347 2(a)
Sixth August 8, 1945 2-25347 2(a)
Seventh July 1, 1946 2-25347 2(a)
Eighth July 1, 1947 2-25347 2(a)
Ninth December 15, 1948 2-25347 2(a)
Tenth November 1, 1949 2-25347 2(a)
Eleventh November 10, 1950 2-25347 2(a)
Twelfth October 1, 1951 2-25347 2(a)
Thirteenth March 1, 1952 2-25347 2(a)
Fourteenth November 5, 1952 2-25347 2(a)
Fifteenth February 1, 1953 2-25347 2(a)
Sixteenth May 1, 1953 2-25347 2(a)
Seventeenth November 3, 1953 2-25347 2(a)
Eighteenth November 8, 1954 2-25347 2(a)
Nineteenth January 1, 1955 2-25347 2(a)
Twentieth November 1, 1955 2-25347 2(a)
Twenty-first November 9, 1956 2-25347 2(a)
Twenty-second November 6, 1957 2-25347 2(a)
Twenty-third November 4, 1958 2-25347 2(a)
Twenty-fourth November 3, 1959 2-25347 2(a)
Twenty-fifth November 1, 1960 2-25347 2(a)
Twenty-sixth January 1, 1961 2-25347 2(a)
Twenty-seventh November 7, 1961 2-25347 2(a)
Twenty-eighth November 6, 1962 2-25347 2(a)
Twenty-ninth November 5, 1963 2-25347 2(a)
Thirtieth November 4, 1964 2-25347 2(a)
Thirty-first November 2, 1965 2-25347 2(a)
Thirty-second September 1, 1966 Form 10-K, 1966 4.10
Thirty-third November 30, 1966 Form 10-K, 1966 4.10
Thirty-fourth November 7, 1967 Form 10-K, 1967 4.10
Thirty-fifth November 5, 1968 Form 10-K, 1968 4.10
Thirty-sixth November 1, 1969 Form 10-K, 1969 4.10
Thirty-seventh December 1, 1970 Form 8-K, 12/70 1
Thirty-eighth November 2, 1971 2-43131 2(g)
Thirty-ninth May 1, 1972 Form 8-K, 5/72 1
Fortieth November 7, 1972 2-56078 2(i)
Forty-first November 7, 1973 2-56078 2(j)
Forty-second September 10, 1974 2-56078 2(k)
Forty-third November 5, 1975 2-56078 2(l)
Forty-fourth July 1, 1976 Form 8-K, 7/76 1
Forty-fifth November 1, 1976 Form 8-K, 12/76 1
Forty-sixth December 1, 1977 2-60040 2(o)
Forty-seventh November 1, 1978 Form 10-Q, 6/30/79 1
Forty-eighth December 1, 1979 Form S-16, 2-65996 2(q)
Forty-ninth November 1, 1981 Form 10-Q,3/31/82 2
Fiftieth December 1, 1980 Form 10-K, 1981 4(s)
Fifty-first December 1, 1982 Form 10-K, 1982 4(t)
Fifty-second December 1, 1983 Form 10-K, 1983 4(u)
Fifty-third December 1, 1984 Form 10-K, 1984 4(v)
Fifty-fourth March 1, 1985 Form 10-K, 1984 4(w)
Fifty-fifth March 1, 1988 Form 10-Q, 5/12/88 4(b)
Fifty-sixth October 1, 1988 Form 10-Q, 11/10/88 4(c)
Fifty-seventh May 1, 1991 Form 10-Q, 8/31/91 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
the Company (successor to 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:
IS File
Dated as of 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)
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(u))
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
Industries' Form 10-K for the year 1987).
10(l) Management Incentive Compensation Plan. (Filed as Exhibit 10(m)
to Industries' Form 10-K for the year 1987).
10(m) Key Employee Deferred Compensation Plan. (Filed as Exhibit 10(n)
to Industries' Form 10-K for the year 1987).
10(n) Long-Term Incentive Plan. (Filed as Exhibit 10(o) to Industries'
Form 10-K for the year 1987).
10(o) Executive Guaranty Plan. (Filed as Exhibit 10(p) to Industries'
Form 10-K for the year 1987).
10(p) Executive Change of Control Severance Agreement. (Filed as
Exhibit 10(s) to Industries' Form 10-K for the year 1989).
10(q) Amendments to Key Employee Deferred Compensation Agreement for
Directors. (Filed as Exhibit 10(u) to Industries' Form 10-Q for
the quarter ended March 31, 1990).
10(r) Amendments to Key Employee Deferred Compensation Agreement for
Key Employees. (Filed as Exhibit 10(v) to Industries' Form 10-Q
for the quarter ended March 31, 1990).
10(s) Amendments to Management Incentive Compensation Plan.
(Filed as Exhibit
10(y) to Industries' Form 10-Q for the quarter ended March 31,
1990).
10(t) Director Retirement Plan. (Filed as Exhibit 10(t) to Industries'
Form 10-K for the year 1993).
10(u) Copy of Supplemental Retirement Income Plan and Form of
Supplemental Retirement Income Agreement. (Filed as Exhibit
10-A-6 to File No. 33-3995).
10(v) 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(w) Copy of Coal Supply Agreement, dated July 27, 1977, between IS and
Sunoco Energy Development Co., and letter memorandum thereto,
dated October 29, 1984, relating to the purchase of coal supplies
for the fuel requirements at the Ottumwa Generating Station.
(Filed as Exhibit 10-A-4 to File No. 33-3995).
10(x) Receivables Purchase and Sale Agreement. (Filed as Exhibit 10(a)
to IE's Form 10-Q for the quarter ended June 30, 1989).
10(y) Terra Comfort Capacity and Energy Agreement dated August 14, 1989
between IE and Terra Comfort Corporation. (Filed as Exhibit 10(n)
to IE's Form 10-K for the year 1989).
10(z) Capacity and Energy Agreement dated December 20, 1990 between
Terra Comfort Corporation and IE.
10(aa) Operating and Transmission Agreement between Central Iowa
Power Cooperative and IE.
10(ab) Capacity and Energy Agreement dated April 3, 1991 between Terra
Comfort Corporation and IE. (Filed as Exhibit 10(r) to IE's Form
10-Q for the quarter ended March 31, 1991).
*12 Ratio of Earnings to Fixed Charges.
*23 Consent of Independent Public Accountants.
*99 Director and Officer Information.
Note: Pursuant to (b)(4)(iii)(A) of Item 601 of Regulation S-K, the Company
has not filed as an exhibit to this Form 10-K certain instruments with
respect to long-term debt that has not been registered if the total
amount of securities authorized thereunder does not exceed 10% of total
assets of the Company but hereby agrees to furnish to the Commission on
request any such instruments.